Oil And Gas Journal 4186g

SEPT. 7, 2015 | USD 10

International Petroleum News and Technology | www.ogj.com

OGJ 150/100 PIPELINE ECONOMICS

SUBSURFACE UPDATE OFF MOZAMBIQUE UBD DESTABILIZES HORIZONTAL WELLS BIOCIDES MITIGATE FORMATION DAMAGE AFPM Q&A: HYDROPROCESSING

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CONTENTS Sept. 7, 2015 Volume 113.9

TOP COMPANIES IN RETURN ON...*

GENERAL INTEREST White House keeps oil, gas in Alaska picture amid climate emphasis

Gas discovery offshore Egypt rivals Mediterranean giants

Nick Snow

Tayvis Dunnahoe

56

60

WOTUS rule implementation uncertain after conflicting court decisions

EIA lowers US oil output estimates amid prolonged oil-price slump 60

Nick Snow

57

Kuwait lets contracts for grassroots refinery

Unconventional production raises unexpected tax questions, forum told Nick Snow

58

Robert Brelsford

61

EIA: Benefits of lifting US crude export ban most evident if output rises 61

Court approves ExxonMobil’s environmental settlement with New Jersey Nick Snow

MarkWest, EMG to develop 2-bcfd Utica dry gas gathering system

Return on total assets, %

20

19.5

Total assets 16.9

15.3

15

12.6 10

10.2

9.6

9.6

9.4

8.5

8.5

5

30

0

SPECIAL REPORT

SPECIAL REPORT

OGJ150 scores higher production, lower earnings

Oil pipelines lead way in strong 2014

Conglin Xu Laura Bell

110

OGJ 150/100

30

PIPELINE ECONOMICS

Christopher E. Smith

Lower oil prices slam OGJ100 2014 earnings Conglin Xu Leena Koottungal

48

63

59

COVER

Linn Energy LLC’s TexLa region consists of properties in East Texas and North Louisiana and primarily produces natural gas from the Cotton Valley and Travis Peak formations. The TexLa region produced 48 MMcfd of gas, or 4% of Linn’s 2014 average production. This year, Linn expects to spend 11% of its total oil and gas capital budget in developing the region. The annual OGJ150/100 report, starting on p. 30, records a downturn in 2014 earnings compared with a year earlier, inflicted by the plunge in oil prices yet despite strong liquids production growth. Photo from Linn.

REGULAR FEATURES

OG&PE

P1

NEWSLETTER 8 LETTERS/CALENDAR 18 JOURNALLY SPEAKING 26 EDITORIAL 28 SERVICES/SUPPLIERS 129 STATISTICS 131 MARKET CONNECTION 134 RS INDEX 139 EDITOR’S PERSPECTIVE/ WATCHING GOVERNMENT 140

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BATHYMETRY OF PAISLEY MOUNT, NORTHERN DAVIE RIDGE 41°E

42°E

64

88

TECHNOLOGY...

EXPLORATION & DEVELOPMENT

DRILLING & PRODUCTION

PROCESSING

TRANSPORTATION

Study updates uplift-erosion correlation, Davie fracture zone

UBD creates wellbore instability in horizontal wells

AFPM Q&A—2: Discussion expands to include hydroprocessing

Oil pipelines lead way in strong 2014

Yannis Bassias Robert Bertagne

Shiming He Wei Wang Ming Tang Ruifeng Zhang

88

76

Nelson-Farrar monthly cost indexes Gary Farrar

64

94

Biocides in fracing fluid mitigate formation damage

Infrastructure issues slow first-half 2015 ethylene production

Robert Fowles Kenneth Worsley Clayton Smith

Dan Lippe

96

82

DELEK REFINERY EXPANSION—1: Nontraditional approach to refinery revamp cuts time, adds flexibility James W. Jones Frank Simmons Tony D. Freeman

MECD CHANGE: NORMAL-FAULTING STRESS REGIME

104

90

75

60 Inclinat io

45 30 n angle, degree s

15

0

90

15 30 45 degrees 60 l angle, ha 75 ut im az Relative

76

0

Christopher E. Smith

110

Petrobras Netherlands B.V., represented by PetrÛleo Brasileiro S.A., will perform an international 6789 999 6 96 9 69 66 6 666 6 99 6 9 !9 68" #7 6 9 ! " $! 9 66789 %87996&!68 '696"# 6( 69 "% ) 9* 6%+!( 9,69,969%69) 9* 6#7 $+-) 9 9!6 9 7896899# $"" 99% %9! 7" ./ 0 '# 61 % 9 7$! ! 2!9 68" 6 7 " 99 $987"969 37 9 $87"96 9 visitation of the Unit for sale is 10/14/2015. 4 "69 6 799 99 6789 5%9"69 6 6 % 76 37 "9 !6 9 8 !69 96789 %87"969 %96 %646"6 96 9# $9 899 6 9

Bidding Committee International Call for Tenders No. 001/2015 PetrÛleo Brasileiro S.A.

THIS PHOTOGRAPH WAS TAKEN IN NOVEMBER, 2006, WHEN THE PLATFORM WAS STILL IN OPERATION.

INTERNATIONAL AUCTION

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PennWell, Houston office

PennWell, Tulsa office

1455 West Loop South, Suite 400, Houston, TX 77027 Tel 713.621.9720/Fax 713.963.6285/ Web site www.ogjonline.com Editor Bob Tippee, [email protected]

1421 S. Sheridan Rd., Tulsa, OK 74112 PO Box 1260, Tulsa, OK 74101 Tel 918.835.3161 / Fax 918.832.9290 Senior Art Director Michelle Gourd, [email protected] Senior Illustrators Mike Reeder Production Director Charlie Cole Production Manager Shirley Gamboa Ad Services Manager Zac Nash

Editorial Advisory Board Pat Dennler Motiva Enterprises LLC, Port Arthur, Tex. Doug Elliot Bechtel Hydrocarbon Technology Solutions/IPSI (Advisor), Houston Fernando Feitosa de Oliveira Pasadena Refining System Inc., Pasadena, Tex. Andy Flower Independent Consultant, Caterham, UK Michelle Michot Foss Bureau of Economic Geology’s Center for Energy Economics, The University of Texas (Houston) Michael Lynch Strategic Energy & Economic Research Inc., Amherst, Mass. Tom Miesner Pipeline Knowledge & Development, Houston Ralph Neumann Badger Midstream Energy LP Kent F. Perry RPSEA, Houston Ignacio Quintero Chevron Pipe Line Co., Houston John A. Sheffield John M. Campbell & Co., Lechlade, UK Andrew J. Slaughter Deloitte Services LP, Houston John Thorogood Drilling Global Consultant LLP, Insch, Scotland Steven Tobias Hess Corp., Houston Shree Vikas ConocoPhillips Co., Houston Clark White Targa Resources Inc., Houston Colin Woodward Woodward International Ltd., Durham, UK

Washington Tel 703.533.1552 Washington Editor Nick Snow, [email protected]

OGJ News Please submit press releases via e-mail to: [email protected]

Subscriber Service P.O. Box 2002, Tulsa OK 74101 Tel 1.800.633.1656 / 918.831.9423 / Fax 918.831.9482 [email protected],

PennWell Corporate Headquarters 1421 S. Sheridan Rd., Tulsa, OK 74112

P.C. Lauinger, 1900-1988 Chairman Frank T. Lauinger President/Chief Executive Officer Robert F. Biolchini Chief Financial Officer/ Senior Vice President Mark C. Wilmoth

Houston istration Publisher Jim Klingele, [email protected]

Member Audit Bureau of Circulations & American Business Media

Copyright 2015 by PennWell Corporation (ed in U.S. Patent & Trademark Office). All rights reserved. Oil & Gas Journal or any part thereof may not be reproduced, stored in a retrieval system, or transcribed in any form or by any means, electronic or mechanical, including photocopying and recording, without the prior written permission of the Editor. Permission, however, is granted for employees of corporations licensed under the Annual Authorization Service offered by the Copyright Clearance Center Inc. (CCC), 222 Rosewood Drive, Danvers, Mass. 01923, or by calling CCC’s Customer Relations Department at 978-750-8400 prior to copying. Requests for bulk orders should be addressed to the Editor. Oil & Gas Journal (ISSN 00301388) is published 12x per year - monthly the first Monday of each month in print and other Mondays in digital form by PennWell Corporation, 1421 S. Sheridan Rd., Tulsa, Okla., Box 1260, 74101. Periodicals postage paid at Tulsa, Okla., and at additional mailing offices. Oil & Gas Journal and OGJ are ed trademarks of PennWell Corporation. POSTMASTER: send address changes, letters about subscription service, or subscription orders to P.O. Box 3497, Northbrook, IL 60065, or telephone (800) 633-1656. Change of address notices should be sent promptly with old as well as new address and with ZIP code or postal zone. Allow 30 days for change of address. Oil & Gas Journal is available for electronic retrieval on Oil & Gas Journal Online (www.ogjonline.com) or the NEXIS® Service, Box 933, Dayton, Ohio 45401, (937) 865-6800. SUBSCRIPTION RATES in the US: 1 yr. $89; Latin America and Canada: 1 yr. $94; Russia and republics of the former USSR, 1 yr. 2,200 rubles; all other countries: 1 yr. $129, 1 yr. digital $59 worldwide. These rates apply only to individuals holding responsible positions in the petroleum industry. Single copies are $10 each except for 100th Anniversary issue which is $20. Publisher reserves the right to refuse non-qualified subscriptions. Oil & Gas Journal is available on the Internet at http://www.ogjonline.com. (Vol. 113, No. 9) Printed in the US. GST No. 126813153. Publications Mail Agreement Number 602914. Return Undeliverable Canadian Addresses to: P.O. Box 1632, Windsor, ON N9A 7C9.

OGJ Newsletter

Sept. 7, 2015

®

International News for oil and gas professionals

GENERAL INTEREST Q U IC K TA K E S EIM, AEP partner for unconventional work in Mexico EIM Capital, a private equity fund in Mexico City, announced a long-term partnership with an of American Energy Partners LP (AEP) of Oklahoma City to explore for unconventional resources in Mexico although financial were not disclosed. The US Energy Information istration reported in January 2014 that Mexico ranked eighth in the world in of oil and condensate technically recoverable from shale, estimated at 13.1 billion bbl. Regarding natural gas, EIA reported Mexico holds 545 tcf of technically recoverable shale resources (UOGR, March-April 2014). Energy reform in Mexico has opened its oil and gas resources to outside exploration and production companies and outside investors. The greatest unconventional potential exists in the part of the Eagle Ford shale that extends into Mexico’s Burgos basin from South Texas. EIM Capital is led by Chief Executive Officer Franco C. Hamdan and former Mexican President Vicente Fox. AEP is led by Aubrey K. McClendon, former Chesapeake Energy Corp. cofounder and chief executive officer. AEP and EIM Capital agreed AEP will invest in EIM Capital to tly pursue investments in Mexico’s energy industry and explore unconventional oil and gas development. No specifics were outlined. Hamdan, EIM Capital founder and chief executive officer, said, “Mexico’s proximity to the US market’s established infrastructure, service providers, and operators could help quickly scale the nascent Mexican shale industry and, with the right conditions, Mexico could rapidly emerge as a global leader in energy production.” AEP Chairman and CEO McClendon said, “EIM’s knowledge of and investments in Mexican infrastructure coupled with [AEP’s] knowledge of and operation within the unconventional energy industry will produce unparalleled opportunities.”

Wood calls for further UKCS incentives The architect of a UK strategy to boost offshore oil and gas work has called on the government and industry to apply “clever thinking to incentivize investment.” Calling crude prices below $50/bbl unsustainable, retired

8

For up-to-the-minute news, visit www.ogjonline.com

Wood Group Chairman Ian Wood told the BBC the industry “is right now facing as tough a time as it has ever faced.” Wood led a committee that in 2013-14 developed recommendations for taxation and regulatory changes to help the country achieve what it called maximum economic recovery from the mature UK Continental Shelf oil and gas resource. The government has implemented many of the recommendations (OGJ Online, Feb. 25, 2015). In his Aug. 28 remarks to the BBC, Wood said the government and industry should continue seeking tax changes to encourage development. “Otherwise, we will not be in a position to take advantage of the upturn,” he said.

E&P startup buys Permian assets from W&T Offshore Ajax Resources LLC, a newly formed exploration and production company backed by private equity firm Kelso & Co., has agreed to acquire all interest in Yellow Rose field belonging to Houston-based W&T Offshore Inc. for $376 million. W&T also reserved a 1-4% sliding scale overriding royalty interest in the field. The deal is effective Jan. 1 and expected to close during the third quarter. W&T’s interest in Yellow Rose field includes 25,800 net acres in Andrews, Martin, Gaines, and Dawson counties in West Texas. Net production from the field in July averaged 3,000 boe/d. Ajax believes that significant resource potential exists in the assets—which the company was formed to acquire—through multiple stacked pay horizontal drilling zones, and the company will benefit from extensive well control with more than 200 vertical and horizontal wells drilled and producing across the property. Ajax will be led by Chief Executive Officer Harvey Klingensmith, who has more than 40 years of operating experience in the oil and gas industry. For W&T, the move represents an opportunity to increase its focus on offshore E&P. Earlier this year the company reported a discovery at Ewing Banks Block 910 and the start of production from the Medusa SS No. 6 well on Mississippi Canyon Block 538, both in the deepwater Gulf of Mexico (OGJ Online, May 28, 2015). “This sale will allow us to strengthen our balance sheet and improve our financial flexibility to pursue the acquisition of Gulf of Mexico assets while valuations are favorable,” explained

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ICE BRENT / NYMEX LIGHT SWEET CRUDE $/bbl 52.00 50.00 48.00 46.00 44.00 42.00 40.00 38.00

US INDUSTRY SCOREBOARD — 9/7 4 wk. average

Latest week 8/21

Aug. 26

Aug. 27

Aug. 28

Aug. 31

Motor gasoline Distillate Jet fuel Residual Other products

Sept. 1

TOTAL PRODUCT SUPPLIED

Crude production NGL production2 Crude imports Product imports Other supply2 3 TOTAL SUPPLY Net product imports

YTD avg. year ago1

Change, %

9,567 3,705 1,667 224 5,121 20,284

9,039 3,928 1,594 198 5,048 19,807

5.8 (5.7) 4.6 13.1 1.4 2.4

9,141 3,943 1,568 207 4,860 19,719

8,773 3,884 1,488 237 4,556 18,938

4.2 1.5 5.4 (12.7) 6.7 4.1

9,386 3,265 7,498 2,233 2,410 24,792 (1,604)

8,554 2,880 7,625 1,686 2,418 23,163 (1,783)

9.7 13.4 (1.7) 32.4 (0.3) 7.0 —

9,400 3,139 7,300 2,115 2,322 24,276 (1,549)

8,330 2,741 7,386 1,810 2,261 22,528 (1,587)

12.8 14.5 (1.2) 16.9 2.7 7.8 —

16,884 17,146 95.5

16,890 16,728 93.9

(0.0) 2.5 —-

16,103 16,412 91.8

15,779 16,073 89.9

2.0 2.1 —-

Refining, 1,000 b/d Aug. 26

Aug. 27

Aug. 28 Aug. 31 1

Sept. 1

Crude runs to stills Input to crude stills % utilization

Latest week 8/21

Latest week

Previous week1

450,761 214,434 149,836 41,694 39,719

456,213 212,774 148,400 42,321 39,155

Same week year ago1 Change

Change

Change, %

Stocks, 1,000 bbl Crude oil Motor gasoline Distillate Jet fuel–kerosine Residual Stock cover (days)4 Aug. 26

Aug. 27

Aug. 28

Aug. 31

(5,452) 1,660 1,436 (627) 564

360,475 212,314 122,794 34,719 36,248

Change, %

90,286 2,120 27,042 6,975 3,471

25.0 1.0 22.0 20.1 9.6

Change, %

Sept. 1

Crude Motor gasoline Distillate Propane Futures prices5 8/28

ICE GAS OIL / NYMEX HEATING OIL ¢/gal 168.00 163.00 158.00 153.00 148.00 143.00 138.00 133.00

YTD average1

Supply, 1,000 b/d

NYMEX NATURAL GAS / SPOT GAS - HENRY HUB $/MMbtu 2.760 2.740 2.720 2.700 2.680 2.660 2.640 2.620

Change, %

Product supplied, 1,000 b/d

WTI CUSHING / BRENT SPOT $/bbl 52.00 50.00 48.00 46.00 44.00 42.00 40.00 38.00

4 wk. avg. year ago1

26.7 22.4 40.4 99.6

27.0 22.2 40.0 99.3

(1.1) 0.9 1.0 0.3

22.0 23.5 31.3 80.5

21.4 (4.7) 29.1 23.7

%

Light sweet crude ($/bbl) Natural gas, $/MMbtu

40.79 2.68

41.38 2.72

(0.6) —

94.91 3.84

(54.12) (1.17)

(57.0) (30.4)

1

Based on revised figures. 2OGJ estimates. 3Includes other liquids, refinery processing gain, and uned for crude oil. 4Stocks divided by average daily product supplied for the prior 4 weeks. 5Weekly average of daily closing futures prices. Source: Energy Information istration, Wall Street Journal Aug. 26

Aug. 27

Aug. 28

Aug. 31

Sept. 1

BAKER HUGHES INTERNATIONAL RIG COUNT: TOTAL WORLD / TOTAL ONSHORE / TOTAL OFFSHORE

PROPANE - MT. BELVIEU / BUTANE - MT. BELVIEU ¢/gal 54.00 52.00 50.00 48.00 43.00 40.00 37.00 34.00

Aug. 26

Aug. 27

Aug. 28

Aug. 31

3,900 3,600 3,300 3,000 2,700 2,400 2,100 1,800 600 300 0

Sept. 1

2,167 1,868 299 Jul. 14

Aug. 14 Sept. 14

Oct. 14

Nov. 14

Dec. 14

Jan. 15

Feb. 15

Mar. 15

Apr. 15

May 15

Jun. 15

July 15

Note: Monthly average count

NYMEX GASOLINE (RBOB)2/ NY SPOT GASOLINE3 ¢/gal 163.00 159.00 155.00 151.00 147.00 143.00 139.00 135.00 1Not

BAKER HUGHES RIG COUNT: US / CANADA 1,914

2,000 1,700 1,400 1,100

877

800 650 409

450

196

250 Aug. 26

Aug. 27

Aug. 28

Aug. 31

Sept. 1 1

available 2Reformulated gasoline blendstock for oxygen blending regular unleaded

3Nonoxygenated

50

6/20/14

6/13/14

7/4/14

6/27/14

7/18/14

7/11/14

8/1/14

7/25/14

8/15/14

8/8/14

5/29/14

5/22/14

6/19/15

6/12/15

7/3/15

6/26/15

7/17/15

7/10/15

7/31/15

7/24/15

8/14/15

8/7/15

5/28/15

5/21/15

Note: End of week average count

10

Oil & Gas Journal | Sept. 7, 2015

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Tracy W. Krohn, W&T chairman and chief executive officer. “We believe that current conditions are good for W&T to identify quality offshore producing assets that offer upside exploration and development opportunity.”

Total to sell retail network in Turkey Total SA has agreed to sell its service-station network and commercial sales, supply, and logistics properties in Turkey to Turkish conglomerate Demiroren Holding for about $356 million. The French company will retain its lubricant and odorless LPG operations in Turkey.

EXPLORATION & DEVELOPMENT Q U IC K TA K E S GeoPark follows Chachalaca success with Jacana GeoPark Ltd.’s Jacana 1 exploration well flowed 1,880 b/d of 14.9° gravity oil with a water cut of 1.9%, the company said. This discovery follows the company’s previously success with the Chachalaca 1 (OGJ Online, Aug. 28, 2015). Jacana field lies southwest of large Tigana oil field on Llanos 34 Block offshore Colombia. Jacana 1 was drilled to a total depth of 10,900 ft. The zone of interest is at 10,200 ft, which includes the Guadalupe and Mirador formations. According to GeoPark, Jacana field follows the same fault trend as Tigana, and appears to be combination structuralstratigraphic trap. The company expects to gather further production history to determine stabilized flow rates and the extent of Jacana field. As previously reported, GeoPark continues drilling operation on appraisal well Tilo 2. It plans drill a second Jacana appraisal well following completion of Jacana 1. GeoPark holds a 45% interest in Llanos 34 Block.

Tap Oil signs PSC for block offshore Myanmar Tap Oil Ltd. reported its entry into Myanmar following the g of the production-sharing contract for shallow-water Block M-7 in the Moattama basin offshore Myanmar. Tap holds 95% participating interest in the block and has assumed operatorship. Tap Energy (M7) Pte. Ltd. and its local t venture participant Smart E&P International Co. Ltd. signed the PSC with Myanmar Oil & Gas Enterprise (MOGE) on Aug. 26. Under the PSC, the JV partners have agreed to undertake an 18-month environmental and social impact assessment and study period followed by an option to proceed to a 3-year commitment exploration work program. Tap anticipates that it will spend $2.75 million on the block up to and including the study period, which has a minimum expenditure requirement of $2 million. The 13,372-sq km Block M-7 lies 160 km east of the 6.5-tcf Yadana gas field, and 70-km north east of the 1.5-tcf Zawtika gas field.

Buru finds more oil onshore Canning basin Buru Energy Ltd., Perth, has intersected a gross 23-m column of oil at the top of the Ungani Dolomite formation with its

12

Praslin-1 wildcat drilled in permit EP 391 in the onshore Canning basin of Western Australia. Well logs indicate the oil-bearing interval is similar to that of the productive zone at the nearby Ungani oil field. However reservoir characteristics still have to be confirmed with a production test program at a later date. Praslin-1 is about 90 km east of Broome and 15 km west of Buru’s producing Ungani field. The well will be plugged back to the base of the interpreted oil column and a completion string run into the hole. The rig will next move further east to the Victory-1 well, which is also on the Ungani trend. This will be followed by Senagi prospect later in the year. Operator Buru and Mitsubishi Corp. each have a 50% interest in EP 391.

USGS estimates Cherokee Platform Province reserves The Cherokee Platform Province in Kansas, Oklahoma, and Missouri contains estimated recoverable reserves totaling 463 million bbl of crude oil, 11.2 tcf of natural gas, and 35 million bbl of natural gas liquids, the US Geological Survey said in a Sept. 1 report. USGS said the assessment was part of its National and Global Petroleum Assessment Project.

DRILLING & PRODUCTION Q U IC K TA K E S Surmont 2 oil sands production launches from Alberta Operator ConocoPhillips and 50-50 partner Total SA have started production from their Surmont 2 in-situ oil sands facility situated 63 km southeast of Fort McMurray in the Athabasca region of Alberta. ConocoPhillips and Total SA have started production from Surmont 2 in the Athabasca region of Alberta. Photo from ConocoPhilips.

ConocoPhillips describes the Surmont 2 facility, construction of which began in 2010 (OGJ Online, Jan. 19, 2010), as “the largest single-phase steam-assisted gravity drainage (SAGD) project ever undertaken.” Since first steam in May (OGJ Online, June 1, 2015), the reservoir has successfully been heated to a point where the well pairs can be converted to a SAGD configuration, allowing the

Oil & Gas Journal | Sept. 7, 2015

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2015

oil to flow. Production was declared once the inspected product was successfully routed to sales tanks, ConocoPhillips says. Production will ramp-up through 2017, adding 118,000 bo/d. Total gross capacity for Surmont 1 and 2 is expected to reach 150,000 bo/d. Surmont 1 started commercial production in 2007 (OGJ Online, Dec. 11, 2007).

Malampaya compression platform installed Installation of a depletion compression platform near deepwater Malampaya gas and condensate field offshore the Philippines is complete, reports Arup, which provided engineering services for the fabrication and installation of the self-installing substructure (OGJ Online, Apr. 30, 2012). The new, 13,000-ton platform is part of the third phase of Malampaya development by Shell Philippines Exploration BV and partners Chevron Corp. and state-owned PNOC Exploration Corp. The platform was set in place in less than 24 hr during February with an in-built jacking system. Since then the facility has been connected via a 43-m bridge link to the existing concrete gravity substructure processing platform. The platforms and a catenary anchor-leg mooring buoy for condensate are in shallow water about 30 km from the field, where wells are completed subsea in 820 m of water in the West Philippine Sea off Palawan. The Malampaya and Camago reservoirs produce about 380 MMscfd of natural gas and 15,000 b/d of condensate. From the platform, dry gas flows through a 504-km, 24-in. OD pipeline to a plant on Luzon south of Manila for further processing and ultimate delivery to electric power plants. Shell Philippines completed the second phase of Malampaya development in 2013 with the addition of two production wells.

UK approves $4.5-billion Culzean development The UK Oil & Gas Authority has greenlighted development of high-pressure, high-temperature (HPHT) Culzean field in the central North Sea. Operator Maersk Oil and coventurers JX Nippon and BP PLC are investing $4.5 billion in the development, which Maersk notes “has benefited from the HPHT Cluster Area Allowance introduced by the UK government as part of the 2015 budget.” The allowance s the development of HPHT projects—which tend to have considerably higher capital costs— and encourages exploration and appraisal activity in the surrounding area, or “cluster,” Maersk says. The gas-condensate field, discovered in 2008 (OGJ Online, Jan. 30, 2009), has resources estimated at 250-300 million boe. Production is expected to start in 2019 and continue for at least 13 years, plateauing at 60,000-90,000 boe/d. The partners will develop Culzean with a standalone facility, which will be a complex of bridge-linked platforms comprising a 12-slot wellhead platform, a central processing facility, and utilities-living quarters (OGJ Online, Nov. 20, 2014). Two front-

14

end engineering and design contracts were let in 2014. Maersk recently let a contract to Tenaris for casing and related services for the project (OGJ Online, Aug. 25, 2015). Separately, Maersk Oil let a $1 billion engineering, procurement, and construction contract to Sembcorp Marine subsidiary SMOE Pte. Ltd., Singapore, for topsides for the project The contract includes construction of the central processing facility and two connecting bridges, wellhead platform, and utilities and living quarters platform topsides.

PROCESSING Q U IC K TA K E S CHS takes full ownership of Kansas refinery US farmer-owned cooperative CHS Inc., Inver Grove Heights, Minn., has completed its purchase of National Cooperative Refinery Association’s refinery and related operations at Mherson, Kan., to take full ownership of the assets (OGJ Online, Dec. 1, 2011). Conclusion of the deal follows a 2011 agreement with then-minority owners Growmark Inc., Bloomington, Ill., and MFA Oil Co., Columbia, Mo., to buy additional interest in the Mherson refinery in four annual increments starting on Sept. 1, 2012, and culminating on Sept. 1, 2015, CHS said. CHS’s current investments in infrastructure and pipelines at the 85,000-b/d refinery, now renamed the CHS Refinery at Mherson, are due to boost crude processing capacity at the Kansas plant to 100,000 b/d in 2016, the cooperative said. CHS began the $330-million Mherson expansion, which was designed to be completed in phases during this year’s second half and early 2016, in 2013 (OGJ Online, Mar. 12, 2013). The expansion project is under way alongside a separate project to construct a $555-million replacement coker at the refinery (OGJ, Dec. 3, 2012, p. 100). The cooperative incurred $186.8 million in costs related to the coker project during fiscal-year 2014 and $121.3 million during the 9 months ended May 31, CHS said in its latest quarterly earnings report to investors. Capital expenditures related to the refinery’s expansion amounted to $128.3 million for fiscal year 2014 and $105.1 million for the 9 months ended May 31.

South Africa’s Engen wraps refinery turnaround Engen Petroleum Ltd. has restarted its 125,000-b/d Enref refinery in Durban, South Africa, following a 4-week period of planned maintenance activities (OGJ Online, July 6, 2015). The 30-day scheduled turnaround, which comes as part of the refinery’s ongoing maintenance program to ensure safe and reliable operations, was completed at a cost of more than 150 million rand, the company said. As a result of the maintenance work, the refinery currently is operating at 99.8% of its full capacity, according to John Naidoo, Engen’s maintenance manager. Turnaround activities included testing of all safety and protection equipment and systems, as well as routine maintenance

Oil & Gas Journal | Sept. 7, 2015

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and services on critical equipment as recommended by the original equipment manufacturer, Naidoo said. The company, which previously warned of potential supply disruptions during the shutdown period, did not disclose details regarding impacts to supply commitments as a result of the planned outage. The Enref refinery, South Africa’s second largest, produces automotive, industrial, aviation, and marine fuels, as well as bitumen, lubricants, and a range of chemicals and solvents.

PDVSA restarts FCCU at Amuay refinery Petroleos de Venezuela SA (PDVSA) has restarted the fluid catalytic cracking unit (FCCU) at its 645,000-b/d Amuay refinery in northwestern Venezuela’s Falcon state following the unit’s unplanned shutdown in early July. Corrective maintenance on the 166,500-b/d FCCU has been completed, with the unit reentering operations as of Aug. 25, PDVSA said. Repairs to the unit previously were scheduled to wrap on or about July 28, the state-run company said previously (OGJ Online, July 20, 2015). PDVSA shuttered the unit on July 1 following unidentified problems with its regenerator and associated minor equipment. Remaining processing units at the Amuay refinery as well as at the nearby 310,000-b/d Cardon refinery—which together comprise PDVSA’s 955,000-b/d Paraguana Refining Center continued to operate normally during the unplanned maintenance period. Despite the unit’s extended outage, the company said it maintains sufficient fuel inventories to meet both its domestic and international supply commitments.

TRANSPORTATION Q U IC K TA K E S PHMSA will award $54.1 million in safety grants The US Pipeline and Hazardous Materials Safety istration plans to award nearly $54.1 million in grants to pipeline safety programs in 46 states, the District of Columbia, and Puerto Rico, the US Department of Transportation agency reported. “These grants ensure state programs have the funding they need for resources, including personnel and equipment, to protect communities, carry out inspections, and enforce safety regulations that keep the entire pipeline network as safe as possible,” US Transportation Sec. Anthony Foxx said. PHMSA Marie Therese Dominguez announced the grants before an audience of state inspectors and regulators as part of the annual National Association of Pipeline Safety Representatives Board of Directors meeting in Tempe, Ariz., on Sept. 1. “These grants extend the reach of PHMSA and our State partners into our communities,” she said. “[They] allow us to have a strong local presence that is vital to effectively monitor pipelines and help protect the public from pipeline incidents.” PHMSA said the grants provide as much as 80% of operating costs for state pipeline regulatory agencies that agree to inspect

16

intrastate pipelines on the federal agency’s behalf. Participating states and territories for 330 inspectors who are responsible for more than 80% of the nation’s intrastate natural gas and hazardous liquid pipeline mileage, the DOT agency said. More than 2.6 million miles of pipelines transport oil and gas to homes and businesses throughout the country, it noted.

Extension sought for Mackenzie Gas Project The earliest possible construction start for the Mackenzie Gas Project, which would connect natural gas fields in the Canadian Arctic with northwestern Alberta, is 2022, according to a request by project sponsors for an extension in federal approval. Canada’s National Energy Board approved the project in December 2010 and issued a certificate of public convenience and necessity for the 1,220-km Mackenzie Valley Pipeline the following March (OGJ Online, Mar. 11, 2011). Unless extended, approval expires at the end of this year if construction doesn’t begin. “Due to the current challenging North American natural gas market conditions, a decision to construct the project has not yet been made,” lead sponsor Imperial Oil advised in letter to the NEB. The company asked the board to extend the sunset clause to Dec. 31, 2022, “to provide time to determine if the currently oversupplied North American natural gas market will recover sufficiently to warrant a resumption in the project work.” If Imperial and its partners decided to proceed with the project, the letter said, they would need about 4 years for preconstruction work including fiscal framework discussions, detailed engineering, and “extensive” permitting. “As a result,” the letter said, “2022 is expected to be the earliest possible construction start.” The project is based on a 6-tcf gas resource in three Mackenzie Delta fields in Northwest Territories. In addition to the gas pipeline and field developments, work would include construction of a gathering system, gas processing plant, and 457-km natural gas liquids pipeline between Inuvik and Norman Wells.

Cenovus completes purchase of rail terminal Cenovus Energy Inc. has completed the purchase of a crudeby-rail transloading facility in Bruderheim, Alta., from Canexus Corp. Both companies are based in Calgary. Originally called North American Terminal Operations, the facility, about 50 km northeast of Edmonton, has been renamed Bruderheim Energy Terminal. Cenovus began moving oil through the terminal last year and currently transports crude oil from its Foster Creek steamassisted gravity drainage operation to Bruderheim via the Cold Lake pipeline. The terminal also has connections to the Access crude oil pipeline and links to the Canadian Pacific and Canadian National rail lines. “The acquisition is part of Cenovus’s strategy to build a strong portfolio of transportation options to help maximize market access and capture global prices for its oil,” the company said.

Oil & Gas Journal | Sept. 7, 2015

Industrial Rubber’s Fast Latch Adapter Makes the Connection

Industrial Rubber’s Fast Latch Coupler, the accepted alternative to threading casing adaptors because of its quality and time-saving value, easily connects to Industrial Rubber’s cement heads with the Fast Latch Adapter. Industrial Rubber (IRI) provides adapters in two confgurations ranging from 4 ½-in. to 20-in. sizes, so that you have the right adapter for the right condition, and a secure, safe connection to the cement head.

Quick Coupling Style

Quick Coupling Style Uses IRI’s existing quick coupling union to attach the Fast Latch to the cement head. And as an option, allows for use of IRI’s circulating cap. Direct Connect Style Suitable for rigs with limited vertical clearance, this adapter attaches directly to the cement head. Compared to the Quick Coupling Style, the Direct Connect can reduce the assembly height 9 in. to 11 in. When it comes to the best products at the best price, make the connection with Industrial Rubber Oil Tools.

Call us for more information and pricing: 800-457-4851, or visit www.iri-oiltool.com

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Direct Connect Style

2015-2016 EVENT CALENDAR Denotes new listing or site: www.asiapacific. cwclng.com/ 8-11. a change in previously published information. SPE Offshore Europe Conference & Exhibition, Aberdeen, web site: www.offshoreeurope.co.uk/ 8-11. SEPTEMBER 2015

APPEA Health, Safety & Environment Conference, Perth, web site: www.appeahseconference.com. au/ 7-9. European Association of Geoscientists & Engineers Petroleum Geostatistics, Biarritz, , web site: www.eage.org/event/ index.php?eventid= 1155&Opendivs=s3 7-11.

India Oil & Gas Review Summit & International Exhibition, Mumbai, web site: www.oilgasevents.com/india-oilgas 9-10. AAPG International Conference & Exhibition, Melbourne, web site: www.aapg. org/events/conferences/ice/details/ articleid/5664/aapg2015-internationalconference-exhibition 13-16.

Africa Oil & Gas EXPO, Johannesburg, SPE North Africa Technical Conference web site: www.afri& Exhibition, Cairo, caoilexpo.com/ 8-9. web site: www.spe. org/events/natc/2015/ World LNG Series: 14-16. Asia Pacific Summit, Singapore, web

SPE Reservoir Characterization & Simulation Conference & Exhibition, Abu Dhabi, web site: www.spe. org/events/rcsc/2015/ 14-16. Middle East Process Engineering Conference & Exhibition (MEPEC), Manama, Bahrain, web site: www.mepec.org/ 14-17. SPE Middle East Intelligent Oil & Gas Conference & Exhibition, Abu Dhabi, web site: www.spe.org/events/ ieme/2015/ 15-16. Oil Sands Trade Show & Conference, Fort McMurray, Alta., web site: www.oilsandstradeshow.com 15-16. Pipeline Week, The Woodlands, Tex., web site: www.pipelineweek.com/ 15-17.

IADC Asset Integrity & Reliability Conference & Exhibition, Houston, web site: www.iadc. org/event/2015iadc-asset-integrityreliability-conferenceexhibition 16-17.

Rio Pipeline Conference & Exhibition, Rio de Janeiro, web site: www.ibp.org.br/ 22-24.

LNG Global Congress Conference (LNGgc), London, web site: GPA Europe Annual- www.lnggc.com 22Conference, Florence, 25. web site: www.gpaeurope.com 16-18. Global Oil & Gas Black Sea & MediterRice Global Engineer- ranean Exhibition & ing & Construction Conference, AthAnnual Forum XVIII, ens, web site: www. Houston, web site: oilgas-events.com/ www.forum.rice.edu/ Global-Oil-Gas-Black21-22. Sea-Mediterranean 23-24. Mozambique Gas Summit, Maputo, Mo- IADC Drilling HSE&T zambique, web site: Europe Conference & www.mozambiqueExhibition, Amstergas-summit.com dam, web site: www. 21-24. iadc.org/event/eurohset-2015 23-24. Upstream & Downstream Oil & Gas Ex- IOGCC Annual Conferhibition & Conference, ence, Oklahoma City, Abuja, Nigeria, web web site: iogcc.pubsite: www.oilandgasex- lishpath.com/events pos.com/ 22-24. 28-30.

SPE Annual Technical Conference & Exhibition, Houston, web site: www.spe.org/ atce/2015/ 28-30. Oil & Gas Anti-Corruption & Compliance Exchange, Houston, web site: momentumevents.com/acoilgas/ 29-30.

OCTOBER 2015 American Fuel & Petrochemical Manufacturers Q&A & Technology Forum, New Orleans, web site: www2.afpm.org/ forms/meeting/Microsite/QA15 4-7. OGIS San Francisco, San Francisco, www. ipaa.org/meetingsevents/ 5-7. KIOGE 2015 Kazakhstan International Oil & Gas Conference & Exhibition, Almaty,

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WE KNOW THE DRILL. When it comes to meeting offshore mission requirements, Airbus Helicopters delivers in the most demanding environments. In the Gulf of Mexico, the North Sea, off the coast of Africa and in the Asia-Pacific region, offshore Oil & Gas companies have accumulated more than 10 million flight hours using Airbus Helicopters products to transport their people to and from work safely. That’s more flight time in exploration, production and SAR missions than any other helicopter manufacturer. We know what it takes to exceed our Oil & Gas customers’ expectations. With the most aircraft operating in Oil & Gas globally, Airbus Helicopters knows the drill.

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2015-2016 EVENT CALENDAR

Kazakhstan, web site: 3P Arctic Polar Petrowww.kioge.kz/en/ 6-9. leum Potential Conference & Exhibition, St. International Confer- Petersburg, web site: ence on Theoretical & www.3parctic.com Experimental Studies 6-9. of Hydrocarbons (ICTESH), Athens, Equatorial Guinea Oil web site: www.ictesh. & Gas Conference & org 6-9. Exhibition, Malabo,

Equatorial Guinea, PIRA New York Anweb site: www.cwceg. nual Conference, New com 7-9. York City, web site: www.pira.com 8-9. International Oil & Gas Expo, Jakarta, SPE Kuwait Oil & Gas web site: www.pam- Show & Conference, erindo.com/events/6 Mishref, web site: 7-10. kogs2015.com 11-14.

High Reliability and Availability Backed by Superior Service

Gas-to-Liquids, London, new-orleans-2015/ web site: www.gas-to- 18-23. liquids.co.uk/ogj 12-13. API Fall Committee on Enterprise MobilPetroleum Measureity—Nigeria Oil & Gas ment Standards Meet2015, Lagos, web site: ing, Atlanta, web site: nog.cwcenterprisemo- www.api.org/eventbility.com 12-14. sand-training/calendarof-events/2015/ fallcopm 19-23. IADC Advanced Rig Technology Conference & Exhibition, SPE Unconventional Amsterdam, web site: Resource Conference, www.iadc.org/event/ Calgary, web site: rig-technology-2015 www.spe.org/events/ 13-14. urc/2015/ 20-22. Offshore Energy Exhibition & Conference, Amsterdam, web site: www.offshore-energy. biz 13-14.

Photo courtesy of Lukoil

Deep Offshore Technology International, The Woodlands, Tex., web site: www.deepoffshoretechnology. com/index 13-15.

Waukesha Magnetic Bearings® brings more than 30 years of experience to equipping the oil & gas industry’s critical rotating machinery.

Every one of our active magnetic bearing (AMB) systems… • Starts with proven technology • Is optimized for operating conditions • Provides remote commissioning, diagnostics and adjustments with an advanced, multi-axis digital controller • Is backed by superior service and training For the most robust AMB systems and lowest total cost of ownership, choose Waukesha Magnetic Bearings.

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SPE/IATMI Asia Pacific Oil & Gas Conference & Exhibition (APOGCE), Bali, web site: www.spe.org/ events/apogce/2015/ 20-22.

PETROTECH International Oil & Gas Conference, New Delhi, web site: www.zapaday.com/ SPE Eastern Regional event/67326/5/ Petrotech.html 25-28. Meeting, Morgantown, WVa., web site: nwvspe.org/regional- SPE Russian Pemeeting.html?_ga=1.8 troleum Technical 4416921.107275622. Conference, Moscow, 1429302557 13-15. web site: www.spe. org/events/rpc/2015/ CEE & Turkey Refining 26-28. & Petrochemicals, Budapest, web site: API Tank, Valves, www.wraconferences. Piping & Pumps com/event/cee-andConference & Expo, turkey-refining-andLas Vegas, web petrochemicals 13-15. site: api.org/eventsandtraining/calendarofevents/2015/tvp International LNG 26-29. in BC Conference, Vancouver, BC, web site: Ingconference. LAGCOE Louisiana ca/ 14-16. Gulf Coast Oil Exposition, Lafayette, web site: www.lagcoe.com SEG International 27-29. Exposition & Annual Meeting, New Orleans, web site: Offshore Technology www.seg.org/web/seg- Conference Brazil,

Oil & Gas Journal | Sept. 7, 2015

2015-2016 EVENT CALENDAR

Rio de Janeiro, web Gas Processors site: www.otcbrasil.org Association North 27-29. Texas Annual Meeting, Dallas, web site: www. Gastech Conference & gpaglobal.org 5. Exhibition, Singapore, web site: www.gasNAPE International techsingapore.com/ Conference & Exhibi27-30. tions, Lagos, web site: www.nape.org.ng/ news/int-l-conferencAsian Downstream es/item/165-2015Week, Singapore, nape-33 8-12. web site: www. downstream-asia.com 28-29. AIChE Annual Meeting, Salt Lake City, web site: www.aiche. org/conferences/ NOVEMBER 2015 aiche-annualmeetBasra Oil, Gas & Infra- ing/2015 8-12. structure Conference NAPE, Denver, web site: 2015, Istanbul, web site: www.cwcbasrao- napeexpo.com/ 9-10. ilgas.com 2-3. SPE Asia Pacific Unconventional OPITO Safety & Competence Confer- Resources Conference, Abu Dhabi, web ence & Exhibition, site: www.opito-oscc. Brisbane, web site: www.spe.org/ events/ com 3. urce/2015/ 9-11. Deepwater Operations Conference & Exhibi- Abu Dhabi Intertion, Galveston, Tex., national Petroleum Exweb site: www.deep- hibition & Conference wateroperations.com/ (ADIPEC), Abu Dhabi, web site: www.adipec. index 3-5. com 9-12. SPE Annual Caspian Technical Conference API Cybersecurity Conference & Expo, & Exhibition, Baku, Houston, web site: web site: www.spe. org/events/ctce/2015/ www.api.org/eventsand-training/calendar4-6. of-events/2015/cyberIADC Annual General security 10-11. Meeting, San Antonio, web site: www.iadc.org/ Mangystau Regional event/2015-iadc-annu- Oil, Gas & Infrastrucal-general-meeting 4-6. ture Exhibition, Aktau, Kazakhstan, web site: International Oil & Gas mangystau.oil-gas.kz/ Exploration, Produc- en/ 10-12. tion & Refining Expo, European Autumn Gas Jakarta, web site: oilgasindonesia.com/ Conference (EAGC), about/about-oil-gasin- Geneva, web site: www. theeagc.com/ 17-19. donesia/ 4-7.

Carbon Management Technology Conference, Sugar Land, Tex., web site: fscarbonmanagement.org/events/ carbon-managementtechnology-conference-2015-cmtc-2015 17-19.

OFFSHORE AND DEEP WATER CONNECTORS

Turkmenistan International Oil & Gas Conference (OGT), Ashgabat, web site: www.oilgas-events. com/OGT 17-19. Petrochemical Operations, Maintenance & Safety Conference & Exhibition USA, Houston, web site: www. petchem-update.com/ petrochemicals-operations-maintenancesafety/ 18-19.

Large choice of configurations:

Petroleum, Refining & Environmental Monitoring Technologies Conference Exhibition & Seminars (PEFTEC), Antwerp, web site: www.peftec.com 18-19.

High and low voltage Coaxial and triaxial Thermocouple Fibre optic Fluidic and pneumatic

IADC Critical Issues Asia Pacific Conference & Exhibition, Singapore, web site: www.iadc.org/event/ asia-pacific-2015 18-19.

Hybrid Custom solutions Cable assembly & Cable solutions

Applications such as:

SPE Latin America & Caribbean Petroleum Engineering Conference (LAEC), Quito, Ecuador, web site: www.spe.org/events/ laec/2015/en/ 18-20. Gas Processors Association Rocky Mountain Annual Meeting, Denver, web

Petroleum / Chemicals Geophysics Seismograph Surveying Data acquisition LEMO SA - Switzerland Phone : (+41 21) 695 16 00 Fax : (+41 21) 695 16 02 [email protected] your local partner on www.lemo.com

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21

2015-2016 EVENT CALENDAR

site: www.gpaglobal. org 19. Project Financing in Oil & Gas, London, web site: www. projectfinance-oilgas. com/ogi 23-24. Saudi Arabia International Oil & Gas Exhibition (SAOGE), Dammam, web site: www.saoge.org/23-25. SPE Thermal Well Integrity & Design Symposium, Banff, Alta., web site: www.spe. org/events/twid/2015/ 23-25. SPE Oil & Gas India Conference & Exhibi-

tion (OGIC), Mumbai, DECEMBER 2015 web site: www.spe. org/events/ogic/2014/ Oil & Gas Vietnam 24-26. (OGAV) 2015, Vung Tau City, Vietnam, Intergas-VII Oil, Gas web site: www.oilgas& Petrochemicals, vietnam.com/ 1-3. Cairo, web site: www. intergas-egypt.com/ International Petro24-26. leum Technology Conference (IPTC), Doha, Kurdistan-Iraq Oil web site: www.iptcnet. & Gas Conference org/pages/about/futu& Exhibition, Erbil, redates.php 6-9. Kurdistan, web site: www.cwckiog.com/ Anniversary Chem Nov. 30-Dec. 2. Show 2015, New York City, web site: www. Brazil Local Content chemshow.com 8-10. Summit & Exhibition, Rio de Janeiro, web site: www.brazil-local- JANUARY 2016 content.com/ Nov. 30-Dec. 3. North Africa Downstream Summit,

T +49 2961 7405-0 T +1 704 716 7022 T +65 6702 3707

Cairo, web site: www. northafricadownstream.com/ 17-19. World Future Energy Summit, Abu Dhabi, web site: www.worldfutureenergysummit. com/ 18-21. Annual Offshore West Africa Conference & Exhibition, Lagos, web site: www.offshorewestafrica.com/ 26-28. SPE/IADC Middle East Drilling Technology Conference & Exhibition, Abu Dhabi, web site: www.spe.org/ events/medt/2015/ 26-28.

Black Sea Oil & Gas Summit, Vienna, web site: www.theenergyexchange.co.uk/event/ black-sea 28-29.

FEBRUARY 2016 Pipeline Pigging & Integrity Management Conference, Houston, web site: www.clarion. org/ppim/ppim16/ index.php 8-11. ARC Industry Forum, Orlando, web site: www.arcweb.com/ events/arc-industryforum-orlando 8-11. Topsides, Platforms & Hulls, Galveston,

Tex., web site: www. topsidesevent.com 9-11. International Petroleum (IP) Week, London, web site: https://www. energyinst.org/events/ ip-week 9-11. SPE Hydraulic Fracturing Technology Conference & Exhibition, The Woodlands, Tex., web site: www. spe.org/events/ hftc/2016/ 9-11. NAPE Summit, Houston, web site: napeexpo.com/shows/ about-the-show/summit 9-12.

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2015-2016 EVENT CALENDAR

IADC Drilling Africa Conference & Exhibition, Cape Town, web site: www.iadc. org/event/drillingafrica-2016 15-16.

CERAWeek, Houston, web site: ceraweek.com/2016/ 22-26. Pipe Line Contractors Association (PLCA) Convention, Scottsdale, Ariz., web site: www. plca.org/ 23-27. SPE International Conference & Exhibition on Formation Damage Control, Lafayette, La., web site: www.spe.org/ events/fd/2016/ 24-26.

MARCH 2016

NACE Corrosion, Vancouver, BC, web site: nacecorrosion. org/ 6-10. Middle East Geosciences Conference (GEO), Manama, web site: geo2016.com/ 7-10. IADC International Deepwater Drilling Conference & Exhibition, Rio de Janeiro, web site: www.iadc. org/event/drillingafrica-2016 15-16. Global Oil & Gas Turkey (formerly TUROGE), Ankara, web site: www.oilgasevents.com/TUROGEConference 16-17.

Gas Compressor Association Expo & IADC/SPE Drilling Con- Conference, Galveston, Tex., web site: ference & Exhibition, www.gascompressor. Fort Worth, web site: org/meetings 21-23. www.spe.org/events/ dc/2016/ 1-3.

24

SPE EOR Conference at Oil & Gas West Asia, Muscat, web site: www.spe.org/events/ ogwa/2016/ 21-23. SPE/ICoTA Coiled Tubing & Well Intervention Conference & Exhibition, Houston, web site: www.spe.org/events/ ctwi/2016/ 22-23. Subsea Tieback Forum, New Orleans, web site: www.subseatiebackforum.com/ index.html 22-24. Offshore Technology Conference—Asia, Kuala Lumpur, web site: 2016.otcasia.org/ 22-25. China International Petroleum & Petrochemical Technology & Equipment Exhibition (CIPPE), Beijing, web site: www.cippe. com.cn/2016/en/ 29-31.

SPE SMN Sand Management EuroForum, Aberdeen, web site: www.sandmanagement.com/ 30-31.

APRIL 2016 SPE Improved Oil Recovery Conference, Tulsa, web site: www. speior.org 9-13. Kuwait Oil & Gas Summit, Kuwait, web site: www.cwckuwait. com 10-12. SPE International Conference & Exhibition on Health, Safety, Security, Environment & Social Responsibility (HSSE–SR), Stavanger, web site: www. spe.org/events/ hse/2016/ 11-13.

oil-gas.kz/en/exhibition/ FLAME 2016, Amsterabout-the-exhibition/ dam, web site: www. 12-14. icbi-flame.com/ 9-12. SPE/IADC Managed Pressure Drilling & Underbalanced Operations Conference & Exhibition, Galveston, Tex., web site: www.iadc.org/ event/2016-speiadcmanaged-pressuredrilling-underbalanced-operationsconference-exhibition/ 12-13.

SPE International Oilfield Scale Conference & Exhibition, Aberdeen, web site: www.spe.org/events/ oss/2016/ 11-12. Uzbekistan International Oil & Gas Conference (OGU), Tashkent, web site: www.oilgas-events. com/OGU-Conference 12-13.

PNEC International Conference on Petroleum Data Integration, Offshore Technology Information & Data Conference, Houston, Management, Houston, web site: 2016.otcnet. web site: www.pneccoorg/ 2-5. nferences.com 17-19.

MAY 2016

SPE International Oilfield Corrosion Conference & Exhibition, Aberdeen, web site: Global Oil & Gas Atyrau www.spe.org/events/ ofcs/2016/ 9-10 . Exhibition, Atyrau, Kazakhstan, web site:

Global Oil & Gas Myanmar Conference, Yangon, web site: www.oilgas-events. com/Myanmar-OilGas-Conference 19-20.

Oil & Gas Journal | Sept. 7, 2015

2015-2016 EVENT CALENDAR

EITEP Pipeline Technology Conference, Berlin, web site: www. pipeline-conference. com/ 23-25.

web site: www. oilgas-events.com/ Caspian-OG-Exhibition/ 7-10.

SPE Trinidad & ToSPE Europec, Vienna, bago Section Energy web site: www.spe. Resources Conferorg/events/euro/2016/ ence, Port of Spain, May 30-June 2. web site: spettconf. org/ 13-15. EAGE Conference & Exhibition, Vienna, IADC World Drilling web site: www.eage. Conference & Exhibiorg/event/index. tion, Lisbon, web site: php?eventid=1391 May www.iadc.org/event/ 30-June 2. world-drilling-2016/ 15-16.

JUNE 2016 Caspian Oil & Gas Exhibition, Baku,

conferences/ace/ 19-22.

North American Custody Transfer Measurement Confer- SEPTEMBER 2016 ence, San Antonio, web site: www.ceesi. SPE Intelligent Energy com 21-23. Conference, Aberdeen, web site: www. intelligentenergyevent. AUGUST 2016 com/ 6-8. IADC/SPE Asia Pacific Drilling Technology Conference & Exhibition, Singapore, web site: www.spe.org/ events/apdt/2016/ 22-24.

AAPG 2016 Annual Convention & Exhibition, Alberta, web site: Offshore Northern www.aapg.org/events/ Seas, Stavanger, web

Oil & Gas Journal | Sept. 7, 2015

site: www.tofairs.com/ www.spe.org/events/ expo.php?fair=103366 calendar/ 26-28. Aug. 29-Sept. 1.

Rio Oil & Gas Expo & Conference, Rio de Janeiro, web site: https:// www.whereinfair.com/ rio-oil-gas-expo/rio-dejaneiro/2016-Sep/ 14-16.

tion, Houston, web site: www.aapg.org/ events/conferences/ ace/ 2-5.

OCTOBER 2016 Arctic Technology Confer- MAY 2018 ence, St. John’s, Newf., web site: www.spe.org/ AAPG 2018 Annual events/calendar/ 24-26. Convention & Exhibition, Salt Lake City, Asia Pacific Oil & Gas web site: www.aapg. Conference & Exhibi- org/events/confertion (APOGCE), Perth, ences/ace/ 20-23. web site: www.spe.org/ events/apogce/2016/ 25-27. JUNE 2018

APRIL 2017 SPE Annual Technical Conference & Exhibi- AAPG 2017 Annual tion, Dubai, web site: Convention & Exhibi-

World Gas Conference, Washington, DC, web site: wgc2018.org/ -us/ 25-29.

25

JOURNALLY SPEAKING

When life gives you lemons

MATT ZBOROWSKI Staff Writer

This year marks separate anniversaries of two catastrophic environmental events for the US Gulf Coast in general, and Louisiana in particular. It was this time a decade ago that New Orleans and surrounding regions were reeling from the fallout of Hurricane Katrina, which caused the deaths of more than a thousand residents while displacing tens of thousands more. Much of the more than $100 billion in damages were attributed to the gradual loss of coastal wetlands over the preceding decades. A study published in 2007 by the US Geological Survey found that between 1932 and 2000, more than 1,900 square miles of land was lost—greater than the size of Delaware—from Louisiana’s coastal lands due to either erosion or subsidence. Almost 5 years after Katrina and about 130 miles southeast of New Orleans, while the Gulf Coast region was still in the midst of recovery from the storm, the deepwater Macondo well blowout and subsequent oil spill resulted in deaths of 11 workers and, according to a January ruling from the US District Court for the Eastern District of Louisiana, the discharge of 3.19 million bbl of oil into the Gulf of Mexico. Numerous species were harmed, killed, or at best displaced from their natural habitat while BP PLC worked to halt and clean the gushing oil.

Gulf Coast preservation In the years since Katrina, New Orleans has rebuilt and the population has approached pre-Katrina levels. The city’s economy has grown at a rate above the national average, with job creation surging. Recovery has far exceeded expectations, and it seems only another Act of God could halt the city’s momentum. How the gulf region has recovered since Deepwater Horizon is less clear, as, for one, it’s impossible to track what became of all the oil that was released into the sea. For the trouble, BP in July agreed to settle federal and state Deepwater Horizon claims for $18.7 billion over an 18-year period. The principle target of money received from BP has been and will be restoration of the Gulf Coast through entities

26

such as the Deepwater Horizon Natural Resources Damage Assessment (NRDA) Early Restoration Program. Thus far $318 million have been allocated for Louisiana outer coastal restoration, which encomes four projects. One announced in June involves excavating as much as 13.4 million cu yards of high-quality sand from Ship Shoal—9 miles offshore on the Outer Continental Shelf—and transporting it through a temporary pipeline to construct 1,100 acres of barrier island habitat at the Caillou Lake Headlands, also known as Whiskey Island. “Restoring barrier islands protects vital wetlands along the Gulf Coast and is part of BOEM’s continuing commitment to work with states and communities to restore and protect our coasts from the effects of storms and climate change,” explained Abigail Ross Hopper, director of the US Bureau of Ocean Energy Management. Four other recent projects along Louisiana’s coastline have already used 11 million cu yards of OCS sand: Caminada Headland Beach and Dune Restoration Increment I, Cameron Parish Shoreline Restoration, Raccoon Island Backbarrier Marsh Restoration, and Pelican Island Restoration. BOEM notes that prior to the recent work, the Holly Beach, La., coastal restoration project in 2002 was the only of its kind in the gulf to use OCS sand. Additional restoration funding from BP and Transocean Ltd. will funnel through the National Fish & Wildlife Foundation, and Gulf Coast Restoration Trust Fund.

Action speaks loudest Major projects requiring billions of dollars funneled through government entities don’t typically reach completion in one fell swoop. Hundreds of these types of projects have been pitched to the organizations tasked with doling out restoration funds, with only a small fraction reaching the implementation phase. Seeing through advancement of such projects is critical. Because the long-term responses to Katrina and Deepwater Horizon should collectively make the Gulf Coast more resilient than ever.

Oil & Gas Journal | Sept. 7, 2015

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EDITORIAL

Egyptian treasure Disclosure of what might be a supergiant gas field off Egypt further complicates the geopolitical tangle confronting development of an expanding hydrocarbon treasure in the eastern Mediterranean. When Eni SPA on Aug. 30 reported plans immediately to appraise “the largest gas field in the Mediterranean Sea,” Israel appeared to lose an important option for exports of gas from its own offshore giants, especially undeveloped Leviathan field. Technically, that judgment might be premature. However confident Eni sounds about the discovery of what it says might be 30 tcf of gas in place at its Zohr prospect, development in nearly 5,000 ft of water won’t happen overnight. Egypt began importing LNG this year to meet fast-rising demand as domestic production sags. Until Zohr gas flows ashore, it might welcome Israeli supply. How much gas Israel promptly can export to Egypt or anywhere else remains a huge question, however—though not the largest question hovering over the future of East Mediterranean production.

‘Sleepwalking’ Political squabbling has frozen work off Israel since December, when then-Antitrust Commissioner David Gilo raised questions about possible market domination by Noble Energy Inc., operator of the Israeli gas fields, and partner Delek Group. The cabinet recently approved a compromise agreement that would allow development to proceed but force companies to shrink their licenses interests and, in Delek’s case, withdraw from some fields. The compromise awaits approval by the legislature, which has been in recess. Minister of the Economy Aryeh Deri recently imposed yet another delay by insisting the agreement not advance until a new antitrust commissioner is in place. As Israeli Energy Minister Yuval Steinitz is reported to have said after Eni announced its Zohr plans, “Israel is sleepwalking [while] the world is changing.” A larger question about development of the Levantine basin’s growing cluster of giant, deepwater gas fields might be Turkey. The country needs increasing amounts of gas for domestic use and relishes its expanding role as a transit country for pipeline supply to Europe. Physically and economically, therefore, it’s a logical destination for

28

gas from Israel’s offshore fields. But the requisite pipeline would have to cross insecure international boundaries. And relations between Turkey and Israel are unsteady. Turkey has watched events in the eastern Mediterranean with more than the ive interest of a potential gas importer. When Noble and partners discovered Aphrodite field off Cyprus, the Turkish government challenged the right of the Republic of Cyprus, which it doesn’t recognize, to develop natural resources unilaterally until maritime border issues are resolved. It underscored its seriousness by dispatching warships to conduct maneuvers near Cypriot drillsites. Aphrodite gas might anchor an LNG project, a potential boon to a country desperate for export revenue, but probably would need to be supplemented by supply from Israeli fields. Until Zohr, Egypt was a likely market for Cypriot LNG. Another important question is whether the Zohr project will induce Turkey to press a dispute with Cyprus that would make Egypt a maritime neighbor. The Aphrodite block abuts Egyptian territory near the block on which Eni made the Zohr discovery. Territory claimed by Turkey against Cyprus also extends to Egyptian waters.

Friendly to bitter Relations between Turkey and Egypt swung from friendly to bitter in 2013, when Gen. Abdel Fattah el-Sisi deposed Egyptian President Mohammad Morsi. Elected a year earlier, Morsi had provoked unrest with initiatives that included a temporary constitutional change giving him unlimited power. Now in prison, Morsi was a leader of the Muslim Brotherhood, which Turkish President Recep Tayyip Erdogan s. Erdogan calls Sisi an “illegitimate tyrant.” He might see the boundary dispute as a way to wedge Turkish interests physically into the affairs of two rivals with big gas discoveries. He also might have a distraction. With his political position inside Turkey weakening, he has called for an early election. In Egypt, notwithstanding international tensions nearby, Zohr promises economic benefits sure to strengthen Sisi. For its part, Eni said it seeks a “fast-track development.”

Oil & Gas Journal | Sept. 7, 2015

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GENERAL INTEREST

OGJ150 scores higher production, lower earnings Conglin Xu Senior Editor-Economics

Laura Bell Statistics Editor

Net income for the OGJ150 group plummeted 17.48% in Prices, refining margins 2014 to $73.98 billion. This was the worst performance For the full-year 2014, West Texas Intermediate and Brent in dollar for annual profits for the OGJ group since prices averaged $93.26/bbl and $99.02/bbl, respectively, 2010. compared with $97.90/bbl and $108.64/bbl in 2013. DurThis year’s financial results illustrate the substantial oil ing second-half 2014, the average WTI and Brent pririce decline that took place during second-half 2014 as well es fell to $88.37/bbl and $92.35/bbl, respectively, from as significant impairments and charges incurred during the $100.76/bbl and $108.77/bbl in the same period in 2013. year. The results were partly mitigated by increased The drop in crude oil prices was mainly due to production and higher natural gas prices. weakening global demand combined with robust As capital spending and drilling efforts of the supply from rising US production, decreasing supOGJ150 companies continued to increase last year, ply disruptions, and of the Organization the group’s oil and gas production and reserves, of Petroleum Exporting Countries maintaining particularly in the US, showed robust growth. production levels. To qualify for the OGJ150, oil and gas proFront-month gas futures on the New York Merducers must be headquartered in the US, publiccantile Exchange averaged $4.26/MMbtu in 2014 SPECIAL ly traded, and hold oil or gas reserves in the US. compared with $3.73/MMbtu in 2013. REPORT Companies appear on the list ranked by total asFull-year 2014 refining cash margins averaged sets but are also ranked by revenues, stockhold$19.43/bbl for Midwest refiners, $15.04/bbl for the ers’ equity, capital expenditures, earnings, production, reWest Coast, $8.50/bbl for the Gulf Coast, and $3.99/bbl serves, and US net wells drilled. In this year’s report, the for the East Coast, according to Muse, Stancil & Co. Durspin-off of California Resources Corp. from Occidental ing 2013, these averaged refining margins were $24.96/bbl, Petroleum Corp. impairs year-over-year comparability of $15.85/bbl, $7.42/bbl, and $2.22/bbl, respectively. Refining some top 20 lists. margins in northwestern Europe and Southeast Asia in 2014 There are 143 companies that qualified for this edition averaged $3.05/bbl and $2.17/bbl, respectively, compared of the OGJ150. Last year’s group contained 139 firms. As with $3.15/bbl and $1.97/bbl a year ago. always, data for this year’s list reflect the prior year’s operations.

SOME KEY CHANGES FROM 2014 OGJ150

Table 1

How company appeared on last year’s list

How company appears on this year’s list

Why change?

Forest Oil Corp. . . . . . . . . . . . . . . . . Freeport McMoRan Copper & Gold Inc. . . . . . . . . . . . . . Pyramid Oil Co. . . . . . . . . . . . . . . . .

Changed name to . . . . . . . . . . . . . . . Freeport-McMoRan Inc. Merged with and into . . . . . . . . . . . . Yuma Energy Inc.

Merged with . . . . . . . . . . . . . . . . . . . Sabine Oil & Gas Corp.

The following companies sold their US producing properties, liquidated, or became private since the last survey: GeoMet Inc. High Mount Exploration & Production LLC

30

Historical spreadsheets of data presented here are available for purchase from PennEnergy Research Center. Visit www. ogjonline.com, and click the link “Energy Industry Surveys in Excel” under the “Industry Surveys” section.

Oil & Gas Journal | Sept. 7, 2015

19 20

Total . . . . . . . . . . . . . . . . . . 1,070,183,327 1

As of Dec . 31, 2014 . 2Parent company data .

ExxonMobil Corp. (1)

Spindletop Oil & Gas Co. (113)

Newfield Exploration Co. (23)

Marathon Oil Corp. (10)

Oasis Petroleum Inc. (35)

SM Energy Inc. (32)

Wexpro (76)

Reserve Petroleum Co. (110)

Abraxas Petroleum Corp. (91)

Venoco Inc. (86)

60

Total revenue 53.7 47.3

50

39.3

40

36.8

34.8

33.8

31.9

31.8

30

31.4

20 10

50

EQT Production (28)

Wexpro (76)

Reserve Petroleum Co. (110)

Energen Corp. (34)

Armada Oil Inc. (120)

Gulfport Energy Corp. (44)

0

Total stockholders’ equity

46.9

40

30.5

30

29.4

29.1 25.1

23.1

22.8

19.8

19.2

18.8

Rosetta Resources Inc. (40)

18

8.5

QEP Resources Inc. (24)

17

8.5

Southwestern Energy Co. (18)

9 10 11 12 13 14 15 16

69.4

20 10 0 PetroQuest Energy (81)

6 7 8

9.4

Newfield Exploration Co. (23)

5

70

Market capitalization, $1,000

ExxonMobil Corp . . . . . . 387,941,345 Chevron Corp . . . . . . . . . 210,859,003 ConocoPhillips . . . . . . . 85,037,217 Anadarko Petroleum Corp . . . . . . . . . . . . . . . 31,748,622 Occidental Petroleum Corp . . . . . . . . . . . . . . . 62,118,577 Apache Corp . . . . . . . . . 31,061,654 Devon Energy Corp . . . . . 25,034,890 Chesapeake Energy Corp . . . . . . . . . . . . . . . 12,981,367 Hess Corp . . . . . . . . . . . 21,100,337 Marathon Oil Corp . . . . . 19,095,750 EOG Resources Inc . . . . 50,481,507 Noble Energy Inc . . . . . . 17,175,650 Freeport-McMoRan Inc .2 24,271,040 Murphy Oil Corp . . . . . . . 8,967,275 Linn Energy LLC . . . . . . 3,362,906 Continental Resources Inc . . . . . . . . . . . . . . . . 14,270,131 Pioneer Natural Resources Co . . . . . . . . 22,178,650 Southwestern Energy Co . . . . . . . . . . . 34,112,198 Whiting Petroleum Corp . 5,512,355 Denbury Resources Inc . 2,872,853

9.6

0

Midstates Petroleum Co. Inc. (53)

1 2 3 4

9.6

5

Newfield Exploration Co. (23)

Rank

Table 3

10.2

10

SM Energy Inc. (32)

TOP 20 IN ASSETS— MARKET CAPITALIZATION 1

12.6

Abraxas Petroleum Corp. (91)

856,774,345

15.3

15

Chaparral Energy Inc. (51)

Total . . . . . . . . . . . . . .

Total assets 16.9

Dorchester Minerals LP (104)

15 16 17 18 19 20

19.5

Dorchester Minerals LP (104)

8 9 10 11 12 13 14

Return on total assets, %

6 7

Return on stockholder equity, %

5

ExxonMobil Corp . . . . . 411,939,000 Chevron Corp . . . . . . . . 211,970,000 ConocoPhillips . . . . . . 55,517,000 Occidental Petroleum Corp . . . . . 21,947,000 Chesapeake Energy Corp . . . . . . . . 20,951,000 Devon Energy Corp . . . 19,566,000 Anadarko Petroleum Corp . . . . . 18,470,000 EOG Resources Inc . . . 18,035,340 Apache Corp . . . . . . . . 13,851,000 Hess Corp . . . . . . . . . . 11,439,000 Marathon Oil Corp . . . . 11,258,000 Murphy Oil Corp . . . . . 5,476,084 Noble Energy Inc . . . . . 5,101,000 Pioneer Natural Resources Co . . . . . . . 5,055,000 Linn Energy LLC . . . . . 4,983,303 Continental Resources Inc . 4,801,618 Freeport-McMoRan Inc . 4,710,000 California Resources Corp . 4,173,000 Southwestern Energy Co . 4,038,000 WPX Energy Inc . . . . . . 3,493,000

20

Return on total revenue, %

Rank Company 1 2 3 4

TOP COMPANIES IN RETURN ON...*

Venoco Inc. (86)

Table 2

Total revenue, $1,000

Abraxas Petroleum Corp. (91)

TOP 20 IN TOTAL REVENUE

*Includes companies whose ing methods vary. Excludes companies whose results were inflated by identifiable extraordinary gains. Excludes royalty trusts. Numbers in parentheses indicate rank by total assets.

Oil & Gas Journal | Sept. 7, 2015

31

GENERAL INTEREST

TOP 20 IN NET INCOME AND STOCKHOLDERS’ EQUITY Rank

Company

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

ExxonMobil Corp. ............................................................33,615,000 Chevron Corp. .................................................................19,310,000 ConocoPhillips ..................................................................6,938,000 Marathon Oil Corp. ............................................................3,046,000 EOG Resources Inc. ..........................................................2,915,487 Hess Corp. ........................................................................2,374,000 Chesapeake Energy Corp. .................................................2,056,000 Devon Energy Corp. ..........................................................1,691,000 Kinder Morgan CO2 Co. LP ................................................1,240,000 Noble Energy Inc. .............................................................1,214,000 Continental Resources Inc. ..................................................977,341 Pioneer Natural Resources Co..............................................930,000 Southwestern Energy Co. .....................................................924,000 Murphy Oil Corp. .................................................................905,611 Newfield Exploration Co. ......................................................900,000 QEP Resources Inc. .............................................................784,400 SM Energy Inc. ....................................................................666,051 Denbury Resources Inc. .......................................................635,491 Range Resources Corp. .......................................................634,382 Occidental Petroleum Corp. .................................................630,000

Net income, $1,000

Table 4

Rank

Company

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

ExxonMobil Corp. ........................................................181,064,000 Chevron Corp. .............................................................156,191,000 ConocoPhillips ..............................................................52,273,000 Occidental Petroleum Corp. ..........................................34,959,000 Apache Corp. ................................................................28,137,000 Devon Energy Corp. ......................................................26,341,000 Hess Corp. ....................................................................22,320,000 Anadarko Petroleum Corp. ............................................22,318,000 Marathon Oil Corp.........................................................21,020,000 Chesapeake Energy Corp. .............................................18,205,000 EOG Resources Inc. ......................................................17,712,582 Noble Energy Inc. .........................................................10,325,000 Pioneer Natural Resources Co. .......................................8,589,000 Murphy Oil Corp. ............................................................8,573,434 Denbury Resources Inc...................................................5,703,856 Whiting Petroleum Corp. .................................................5,703,044 Concho Resources Inc. ...................................................5,280,788 Continental Resources Inc. .............................................4,967,844 Southwestern Energy Co. ................................................4,662,000 Linn Energy LLC..............................................................4,543,605

Total ...............................................................................82,386,763

Stockholders’ equity, $1,000

Total ...........................................................................638,889,153

20 FASTEST-GROWING COMPANIES1 Rank by total assets 55 91 46 50 82 106 77 72 95 26 51 32 22 35 89 81 23 49 18 16

Company

Stockholders’ –––––––––––––– equity ––––––––––––– 2014 2013 Change, ––––––––– $1,000 –––––––– %

Exco Resources Inc. .................................510,004 Abraxas Petroleum Corp. ..........................207,495 Diamondback Energy Inc. .....................1,985,213 Memorial Production Partners LP ..........1,075,657 Gastar Exploration Inc. .............................350,286 EnerJex Resources Inc. ..............................46,001 Callon Petroleum Co. ................................433,735 Matador Resources Co. ............................866,541 PrimeEnergy Corp. .....................................78,260 Range Resources Corp. .........................3,457,429 Chaparral Energy Inc. ...............................711,858 SM Energy Inc. ......................................2,286,655 Concho Resources Inc. .........................5,280,788 Oasis Petroleum Inc. .............................1,872,301 Synergy Resources Corp.2.........................281,490 PetroQuest Energy Inc. .............................136,909 Newfield Exploration Co. ........................3,893,000 Carrizo Oil & Gas Inc. ............................1,103,441 Southwestern Energy Co. .......................4,662,000 Continental Resources Inc. ....................4,967,844

147,905 86,906 845,541 579,616 210,029 28,911 279,094 568,924 53,138 2,414,452 497,264 1,606,821 3,757,949 1,348,549 203,200 99,095 2,956,000 841,604 3,622,030 3,953,118

244.8 138.8 134.8 85.6 66.8 59.1 55.4 52.3 47.3 43.2 43.2 42.3 40.5 38.8 38.5 38.2 31.7 31.1 28.7 25.7

Net –––––––––––– income ––––––––––– 2014 2013 Change, –––––––– $1,000 –––––––– % 120,669 63,269 195,971 118,079 50,953 4,574 37,766 110,754 29,149 634,382 209,293 666,051 538,175 506,877 28,853 31,190 900,000 226,343 924,000 977,341

22,204 38,647 54,587 20,268 49,342 1,290 4,304 45,094 13,440 115,722 55,687 170,935 251,003 227,959 9,581 14,082 147,000 43,683 703,503 764,219

443.5 63.7 259.0 482.6 3.3 254.6 777.5 145.6 116.9 448.2 275.8 289.7 114.4 122.4 201.1 121.5 512.2 418.1 31.3 27.9

Table 5 Long-term ––––––– debt –––––––– 2014 2013 –––––––– $1,000 ––––––––

1,446,535 41,790 673,500 1,595,413 360,303 23,012 335,000 — 120,023 — 1,628,425 — 3,517,320 2,700,000 — — 2,892,000 1,351,346 2,466,000 5,995,837

1,858,912 76,554 460,000 792,067 312,994 31,547 70,481 — 122,000 — 1,557,528 — 3,630,421 2,535,570 — — 3,694,000 900,247 1,950,000 4,713,821

1

Companies were selected on the basis of growth in stockholder’s equity. Only companies with positive net income for both 2013 and 2014 were considered. Companies were not considered if they had a decline in net income for 2014, were subsidiaries of another company, or became public within the last year. 2Fiscal yearend Aug. 31.

Changes to the group

Eclipse Resources Corp., Bonanza Creek Energy Inc., and Glori Energy Inc. Seven companies appear in the OGJ150 for the Eleven companies that were previously included first time. The highest-ranking of these, Califorin the OGJ150 no long appear. Alamo Energy Corp., nia Resources, sits at No. 21 with yearend 2014 Gasco Energy Inc., Sun River Energy Inc., and Texas assets totaling $12.49 billion. The company, preVanguard Oil Co. terminated their registration to the viously an Oxy subsidiary, began regular trading SPECIAL US Securities & Exchange Commission. Baron Enon the New York Stock Exchange as a stand-alone REPORT ergy Inc., Glen Rose Petroleum Corp., John D. Oil & company in December 2014. The spin-off actually Gas Co., and Savoy Energy Corp. dropped off the list explains why Oxy fell in some of the top 20 categories and California Resources made some of the due to no filings in a long time. EPL Oil & Gas Inc. merged with Energy XXII, which is incorporated in Bermuda. top 20 tables. GeoMet Inc. and Highmount Exploration & Production LLC Other newcomers include Memorial Resources Develsold off their US producing properties. opment Corp., Sanchez Energy Corp., RSP Permian Inc.,

32

Oil & Gas Journal | Sept. 7, 2015

GENERAL INTEREST

TOP 20 IN SPENDING AND US NET WELLS DRILLED Rank

Company

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Chevron Corp. ................................................................ 35,407,000 ExxonMobil Corp. ........................................................... 34,621,000 ConocoPhillips ................................................................ 17,085,000 Apache Corp. ................................................................. 10,880,000 Anadarko Petroleum Corp. ............................................... 9,508,000 Occidental Petroleum Corp. .............................................. 8,930,000 EOG Resources Inc. ......................................................... 8,246,805 Devon Energy Corp. .......................................................... 6,988,000 Hess Corp. ....................................................................... 5,274,000 Marathon Oil Corp. ........................................................... 5,160,000 Noble Energy Inc. ............................................................. 4,871,000 Continental Resources Inc. ............................................... 4,604,468 Chesapeake Energy Corp. ................................................. 4,581,000 Murphy Oil Corp. .............................................................. 3,679,464 Pioneer Natural Resources Co. ......................................... 3,243,000 Freeport McMoran Inc. ..................................................... 3,205,000 Whiting Petroleum Corp. ................................................... 2,842,837 Concho Resources Inc. .................................................... 2,554,914 EQT Production ................................................................ 2,441,486 Cimarex Energy Co. .......................................................... 2,108,250

Capital, exploratory spending, $1,000

Table 6

Rank

Company

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Chevron Corp. ..................................................................... 1,125.0 California Resources Corp. ..................................................... 986.6 EOG Resources Inc. ............................................................... 869.0 Anadarko Petroleum Corp. ..................................................... 854.6 Apache Corp. ......................................................................... 816.5 ExxonMobil Corp. ................................................................... 732.0 Linn Energy LLC..................................................................... 699.0 Chesapeake Energy Corp. ...................................................... 682.0 Marathon Oil Corp.................................................................. 666.0 Sandridge Energy Inc. ............................................................ 502.9 Pioneer Natural Resources Co. .............................................. 502.0 ConocoPhillips ....................................................................... 492.0 Devon Energy Corp. ............................................................... 481.0 Occidental Petroleum Corp. ................................................... 478.8 Continental Resources Inc. .................................................... 388.5 WPX Energy Inc. .................................................................... 375.0 Newfield Exploration Co. ........................................................ 345.0 EQT Production ..................................................................... 342.4 Concho Resources Inc. .......................................................... 329.0 Noble Energy Inc. .................................................................. 324.4

Total ............................................................................. 176,231,224

US net wells drilled

Total ................................................................................. 11,991.7

TOP 20 IN LIQUIDS RESERVES

Table 7

Rank

Company

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

ConocoPhillips ......................................................................2,299.0 ExxonMobil Corp. .................................................................2,108.0 EOG Resources Inc. .............................................................1,596.6 Occidental Petroleum Corp. ..................................................1,495.0 Chevron Corp. ......................................................................1,432.0 Anadarko Petroleum Corp. ...................................................1,170.0 Apache Corp. ..........................................................................938.2 Devon Energy Corp. .................................................................929.0 Continental Resources Inc. ......................................................866.4 Marathon Oil Corp. ..................................................................795.0 Whiting Petroleum Corp. ..........................................................698.3 Chesapeake Energy Corp. ........................................................687.1 California Resources Corp. ......................................................636.0 Hess Corp. ..............................................................................631.0 Range Resources Corp. ...........................................................564.6 Pioneer Natural Resources Co. ................................................521.3 Linn Energy LLC ......................................................................508.1 Concho Resources Inc. ...........................................................370.3 Denbury Resources Inc. ..........................................................362.3 Noble Energy Inc. ....................................................................349.0

US liquids reserves, million bbl

Total ...................................................................................18,957.3

Rank

Company

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

ExxonMobil Corp. ...............................................................11,823.0 Chevron Corp. ......................................................................4,285.0 ConocoPhillips .....................................................................3,267.0 Occidental Petroleum Corp. .................................................2,132.0 Marathon Oil Corp................................................................1,768.0 EOG Resources Inc. .............................................................1,606.8 Devon Energy Corp. .............................................................1,473.0 Anadarko Petroleum Corp. ...................................................1,408.0 Apache Corp. .......................................................................1,356.5 Hess Corp. ...........................................................................1,117.0 Continental Resources Inc. .....................................................866.4 Whiting Petroleum Corp. .........................................................698.3 Chesapeake Energy Corp. .......................................................687.1 California Resources Corp. ......................................................636.0 Range Resources Corp. ..........................................................564.6 Pioneer Natural Resources Co. ...............................................521.3 Linn Energy LLC......................................................................508.1 Murphy Oil Corp. ....................................................................472.4 Noble Energy Inc. ...................................................................432.0 Concho Resources Inc. ...........................................................370.3

Worldwide liquids reserves, million bbl

Total ..................................................................................35,992.8

Freeport McMoRan Copper & Gold Inc. changed Financial performance its name and now appears in the list as FreeportAssets for the OGJ150 group totaled $1.5 trillion McMoRan Inc. at yearend 2014, an increase of 4.07% from yearForest Oil Corp., which merged with Sabine Oil end 2013, reflecting continued capital invest& Gas Corp., and Pyramid Oil Co., which merged ment and development. Revenues for 2014 were with Yuma Energy Inc., are no longer listed sepa$920.5 billion, up $6 billion from a year earlier. SPECIAL rately. Combined stockholder equity gained 1.61% to REPORT The 2014 OGJ150 contains 10 limited partner$718.29 billion. Thirteen firms posted negative ships. The largest of these is BreitBurn Energy Partstockholder equity at the end of last year, as their ners LP with assets of $7.6 billion. The smallest, Apache Offliabilities exceeded assets. shore LP, had assets of $13.5 million. As previously mentioned, the group’s collective net inThere are five royalty trusts in the compilation and six come was $73.98 billion, down 17.48%. The number of comsubsidiaries of non-US energy companies or of companies panies in the group that posted a net loss is 55 compared operating mainly in other sectors. with 54 in last year’s compilation. Sixteen of the firms re-

34

Oil & Gas Journal | Sept. 7, 2015

GENERAL INTEREST

TOP 20 IN LIQUIDS PRODUCTION

Table 8

Rank

Company

US liquids production, million bbl

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

ConocoPhillips .........................................................................172.0 Chevron Corp. .........................................................................166.0 EOG Resources Inc. ................................................................132.0 Anadarko Petroleum Corp. ......................................................118.0 ExxonMobil Corp. ....................................................................111.0 Occidental Petroleum Corp. .......................................................87.0 Chesapeake Energy Corp. ..........................................................75.4 Apache Corp. ............................................................................70.3 Marathon Oil Corp. ....................................................................68.0 Devon Energy Corp. ...................................................................67.0 Hess Corp. ................................................................................54.0 Pioneer Natural Resources Co. ..................................................48.5 Continental Resources Inc. ........................................................44.5 Freeport-McMoRan Inc. ............................................................43.0 California Resources Corp. ........................................................43.0 Linn Energy LLC ........................................................................38.8 Whiting Petroleum Corp. ............................................................36.8 Consol Energy Inc. ....................................................................34.2 Noble Energy Inc. ......................................................................32.0 SM Energy Inc. ..........................................................................29.7

Rank 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Total .....................................................................................1,471.2

Company

Worldwide liquids production, million bbl

ExxonMobil Corp. ....................................................................631.0 Chevron Corp. .........................................................................508.0 ConocoPhillips ........................................................................270.0 Occidental Petroleum Corp. ....................................................163.0 Anadarko Petroleum Corp. ......................................................154.0 Apache Corp. ..........................................................................142.2 EOG Resources Inc. ................................................................134.7 Devon Energy Corp. ................................................................129.0 Marathon Oil Corp...................................................................118.0 Hess Corp. ................................................................................89.0 Chesapeake Energy Corp. .........................................................75.4 Murphy Oil Corp. ......................................................................55.4 Noble Energy Inc. .....................................................................49.0 Pioneer Natural Resources Co. .................................................48.5 Continental Resources Inc. .......................................................44.5 Freeport-McMoRan Inc. ............................................................43.0 California Resources Corp. ........................................................43.0 Linn Energy LLC........................................................................38.8 Whiting Petroleum Corp. ...........................................................36.8 Consol Energy Inc. ....................................................................34.2 Total ....................................................................................2,807.5

TOP 20 IN GAS PRODUCTION

Table 9

Rank

Company

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

ExxonMobil Corp. .................................................................1,346.0 Chesapeake Energy Corp. .....................................................1,095.0 Anadarko Petroleum Corp. ......................................................951.0 Southwestern Energy Co. .........................................................765.0 ConocoPhillips .........................................................................679.0 Devon Energy Corp. .................................................................660.0 Cabot Oil & Gas Corp. .............................................................508.0 Chevron Corp. .........................................................................456.0 EQT Production .......................................................................444.8 EOG Resources Inc. ................................................................348.4 WPX Energy Inc. .....................................................................335.4 Range Resources Corp. ...........................................................286.9 Ultra Petroleum .......................................................................228.5 Consol Energy Inc. ..................................................................216.3 Apache Corp. ..........................................................................215.8 Linn Energy LLC ......................................................................209.0 Noble Energy Inc. ....................................................................189.0 QEP Resources Inc. ................................................................179.3 Occidental Petroleum Corp. .....................................................173.0 Cimarex Energy Co. .................................................................155.1

US gas production, bcf

Total .....................................................................................9,441.6

Rank

Company

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

ExxonMobil Corp. .................................................................2,645.0 Chevron Corp. ......................................................................1,744.0 ConocoPhillips .....................................................................1,443.0 Chesapeake Energy Corp. ....................................................1,095.0 Anadarko Petroleum Corp. ......................................................951.0 Southwestern Energy Co. ........................................................765.0 Devon Energy Corp. ................................................................701.0 Apache Corp. ..........................................................................580.0 Cabot Oil & Gas Corp. .............................................................508.0 EOG Resources Inc. ................................................................506.3 EQT Production ......................................................................444.8 Noble Energy Inc. ...................................................................362.0 WPX Energy Inc. .....................................................................335.4 Occidental Petroleum Corp. ....................................................331.0 Marathon Oil Corp...................................................................295.0 Range Resources Corp. ..........................................................286.9 Ultra Petroleum ......................................................................228.5 Consol Energy Inc. ..................................................................216.3 Linn Energy LLC......................................................................209.0 Hess Corp. ..............................................................................197.0

Worldwide gas production, bcf

Total ..................................................................................13,844.2

corded net loss in excess of $100 million, up from ed impairments in billions of dollars during 2014. 12 in last year’s OGJ150. There are 48 firms in the group with net income The highest-ranking company that reported of more than $100 million. In last year’s group, a net loss for 2014 is Anadarko Petroleum Corp., there were 38 such companies. which posted a $1.56 billion loss that included The group’s 2014 return on assets was 4.9%, charges of $4 billion associated with the settlement down from 6.2% a year earlier. Return on stockSPECIAL of the Tronox Adversary Proceeding. This compares holders’ equity declined to 10.3% in 2014 from REPORT with earnings of $941 million in 2013. 12.7% in 2013. With reduced revenues and higher costs and expenses, Apache reported a net loss of $5 billion for 2014 Group operations compared with earnings of $2.28 billion in 2013. Apache Capital and exploration expenditures of the group increased recorded aftertax, noncash charges of $5.2 billion for fourth9.31% to $226.36 billion during 2014. Up 5.4% from 2013, quarter 2014. the number of US net wells drilled by the group last year Oxy, California Resources, and Linn Energy also reporttotaled 18,296.

36

Oil & Gas Journal | Sept. 7, 2015

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GENERAL INTEREST

TOP 20 IN GAS RESERVES

Table 10

Rank

Company

US gas reserves, bcf

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

ExxonMobil Corp. .............................................................. 25,987.0 Chesapeake Energy Corp. .................................................. 10,692.0 Southwestern Energy Co. ..................................................... 9,809.0 EQT Production ................................................................... 9,776.0 ConocoPhillips ..................................................................... 9,664.0 Anadarko Petroleum Corp. .................................................. 8,668.0 Devon Energy Corp. ............................................................. 7,651.0 Cabot Oil & Gas Corp. ......................................................... 7,082.0 Range Resources Corp. ....................................................... 6,922.8 Consol Energy Inc. .............................................................. 6,317.6 EOG Resources Inc. ............................................................ 4,905.5 Ultra Petroleum ................................................................... 4,831.2 Linn Energy LLC .................................................................. 4,255.0 Chevron Corp. ..................................................................... 4,174.0 WPX Energy Inc. ................................................................. 3,149.6 Continental Resources Inc. .................................................. 2,908.4 Noble Energy Inc. ................................................................ 2,804.0 QEP Resources Inc. ............................................................ 2,317.2 Apache Corp. ...................................................................... 2,196.8 Sandridge Energy Inc. ......................................................... 1,788.2 Total ................................................................................ 135,899.3

Rank 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Company

Worldwide gas reserves, bcf

ExxonMobil Corp. ...............................................................43,143.0 Chevron Corp. ....................................................................25,707.0 ConocoPhillips ...................................................................15,258.0 Chesapeake Energy Corp. ..................................................10,692.0 Southwestern Energy Co. .....................................................9,809.0 EQT Production ...................................................................9,776.0 Anadarko Petroleum Corp. ...................................................8,699.0 Devon Energy Corp. .............................................................7,687.0 Cabot Oil & Gas Corp. ..........................................................7,082.0 Range Resources Corp. .......................................................6,922.8 Consol Energy Inc. ...............................................................6,317.6 Apache Corp. .......................................................................6,238.8 Noble Energy Inc. ................................................................5,833.0 EOG Resources Inc. .............................................................5,342.6 Ultra Petroleum ...................................................................4,831.2 Linn Energy LLC...................................................................4,255.0 Occidental Petroleum Corp. .................................................4,127.0 WPX Energy Inc. ..................................................................3,149.6 Continental Resources Inc. ..................................................2,908.4 Marathon Oil Corp................................................................2,580.0 Total ................................................................................190,358.9

The average number of active rigs in the US Chevron, and ConocoPhillips, represent 83.5% of climbed 5.7% to 1,862 last year, according to Baker the assets of all OGJ150 companies. Hughes Inc. At the same time, the rig count in CanEOG Resources Inc.’s assets of $34.7 billion at ada increased 7% to 380 and the worldwide numyearend 2014 represent a 13.7% increase over yearber of active rigs excluding US and Canada rose 3% end 2013. Noble Energy also ed a 14.8% into 1,337. crease in assets to $22.55 billion. SPECIAL As the capital spending and drilling efforts of Southwestern Energy Co., ranked at No. 24 preREPORT the OGJ150 companies continued to increase last viously, climbed to No. 18, with asset portfolio exyear, their production and reserves totals moved panded through acquisitions in West Virginia and upward. The OGJ150 group’s worldwide liquids producsouthwest Pennsylvania. The company’s total proved retion increased 8.41% in 2014 to 3.32 billion bbl. The serves were up 54% compared with 2013 levels. group’s US liquids production totaled 1.97 billion bbl, up Whiting Petroleum Corp. moved to No. 19 by assets from 16.73% from a year earlier. Total worldwide liquids reNo. 22 a year ago. With the acquisition of Kodiak Oil & Gas, serves were up 5.06% in 2014 to 42.73 billion bbl. The Whiting became the largest Bakken and Three Forks-area group’s combined US liquids reserves increased 9.85% to producer in the Williston basin. 25.53 billion bbl. Group worldwide gas production moved up 0.54% to 17 Earnings leaders tcf. US natural gas production for the group was up 3.95% The top three companies as ranked by assets—ExxonMobil, to 12.36 tcf. Worldwide natural gas reserves for the OGJ150 Chevron, and ConocoPhillips—also reported the highest group increased 4.11% to 231.4 tcf in 2014. Group natural 2014 earnings in the OGJ150 group. gas reserves in the US grew 8.56% to 172.92 billion tcf. With 2014 net income of $33.6 billion, ExxonMobil again OGJ150’s worldwide liquids reserves to production ratio leads the OGJ150 group. ExxonMobil’s 2013 earnings were was 12.9 years in 2014 compared with 13.3 years in 2013. $33.45 billion. The OGJ150 liquids reserves-to-production ratio in the US Chevron and ConocoPhillips reported 2014 earnings of was 12.9 years in 2014 compared with 13.7 years in 2013. $19.3 billion and $6.9 billion, respectively, down 10.6% and The group’s US natural gas reserves to production ratio 24.6% from a year ago, largely due to the sharp decline in increased to 14 years in 2014 from 13.4 years in 2013. The crude oil prices. worldwide ratio was 13.5 years compared to 13.1 years a Also slammed by low oil prices and with the absence of year earlier. large gains on asset sales seen a year ago, Hess reported a 54% plunge in earnings to $2.3 billion last year. Top 20 companies by assets Meanwhile, some midsized independents focused mainly The top 20 companies as ranked by yearend 2014 assets on North American shale plays displayed stable earnings in posted collective assets of $1,255 billion, up 1.87% from a 2014, thanks to significant increase in light oil production. year earlier. The assets of the 20 firms, led by ExxonMobil, For the full year 2014, EOG’s crude oil and condensate

38

Oil & Gas Journal | Sept. 7, 2015

GENERAL INTEREST production increased 31% over last year, driven by 33% worldwide liquids reserves holders in the OGJ150 group growth in the US. The company’s net income in 2014 was that follow ExxonMobil are Chevron, ConocoPhillips, Oxy, $2.9 billion, up from $2.2 billion a year ago. Marathon Oil Corp., and then EOG. Six of the firms in the top 20 by net income list are ConocoPhillips tops the group in US liquids production not ranked in the top 20 by assets. These include Kinder and reserves. EOG ranks at No. 3 in both categories with reMorgan Inc., Noble Energy, Newfield Exploraported US liquids production of 132 million bbl and tion Co., QEP Resources Inc., SM Energy Co., US liquids reserves of 1.6 billion bbl, up from 100 and Range Resources Corp. million bbl and 1.25 billion bbl a year ago. There are five companies qualified for the list Following ExxonMobil in US gas production are of top 20 earners that did not qualify a year ago. Chesapeake, Anadarko, Southwestern, and ConoThese are Devon Energy Corp., Pioneer Natural coPhillips. Second in US gas reserves for 2014 among Resources Co., Newfield, QEP, and Range Rethe OGJ150 firms is Chesapeake, followed by SouthSPECIAL sources. western, EQT Corp., ConocoPhillips, and Anadarko.

REPORT

Production, reserves leaders ExxonMobil leads the OGJ150 companies in worldwide liquids production and reserves, worldwide gas production and reserves, as well as in US gas production and reserves. Following ExxonMobil in worldwide liquids production are Chevron, ConocoPhillips, Oxy, and Anadarko. The

Top 20 in spending, drilling Capital and exploratory expenditures in 2014 by the top 20 totaled $176.23 billion, up from $170.63 billion in 2013 and $169.16 billion in 2012. Expenditures of the top 20 amounted to 77.8% of the OGJ150 total. Chevron, ExxonMobil, and ConocoPhillips were the leading three companies in capex spending last year, followed by Apache, Anadarko, Oxy, and EOG.

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GENERAL INTEREST Chevron’s spending was $35.4 billion, down 6.8% from 2013 outlays. ExxonMobil decreased its 2014 outlays by $1 billion to $34.6 billion, while ConocoPhillips boosted it spending last year by 10% to $17 billion. Anadarko increased its capital spending by 23% to $9.5 billion last year from a year ago. With a count of 1,125 wells, Chevron leads the OGJ150 group in the number of net wells drilled in the US during 2014. The second company on the list is California Resources with 986 wells, followed by EOG, Anadarko, Apache, and ExxonMobil. Linn Energy LLC ranks at No. 7 and drilled 699 net wells in the US last year, up from 306 a year ago. Oxy, if without the spinoff of California Resources, would have had 1,465 net wells drilled in the US last year, up from 1,289 wells drilled for 2013. The ing of California Resources actually has shrunk the top 20 list by drilling.

Fast growers The list of fastest-growing companies ranks firms based on growth in stockholder equity. For a company to appear on

this list, it must have posted positive net income in both 2013 and 2014, and it must have had an increase in net income last year. Excluded from this list are limited partnerships, newly public companies, and subsidiaries. The list is limited to the top 20 fast growers. Exco Resources Inc., ranked No. 55 in total assets, leads the list this year. With headquarters in Dallas, Exco reported stockholders’ equity of $510 million last year compared with $147.9 million in 2013. Earnings climbed to $120.67 million in 2014 from $22.2 million in 2013. Abraxas Petroleum Corp., the second fastest grower and No. 91 in total assets, posted an increase in stock equity of 138.8% to $207.49 million and net income increased 63.7% to $63.27 million from a year ago. Three of the current fast growers were also on the list in the previous edition of the OGJ150, which was based on 2013 results. These are Oasis Petroleum Inc., Callon Petroleum Co., and Continental Resources Inc. The long-term debt positions of the firms on the list were mixed. Nine of the companies increased long-term debt while six decreased long-term debt.

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GENERAL INTEREST

OGJ150 Rank Rank total Total bybytotal ––– assets ––– —-assets—— 2014 2013 Company 20022001 Company 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62

42

1 2 3 6 4 5 7 9 8 10 11 13 12 14 15 17 16 24 22 18 — 19 21 20 23 26 27 29 36 30 25 35 31 28 33 32 34 — 37 38 40 44 47 42 41 63 — 39 55 62 49 45 51 69 48 56 — 53 52 50 46 43

ExxonMobil Corp. Chevron Corp. ConocoPhillips Anadarko Petroleum Corp. Occidental Petroleum Corp. Apache Corp. Devon Energy Corp. Chesapeake Energy Corp. Hess Corp. Marathon Oil Corp. EOG Resources Inc. Noble Energy Inc. Freeport-McMoRan Inc. Murphy Oil Corp. Linn Energy LLC Continental Resources Inc. Pioneer Natural Resources Co. Southwestern Energy Co. Whiting Petroleum Corp. Denbury Resources Inc. California Resources Corp. Concho Resources Inc. Newfield Exploration Co. QEP Resources Inc. WPX Energy Inc. Range Resources Corp. Cimarex Energy Co. EQT Production BreitBurn Energy Partners LP Consol Energy Inc. Sandridge Energy Inc. SM Energy Inc. Halcon Resources Corp. Energen Corp. Oasis Petroleum Inc. Cabot Oil & Gas Corp. Kinder Morgan CO2 Co. LP Memorial Resources Development Corp. Unit Corp. Rosetta Resources Inc. Ultra Petroleum Laredo Petroleum Inc. Vanguard Natural Resources LLC Gulfport Energy Corp. Seneca Resources Corp.6, 7 Diamondback Energy Inc. Sanchez Energy Corp. Stone Energy Corp. Carrizo Oil & Gas Inc. Memorial Production Partners LP Chaparral Energy Inc. W&T Offshore Inc. Midstates Petroleum Co. Inc. Sabine Oil & Gas Exco Resources Inc. PDC Energy RSP Permian Inc. Comstock Resources Inc. EV Energy Partners LP Bill Barrett Corp. Penn Virginia Corp. Swift Energy Co.

Total Total assets assets $1,000 $1,000 349,493,000 266,026,000 116,539,000 61,689,000 56,259,000 55,952,000 50,637,000 40,751,000 38,578,000 36,011,000 34,762,687 22,553,000 20,834,000 16,742,307 16,423,509 15,145,070 14,926,000 14,925,000 14,019,504 12,727,802 12,497,000 11,799,963 9,598,000 9,286,800 8,798,000 8,746,780 8,725,293 8,153,199 7,638,334 7,364,185 7,259,225 6,516,700 6,434,475 6,138,258 5,938,412 5,437,716 5,227,000 4,593,547 4,473,728 4,250,667 4,225,690 3,932,549 3,793,592 3,632,393 3,100,514 3,095,481 3,075,410 3,018,611 2,981,476 2,930,559 2,831,816 2,709,107 2,475,793 2,438,350 2,356,896 2,340,588 2,289,947 2,274,337 2,249,203 2,244,484 2,226,434 2,173,347

Total Net –––– revenue ——–– revenue––––– ––—— $1,000 Rank $1,000 1 2 3 7 4 9 6 5 10 11 8 13 17 12 15 16 14 19 22 26 18 24 28 21 20 23 27 32 35 40 34 25 39 31 36 29 30 42 33 37 38 47 48 51 44 63 52 45 49 64 50 41 46 67 53 43 75 59 71 65 54 60

411,939,000 211,970,000 55,517,000 18,470,000 21,947,000 13,851,000 19,566,000 20,951,000 11,439,000 11,258,000 1 18,035,340 5,101,000 4,710,000 5,476,084 4,983,303 4,801,618 5,055,000 2 4,038,000 3,085,097 2,435,205 4,173,000 2,660,147 2,288,000 3,414,300 3,493,000 2,711,695 2,424,176 2 1,612,730 1,429,969 1,028,117 1,558,758 2,522,307 2 1,148,261 1,679,213 1,390,228 2 2,173,011 1,960,000 899,345 1,572,944 1,304,694 2 1,230,020 793,885 788,065 671,461 806,005 495,718 666,353 796,116 710,187 494,105 681,557 948,708 794,183 464,723 660,269 857,497 281,925 555,231 339,405 473,585 636,773 549,456

StockholderNet –––––– income——— –––– ——income Rank $1,000 Rank $1,000 1 2 3 133 20 135 8 7 6 4 5 10 134 14 130 11 12 13 51 18 132 23 15 16 36 19 24 26 27 119 28 17 29 21 25 48 9 131 39 30 22 31 52 32 42 35 105 124 33 45 34 101 46 127 43 38 78 116 40 70 129 125

33,615,000 19,310,000 6,938,000 (1,563,000) 630,000 (5,060,000) 1,691,000 2,056,000 2,374,000 3,046,000 2,915,487 1,214,000 (4,479,000) 905,611 (451,809) 977,341 930,000 924,000 64,745 635,491 (1,434,000) 538,175 900,000 784,400 171,000 634,382 507,204 505,950 421,316 4 (94,639) 351,898 666,051 315,956 568,032 506,877 104,468 5 1,240,000 (636,063) 136,276 313,562 542,851 265,573 64,345 247,403 121,569 195,971 (21,791) (189,543) 226,343 118,079 209,293 (11,661) 116,929 (326,720) 120,669 155,435 2,498 (57,111) 129,720 15,081 (409,592) (283,427)

Stockholders’ Capital & expl. –––––equity equity———–––––– —— Rank $1,000 Rank $1,000 1 2 3 8 4 5 6 10 7 9 11 12 — 14 20 18 13 19 16 15 29 17 24 23 22 26 21 — 25 — 28 32 36 27 35 33 — 37 30 38 77 39 40 31 — 34 49 45 44 46 56 64 65 124 63 43 41 50 47 48 57 52

181,064,000 156,191,000 52,273,000 22,318,000 34,959,000 28,137,000 26,341,000 18,205,000 22,320,000 21,020,000 17,712,582 10,325,000 — 8,573,434 4,543,605 4,967,844 8,589,000 4,662,000 5,703,044 5,703,856 2,611,000 5,280,788 3,893,000 4,075,300 4,428,000 3,457,429 4,500,632 — 3 3,766,176 — 3,209,820 2,286,655 1,772,169 3,414,604 1,872,301 2,142,733 — 1,702,964 2,332,394 1,669,113 211,660 1,563,201 1,534,116 2,296,296 — 1,985,213 999,587 1,101,603 1,103,441 3 1,075,657 711,858 509,308 465,862 (63,792) 510,004 1,137,359 1,325,771 870,272 3 1,066,113 1,029,488 675,817 794,378

Capital & expl. ––––– spending——–––– —— spending $1,000 Rank $1,000 2 1 3 5 6 4 8 13 9 10 7 11 16 14 27 12 15 22 17 39 23 18 21 26 25 36 20 19 64 37 28 24 29 33 31 30 42 47 38 35 54 34 80 32 52 61 43 40 41 72 46 59 57 60 66 51 109 50 88 55 44 69

34,621,000 35,407,000 17,085,000 9,508,000 8,930,000 10,880,000 6,988,000 4,581,000 5,274,000 5,160,000 8,246,805 4,871,000 3,205,000 3,679,464 1,569,877 4,604,468 3,243,000 2,043,000 2,842,837 946,846 2,020,000 2,554,914 2,064,000 1,765,900 1,807,000 1,200,419 2,108,250 2,441,486 417,755 1,103,656 1,553,332 1,974,798 1,524,341 1,264,059 1,354,281 1,479,632 792,000 674,396 981,374 1,218,614 599,913 1,251,757 143,371 1,329,277 602,705 494,708 791,260 927,247 860,604 264,245 685,459 554,378 561,691 548,841 391,776 628,592 5,475 634,787 102,761 580,943 774,139 386,336

Oil & Gas Journal | Sept. 7, 2015

GENERAL INTEREST

Worldwide Worldwide Worldwide Worldwide US US Worldwide liquids Worldwidenatural natural gas gas Worldwide natural US liquids liquids US natural natural gas liquids liquidsliquids Worldwide natural gas gas –— production ––—— –— production –— – –——–reserves—– reserves –— –— reserves —– –——production —–– — — production – production ——–reserves–—– production — ——production production— RankRankMillion bblbblRank Rank BcfBcf Rank Rank BcfBcf Rank Bcf Mill Rank Million Mill bbl bbl Rank Rank Million Millbbl bbl Rank Rank Bcf 1 2 3 5 4 6 8 11 10 9 7 13 16 12 18 15 14 97 19 24 17 23 27 25 30 26 22 100 36 20 33 21 34 29 32 59 28 68 38 31 64 42 45 56 69 43 37 40 39 53 47 35 41 58 73 44 61 57 65 51 48 52

631.0 508.0 270.0 154.0 163.0 142.2 129.0 75.40 89.00 118.0 134.7 49.00 43.00 55.40 38.80 44.53 48.48 0.466 36.77 25.77 43.00 26.32 20.00 23.90 15.50 22.89 26.98 0.449 9.088 34.24 14.67 29.70 13.90 15.92 14.88 3.961 16.39 3.171 8.473 15.36 3.409 6.901 6.060 4.734 3.036 6.383 8.670 7.682 7.831 5.235 5.812 9.300 7.561 4.200 2.460 6.078 3.767 4.313 3.363 5.488 5.754 5.324

1 2 3 5 14 8 7 4 20 15 10 12 35 22 19 29 24 6 52 79 30 31 27 21 13 16 23 11 53 18 32 25 78 39 77 9 123 38 41 42 17 54 34 40 26 86 69 45 58 48 62 43 57 44 28 64 93 49 46 60 33 47

2,645.0 1,744.0 1,443.0 951.0 331.0 580.0 701.0 1,095.0 197.0 295.0 506.3 362.0 82.00 162.8 209.0 114.3 154.4 765.0 30.22 8.379 90.00 87.34 127.0 179.3 335.4 286.9 155.1 444.8 30.16 216.3 85.70 152.9 8.812 59.56 10.69 508.0 0.037 63.80 58.85 51.62 228.5 28.97 83.04 59.32 142.3 4.346 14.83 47.43 24.88 41.49 19.83 50.10 25.01 48.30 121.0 19.30 2.974 39.77 43.36 21.74 83.20 42.38

1 11,823.0 2 4,285.0 3 3,267.0 8 1,408.0 4 2,132.0 9 1,356.5 7 1,473.0 13 687.1 10 1,117.0 5 1,768.0 6 1,606.8 19 432.0 24 288.0 18 472.4 17 508.1 11 866.4 16 521.3 35 156.3 12 698.3 21 362.3 14 636.0 20 370.3 23 301.0 25 269.1 30 201.6 15 564.6 27 244.3 101 5.005 31 198.6 50 85.00 29 217.8 22 303.2 33 171.9 26 254.7 28 235.4 63 53.14 39 108.4 53 75.19 54 71.20 32 172.5 58 67.77 37 140.2 45 92.58 69 35.77 68 38.48 44 94.23 41 99.82 55 70.21 38 114.2 36 149.0 40 103.2 52 77.50 47 90.77 60 61.20 80 18.13 34 160.6 46 91.01 79 20.85 66 48.05 42 96.68 49 88.23 51 79.37

Oil & Gas Journal | Sept. 7, 2015

1 2 3 7 17 12 8 4 22 20 14 13 46 24 16 19 26 5 52 53 37 29 28 21 18 10 27 6 41 11 23 31 78 40 66 9 120 32 44 43 15 45 30 38 25 75 76 51 65 48 61 63 55 34 33 49 80 50 39 71 70 42

43,143.0 25,707.0 15,258.0 8,699.0 4,127.0 6,238.8 7,687.0 10,692.0 1,881.0 2,580.0 5,342.6 5,833.0 610.0 1,704.7 4,255.0 2,908.4 1,668.9 9,809.0 492.0 452.4 790.0 1,601.0 1,607.0 2,317.2 3,149.6 6,922.8 1,666.7 9,776.0 700.1 6,317.6 1,788.2 1,466.5 103.7 707.9 220.1 7,082.0 2.069 1,180.9 647.0 655.1 4,831.2 642.8 1,475.9 719.0 1,682.9 111.6 110.5 493.8 221.0 559.6 257.1 254.9 377.8 989.8 1,155.0 537.0 92.42 495.3 712.2 153.9 159.3 686.7

5 2 1 4 6 8 10 7 11 9 3 19 15 24 16 13 12 97 17 23 14 22 27 25 30 26 21 100 36 18 33 20 34 29 32 59 28 68 38 31 64 42 45 56 69 43 37 39 41 53 47 35 40 58 73 44 61 57 65 51 48 52

111.0 166.0 172.0 118.0 87.00 70.25 67.00 75.40 54.00 68.00 132.0 32.00 43.00 25.00 38.80 44.53 48.48 0.466 36.77 25.77 43.00 26.32 18.00 23.90 15.50 22.89 26.98 0.449 9.088 34.24 14.67 29.70 13.90 15.92 14.88 3.961 16.39 3.171 8.473 15.36 3.409 6.901 6.060 4.734 3.036 6.383 8.670 7.682 6.906 5.235 5.812 9.300 7.561 4.200 2.460 6.078 3.767 4.313 3.363 5.488 5.754 5.324

1 8 5 3 19 15 6 2 34 27 10 17 33 51 16 26 21 4 52 79 28 29 24 18 11 12 20 9 53 14 30 22 78 37 77 7 110 36 39 40 13 54 32 38 23 86 69 43 58 47 62 41 57 42 25 64 92 48 45 60 31 46

1,346.0 456.0 679.0 951.0 173.0 215.8 660.0 1,095.0 66.00 113.0 348.4 189.0 82.00 32.30 209.0 114.3 154.4 765.0 30.22 8.379 90.00 87.34 127.0 179.3 335.4 286.9 155.1 444.8 30.16 216.3 85.70 152.9 8.812 59.56 10.69 508.0 0.373 63.80 58.85 51.62 228.5 28.97 83.04 59.32 142.3 4.346 14.83 47.43 24.88 41.49 19.83 50.10 25.01 48.30 121.0 19.30 2.974 39.77 43.36 21.74 83.20 42.38

US USliquids liquids —–– —– reserves reserves —–– —– Rank Million bbl Rank Mill bbl 2 5 1 6 4 7 8 12 14 10 3 20 22 28 17 9 16 35 11 19 13 18 23 24 30 15 26 101 31 50 29 21 33 25 27 63 38 53 54 32 58 37 45 69 68 44 41 55 40 36 39 52 47 60 80 34 46 79 66 42 49 51

2,108.0 1,432.0 2,299.0 1,170.0 1,495.0 938.2 929.0 687.1 631.0 795.0 1,596.6 349.0 288.0 234.0 508.1 866.4 521.3 156.3 698.3 362.3 636.0 370.3 278.0 269.1 201.6 564.6 244.3 5.005 198.6 85.00 217.8 303.2 171.9 254.7 235.4 53.14 108.4 75.19 71.20 172.5 67.77 140.2 92.58 35.77 38.48 94.23 99.82 70.21 100.7 149.0 103.2 77.50 90.77 61.20 18.13 160.6 91.01 20.85 48.05 96.68 88.23 79.37

US US US natural US wells net wells natural gas gas net reserves—– — —––— drilled–—– –— ——reserves drilled Rank Bcf RankRank Wells Wells Rank Bcf 1 25,987.0 14 4,174.0 5 9,664.0 6 8,668.0 21 1,714.0 19 2,196.8 7 7,651.0 2 10,692.0 44 620.0 31 1,144.0 11 4,905.5 17 2,804.0 45 610.0 64 226.3 13 4,255.0 16 2,908.4 23 1,668.9 3 9,809.0 51 492.0 52 452.4 35 790.0 26 1,601.0 25 1,607.0 18 2,317.2 15 3,149.6 9 6,922.8 24 1,666.7 4 9,776.0 39 700.1 10 6,317.6 20 1,788.2 28 1,466.5 78 103.7 38 707.9 66 220.1 8 7,082.0 119 2.069 29 1,180.9 42 647.0 41 655.1 12 4,831.2 43 642.8 27 1,475.9 36 719.0 22 1,682.9 75 111.6 76 110.5 50 493.8 65 221.0 47 559.6 60 257.1 62 254.9 54 377.8 32 989.8 30 1,155.0 48 537.0 80 92.42 49 495.3 37 712.2 71 153.9 70 159.3 40 686.7

6 732.0 1 1,125.0 12 492.0 4 854.6 14 478.8 5 816.5 13 481.0 8 682.0 26 211.0 9 666.0 3 869.0 20 324.4 27 210.0 29 189.0 7 699.0 15 388.5 11 502.0 25 221.0 21 257.1 56 55.90 2 986.6 19 329.0 17 345.0 23 242.5 16 375.0 24 239.1 33 174.6 18 342.4 34 161.0 31 185.8 10 502.9 22 248.0 44 98.30 28 190.6 35 151.1 32 176.5 42 110.0 74 33.20 40 121.0 37 139.9 46 89.90 30 186.7 81 27.20 43 106.8 41 115.1 50 74.00 47 87.50 70 38.56 48 86.50 53 59.20 39 122.0 71 36.70 45 98.00 63 49.10 78 29.60 36 148.2 49 85.80 58 55.00 68 38.80 51 72.70 59 51.60 76 31.50

43

GENERAL INTEREST

OGJ150 Rank Rank total Total bybytotal ––– assets ––– —-assets—— 2014 2013 Company 20022001 Company 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 100 101 102 103 104 105 106 107 108 109 110 111 112 113 114 115 116 117 118 119 120 121 122 123 124

44

64 — 60 — 61 58 75 67 65 74 71 68 66 70 81 73 82 54 77 78 79 72 80 76 91 111 84 86 89 85 83 90 88 93 92 97 123 94 119 95 98 96 99 101 — 102 100 105 108 106 113 107 112 104 109 114 115 110 124 120 122 126

Northern Oil and Gas Inc. Bonanza Creek Energy Inc. Legacy Reserves LP Eclipse Resources Corp. Fidelity Exploration & Production Co.7, 9 Magnum Hunter Resources Corp. Triangle Petroleum Corp.10 Clayton Williams Energy Inc. Resolute Energy Corp. Matador Resources Co. Rex Energy Corp. Approach Resources Inc. Quicksilver Resources Inc. Wexpro Callon Petroleum Co. Contango Oil & Gas Co. Warren Resources Inc. Eagle Rock Energy Partners LP PetroQuest Energy Inc. Gastar Exploration Inc. Miller Energy Resources Inc.12 Goodrich Petroleum Corp. Emerald Oil Inc. Venoco Inc. Mid-Con Energy Partners LP Earthstone Energy Inc.13 Synergy Resources Corp.14 New Source Energy Partners LP Abraxas Petroleum Corp. Black Hills Corp.15 Forestar Group Inc.15 American Eagle Energy Corp. PrimeEnergy Corp. Panhandle Oil and Gas Inc.7 PostRock Energy Services Corp. Ring Energy Inc. Yuma Energy Inc. Escalera Resources Co. Cubic Energy Inc.16 US Energy Corp. VOC Energy Trust Dorchester Minerals LP FX Energy Inc. EnerJex Resources Inc. Glori Energy Inc. Evolution Petroleum Corp.16 Zaza Energy Corp. Reserve Petroleum Co. Lucas Energy Inc.13 Tengasco Inc. Spindletop Oil & Gas Co. Cross Border Resources Corp. Pegasi Energy Resources Corp. Lilis Energy Inc. Adams Resources & Energy Inc.15 Hydrocarb Energy Corp.19 FieldPoint Petroleum Corp. Armada Oil Inc. Houston American Energy Corp. Mexco Energy Corp.13 Royale Energy Inc. Apache Offshore Investment Partnership

Total Total assets assets $1,000 $1,000 2,026,746 2,006,089 1,898,606 1,884,946 1,738,064 1,669,829 1,550,371 1,510,885 1,455,101 1,436,291 1,401,721 1,401,427 1,214,302 977,500 876,770 843,415 818,680 794,275 790,895 775,794 766,822 722,138 689,060 616,254 454,628 451,388 448,542 377,465 374,899 366,247 342,703 270,934 264,900 246,641 195,675 167,641 148,106 127,879 124,971 123,523 101,603 97,509 78,893 76,058 67,435 65,016 60,216 44,171 40,738 37,209 33,506 33,290 33,288 32,575 25,888 25,732 22,898 21,324 18,614 17,918 13,579 13,501

Total Net ––––– revenue ——–– revenue–––––– ––—— $1,000 Rank 55 58 62 86 61 69 56 66 72 68 74 77 57 70 83 76 84 73 78 81 94 80 89 79 88 101 90 82 87 99 92 98 85 91 93 104 103 102 112 107 105 95 106 113 111 109 118 108 120 114 116 117 128 126 115 121 119 122 133 124 125 127

595,027 558,633 533,172 137,816 2 547,571 391,625 572,955 468,456 329,371 432,381 2 297,987 258,529 569,428 385,900 2 151,862 276,458 2 150,723 298,204 225,021 171,418 70,558 208,643 112,608 224,209 126,285 47,994 104,301 165,643 133,776 55,114 84,300 60,549 144,580 84,411 83,505 38,175 43,336 44,089 15,849 32,379 38,113 2 65,170 38,101 14,293 15,859 17,704 11,480 2 21,168 2 5,220 13,788 13,208 12,352 2,000 3,140 13,361 5,065 9,234 4,451 370 4,042 3,221 2,934 8

StockholderNet –––––– income——— –––– ——income $1,000 Rank 37 68 126 123 49 122 50 59 106 47 113 56 120 41 60 107 66 121 62 57 110 128 115 44 67 111 64 112 53 102 108 118 63 65 75 72 104 98 71 89 61 58 117 74 103 76 99 73 94 85 77 92 100 109 97 96 88 79 93 81 90 80

163,746 20,283 (283,645) (183,176) 2 96,733 (147,127) 93,397 43,881 (21,850) 110,754 (42,650) 56,172 (103,100) 122,800 37,766 (21,874) 24,030 (139,907) 31,190 50,953 (28,567) (353,136) (52,145) 120,437 22,492 (28,834) 28,853 (42,075) 63,269 2 (15,129) (22,686) (92,216) 29,149 25,001 3,850 8,421 (20,225) (7,585) 9,114 (2,091) 17 37,230 3 45,239 (59,220) 4,574 (18,756) 3,597 (8,226) 6,763 (4,688) (788) 3,205 (2,464) (8,911) (28,439) 2 (7,510) (6,555) (1,947) 1,548 (4,353) 301 (2,152) 812

Stockholders’ Capital & expl. –––––– equity———–––––– —— equity Rank $1,000 Rank

Capital & expl. –––––spending spending——––––– —— $1,000 Rank $1,000

54 55 58 42 — 67 60 68 62 51 61 53 125 — 66 59 73 69 81 70 74 121 71 122 76 72 75 78 79 — — 89 86 82 98 80 87 96 116 83 84 85 97 90 91 88 123 92 94 93 95 99 100 101 — 107 106 102 109 103 115 105

62 48 49 45 53 56 70 63 75 58 67 68 83 84 73 76 65 81 77 79 82 71 118 89 95 90 91 99 74 85 87 78 93 94 96 86 98 110 102 97 — — 100 104 92 122 101 106 108 112 115 111 121 124 — 120 107 103 114 117 116 126

770,862 740,071 637,205 1,152,711 — 431,855 535,740 397,794 526,618 866,541 531,373 774,327 (1,137,871) — 433,735 567,466 292,552 3 388,470 136,909 350,286 282,759 (15,774) 321,888 (19,845) 3 234,142 316,528 281,490 3 211,314 207,495 — — 46,974 78,260 119,189 18,224 142,543 71,056 20,906 (1,685) 107,395 18 101,603 96,524 20,584 46,001 41,215 51,878 (59,449) 36,742 29,684 32,169 24,246 17,294 15,950 14,066 — 9,924 10,968 14,026 9,272 13,399 (1,141) 3 10,973

476,871 641,204 638,942 745,766 600,572 562,324 351,156 422,473 183,565 560,849 391,422 390,506 133,481 114,400 232,596 180,422 412,531 136,694 174,633 155,631 136,320 322,352 1,692 88,307 33,969 83,041 66,137 24,671 192,799 109,439 103,385 164,265 38,758 38,613 32,973 105,215 25,527 5,158 9,398 29,831 — — 16,555 7,096 42,362 312 10,569 6,508 5,662 3,708 3,357 5,019 1,070 191 — 1,222 6,132 9,147 3,365 2,150 3,183 35

Oil & Gas Journal | Sept. 7, 2015

GENERAL INTEREST

Worldwide Worldwide Worldwide Worldwide US US Worldwide liquids Worldwidenatural natural gas gas Worldwide natural US liquids liquids US natural natural gas liquids liquidsliquids Worldwide natural gas gas –— production ––—— –— production –— – –——–reserves—– reserves –— –— reserves —– –——production —–– — — production – production ——–reserves–—– production — ——production production— RankRankMillion bblbblRank Rank BcfBcf Rank Rank BcfBcf Rank Bcf Mill Rank Million Mill bbl bbl Rank Rank Million Millbbl bbl Rank Rank Bcf 54 46 50 81 49 70 60 55 62 66 67 63 75 92 78 74 82 72 88 76 91 77 80 71 83 95 85 84 79 96 86 89 87 94 104 98 102 124 126 103 93 90 117 105 108 106 109 112 116 107 115 110 129 121 111 118 113 119 133 123 135 125

5.151 6.018 5.519 1.131 5.528 2.618 3.771 4.779 3.489 3.320 3.224 3.485 2.188 0.587 1.692 2.409 1.118 2.471 0.803 1.775 0.685 1.693 1.239 2.556 1.112 0.527 0.941 1.049 1.601 0.472 0.931 0.763 0.930 0.554 0.275 0.458 0.330 0.026 0.013 0.330 0.574 0.721 0.047 0.210 0.145 0.173 0.138 0.109 0.053 0.154 0.089 0.128 0.008 0.034 0.127 0.042 0.098 0.040 0.003 0.027 0.001 0.026

91 70 55 63 61 59 95 84 83 67 51 76 36 37 96 56 66 73 50 74 105 65 112 103 116 97 90 92 94 82 98 121 88 75 72 122 71 80 89 104 109 81 87 — — 124 107 101 — — 106 110 113 120 100 114 117 118 127 111 108 119

3.683 14.11 25.94 19.76 20.82 21.85 2.429 5.901 6.942 15.30 37.01 10.77 77.20 64.30 2.220 25.88 16.09 12.00 11 38.51 11.60 0.794 16.60 0.339 0.884 0.157 2.132 3.747 3.674 2.918 7.156 1.861 0.042 4.182 10.77 13.23 0.039 14.01 8.077 4.044 0.813 0.421 7.256 4.235 — — 0.027 0.562 1.019 — — 0.740 0.375 0.224 0.078 1.133 0.174 0.148 0.096 0.013 0.362 0.548 0.096

48 61 56 82 65 74 64 59 57 76 87 43 70 102 73 84 81 75 107 62 96 72 77 67 78 85 83 88 71 97 93 91 92 89 104 90 106 126 129 105 94 98 123 103 110 86 128 118 100 108 122 109 116 114 124 112 111 117 131 119 135 120

Oil & Gas Journal | Sept. 7, 2015

88.91 58.11 69.30 16.58 51.11 24.92 52.17 62.83 68.09 24.18 11.77 96.25 34.25 4.731 25.73 15.92 16.79 24.85 2.437 54.23 6.096 28.14 22.83 38.56 22.14 15.76 16.33 10.90 33.10 5.996 7.672 9.587 8.399 10.61 4.134 10.24 2.715 0.247 0.064 4.120 6.670 5.746 0.357 4.400 1.411 12.81 0.078 0.524 5.038 1.797 0.405 1.695 0.673 0.900 0.318 1.022 1.115 0.622 0.034 0.502 0.002 0.502

84 67 102 62 64 56 89 83 92 60 36 58 35 47 88 68 57 69 54 59 97 77 98 105 108 90 79 95 86 85 101 106 96 72 74 123 94 82 81 117 114 87 91 — — 118 119 111 116 — 107 115 103 112 110 104 121 — 126 109 113 122

70.94 188.6 12.37 256.3 245.0 353.0 40.19 75.58 36.80 267.1 839.2 300.0 908.3 566.1 42.55 179.7 327.3 169.1 11 38.51 287.0 27.64 104.8 21.07 10.93 6.542 38.58 95.18 32.49 55.85 65.44 12.65 7.820 32.27 142.5 119.1 0.988 35.26 85.85 90.34 3.211 3.970 55.70 37.39 — — 2.907 2.600 4.477 3.316 — 6.939 3.740 12.16 4.237 5.611 12.03 1.909 — 0.073 6.259 4.132 1.250

54 46 50 81 49 70 60 55 62 66 67 63 75 92 78 74 82 72 88 76 91 77 80 71 83 95 85 84 79 96 86 89 87 94 104 98 102 124 126 103 93 90 117 105 108 106 109 112 116 107 115 110 129 121 111 118 113 119 133 123 135 125

5.151 6.018 5.519 1.131 5.528 2.618 3.771 4.779 3.489 3.320 3.224 3.485 2.186 0.587 1.692 2.409 1.118 2.471 0.803 1.775 0.685 1.693 1.239 2.556 1.112 0.527 0.941 1.049 1.601 0.472 0.931 0.763 0.930 0.554 0.275 0.458 0.330 0.026 0.013 0.330 0.574 0.721 0.047 0.210 0.145 0.173 0.138 0.109 0.053 0.154 0.089 0.128 0.008 0.034 0.127 0.042 0.098 0.040 0.003 0.027 0.001 0.026

90 70 55 63 61 59 94 84 83 67 50 76 44 35 95 56 66 73 49 74 104 65 112 102 116 96 89 91 93 82 97 121 87 75 72 122 71 80 88 103 108 81 — — — 123 106 100 — — 105 109 113 120 99 114 117 118 126 111 107 119

3.683 14.11 25.94 19.76 20.82 21.85 2.429 5.901 6.942 15.30 37.01 10.77 46.03 64.30 2.220 25.88 16.09 12.00 11 38.51 11.60 0.794 16.60 0.339 0.884 0.157 2.132 3.747 3.674 2.918 7.156 1.861 0.042 4.182 10.77 13.23 0.039 14.01 8.077 4.044 0.813 0.421 7.256 — — — 0.027 0.562 1.019 — — 0.740 0.375 0.224 0.078 1.133 0.174 0.148 0.096 0.013 0.362 0.548 0.096

US USliquids liquids —–– —– reserves reserves —–– —– Rank Million bbl Rank Mill bbl 48 61 56 82 65 74 64 59 57 76 87 43 70 102 73 84 81 75 107 62 96 72 77 67 78 85 83 88 71 97 93 91 92 89 104 90 106 126 129 105 94 98 123 103 110 86 128 118 100 108 122 109 116 114 124 112 111 117 131 119 135 120

88.91 58.11 69.30 16.58 51.11 24.92 52.17 62.83 68.09 24.18 11.77 96.25 34.24 4.731 25.73 15.92 16.79 24.85 2.437 54.23 6.096 28.14 22.83 38.56 22.14 15.76 16.33 10.90 33.10 5.996 7.672 9.587 8.399 10.61 4.134 10.24 2.715 0.247 0.064 4.120 6.670 5.746 0.357 4.400 1.411 12.81 0.078 0.524 5.038 1.797 0.405 1.695 0.673 0.900 0.318 1.022 1.115 0.622 0.034 0.502 0.002 0.502

US US US natural US wells net wells natural gas gas net reserves—– — —––— drilled–—– –— ——reserves drilled Rank Bcf RankRank Wells Wells Rank Bcf 84 67 101 61 63 55 89 83 91 59 34 57 33 46 88 68 56 69 53 58 96 77 97 104 107 90 79 94 86 85 100 105 95 72 74 122 93 82 81 116 113 87 — — — 117 118 110 115 — 106 114 102 111 109 103 120 — 125 108 112 121

70.94 188.6 12.37 256.3 245.0 353.0 40.19 75.58 36.80 267.1 839.2 300.0 908.3 566.1 42.55 179.7 327.3 169.1 11 382.5 287.0 27.64 104.8 21.07 10.93 6.542 38.58 95.18 32.49 55.85 65.44 12.65 7.820 32.27 142.5 119.1 0.988 35.26 85.85 90.34 3.211 3.970 55.70 — — — 2.907 2.600 4.477 3.316 — 6.939 3.740 12.16 4.237 5.611 12.03 1.909 — 0.073 6.259 4.132 1.250

64 38 65 73 84 67 69 57 92 60 62 52 72 96 82 87 54 90 83 85 100 89 80 108 61 98 75 97 88 102 55 — 91 95 86 — 113 105 118 103 99 — 106 66 79 — 112 104 114 93 111 116 — — 110 — — — 109 117 107 —

41.60 124.3 41.10 34.10 22.00 39.30 38.60 55.80 10.00 50.50 49.60 70.00 34.60 7.700 27.20 16.70 58.90 12.00 22.65 20.90 5.000 16.20 27.30 2.000 50.00 7.300 33.00 7.400 16.40 4.430 57.30 NA 11.79 7.784 18.00 NA 1.150 3.600 0.250 4.280 5.300 NA 3.000 41.00 29.00 — 1.200 3.940 1.000 10.00 1.220 0.860 — — 1.660 — — NA 1.943 0.430 2.520 —

45

GENERAL INTEREST

OGJ150 Rank Rank total Total bybytotal ––– assets ––– —-assets—— 2014 2013 Company 20022001 Company 125 126 127 128 129 130 131 132 133 134 135 — — — — — — — —

128 121 125 129 130 132 131 136 133 137 138 118 139 127 87 116 134 135 —

Daybreak Oil & Gas Inc.20 San Juan Basin Royalty Trust Cross Timbers Royalty Trust Sabine Royalty Trust Legand Oil and Gas Ltd. Permian Basin Royalty Trust Pioneer Oil & Gas7 Avalon Oil & Gas Inc.13 Blacksands Petroleum Inc.21 TN-K Energy Group Inc. United American Petroleum Corp. American Natural Energy Corp.22 Breitling Energy Corp.22 Daleco Resources Corp.22 Dune Energy Inc.22 GeoPetro Resources Co.22 Humble Energy Inc.22 Petron Energy II Inc.22 Treaty Energy Corp.22 Totals

Total Total assets assets $1,000 $1,000 13,429 13,374 12,273 6,845 4,953 2,828 2,818 2,731 2,197 1,860 866 NA NA NA NA NA NA NA NA ––––––––––––– 1,501,644,996

Total Net ––––– revenue ——–– revenue–––––– ––—— $1,000 Rank 123 96 110 97 131 100 129 135 130 134 132 — — — — — — — —

4,165 61,583 16,449 61,092 692 49,011 1,330 156 1,229 196 622 NA NA NA NA NA NA NA NA ––––––––––– 920,511,409

StockholderNet –––––– income——— –––– ——income $1,000 Rank 83 54 69 55 91 114 87 84 95 82 86 — — — — — — — —

(733) 59,873 17 15,945 17 58,688 (2,356) 17 (47,717) (1,076) (786) (6,216) (674) (836) NA NA NA NA NA NA NA NA –––––––––– 73,983,270 17

Stockholders’ Capital & expl. –––––– equity———–––––– —— equity Rank $1,000 Rank 119 108 104 110 118 113 111 112 120 117 114 — — — — — — — —

(4,786) 18 9,363 18 10,995 18 4,535 (3,588) 18 723 2,735 1,212 (6,463) (2,068) (614) NA NA NA NA NA NA NA NA ––––––––––– 718,294,130

Capital & expl. –––––spending spending——––––– —— $1,000 Rank $1,000 119 105 — — 125 — — — 113 123 — — — — — — — — —

1,516 6,531 — — 150 — — — 3,682 284 — NA NA NA NA NA NA NA NA ––––––––––– 226,364,463

NA.

Not Available. (s)indicates less than 500 bbl or 500 mcf. 1Net operating. 2Operating. 3Partners equity. 4Before interest and taxes. 5Before depreciation, depletion and amortization. 6Subsidiary of National Fuel Gas Co 7Fiscal yearend Sept. 30. 8Sales. 9Subsidiary of MDU Resources Group. 10Fiscal yearend Jan. 31, 2015. 11Includes NGL. 12 Fiscal yearend Apr. 30. 13Fiscal yearend Mar. 31. 14Fiscal yearend Aug. 31. 15Oil and gas operations only. 16Fiscal yearend June 30. 17Distributable income. 18Trust corpus. 19Net profits income. 20Fiscal yearend Feb. 28, 2015. 21Fiscal yearend Oct. 31. 22Not filed at press time.

46

Oil & Gas Journal | Sept. 7, 2015

GENERAL INTEREST

Worldwide Worldwide Worldwide Worldwide US US Worldwide liquids Worldwidenatural natural gas gas Worldwide natural US liquids liquids US natural natural gas liquids liquidsliquids Worldwide natural gas gas –— production ––—— –— production –— – –——–reserves—– reserves –— –— reserves —– –——production —–– — — production – production ——–reserves–—– production — ——production production— RankRankMillion bblbblRank Rank BcfBcf Rank Rank BcfBcf Rank Bcf Mill Rank Million Mill bbl bbl Rank Rank Million Millbbl bbl Rank Rank Bcf 120 122 114 101 128 99 131 132 127 134 130 — — — — — — — —

0.038 0.030 0.096 0.381 0.009 0.453 0.004 0.004 0.011 0.001 0.006 NA NA NA NA NA NA NA NA ––––– 3,320

125 68 99 85 — 102 115 — 126 — — — — — — — — — —

0.022 15.30 1.464 5.156 — 0.931 0.158 — 0.019 — — NA NA NA NA NA NA NA NA –––––– 17,089

115 125 113 95 121 99 134 132 133 130 127 — — — — — — — —

0.846 0.276 0.989 6.410 0.446 5.376 0.017 0.029 0.029 0.060 0.119 NA NA NA NA NA NA NA NA ––––––– 42,727

125 73 99 93 — 100 124 — 127 — 128 — — — — — — — —

0.255 120.7 20.09 36.33 — 13.18 0.938 — 0.017 — 0.001 NA NA NA NA NA NA NA NA –––––––– 231,407

120 122 114 101 128 99 132 131 127 134 130 — — — — — — — —

0.038 0.030 0.096 0.381 0.009 0.453 0.004 0.004 0.011 0.001 0.006 NA NA NA NA NA NA NA NA ––––– 1,976

124 68 98 85 — 101 115 — 125 — — — — — — — — — —

0.022 15.30 1.464 5.156 — 0.931 0.158 — 0.019 — — NA NA NA NA NA NA NA NA –––––– 12,366

US USliquids liquids —–– —– reserves reserves —–– —– Rank Million bbl Rank Mill bbl 115 125 113 95 121 99 134 132 133 130 127 — — — — — — — —

0.846 0.276 0.989 6.410 0.446 5.376 0.017 0.029 0.029 0.060 0.119 NA NA NA NA NA NA NA NA ––––––– 25,527

US US US natural US wells net wells natural gas gas net reserves—– — —––— drilled–—– –— ——reserves drilled Rank Bcf RankRank Wells Wells Rank Bcf 124 73 98 92 — 99 123 — 126 — 127 — — — — — — — —

0.255 120.7 20.09 36.33 — 13.18 0.938 — 0.017 — 0.001 NA NA NA NA NA NA NA NA ––––––– 172,923

94 8.000 — — — — — — 77 31.00 — NA — NA — NA 115 1.000 101 4.763 — — — NA — NA — NA — NA — NA — NA — NA — NA –––––––– 18,296.3

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Oil & Gas Journal | Sept. 7, 2015

47

GENERAL INTEREST

Lower oil prices slam OGJ100 2014 earnings Conglin Xu

averaged 49.3 million b/d in 2014 vs. 48.7 million b/d in 2013. Unchanged from the previous OGJ100, the world’s top two oil producers in of volume are Saudi Aramco and Leena Koottungal OAO Rosneft. During 2014, Iraq National Oil Co. overtook Survey Editor/News Writer National Iranian Oil Co. (NIOC), which is now No. 4, as the No. 3 oil producer. Oil & Gas Journal’s latest look at the top 100 oil and gas Reporting production of 1 billion bbl last year, an inproducing companies based outside the US shows that profcrease of 9.2%, Abu Dhabi Co. has moved up to No. 6 from its were down worldwide last year, weighted by the sharp the No. 7 producer in the previous OGJ100. decline in crude oil prices in the second half of the year as BP PLC has slipped to No. 12 from No. 11 with total year well as the stronger US dollar. 2014 output down 4.5% to 665.4 million bbl, partly The OGJ100 list of major non-US companies allows reflecting the Abu Dhabi onshore concession excomparison of size and performance of prominent piry. Production from Total SA declined 11.4% to companies throughout the world. The companies are 377.4 million bbl. Royal Dutch Shell PLC’s 2014 oil listed by region according to the location of corporate production dipped 4.2%. headquarters rather than ranked by assets or revenues, With reported crude reserves of 298 billion bbl, since many do not report financial results. Petroleos de Venezuela SA exceeds the second leadTwo Canadian companies included last year no ing company, Saudi Aramco, with 32 billion bbl in SPECIAL longer appear in this year’s OGJ100 list: Sonde Rereserves, and the third, NIOC, with 140 billion bbl. REPORT sources Corp. filed for bankruptcy, and Petrobank Petroleo Brasileiro SA moved up to 13th from Energy & Resources Ltd. merged with Touchstone 14th on the reserves list from a year earlier, with Exploration Inc. Touchstone and Crescent Point Energy updated reserves of 11.1 billion bbl. Corp. the list instead. Based on the latest OGJ estimates, the top 20 reserves There were no replacements of companies in the top 20 leaders control 78% of total world crude oil reserves (OGJ, list of oil producers and reserves holders, although the order Dec. 1, 2014, p. 30). has changed. State-owned companies continue to dominate If the top 20 production and reserve leaders tables inboth lists. cluded international oil companies headquartered in the US, ExxonMobil Corp. would rank 14th in worldwide liqTop 20 in oil production, reserves uids production and 5th in worldwide liquids reserves. Oil production of the top 20 producers based outside the US cont’d on p. 56 Senior Editor-Economics

OGJ100: PRODUCTION AND RESERVE LEADERS Rank

Company

Production, million bbl

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Saudi Arabian Oil Co. .......................................................... 3,540.5 OAO Rosneft ....................................................................... 1,618.7 Iraq National Oil Co. ........................................................... 1,204.1 National Iranian Oil Co. ...................................................... 1,022.0 Kuwait Petroleum Corp. ....................................................... 1,018.0 Abu Dhabi National Oil Co. .................................................. 1,014.0 PetroChina Co. Ltd. ................................................................ 945.5 Petroleos de Venezuela SA ..................................................... 912.5 Petroleos Mexicanos ............................................................... 886.5 Petroleo Brasileiro SA ............................................................. 783.7 Nigerian National Petroleum Corp........................................... 693.9 BP PLC .................................................................................. 665.4 OAO Lukoil ............................................................................. 656.0 Sonangol ................................................................................ 607.0 Royal Dutch Shell .................................................................. 488.0 OJSC Surgutneftegas .............................................................. 451.5 Sonatrach............................................................................... 404.1 Total SA .................................................................................. 377.4 Statoil ASA ............................................................................. 357.0 Petroleum Development Oman LLC ........................................ 346.0 Total .................................................................................. 17,991.7

48

Rank 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Company

Reserves, million bbl

Petroleos de Venezuela SA ...............................................298,000.0 Saudi Arabian Oil Co. .......................................................265,789.0 National Iranian Oil Co. ...................................................157,800.0 Iraq National Oil Co. ........................................................144,211.0 Kuwait Petroleum Corp. ...................................................101,500.0 Abu Dhabi National Oil Co. ................................................92,200.0 National Oil Corp. (Libya) ...................................................48,363.0 Nigerian National Petroleum Corp. .....................................37,070.0 Qatar Petroleum Corp. .......................................................25,244.0 OAO Rosneft ......................................................................25,053.6 OAO Lukoil ........................................................................13,349.0 Sonatrach ..........................................................................12,200.0 Petroleo Brasileiro SA.........................................................11,109.6 PetroChina Co. Ltd. ............................................................10,593.0 Petroleos Mexicanos ............................................................9,711.0 BP PLC ................................................................................9,694.0 Sonangol..............................................................................9,011.0 Petroleos del Ecuador ..........................................................8,200.0 Total SA ...............................................................................5,303.0 Petroleum Development Oman LLC ......................................5,151.0 Total .............................................................................1,289,552.2

Oil & Gas Journal | Sept. 7, 2015

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F L A M E R E S I S TA N T FA B R I C S F O R W O R K W E A R

GENERAL INTEREST

OGJ100 LEADING OIL AND GAS COMPANIES OUTSIDE THE US

Country

Company

CANADA Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada

Advantage Oil & Gas Ltd. ARC Resources Ltd. Baytex Energy Ltd. Bonavista Energy Trust Canadian Natural Resources Ltd. Canadian Oil Sands Ltd. Cenovus Energy Crescent Point Energy Corp. EnCana Corp. Enerplus Resources Fund Gran Tierra Energy Inc. Harvest Energy Trust Husky Energy Inc. Imperial Oil Ltd. Paramount Resources Ltd. Pembina Pipeline Corp. Pengrowth Energy Trust Penn West Exploration Peyto Energy Trust Sherritt International Corp. Suncor Energy Inc. Talisman Energy Inc. Touchstone Exploration Inc. Vermilion Energy Trust

LATIN AMERICA Argentina Argentina Barbados Brazil Colombia Cuba Ecuador Mexico Suriname Trinidad and Tobago

Techint Teetrol SA6 YPF SA Barbados National Oil Co. Ltd.6 Petroleo Brasileiro SA Ecopetrol Cubapetroleo Petroleos del Ecuador Petroleos Mexicanos State Oil Co. Suriname Ltd.

Venezuela

Petroleum Co. of Trinidad & Tobago Ltd. (Petrotrin)2 Petroleos de Venezuela SA

EUROPE Austria Denmark Denmark Finland Greece Hungary Ireland Ireland Italy Netherlands Norway Poland Romania Russia Russia Russia Russia Spain Spain Sweden Turkey United Kingdom

OMV AG Dong Energy AS Maersk Oil & Gas Neste Oil9 Total SA RWE Dea AG Wintershall AG Hellenic Petroleum SA MOL Group PLC Dragon Oil PLC Tullow Oil PLC Eni SPA Royal Dutch Shell PLC Statoil ASA Polish Oil & Gas Co. OMV Petrom SA OAO Gazprom OAO Lukoil OAO Rosneft OJSC Surgutneftegas Compania Espanola de Petroleos SA Repsol YPF SA Lundin Petroleum AB Turkish Petroleum Corp. BG Group PLC

50

Capital and exploratory –––––– Total assets ––––– –––– Total revenues –––– ––– Total net income ––– ––––– expenditures –––– –––––––––––––––––––––––––––––––––––––––––––––––– Million $ –––––––––––––––––––––—–––––––––––––––––––– 2014 2013 2014 2013 2014 2013 2014 2013 1,687.6 7,337.6 7,227.5 5,138.1 69,832.0 11,616.2 28,646.2 19,103.5 24,621.0 4,735.5 1,714.1 5,906.3 45,063.7 47,362.8 3,711.3 13,063.9 7,157.0 11,428.3 3,627.3 6,128.5 92,418.4 20,102.8 32,538.5 5,087.9

1,878.2 6,103.1 2,871.0 4,506.7 55,066.3 10,842.2 26,838.3 13,548.1 17,648.0 3,917.4 1,904.6 5,628.5 39,265.9 39,600.0 2,604.5 9,727.1 7,057.7 13,118.1 2,631.7 6,651.5 83,327.2 20,387.3 61,471.2 3,946.1

227.0 1,997.9 1,689.0 1,222.0 20,824.8 4,074.9 21,684.8 4,652.5 8,019.0 1,943.7 562.3 4,773.0 26,597.6 40,810.5 386.4 6,700.2 1,652.6 2,639.7 863.3 503.0 44,007.6 4,154.4 35,443.5 1,448.0

263.6 1,443.2 1,148.9 993.2 16,629.4 4,155.0 19,216.7 2,749.5 5,858.0 1,349.9 606.0 5,525.6 24,585.1 33,916.9 239.5 5,156.2 1,641.2 2,948.9 551.1 462.0 40,780.8 4,620.6 NA 1,242.1

17.3 420.4 (145.7) 5.3 4,337.6 507.8 821.4 562.2 3,392.0 330.1 171.3 (486) 1,388.8 4,178.6 (71.7) 422.8 639.0 1,913.2 223.0 320.2 2,979.7 (1,005.7) 57.8 297.3

(3.5) 247.9 169.7 51.0 2,338.1 859.0 681.9 149.2 236.0 49.4 126.3 (805) 1,883.9 2,912.8 (59.1) 361.5 326.4 833.3 147.3 680.1 4,028.3 (1,210.3) 54.5 337.4

261.3 1,043.8 3,664.7 521.2 12,965.4 1,026.7 3,149.7 4,818.3 1,329.0 903.1 416.0 451.0 5,545.4 6,242.0 942.8 1,558.8 998.0 189.9 761.8 89.2 7,684.9 2,205.2 75.6 759.2

160.1 885.7 531.4 464.1 7,492.2 1,382.3 3,367.1 1,921.0 521.0 708.5 374.4 332.0 5,178.8 8,260.6 725.9 906.4 716.7 168.9 595.3 82.0 6,980.3 2,536.9 26.1 559.0

NA 33,226.0 20,855.4 20,803.0 213.0 213.9 298,687.0 321,423.0 45,168.6 66,214.0 NA NA NA NA 144,610.0 156,570.0 1,987.9 1,562.2

NA 16,763.4 364.5 143,657.0 29,046.3 NA NA 107,809.0 1,042.0

25,378.0 13,825.0 397.2 141,462.0 32,757.1 NA NA 122,984.0 1,022.9

NA 1,045.1 14.8 (7,503.0) 3,906.3 NA NA (36,071) 275.9

NA 779.0 14.7 10,832.0 6,676.5 NA NA (13,005) 298.5

NA NA 3.2 34,808.0 NA NA NA 24,240.0 233.9

2,085.0 NA 9.1 45,110.0 NA NA NA 25,127.0 293.6

7,147.5 NA

7,238.1 NA

4,605.6 NA

5,019.7 NA

(31,702.1) NA

2,472.8 NA

NA NA

NA NA

45,100.2 27,704.1 68,844.0 8,629.9 229,798.0 68,252.3 NA 9,027.1 17,943.0 4,960.1 17,549.4 186,301.1 353,116.0 131,881.7 13,809.6 9,159.9 574,776.8 111,800.0 287,414.4 77,842.2 NA 68,955.3 5,092.0 NA 96,343.7

43,798.2 26,920.2 74,509.0 9,700.4 239,223.0 67,470.5 NA 8,446.0 21,515.0 4,396.2 20,135.4 191,360.0 357,512.0 146,035.4 15,595.2 11,725.7 501,472.8 109,439.0 247,769.9 63,985.6 NA 76,538.2 4,361.4 7,118.8 104,608.4

43,458.3 10,895.3 47,569.0 18,164.8 212,018.0 58,651.1 NA 10,588.6 20,975.0 1,093.1 3,734.0 132,925.9 421,235.0 96,299.2 10,871.8 10,723.6 176,623.2 144,167.0 212,415.8 26,151.5 NA 57,228.0 785.2 NA 31,616.9

56,347.9 13,020.0 47,386.0 23,198.3 227,969.0 72,236.4 NA 12,852.3 24,141.0 1,047.9 4,465.1 154,248.1 451,235.0 104,945.3 10,387.6 13,036.8 167,475.0 141,452.0 149,738.6 25,523.1 NA 62,877.9 1,132.0 3,479.7 32,006.1

844.7 858.7 5,195.0 705.5 4,250.0 2,062.0 NA 379.5 (219) 650.5 (2,767.2) 1,562.2 14,730.0 3,744.4 894.4 165.4 42,998.4 4,714.0 13,511.6 27,952.3 NA 1,950.7 (252.2) NA 1,719.9

2,296.4 176.9 3,777.0 696.1 11,521.0 3,798.9 NA 362.0 (85) 512.6 364.5 6,605.3 16,526.0 6,671.8 607.7 518.7 37,185.8 7,627.0 17,576.9 8,041.3 NA 268.7 371.0 454.8 4,060.6

4,637.1 NA NA 505.8 30,509.0 4,162.7 NA NA 2,277.0 679.0 3,374.8 14,811.6 31,854.0 22,639.2 NA 1,034.1 34,608.3 14,545.0 20,573.8 NA NA NA 674.5 NA 14,624.0

6,942.7 NA NA 284.3 34,431.0 5,481.3 NA 688.3 1,206.0 331.0 3,036.4 14,432.8 40,145.0 15,539.8 NA 1,571.7 36,198.4 14,957.0 17,864.0 NA NA NA 569.9 NA 19,282.2

Oil & Gas Journal | Sept. 7, 2015

GENERAL INTEREST

Worldwide oil production –––––––––– Million bbl –––––––––– 2014 2013

Worldwide natural gas production –––––––––––– Bcf ––––––––––––– 2014 2013

Worldwide oil reserves –––––––––––– Million bbl ––––––––––– 2014 2013

0.1 15.0 1 24.6 1 9.1 1 193.9 34.6 203.5 46.9 1 18.0 1 14.7 15 6.7 1 10.9 1 66.4 1 102.9 1 1.5 NA 1 14.4 1 21.7 1 2.8 NA 1 0.3 1 30.5 565.0 1 10.5

0.2 13.0 1 18.3 1 9.9 1 174.5 35.8 179.3 39.8 1 9.4 1 14.0 15 7.0 1 12.4 1 65.3 1 95.3 1 1.2 NA 1 16.8 1 27.5 1 2.3 NA 1 1.9 1 48.2 80.2 1 9.4

47.7 148.2 23.8 114.6 567.6 NA 178.1 27.0 857.8 356.1 5 0.3 35.1 226.7 61.3 40.3 NA 202.1 79.9 151.0 NA 6.2 380.0 NA 39.7

44.2 127.5 15.3 101.5 422.7 NA 193.1 24.5 1,013.6 288.4 5 1.4 40.6 187.1 73.4 38.7 NA 231.8 109.5 116.0 NA 70.1 529.6 NA 29.6

13 6.8 192.5 3 218.4 1 93.3 1 4,511.0 3 1,600.0 166.0 NA 1 454.7 13 115.0 15 36.9 NA 1 835.0 1 NA 3 163.7 NA 3 398.3 13 298.0 3 48.0 NA 13 721.0 142.2 17.6 13 117.9

20.0 194.1 3 184.7 1 97.8 1 4,420.0 3 1,700.0 165.0 NA 1 277.3 13 136.0 15 40.0 NA 1 464.0 1 NA 3 57.8 NA 3 311.2 13 396.0 3 48.0 NA 13 761.0 116.2 NA 13 103.6

NA 89.0 0.3 1 783.7 NA 7 53.0 7 202.9 886.5 6.0

NA 102.0 0.3 1 750.4 NA 7 52.1 7 190.2 920.6 5.9

NA 547.0 0.8 2.1 NA 7 36.0 7 18.0 2,384.1 NA

NA 437.0 0.8 2.8 NA 7 35.2 7 12.0 2,325.2 NA

NA 674.0 2.5 1 11,109.6 NA NA 7 8,200.0 9,711.0 100.0

NA 628.0 2.8 1 10,658.0 NA NA 7 8,240.0 9,812.1 92.5

NA 904.8

NA 420.0

NA 720.0

309.7 31.2 NA NA 2,213.0 NA NA NA 117.5 NA 27.3 1,541.8 3,379.0 1,565.0 NA 309.7 15,675.9 819.0 2,002.3 335.5 NA NA NA NA 841.0

296.4 23.5 NA NA 2,257.2 91.8 NA NA 123.4 NA 42.7 1,576.8 2,634.5 1,571.0 NA 186.8 17,212.0 963.0 1,349.0 427.3 NA NA NA 22.4 967.0

1

NA 912.5

7

1

57.8 10.6 NA NA 1 377.4 NA NA NA 1 15.5 NA 22.9 302.2 1 488.0 1 357.0 NA 1 57.8 257.7 656.0 1,618.7 451.5 NA NA NA NA 1 80.9

1

7

1

52.2 8.2 NA NA 1 426.0 1 14.5 NA NA 1 16.7 NA 23.5 304.0 1 509.5 1 345.0 NA 1 32.1 246.7 664.0 1,494.7 452.2 NA NA NA 12.3 1 69.7

Oil & Gas Journal | Sept. 7, 2015

13

13

7

NA 298,000.0

1

615.8 NA NA NA 5,303.0 NA NA NA 1 200.4 3 663.0 3 307.6 3,350.0 1 3,939.0 1 1,942.0 NA 1 513.1 13,511.6 13,349.0 25,053.6 NA NA NA 3 172.7 NA 1 536.5

Worldwide natural gas reserves ––––––––––– Bcf –––––––––––– 2014 2013 3

13

7

NA 297,740.0

1

517.7 NA NA NA 5,413.0 3 127.7 NA NA 1 207.9 3 675.0 3 327.3 3,134.0 1 4,468.0 1 2,318.0 NA 1 386.6 9,155.7 13,223.0 24,805.4 NA NA NA 3 178.8 NA 1 470.4

7

3

1,709.2 2,882.0 3 200.7 1,094.4 6,001.0 NA 1,056.0 NA 5,522.0 1,408.0 5 9.8 NA 2,662.0 NA 3 1,090.9 NA 3 953.0 3 787.0 3 2,591.0 NA 3 73.0 2,087.3 0.5 3 622.0

1,618.8 2,639.0 3 188.6 950.4 4,305.0 NA 1,165.0 NA 8,576.0 1,340.3 5 13.5 NA 1,969.0 NA 3 450.5 NA 3 996.0 3 757.0 3 2,233.0 NA 3 92.0 2,336.3 NA 3 486.0

NA 3,016.0 5.0 1 12,127.9 NA NA 7 212.0 15,290.5 NA

NA 2,558.0 5.2 1 11,291.8 NA NA 7 212.0 16,548.5 NA

7 15,537.1 196,000.0

1,858.2 NA NA NA 33,590.0 NA NA NA 1,000.3 NA 3 226.4 14,190.0 40,316.0 16,919.0 NA 1.9 263,346.0 23.9 49,914.2 NA NA NA 88.5 NA 5,810.0

7

7 13,110.0 195,100.0

2,024.3 NA NA NA 33,026.0 3 1.9 NA NA 945.5 NA 3 330.5 15,582.0 42,473.0 18,416.0 NA 1.8 169,681.2 23.4 46,913.7 NA NA NA 91.4 NA 5,427.0

51

GENERAL INTEREST

OGJ100 LEADING OIL AND GAS COMPANIES OUTSIDE THE US

Country

Company

United Kingdom United Kingdom United Kingdom

BP PLC Cairn Energy PLC Premier Oil PLC

AFRICA Algeria Angola Egypt South Africa Libya Morocco Nigeria

Sonatrach Sonangol Egyptian General Petroleum Corp. Sasol Limited4 National Oil Corp. Office National des Hydrocarbons et des Mines (ONHYM) Nigerian National Petroleum Corp.

MIDDLE EAST Abu Dhabi Bahrain Dubai Iran Iraq Israel Kuwait Oman Qatar Saudi Arabia

Abu Dhabi National Oil Co. Bahrain National Oil Co. Dubai Petroleum Co. National Iranian Oil Co. Iraq National Oil Co. Ministry of Energy & Infrastructure Kuwait Petroleum Corp.6 Petroleum Development Oman LLC Qatar Petroleum Corp. Saudi Arabian Oil Co.

ASIA PACIFIC Australia Australia Australia Australia Australia China China China, Taiwan India India India Indonesia Indonesia Japan Malaysia Myanmar New Zealand Pakistan Pakistan Thailand

Australia Worldwide Exploration Ltd.4 BHP Billiton Petroleum4 Samson Oil & Gas4 Santos Ltd. Woodside Petroleum Ltd. China National Offshore Oil Corp. Ltd. PetroChina Co. Ltd. Chinese Petroleum Corp. Gujarat State Petroleum Corp. Ltd.6 Oil & Natural Gas Corp. Ltd.6 Oil India Ltd.6 MedcoEnergi Pertamina Japan Petroleum Exploration Co. Ltd.6 Petronas6 Myanma Oil & Gas Enterprise New Zealand Oil & Gas Ltd.4 Pakistan Oilfields Ltd.4 Pakistan Petroleum Ltd. PTT Exploration & Production Public Co. Ltd.

Capital and exploratory –––––– Total assets ––––– –––– Total revenues –––– ––– Total net income ––– ––––– expenditures –––– –––––––––––––––––––––––––––––––––––––––––––––––– Million $ –––––––––––––––––––––—–––––––––––––––––––– 2014 2013 2014 2013 2014 2013 2014 2013 284,305.0 305,690.0 3,017.4 3,606.1 6,087.6 5,813.9

353,568.0 NA 1,668.8

379,136.0 NA 1,550.6

4,003.0 NA 210.3

23,758.0 NA 234.0

22,546.0 432.1 1,195.5

24,520.0 408.5 878.0

NA NA NA 26,341.0 NA

NA NA NA 25,253.0 NA

NA NA NA 8 19,508.0 NA

NA NA NA 8 19,197.0 NA

NA NA NA 2,928.0 NA

NA NA NA 3,063.0 NA

NA NA NA NA NA

NA NA NA NA NA

NA NA

NA NA

NA NA

NA NA

NA NA

NA NA

NA NA

NA NA

NA NA NA NA NA NA NA NA NA NA

NA NA NA NA NA NA NA NA NA NA

NA NA NA NA NA NA NA NA NA NA

NA NA NA NA NA NA NA NA NA NA

NA NA NA NA NA NA NA NA NA NA

NA NA NA NA NA NA NA NA NA NA

NA NA NA NA NA NA NA NA NA NA

NA NA NA NA NA NA NA NA NA NA

982.8 151,413.0 41.8 18,262.6 24,082.0 106,833.5 387,691.9 NA 30.5 51,540.4 55,321.1 2,702.5 50,327.9 5,532.2 164,303.4 NA 170.2 596.9 2,383.0 23,290.5

1,055.0 138,109.0 46.1 18,401.8 23,770.0 102,667.3 386,916.6 29,464.7 NA 41,060.1 40,793.0 2,531.7 49,341.9 4,989.1 167,796.7 NA 194.2 509.6 2,067.9 21,572.4

297.3 67,206.0 8.7 3,700.3 7,435.0 44,578.7 8 370,571.1 NA 65.4 30,456.1 18,423.2 750.7 70,648.4 2,612.9 24,261.5 NA 86.1 361.9 1,201.2 8,017.5

292.3 65,953.0 5.9 3,535.6 5,926.0 46,508.9 8 362,428.9 39,543.6 NA 29,655.7 19,578.9 888.9 71,102.1 2,380.2 26,929.1 NA 89.4 283.0 1,007.4 7,444.9

56.4 15,224.0 3.5 (844) 2,516.0 9,771.5 19,320.7 NA 6.9 4,368.1 4,886.0 10.1 2,912.4 274.1 7,275.0 NA 8.3 124.0 503.5 677.5

19.4 12,820.0 12.2 499.7 1,814.0 9,186.2 23,148.0 110.9 NA 4,099.9 6,134.2 12.6 3,000.0 8.9 13,299.0 NA 21.3 106.1 412.7 1,845.6

35.9 1,010.0 NA 2,931.2 561.0 15,570.8 47,353.5 NA NA 9,125.8 NA 187.6 NA 1,202.0 NA NA NA 16.9 215.6 7,054.7

9.4 1,326.0 NA 3,587.0 590.0 12,862.7 51,851.8 640.9 NA 7,062.4 NA 225.0 NA 261.2 NA NA NA 17.6 212.0 4,022.8

NA

Not available. All financial data are given in millions of US dollars. End of period exchange rates are used for assets. Annual averages are used for other financial data. Fiscal yearend is Dec. 31 unless otherwise noted. 1Includes NGL. 2Fiscal yearend is Sept. 30. 3Proved and probable. 4 Fiscal yearend is June 30. 5After royalty. 6Fiscal yearend is Mar. 31. 7Estimate. 8Turnover

52

Oil & Gas Journal | Sept. 7, 2015

GENERAL INTEREST

Worldwide oil production –––––––––– Million bbl –––––––––– 2014 2013

Worldwide natural gas production –––––––––––– Bcf ––––––––––––– 2014 2013

5

5

5

7

7

7

7

7

665.4 NA 1 11.5

404.1 607.0 7 243.5 NA 7 487.0 NA 693.9

7

7

696.8 NA 1 10.3

417.5 640.9 7 244.6 NA 7 450.2 NA 697.3

7

7

2,591.5 NA 64.0

5

2,760.0 7 48.0 1,260.0 NA 7 300.0

7

NA 840.0

7

Worldwide oil reserves –––––––––––– Million bbl ––––––––––– 2014 2013

2,576.9 NA 64.5

135

2,760.0 7 48.0 1,260.0 NA 7 300.0

7

NA 840.0

7

9,694.0 NA 13 144.9

135

12,200.0 7 9,011.0 7 4,400.0 NA 7 48,363.0

7

7

7 0.7 37,070.0

7

Worldwide natural gas reserves ––––––––––– Bcf –––––––––––– 2014 2013 5

10,243.0 NA 13 141.9

12,200.0 7 9,060.0 7 4,400.0 NA 7 48,470.0 7 0.7 37,140.0

5

32,496.0 NA 571.8

7

7

7

7

7

159,054.0 7 9,711.0 7 77,200.0 NA 7 53,183.0 7 51.0 180,490.0

34,187.0 NA 678.4

7

159,054.0 7 9,711.0 7 77,200.0 NA 7 54,701.0

7

7 51.0 180,737.0

7

1,014.0 7 18.2 7 42.1 7 1,022.0 7 1,204.1 NA 7 1,018.0 7 346.0 7 260.2 3,540.5

928.4 7 15.4 7 42.1 7 1,095.0 7 1,177.4 NA 7 935.1 7 346.7 7 265.4 3,431.0

NA 384.0 NA 5,580.0 7 465.0 NA 7 511.2 7 991.3 7,215.8 3,000.0

NA 363.3 NA 5,580.0 7 336.0 NA 7 336.0 7 1,128.0 4,200.0 3,000.0

92,200.0 7 124.6 7 4,000.0 7 157,800.0 7 144,211.0 7 13.9 7 101,500.0 7 5,151.0 7 25,244.0 265,789.0

92,200.0 7 124.6 7 4,000.0 7 157,300.0 7 140,300.0 7 11.5 7 101,500.0 7 5,500.0 7 25,240.0 265,850.0

200,000.0 7 3,250.0 7 3,785.0 7 1,201,382.0 7 111,522.0 7,027.0 7 63,000.0 7 24,910.0 7 871,585.0 293,707.0

200,000.0 7 3,250.0 7 3,785.0 7 1,192,907.0 7 111,522.0 10,064.0 7 63,000.0 7 30,000.0 7 890,000.0 290,811.0

1.1 84.1 105.0 5 9.6 8.5 340.2 945.5 NA NA NA NA 9.0 87.2 5 8.0 NA 7 7.3 NA NA 4.7 NA

1.3 72.5 61.6 5 10.3 8.9 324.8 932.9 NA NA NA NA 9.5 73.6 5 4.9 NA 7 7.3 NA NA NA NA

18.0 839.3 182.7 NA 450.2 434.3 3,028.8 NA NA NA NA 65.1 588.7 5 54.1 1,405.0 NA NA NA 311.7 NA

16.1 874.3 167.1 NA 413.0 407.7 2,801.9 NA NA NA NA 58.2 557.7 5 74.9 1,152.0 NA NA NA NA NA

13.3 610.5 1.5 35 114.0 49.1 5 3,039.8 10,593.0 NA NA NA NA 95.2 129.4 54.0 NA 7 50.0 3 2.8 NA 40.2 NA

15.6 635.4 3.5 35 133.0 61.4 5 3,060.4 10,820.0 NA NA NA NA 84.5 102.0 46.0 NA 7 50.0 3 2.6 NA NA NA

3 273.6 9,561.5 1.8 NA 3,723.7 5 6,730.8 71,098.0 NA NA NA NA 711.8 973.2 778.4 NA 7 10,000.0 3 35.0 NA 2,250.4 NA

3 329.6 10,129.5 4.2 NA 5,708.0 5 6,323.3 69,323.0 NA NA NA NA 687.6 783.7 812.0 NA 7 10,000.0 3 39.0 NA NA NA

1

1

Oil & Gas Journal | Sept. 7, 2015

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GENERAL INTEREST

THE OGJ150 COMPANY INDEX Rank by total assets Company 91 117 94 — 4

6 124 74 120 132 60 92 133 64 29 — 36 21 77 49 51 8 2 27 70 58 22 3 30 78 16 114 127 101 — 125 20 7 46 104 —

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Abraxas Petroleum Corp. Adams Resources & Energy Inc. American Eagle Energy Corp. American Natural Energy Corp. Anadarko Petroleum Corp. Apache Corp. Apache Offshore Investment Partnership Approach Resources Inc. Armada Oil Inc. Avalon Oil & Gas Inc.

80 Headquarters city San Antonio Houston Littleton, Colo. Tulsa The Woodlands, Tex. Houston

Houston Ft. Worth Dallas Minneapolis, Minn. Bill Barrett Corp. Denver Black Hills Corp. Rapid City, SD Blacksands Petroleum Inc. Houston Bonanza Creek Energy Inc. Denver BreitBurn Energy Partners LP Los Angeles Breitling Energy Corp. Dallas Cabot Oil & Gas Corp. Houston California Resources Corp. Los Angeles Callon Petroleum Co. Natchez, Miss. Carrizo Oil & Gas Inc. Houston Chaparral Energy Inc. Oklahoma City Chesapeake Energy Corp. Oklahoma City Chevron Corp. San Ramon, Calif. Cimarex Energy Co. Denver Clayton Williams Energy Inc. Midland, Tex. Comstock Resources Inc. Frisco, Tex. Concho Resources Inc. Midland, Tex. ConocoPhillips Houston Consol Energy Inc. Canonsburg, Pa. Contango Oil & Gas Co. Houston Continental Resources Inc. Oklahoma City Cross Border Resources Corp. Dallas Cross Timbers Royalty Trust Ft. Worth Cubic Energy Inc. Dallas Daleco Resources Corp. West Chester, Pa. Daybreak Oil & Gas Inc. Spokane, Wash. Denbury Resources Inc. Plano, Tex. Devon Energy Corp. Oklahoma City Diamondback Energy Inc. Midland, Tex. Dorchester Minerals LP Dallas Dune Energy Inc. Houston

88 66 85 34 106 11 28 100 59 108 55 1 67 119 93 13 105 82 — 107 84 44 33 9 121 — 118 37 42 65 129 116 15 111 68 10 72 50 38 122 87 53 83 14 90 23 12 63 35

Eagle Rock Energy Partners LP Earthstone Energy Inc.

Houston The Woodlands, Tex. Eclipse Resources Corp. State College, Pa. Emerald Oil Inc. Denver Energen Corp. Birmingham, Ala. EnerJex Resources Inc. San Antonio EOG Resources Inc. Houston EQT Production Pittsburgh Escalera Resources Co. Denver EV Energy Partners LP Houston Evolution Petroleum Corp. Houston Exco Resources Inc. Dallas ExxonMobil Corp. Irving, Tex. Fidelity Exploration & Production Co. Bismarck, ND FieldPoint Petroleum Corp. Austin Forestar Group Inc. Austin Freeport-McMoRan Inc. Phoenix FX Energy Inc. Salt Lake City Gastar Exploration Inc. Houston GeoPetro Resources Co. San Francisco Glori Energy Inc. Houston Goodrich Petroleum Corp. Houston Gulfport Energy Corp. Oklahoma City Halcon Resources Corp. Houston Hess Corp. New York Houston American Energy Corp. Houston Humble Energy Inc. Paron, Ark. Hydrocarb Energy Corp. Houston Kinder Morgan CO2 Co. LP Lakewood, Colo. Laredo Petroleum Inc. Tulsa Legacy Reserves LP Midland, Tex. Legand Oil & Gas Ltd. Alpharetta, Ga. Lilis Energy Inc. Denver Linn Energy LLC Houston Lucas Energy Inc. Houston Magnum Hunter Resources Corp. Houston Marathon Oil Corp. Houston Matador Resources Co. Dallas Memorial Production Partners LP Houston Memorial Resources Development Corp. Houston Mexco Energy Corp. Midland, Tex. Mid-Con Energy Partners LP Dallas Midstates Petroleum Co. Inc. Tulsa Miller Energy Resources Inc. Knoxville, Tenn. Murphy Oil Corp. El Dorado, Ark. New Source Energy Partners LP Oklahoma City Newfield Exploration Co. The Woodlands, Tex. Noble Energy Inc. Houston Northern Oil & Gas Inc. Wayzata, Minn. Oasis Petroleum Inc. Houston

5 96 56 115 61 130 — 81 17 131 97 95 24 75 26 110 71 73 98 40 123 57 54 128 126

Occidental Petroleum Corp. Panhandle Oil & Gas Inc. PDC Energy Pegasi Energy Resources Corp. Penn Virginia Corp. Permian Basin Royalty Trust Petron Energy II Inc. PetroQuest Energy Inc. Pioneer Natural Resources Co. Pioneer Oil & Gas PostRock Energy Services Corp. PrimeEnergy Corp. QEP Resources Inc. Quicksilver Resources Inc. Range Resources Corp. Reserve Petroleum Co. Resolute Energy Corp. Rex Energy Corp.

47 31 45

Ring Energy Inc. Rosetta Resources Inc. Royale Energy Inc. RSP Permian Inc. Sabine Oil & Gas Sabine Royalty Trust San Juan Basin Royalty Trust Sanchez Energy Corp. Sandridge Energy Inc. Seneca Resources Corp.

32 18 113 48 62 89 112

SM Energy Inc. Southwestern Energy Co. Spindletop Oil & Gas Co. Stone Energy Corp. Swift Energy Co. Synergy Resources Corp. Tengasco Inc.

134 — 69 41 39 135

TN-K Energy Group Inc. Treaty Energy Corp. Triangle Petroleum Corp. Ultra Petroleum Unit Corp. United American Petroleum Corp. US Energy Corp. Vanguard Natural Resources LLC Venoco Inc. VOC Energy Trust W&T Offshore Inc. Warren Resources Inc. Wexpro Whiting Petroleum Corp. WPX Energy Inc. Yuma Energy Inc. Zaza Energy Corp.

102 43 86 103 52 79 76 19 25 99 109

Los Angeles Oklahoma City Denver Tyler, Tex. Radnor, Pa. Dallas Dallas Lafayette, La. Irving, Tex. South Jordan, Utah Oklahoma City Houston Denver Ft. Worth Ft. Worth Oklahoma City Denver State College, Pa. Midland, Tex. Houston El Cajon, Calif. Dallas Houston Dallas Ft. Worth Houston Oklahoma City Williamsville, NY Denver Spring, Tex. Dallas Lafayette, La. Houston Platteville, Colo. Greenwood Village, Colo. Crossville, Tenn. New Orleans Denver Houston Tulsa Austin Riverton, Wyo. Houston Denver Austin Houston New York Salt Lake City Denver Tulsa Houston Houston

Oil & Gas Journal | Sept. 7, 2015

OPERATIONOFFSHORE.COM #operationoffshore

T.D. WILLIAMSON / MCG PRODUCTIONS PRESENTìOPERATION OFFSHOREî m MARK SIM, TODD BEADLE, GORDON BLAIR, ALEXEY TUGANOV, ANTON KOVALENKO, LAURENT FABRY, TAMMY WISENBAKER, KEVIN MCNAUGHTON, PAOLA CORRALES, STEVE APPLETON, ALEXANDRE PETRAGLIA, /ROLF GUNNAR LIE DEVELOPMENT TECHNICAL BASED ON DIRECTORS LARRY RYAN, GEORGE LIM DIRECTORS JEFF WILSON, GARY ANDERSON x MIKE BENJAMIN, CHAD FLETCHER THE STORY RISK ON THE PLATFORM © Copyright 2015 T.D. Williamson, Inc

GENERAL INTEREST cont’d from p. 48

EnCana Corp. reported 2014 net earnings of $3.39 billion compared with year-ago earnings of Chevron Corp. would be 16th in of world$236 million. Results for 2014 included gains on diwide liquids production. vestitures of about $3.4 billion (before tax). In Latin America, Petroleo Brasileiro SA posted a Financial results loss of $7.5 billion for 2014 that was caused by imSPECIAL Collectively, reported earnings of the OGJ100 compairment charges, down from earnings of $10.83 REPORT panies declined 17.1% in 2014 from a year earlier. billion a year earlier. Petroleos Mexicanos reported Total reported revenues dipped 2.6%. a loss of $36 billion last year following a loss of $13 For the 2014 full year, BP’s profit was $4 billion, down billion posted in 2013 because of lower prices for oil exports from $23.75 billion a year ago which included a $12.5 biland the devalued peso. lion gain relating to the disposal of their interest in TNK-BP. PetroChina’s 2014 earnings declined 16.5% to $19.32 billion, primarily attributable to the sharp drop in oil prices.

White House keeps oil, gas in Alaska picture amid climate emphasis Nick Snow Washington Editor

The White House quietly refused to rule out oil and gas development in Alaska as US President Barack Obama, Secretary of State John F. Kerry, and other top officials prepared to participate in a 2-day Arctic issues conference Aug. 31 and Sept. 1 in Anchorage with other dignitaries from as many as 20 other countries. Obama continued to emphasize climate change impacts on Alaska in his Aug. 29 weekly address leading up to his visit. “This is all real. This is happening to our fellow Americans right now,” he declared. “In fact, Alaska’s governor recently told me that four villages are in ‘imminent danger’ and have to be relocated.” The US is leading the way in making a necessary transition from “dirty energy sources” to solar, wind, and other alternatives to address climate change impacts, the president said. But the US economy still has to rely on oil and gas as it accelerates the transition, he maintained. “As long as that’s the case, I believe we should rely more on domestic production than on foreign imports, and we should demand the highest safety standards in the industry—our own,” Obama said. He acknowledged some Americans’ concerns over developing offshore oil resources in environmentally sensitive waters, and specifically mentioned approvals by the US Bureau of Safety and Environmental Enforcement and other federal agencies for Shell Offshore Co. to drill on Chukchi Sea leases it has held since 2008 (OGJ Online, July 23, 2015). “We don’t rubber-stamp permits,” Obama said. “We made it clear that Shell has to meet our high standards in how [it

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conducts its] operations—and it’s a testament to how rigorous we’ve applied those standards that Shell has delayed and limited its exploration off Alaska while trying to meet them.”

Safety is top priority Obama said, “The bottom line is, safety has been and will continue to be my istration’s top priority when it comes to oil and gas exploration off America’s precious coasts—even as we push our economy and the world to ultimately transition off of fossil fuels.” A senior US Department of State official made similar points in an Aug. 28 teleconference with reporters. “There are people who are protesting against the drilling; there are people that are upset and believe that the president has gone too far in of opening up the Arctic,” he said. “There are an equal number of people who believe that it has not been opened up enough. “I’m not talking about the oil companies; I’m talking about the citizens of Alaska, and in particular, Alaskan natives. The people of Alaska want sustainable development that also protects the environment,” the official said. “But at the same time, in a very pragmatic approach, we understand that we’re going to need the petroleum products at least for the foreseeable future,” he said. “Certain segments of the Chukchi and Beaufort Seas have been opened up for leases, and the companies that are up there have been doing things under a legal process and with strict review by the Department of the Interior and the US Coast Guard, and that is proceeding.” The istration has taken a balanced approach, “and

Oil & Gas Journal | Sept. 7, 2015

GENERAL INTEREST the fact that we probably have parties on both sides of the issue that are not completely satisfied is probably an indicator that we’re on a fairly safe course here,” the senior DOS official said. Leaders from the Arctic Slope Regional Corp., Alaska’s largest Native-owned business, placed an open letter welcoming Obama to the state in news outlets there on Aug. 31. It urged him to strike a balance between responsible energy development and environmental stewardship within the Arctic. “As stewards of our Arctic homelands, we have a unique and very important interest in ensuring that any development activities in the Arctic are carried out in a safe and responsible manner,” ASRC Chief Executive Rex Rock Sr. and Chairman Crawford Patkotak said in the letter. “We are also no strangers to oil and gas development. The industry has operated safely in our backyard for over four decades producing more than 15 billion bbl of oil from the North Slope in that time. With those barrels come jobs, security, and opportunity.”

Ralph R. Erickson, US District Court for North Dakota’s chief judge, issued a preliminary injunction on Aug. 27 delaying scheduled implementation of the rule a day later in Alaska, Arizona, Arkansas, Colorado, Idaho, Missouri, Montana, Nebraska, Nevada, New Mexico, North Dakota, South Dakota, and Wyoming. “The states here have demonstrated that they will face irreparable harm in the absence of an injunction,” Erickson wrote. “It is within the purview of the traditional powers of the states to maintain their ‘traditional and primary power over land and water use.’ Once the rule takes effect, the states will lose their sovereignty over intrastate waters that will then be subject to the scope of the Clean Water Act.” But Judge Irene M. Keeley of US District Court for Northern West Virginia dismissed a challenge on Aug. 26 by Clairsville, Ohio, coal producer Murray Energy Corp. to the agencies’ argument that the federal district court in West Virginia did not have jurisdiction. Keeley’s ruling said jurisdiction lies within the Sixth Circuit US Court of Appeals in Cincinnati, where Murray also sued to overturn the rule on July 1.

WOTUS rule implementation uncertain after conflicting court decisions

‘Regulatory overreach’

Nick Snow Washington Editor

The US Environmental Protection Agency and Army Corps of Engineers began to implement their controversial Waters of the United States (WOTUS) rule in all but 13 states on Aug. 28 after federal district court judges in North Dakota and West Virginia issued conflicting orders. “Under the order issued by the District Court of North Dakota, the parties that obtained the preliminary injunction are not subject to the new rule, and instead continue to be subject to the prior regulation,” EPA said in a statement e-mailed to OGJ. “In light of the order, EPA and the Army Corps of Engineers will continue to implement the prior regulation.” EPA said in all other respects, the rule would become effective on Aug. 28. “The agencies are evaluating these orders and considering next steps in the litigation,” EPA said. States and several trade associations immediately protested the rule establishing federal control over domestic bodies of water after EPA and the Corps tly issued it in late May (OGJ Online, May 28, 2015). Several sued to block it.

Oil & Gas Journal | Sept. 7, 2015

Federal lawmakers and groups opposing the rule focused on the North Dakota court decision’s impact. “The US District Court for North Dakota agreed with 13 states, who believe the EPA’s [WOTUS] rule to be an unconstitutional regulatory overreach exceeding the authority Congress gave it to create rules for the Clean Water Act,” US Senate Energy and Natural Resources Committee member John Hoeven (R-ND) said on Aug. 28. “If implemented, it will have real impacts not only on farmers and ranchers, but also on small businesses across North Dakota and the nation,” he said. “That’s why we worked to a provision in the Senate Interior Appropriations bill in June that prohibits the EPA from implementing the regulation.” US House Oversight and Government Reform Committee Chairman Jason Chaffetz (R-Utah) said, “Judge Erickson’s ruling is a significant and rightful win for states’ rights. I am pleased that the arbitrary and subjective guidelines imposed by EPA’s WOTUS rule will no longer go into effect today. This ruling is an important check on an istration that continues to overreach in its authority. Such flawed policy should never see the light of day.” National Association of Manufacturers Senior Vice-Pres. and General Counsel Linda Kelly said, “Manufacturers are responsible stewards of our environment, and protecting our nation’s waters will always be a priority, but we very much agree with the US District Court in North Dakota that the regulation from [EPA and the Corps] was developed through ‘a process that is inexplicable, arbitrary, and devoid of a reasoned process.’”

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GENERAL INTEREST

Unconventional production raises unexpected tax questions, forum told Nick Snow Washington Editor

Unconventional oil and gas resource development has raised unexpected taxation questions that potentially could strain federal, state, and local government relationships, a public policy scholar at the Woodrow Wilson Center for International Scholars said. State governments in particular are considering whether severance taxes need provisions to set money aside strictly to help counties and communities cope with development impacts, or to place a portion in a state-istered investment trust that can’t be raided if plunging commodity prices reduce revenue, said Barry Rabe, who also is a professor at the University of Michigan’s Gerald R. Ford School for Public Policy. “There are several triggers built deep into tax codes,” he said in a Sept. 1 presentation hosted by the Wilson Center’s Canada Institute. “It’s an unexplored area, but I wouldn’t be surprised to see more of this in the next stage of tax reforms—possibly even reverse triggers to reduce a tax if prices fall very far.” Severance taxes have a history dating back to before the Civil War, when Texas enacted its first such levy to try and capture revenue during an economic boom for broader public good, Rabe said. They appeal more to Republicans than Democrats because they usually export the taxation impact out of state and away from voters, he said. “States which tend to be Republican tend to have the highest severance taxes, which often are a substantial portion of their general revenue,” Rabe said. “Texas Gov. Rick Perry has not had to worry much about education funding because of the severance tax’s substantial contribution, and Ohio Gov. John R. Kasich said earlier this year that his state’s tax needs to be raised because the oil and gas industry there is getting off too easily,” he noted.

When states have trouble Since 2008, states where there previously was little if any oil and gas production had to quickly consider ways to keep new development from tight shales enabled by hydraulic fracturing and horizontal drilling a blessing instead of a curse, Rabe said. States that have not established trust funds tend to get into trouble when a severance tax represents 10-15% of total revenue and commodity prices plunge, he said. States’ energy trust funds tend to work better than their

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counterparts overseas because they have to be more transparent and able, Rabe said. “States like North Dakota and Colorado started setting funds aside to hire more staff and started returning money to communities,” he said. “When you have a severance tax in a particular region, the state vs. local jurisdiction question emerges. This area hasn’t been looked at much, but it can be every bit as contentious as state vs. federal powers.” State governments work hard to remain the primary resource tax collectors from production on nonfederal acreage, resisting not just federal efforts to impose levies but also local initiatives aimed at regulating activity, Rabe said. When then-Pennsylvania Gov. Tom Corbett (R) signed a modest community energy development impact fee into law in early 2012, it included specific conditions communities needed to satisfy before receiving the money, he said. “That first year, seven such communities didn’t receive impact funds,” he said. Corbett also lost his 2014 reelection bid to Democrat Tom Wolf, whose campaign platform included raising the commonwealth’s oil and gas severance tax to help fund education. More states also are looking hard at which approaches have, or have not, worked elsewhere, he said. “So much of Alaska’s economy is based on citizens receiving their December oil and gas production dividends,” Rabe said. “Those can’t be touched, so the state’s options are severely limited.

Revenue review delayed “So much money has come into Alberta’s coffers from oil sands production and has gone right out again that there’s little left in its budget,” he said. “That’s why [Premier Rachel Notley] has begun to talk about establishing a trust fund, while the oil revenue review she launched has been delayed.” He noted that Norway’s trust fund, which many state and national governments consider the most successful, even mentions pensions, which implies providing assistance to senior citizens eventually. “In the US, that would be like partially funding Social Security with oil and gas revenue— which isn’t going to happen anytime soon,” he said. Rabe said states also are seeing conflicts-of-interest develop within agencies that both collect severance taxes and promote oil and gas development. US Interior Sec. Ken Salazar identified such a conflict within the US Minerals Management Service during US President Barack Obama’s first term, and started restructuring the agency by spinning its revenue collection responsibilities off into a new energy royalties and revenue department elsewhere in the department. “Almost with the ing of each month, we see a new consequence from shale resource development which was not anticipated,” Rabe said. “Oil trains are a recent dramatic transportation example, with issues that still need to be worked out.” He also suggested that federal interest in reducing flaring

Oil & Gas Journal | Sept. 7, 2015

GENERAL INTEREST of gas associated with oil production and controlling methane emissions overall potentially could create jurisdictional creep, under which states that previously were primarily responsible will have to demonstrate to Washington that they are making sufficient progress. Tax proposals that are designed to raise money for specific purposes relatively painlessly still attract more than proposals which contain taxes aimed at influencing consumers’ behavior, Rabe said.

a mistake. Margaret Brown, an attorney with the Natural Resources Defense Council, which tried with six similar groups to block the settlement, called it a multibillion dollar gift to ExxonMobil from Gov. Chris Christie (R) and his istration. “After a decade-long court battle, this spring [it] abruptly and inexplicably gave the oil giant a more than 98% discount on the damages due for its destruction,” she said.

Additional payments

Court approves ExxonMobil’s environmental settlement with New Jersey Nick Snow Washington Editor

A New Jersey Superior Court judge approved a $225-million environmental settlement between the state and ExxonMobil Corp. to resolve environmental damages over several decades from refineries in Linden and Bayonne, and retail outlets and other facilities across the state. Judge Michael J. Hogan said in his Aug. 25 settlement opinion that the settlement was fair, reasonable, in the public interest, and consistent with goals in the state’s Spill Compensation and Controls Act. “The record shows that the negotiations between two highly sophisticated parties with sharply conflicting interests were full of adversarial vigor,” he observed in his 82-page opinion. The agreement is the single largest environmental settlement with a corporate defendant in state history, Acting New Jersey Atty. Gen. John J. Hoffman and Department of Environmental Protection (NJDEP) Commissioner Bob Martin tly said. They indicated that it would end, following resolution of any appeals, more than a decade of aggressive and costly litigation and negotiations by the state spanning multiple istrations. But a member of New Jersey’s congressional delegation strongly criticized the settlement of the state’s $8.9-billion environmental lawsuit against ExxonMobil. “New Jerseyans deserved nothing less than to be fairly compensated for the degradation of our land and resources,” said US Rep. Frank Pallone Jr. (D), the House Energy and Commerce Committee’s ranking minority member. “However, the settlement and the ruling, along with ExxonMobil’s attempts—ed by the Christie istration—to shirk responsibility, are an insult to New Jersey.” Environmental organizations also felt the agreement was

Oil & Gas Journal | Sept. 7, 2015

In their Aug. 25 announcement, Hoffman and Martin said the $225-million settlement also represents the second largest natural resources payout from a single company in US history. It is separate and in addition to the hundreds of millions of dollars ExxonMobil has spent and its obligation to further spend for complete remediation of the contaminated Bayonne and Linden refinery sites, pursuant to istrative consent orders previously entered into between the company and NJDEP, they emphasized. While the settlement resolves ExxonMobil’s alleged liability for discharges from the Linden and Bayonne refineries, it preserves the state’s claims against the company with respect to natural resource damages to the Arthur Kill, Newark Bay, and any other surface waters affected by ExxonMobil’s operations, the announcement said. It said the settlement also preserves New Jersey’s claims against ExxonMobil relating to the Lail facility, which requires further investigation as to the impact of ExxonMobil’s operations on natural resources. The settlement also addresses some pending and potential NRD claims involving a company refinery operation in Paulsboro, it added. The two state officials said the agreement resolves relatively minor natural resources damage claims concerning 16 other facilities and ExxonMobil’s retail outlets, but preserves all of New Jersey’s NRD claims relating to the discharge of methyl tertiary butyl ether at those outlets. Refiners used MTBE as a replacement for lead as a gasoline octane enhancer in the 1980s before turning to ethanol. Martin said NJDEP will continue to vigorously litigate those claims. In his opinion, Hogan also noted that New Jersey retains its right to refile surface water claims and pursue MTBE pollution which ExxonMobil allegedly caused. “Although far smaller than the estimated $8.9 billion in damages, Exxon’s payment represents a reasonable compromise given the substantial litigation risks [NJDEP] faced at trial and would face on appeal,” the judge said. In response to OGJ’s request for a comment, an ExxonMobil spokesman said the company welcomes the settlement, which it believes has brought this case to a fair and reasonable conclusion. “Both parties will now have the benefit of the certainty and finality that comes from this settlement,” he said.

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GENERAL INTEREST

Gas discovery offshore Egypt rivals Mediterranean giants Tayvis Dunnahoe Exploration Editor

Eni SPA expects accelerated development of what it describes as a “supergiant gas discovery” at its deepwater Zohr prospect offshore Egypt. The company will immediately appraise its discovery, which it says might hold 30 tcf of lean gas in place in an area covering 100 sq km. The Zohr 1X NFW discovery well was drilled to a total depth of 13,553 ft in 4,757 ft of water on Egypt’s Shorouk Block 9. The well hit a 2,067-ft hydrocarbon column in a carbonate sequence of Miocene age with 400 m of net pay, Eni said. The company has future plans to target a deeper Cretaceous upside with a dedicated well. Zohr is the largest gas discovery made in Egypt and the Mediterranean Sea, and if early estimates hold true, could become one of the world’s largest natural gas finds, the company said. As Eni begins to fast track development for the Zohr discovery, the Mediterranean region looks on. Egypt’s Sharouk Block is on the country’s offshore boundary, and is in close proximity to Cyprus’ Block 12 contain-

ing the Aphrodite discovery and Isreal’s Leviathan discovery. Mediterranean development has been gridlocked for quite some time, and this latest discovery stands to alter the flow of gas from other recent major discoveries (OGJ Online, Apr. 7, 2014). Isreal’s National Infrastructure, Energy, and Water Minister Yuval Steinitz told The Jerusalem Post: “Following the reports, the discovery of the huge gas field in Egypt is a painful reminder that while the state of Isreal is standing still and taking its time with the final approval of the gas outline, and delaying further exploration, the world is changing before our very eyes, also with ramifications on export possibilities.” While Isreal has made progress, this latest discovery may take away Egypt as an export client (OGJ Online, Apr. 6, 2015). Analysts with Raymond James & Associates Inc. noted that development of the Zohr discovery is not realistic before 2020, but the long-term opportunity is ive of greater energy independence for Egypt. The discovery is less encouraging for plans to supply Egypt from fields offshore Israel and Cyprus. Eni, through its subsidiary IEOC Production BV, holds a 100% working interest in the Sharouk Block and is operator.

EIA lowers US oil output estimates amid prolonged oil-price slump US crude oil production in June totaled 9.3 million b/d, a decline of 100,000 b/d from the revised May figure, according to the US Energy Information istration’s Petroleum Supply Monthly (PSM) released Aug. 31. The US hit a peak of 9.61 million b/d in April. EIA revised downward production estimates released in the PSM for January through May by 40,000 b/d to 130,000 b/d. The largest revisions in volume include decreases of oil production in Texas, ranging 100,000-150,000 b/d; and increases in the federal Gulf of Mexico, ranging 10,000-50,000 b/d. The revisions reflect a slowing of production as crude-oil prices have plunged over the past year. US crude production for the first 6 months of 2015 averaged 9.4 million b/d. While the oil-directed rig count has risen over the past 6 weeks, Raymond James & Associates Inc. last week revised downward its rig count projections for the next few years (OGJ Online, Aug. 28, 2015). Beginning with the June PSM data, EIA is providing estimates for crude production, including lease condensate, based on data from the EIA-914 survey. The expanded survey collects monthly oil production data from a sample of operators of oil and natural gas wells in 15 individual states and the federal gulf. Production from all remaining states and the federal Pacific is reported collectively in an “other states” category.

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EIA says the survey-based approach improves estimates by representing more than 90% of oil production in the US. Later this year EIA will report monthly crude production by API gravity category for the individually surveyed EIA-914 states.

June movement varies During June, Texas oil output averaged 3.46 million b/d, down from 3.53 million b/d in May but still up from 3.15 million b/d in June 2014. The state peaked at 3.64 million b/d in March. North Dakota, meanwhile, reported output of 1.2 million b/d, up slightly from 1.19 million b/d in May and more noticeably from 1.09 million b/d in June 2014. Its recent peak was 1.23 million b/d in December 2014. In its Drilling Productivity Report (DPR) released earlier in August, EIA projected that crude production in September from seven major US shale plays will decline 93,000 b/d to 5.27 million b/d (OGJ Online, Aug. 10, 2015). A bulk of recent shale oil declines have come in the Eagle Ford and Bakken shale plays. According to the PSM, production from federal waters in the Gulf of Mexico during June reached 1.45 million b/d, up slightly from 1.44 million b/d in May and more noticeably up from 1.41 million b/d in June 2014. EIA earlier in the year forecast crude output would reach 1.52 million b/d in 2015 and 1.61 million b/d in 2016—or respectively 16% and 17% of total US

Oil & Gas Journal | Sept. 7, 2015

GENERAL INTEREST crude production during each year (OGJ Online, Mar. 3, 2015). US gas production fell in June to 89.5 bcfd from 89.6 bcfd in May, but represented an increase from 86.6 bcfd in June 2014. Output in Texas increased during the month to 24.92 bcfd from just fewer than 24 bcfd in May and 23.52 bcfd in June 2014. Pennsylvania monthly production fell to 12.35 bcfd in June from 12.46 bcfd in May. Ohio and Alaska reported the most significant monthly changes of the major gas-producing states. Ohio’s 2.85 bcfd in June represented a 12.6% increase from 2.53 bcfd in May, while Alaska’s 7.45 bcfd in June represented an 11.6% decrease from 8.43 bcfd in May.

Kuwait lets contracts for grassroots refinery Robert Brelsford Downstream Technology Editor

Kuwait National Petroleum Co. (KNPC) has let a series of contracts to groups of oil and gas service providers to build the planned 615,000-b/d Al-Zour refinery complex in southern Kuwait as part of the company’s Clean Fuels Project (CFP) (OGJ Online, July 1, 2011). KNPC officially awarded four contract packages worth an estimated $11.5 billion for the grassroots refinery on July 28, with a fifth contract package due to be awarded in the coming weeks, the state-run company confirmed in a series of posts to its social media s. KNPC let a $4.1 billion lump-sum turnkey contract to a consortium of Spain’s Tecnicas Reunidas SA, China’s Sinopec Engineering (Group) Co. Ltd., and Hanwha Engineering & Construction Corp. of South Korea to provide engineering, procurement, construction, and commissioning for main processing units at the plant, Tecnicas Reunidas said. The consortium’s scope of work under the contract, which is to last 45 months, includes delivery of services for the following: • 3 crude distillation units, each with a processing capacity of 210,000 b/d. • 3 atmospheric residue desulfurization units, each with a processing capacity of 110,000 b/d. • 3 diesel hydrotreating units, each with a processing capacity of 62,000 b/d. • 2 naphtha hyrdrotreating units, each with a processing capacity of 18,200 b/d. • 2 kerosene hydrotreating units, each with a processing capacity of 53,000 b/d. • An 8,500-b/d saturated gas unit. • A heavy oil cooling unit. KNPC let two additional contract packages with a combined value of about $5.75 billion to a t venture of Fluor

Oil & Gas Journal | Sept. 7, 2015

Corp., Daewoo Engineering & Construction Co., and Hyundai Heavy Industries Co. for delivery of engineering, procurement, and construction on associated units and infrastructure necessary for the project, Daewoo said. This latest contract to the Daewoo-Fluor-Hyundai consortium follows KNPC’s previous award of a $3.4-billion contract to the venture to design, construct, and commission a second phase of the Mina Abdullah refinery in southern Kuwait as part of the CFP (OGJ Online, Feb. 19, 2014). KNPC let a fourth contract package worth $1.5 billion to a consortium of South Korea’s Hyundai Engineering Co. Ltd., SK Engineering & Construction, and Italy’s Saipem SPA to provide EPC services on an associated marine export terminal at the refinery, KNPC said. Since announcing the greenfield refinery, KNPC has let several contracts for the Al-Zour plant (OGJ Online, Mar. 13, 2014; Dec. 3, 2013; Dec. 4, 2012). The Al-Zour refinery, which will become the largest in the Middle East upon completion, has a current overall investment cost of about $13 billion, Tecnicas Reunidas reported. Under the CFP, KNPC plans to integrate and upgrade the 270,000-b/d Mina Abdullah and 466,000-b/d Mina Al Ahmadi refineries and ultimately close the 200,000-b/d refinery at Shuaiba once construction is completed on the Al Zour plant (OGJ Online, Mar. 5, 2015). The newly integrated refineries will operate as a merchant complex with total capacity of about 800,000 b/d.

EIA: Benefits of lifting US crude export ban most evident if output rises A study released Sept. 1 by the US Energy Information istration was apparent cause for celebration for several oil and gas industry groups, which took its findings as confirmation that lifting restrictions on US crude oil exports would be a net positive for the industry as well as consumers. EIA developed several analyses that examine the implications of removing the restrictions for the price of US and global marker crude streams, gasoline prices, crude production, refining activity, and trade in crude and petroleum products. The study, Effects of Removing Restrictions on US Crude Oil Exports, was conducted in response to requests from US Sen. and current Senate Energy and Natural Resources Committee Chairman Lisa Murkowski (R-Alas.) and former chairman and Sen. Mary L. Landrieu (D-La.), (OGJ Online, Apr. 14, 2014), as well as current committee Ronald L. Wyden (D-Ore.) and Maria E. Cantwell (D-Wash.). Murkowski previously included language ending the 1970s-era ban in her Offshore Production and National

61

GENERAL INTEREST Security (OPENS) Act, which was approved by the energy committee at the end of July (OGJ Online, July 24, 2015). “Multiple studies have shown that lifting the export ban will improve our economic and energy security without harming American consumers,” Murkowski remarked in a statement welcoming the study. “It’s time to leave the old scarcity mindset behind and seize the opportunities provided by America’s energy resurgence.”

Higher output, bigger impact The report applies EIA’s energy models to directly compare cases over the next decade with and without the removal of current restrictions on crude exports. Four baseline cases using EIA’s National Energy Modeling System are considered to reflect a range of outlooks for resources and technology as well as prices, which are key drivers of crude production. For this analysis, EIA generally assumes that all streams with 50° gravity oil and above would be eligible for processing and export under recent BIS guidance. The analysis finds no difference between projections with and without current export restrictions in two analysis cases in which projected production with current export restrictions remains below 10.6 million b/d over the next decade. However, in two other analysis cases where production in 2025 ranges 11.7-13.6 million b/d, projections without export restrictions show increased production, higher crude exports, reduced product exports, and slightly lower gasoline prices to US consumers compared with parallel cases that maintain current export restrictions. The variation in projected production across the four baseline cases used in the report reflect differences in the characterization of oil resources and technology as well as future crude prices. EIA notes there is a considerable spread in projected production across these cases. The removal of crude export restrictions does not lead to additional production in the reference and low oil price cases, where production remains at or below 10.6 million b/d through 2025. However, the removal of crude export restrictions leads to additional production between 400,000-500,000 b/d by 2025 in the high oil and gas resource (HOGR) and HOGRlow price (HOGR-LP) cases that have significantly higher baseline production based on more optimistic resource and technology assumptions.

Gas prices could fall, not rise Petroleum product prices in the US, including gasoline prices, would be either unchanged or slightly reduced by the removal of current restrictions on crude exports. EIA notes that petroleum product prices throughout the US have a much stronger relationship to North Sea Brent prices than to West Texas Intermediate prices. In the HOGR and HOGR-LP high-production cases, the elimination of current restrictions on crude exports narrows the BrentWTI spread by raising the WTI price. As producers respond to the higher WTI price with higher production, the global supply62

demand balance becomes looser unless increased production is fully offset by production cuts elsewhere. The looser balance implies lower Brent prices, which in turn result in slightly lower petroleum product prices for US consumers. Combined net exports of crude and petroleum products from the US are generally higher in cases with higher US crude production regardless of US crude export policies. However, crude export policies materially affect the mix between crude and product exports, particularly in the HOGR and HOGRLP cases, which have high levels of production. Crude exports tend to represent a larger share of combined crude and product exports in cases where crude exports are unrestricted. Also, in cases where the level of crude production increases with the removal of crude export restrictions, total combined crude and product exports are higher than in parallel cases with current crude export restrictions in place. Although unrestricted exports of US crude would either leave global crude prices unchanged or result in a small price reduction compared with parallel cases that maintain current restrictions on crude exports, other factors affecting global supply and demand will largely determine whether global crude prices remain close to their current level, as in EIA’s low oil price case, or rise along a path closer to the reference case trajectory. As noted by EIA, resource and technology outcomes as well as global price drivers will affect growth in US crude production whether or not current US crude export policies are maintained.

‘Win-win’ for US consumers “Today’s EIA report is a win-win for American energy consumers and energy producers,” said Barry Russell, president of the Independent Petroleum Association of America, in a statement released subsequent to the report. “By lifting the 4-decades-old ban on US crude oil exports, Americans would see an increase in American energy production, which would, in turn, grow our economy, create good-paying American jobs, and help lower gasoline prices for hardworking American families.” Russell last month urged further istrative action on US crude exports after the Obama istration approved a crude exchange between the US and Mexico (OGJ Online, Aug. 14, 2015). Following news of a secured agreement with Iran that would allow Iranian oil to get traded on the world market, Russell questioned why America wouldn’t allow its companies to do the same with their American-made surplus of crude. IPAA also voiced its in May for Murkowski’s and Heidi Heidi Heitkamp’s (D-ND) legislation seeking to lift the ban (OGJ Online, May 13, 2015). The American Petroleum Institute also noted that “consumers could save on fuel costs if policymakers act now to lift trade restrictions on US crude oil.” Margo Thorning, senior vice-president and chief economist for the American Council for Capital Formation took it a step further, stating, “It’s not only the increased economic growth and lower gas prices that we stand to lose by keeping this outdated energy policy in place, but our global credibilOil & Gas Journal | Sept. 7, 2015

GENERAL INTEREST ity as well. This begs the question, why the government is standing in the way of a policy change that it itself finds will benefit American taxpayers?”

MarkWest, EMG to develop 2-bcfd Utica dry gas gathering system MarkWest Energy Partners LP and The Energy & Minerals Group (EMG) are developing a new 2-bcfd dry gas gathering system in the Utica shale. A fee-based contract with Ascent Resources– Utica LLC, a subsidiary of Ascent Resources LLC will underpin the system, dedicating roughly 100,000 gross acres in northern Belmont and Jefferson counties, Ohio. Growing dry gas production from Ascent’s acreage is expected to the system’s initial growth, but the new system will also gather dry gas from other producers. MarkWest estimates the system will comprise more than 250 miles of pipeline and 200,000 hp of compression. It expects initial operation by yearend. Takeaway options include connections to the Ohio River System, a gathering trunkline project delivering gas to Rockies Express pipeline, Texas Eastern Transmission through its new Ohio Pipeline Energy Network (OPEN) project, En-

ergy Transfer Partner’s Rover pipeline, among others. MarkWest and EMG, together with Summit Midstream Partners LLC, already operate the Ohio Gathering Co. LLC t venture consisting of hundreds of miles of low- and high-pressure pipelines and numerous compressor stations throughout southeastern Ohio, including Harrison, Guernsey, Belmont, Noble, and Monroe counties. Ohio Gathering over the past year has extended its rich gas footprint into dry gas development areas, beginning initial operations in mid-May of a dry gas gathering system in northern Monroe County and southern Belmont County, Ohio. It currently s Gulfport Energy Corp. and Rice Energy, transporting more than 150 MMcfd of dry gas in addition to 600 MMcfd of rich gas. MarkWest has more than 1.3 bcfd of gas processing and 160,000 b/d of fractionation in Ohio. Ascent is one of the largest pure-play Appalachian exploration and production companies with about 280,000 net acres in the Utica and Marcellus shales. Development of the new system will occur under a separate t venture between MarkWest and EMG, which will be owned twothirds by the former and one-third by the latter. MarkWest last month agreed to merge with MPLX LP, a master limited partnership formed by Marathon Petroleum Corp., in a deal that will make MarkWest a wholly owned subsidiary of MPLX (OGJ Online, July 27, 2015).

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Now with offices in Dubai UAE 63

TECHNOLOGY

Study updates uplift-erosion correlation, Davie fracture zone Yannis Bassias

Amphore Energy Inc. Houston

Robert Bertagne Marex Inc. Houston

EXPLORATION & DEVELOPMENT

The basins along the eastern African margin and Madagascar contain proven petroleum systems where hydrocarbon discoveries are classified either as stratigraphic traps or as having a combination of stratigraphic and structural components. The Davie Ridge, a post-Cretaceous expression of the Davie fracture zone (DFZ) may display similar evidence for these petroleum systems or part of them. The understanding of depositional environments is important for identifying potential prospects and seismic imaging alone cannot provide this information as clearly as it does for the structural compenents of geologic traps. This article synthesizes information derived from a large set of dredging and coring data recovered on the Davie Ridge and its flanks. The results will bring additional confidence to the identification of the Mesozoic and Cenozoic seismic markers as well as to the extent of the uplift and erosion of this fracture zone through time. This article classifies, from north to south, the potential provinces in respect to the uplift and erosion phases that governed the region’s sedimentation history to help derisk future exploration. From an exploration standpoint results point toward conventional production from the Albian sands. The finding that these sands may have

BATHYMETRY OF PAISLEY MOUNT, NORTHERN DAVIE RIDGE

64

41°E

FIG. 1

42°E

14°S

15°S

Oil & Gas Journal | Sept. 7, 2015

BASALTIC BRECCIA PRESENCE: SEISMIC LINE MD40-23

FIG. 2

1 cm

1 cm

MD84581

SU7702

84DR02 SU7702 84DR03

W

E MD84581

Basalt above basement

been eroded on parts of the structures is a limiting factor, but the sands are also well defined by recent seismic. Several other objectives exist on both flanks of the DFZ, with the western side being the most attractive due to the increased thickness of the sedimentary section.

Historical observation The Davie Ridge, an exceptional structural feature of the Mozambique channel, was identified in 1970 by the research vessel (R/V) Chain (CH99), and led geologists to suggest that it could represent a fault along which Madagascar was displaced southwards in Late Jurassic.1 Further seismic and magnetic data collected in the late 1970s showed that the breakup between Madagascar and Africa began 150 million years ago, that Madagascar moved southwards, and that the Davie Ridge should correspond to the trace of the transform fault along which Madagascar drifted until the time of anomaly MD (110 Ma).2 3

Oil & Gas Journal | Sept. 7, 2015

Site 242, drilled by the Glomar Challenger Leg 25 in 1972, did not reach the basement but the recovered sedimentary column (676 m) is a complete hemipelagic sequence from Late Eocene to Quaternary with a well-defined Eocene-Oligocene boundary.4 Piston cores recovered by R/V Suroit (SU2) in 1977 showed a basal, discontinuous, and thin pelagic sedimentary sequence of Late Cretaceous (Middle Coniacian) age overlaying arkosic sandstones.5 6 Dredging and coring from the R/V Marion Dufresne cruise (MD 39) in 1984 confirmed these results and demonstrated that the ridge is built on continental basement consisting of gneisses and meta-arkoses which locally are covered by a deformed flysch, alkaline lavas, tuffs and breccias, and by a thin succession of carbonate oozes ranging from Cretaceous to present.7 8 Seismic cruises MD 40 and MD 60 provided additional information on the structural setting of the ridge.9 The variety of dredged and cored samples are described and projected for selected seismic lines.

65

TECHNOLOGY

SEISMIC LINE MD40-05: PROJECTED SAMPLES

S

84DR02 Miocene with basaltic breccia

MD84582 Pliocene MD84583 Early Miocene

SU7726 Mio-Pliocene

84DR04 Upper Eocene SU7705 Cretaceous

SU7727 Eocene

Crystalline basement

Rock samples The northern part of the ridge, Paisley Mount around 14°S, offers a WNW-ESE cross section (Fig. 1). At the western flank, fragments of altered aphyric basalt were cored below Pleistocene oozes (MD84581, 2,063 m below sea level [mbsl]). Upslope, decimetric angular blocks of vesicular greenish and reddish basalts and tuffs were recovered (84DR03, 1,831-1,760 mbsl). The basalts are alkaline with plagioclase, K-feldspar, biotite, kaersutite, apatite, and relics of clinopyroxene. Dredging of basaltic breccia, conglomerates, and Miocene bioclastic limestone (84DR02, 810-800 mbsl) occurred further east. The breccia elements are vesicular alkaline basalts with clinopyroxene phenocrysts set in a groundmass rich in plagioclase, K-feldspar, clinopyroxene, and phillipsite crystallizing in the vesicles. The basaltic elements are reworked and cemented with a bioclastic carbonate matrix rich in planctonic foraminifers of Miocene age. The coring also consists of basaltic glass fragments at the eastern flank of the mounts (SU7702, 1,110 mbsl). The seismic line is parallel to the cross section and situated around 10 km to the north (Fig. 2). Fig. 3 shows a projection of the dredged and cored material on seismic line MD84-23 and interpretation of the strong reflectors and unconformities east and west of the volcanic mount. Research expeditions have dredged pelagic sediments with polymetallic crusts (84DR04, 2,255-1,905 mbsl) at the

66

FIG. 3

SU7702 Pleistocene above basalts

N

84DR03 Miocene above basaltic breccia MD84581 Pleistocene above basalts

Basalt above basement

southern portions of Paisley Mount, along with tuffs similar to those from the top of Mount Paisley (Fig. 1). The matrices of the tuffs are green, rarely reddish, without calcite or dolomite, and contain fine basalt fragments. Coring of sands and arkosic fragments took place updip northwards at the base of Pleistocene oozes (MD84582, 2,025 mbsl). The same location (MD84583, 1,905 mbsl) also features Early Miocene (NN2) oozes with reworked Upper Eocene (NP20) while further to the north Eocene and Miocene-Pliocene sediments cover the sea bottom (SU7726, 2,230 mbsl). At the southernmost part, cores showed calcareous sands of probable Cretaceous age (SU7704, 1,912 mbsl). Fig. 3 shows a projection of the dredged and cored material on seismic line MD84-05. A tentative interpretation points to the strong reflector and unconformities east and west of the volcanic mount. The eroded crystalline basement emerges south of Mount Paisley at the base of the western flank of the ridge (84DR05, 2,450-1,950 mbsl) and consists of recrystalized pelites and arkoses with small clasts of gneisses (Fig. 4). A comparable sequence was found further south at 16°S (84DR09). Sandy-clayey carbonates of Late Cretaceous age (SU7704, 1,807 mbsl) and Late Miocene (NN11) oozes (U77-0003, 1,815 mbsl) were sampled above the pelites and arkoses. On the same flank, Coniacian oozes (SU7720, 1,845 mbsl) are associated with reworked arkosic (SU7719, 1,935 mbsl) below

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY

SEISMIC LINE MD40-28, INTERPRETED SAMPLES

FIG. 4

Samples

FIG. 4a

Calcareous turbiditic breccia with redeposited fine arkosic and psammitic clasts (84DR06)

Thin sections from meta-arkose with clasts from high grade metamorphic rocks (84DR05). Photomicrograph of clast (enclave) with high grade metamorphic assemblage comprising garnet, biotite, muscovite and chlorite (84DR05). The initial texture is overprint by a younger (post-sedimentary) cleavage which is outlined by low-grade metamorphic Black psammitic beds and fracturated recrystallized phengite and chlorite (84DR05). calcareous sandstones (84DR06)

Sample locations

FIG. 4b

MD84586 Late Eocene

SU7718 Middle-Late Eocene in Pleistocene oozes MD84585 Late Eocene SU7704 CampanianMaastrichtian

84DR06 Cretaceous arkoses, black psammites 84DR05 Recrystallized pelites, arkoses and gneiss, arkoses and black psammites

SU7720 Coniacian oozes

Crystalline basement

Tertiary pull-apart basin

Davie Ridge

Interpretation

FIG. 4c

Intra-Cretaceous unconformities Neogene Base Tertiary

Jurassic-Cretaceous unconformity

Oil & Gas Journal | Sept. 7, 2015

67

TECHNOLOGY

BATHYMETRY, CENTRAL MOUNT MACUA 41°E

Pleistocene oozes, with dredge 84DR06 (1,900-1,875 mbsl) and core MD84585 (1,940 mbsl) recovering fragments of strongly lithified black psammitic beds and of calcareous sandstones (Fig. 4). The psammitic rocks are blackish flysch-like and appear intensively fractured and strongly recrystallized. These sediments correlate with those from Site 249 (top of Unit III), Site 241 (cores 27-28: Turonian Early Senonian) and Site 250 (cores 24-25: Coniacian) and underlie mid-Cretaceous pelagic sediments or Eocene calcareous sandstones. Calcareous sandstones from 84DR06 are white to lightbrown, variously brecciated or fractured. These rocks, dated by nannoplanktons of Upper Eocene age, are locally bioturbated, dissolved, and covered by thin Mn-oxide layers. They are comparable with those from Leg 25, Site 241 (Cores 2728) and Site 249 (Units II and III) of Late Cretaceous-Eocene age. Slightly-lithified calcareous breccia contain redeposited fine arkosic and psammitic clasts and are covered by Pleis-

68

tocene oozes with reworked Middle and Late Eocene nannofauna. These 42°E calcareous breccia are covered by thin 15°S layers of Mn-oxide. The breccia contain small, heavily reworked arkosic and large rounded slightly reworked calcareous fragments which are cemented with an Upper Eocene matrix with composition similar to that of the calcareous sandstones. Lithological features such as rounded fragments, mass flows, microslumps, and differential compaction suggest a high energy, depositional environment and turbiditic activity. Angular psammitic fragments of varied dimensions (1 mm - 2 cm) are cemented in a calcareous matrix rich in Fe-Mg oxides. Samples projected on seismic line MD40-28 demonstrate the amplitude 16°S of erosion and of uplift phases of the crystalline basement (Fig. 4). The interpretation of the strong reflectors and unconformities east and west of the crystalline mount suggest that three large erosion phases took place and recent faulting brought the western part of the edifice to a total vertical displacement of around 2 sec (two-way travel time). At the central part of Mount Macua (16°S, Fig. 5) the eroded crystalline basement rocks are comparable to those found at 15°S (B4DR05 and 17°S B4DR06). The sample consists of calcareous breccia with psammitic and arkosic clasts, recrystallized and karstified bioclastic limestones with Miocene planktonic foraminifers, calcareous sandy oozes, and Plio-Quaternary oozes rich in nannofauna (84DR09, 953-700 mbsl) (Fig. 6). To the west, 84DR08 (1,350-860) recovered white Neogene calcareous oozes with arkosic fragments. Further west the sea bottom is covered by brown Neogene calcareous ooze (84DR07, 1,837-1,390 mbsl). Samples projected on seismic line MD40-32 show again the amplitude of erosion and uplift of the crystalline basement and the large volumes of mass redeposited on the flanks (Fig. 6). The crests of the Sakalaves Mounts (18°S) are covered by Miocene basaltic breccia, rounded and highly altered (84DR10 and 84DR11) (Fig. 7). They were found together with karstified limestones containing Eocene calcareous fragments and with Pleistocene, probably Miocene oozes (Fig. 8). The crests expose Miocene (NN2) oozes and polymetallic oxides (SU7714, 1,240 mbsl) further south. At FIG. 5

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY

SEISMIC LINE MD40-32, PROJECTED SAMPLES

Arkosic sandstones in with Quaternary bioclastic sediments

FIG. 6

Bioclastic limestone highly intruded by Mn-oxides

Burrowing, dissolution, recrystallization of limestone

84DR09 Miocene limestone, arkosic breccia 84DR08 Mio-Pliocene with arkosic clasts 84DR07 Mio-Pliocene

Plio-Quaternary oozes rich in foraminifera

W

E Crystalline basement

Mount Antandroy, to the north, cores recovered Late Eocene (NP20) oozes (SU7710, 2,050 mbsl), Early Miocene (NN2) limestone (SU7712, 2,005 mbsl) and oozes with reworked Oligocene (SU7711, 1,920 mbsl). The southern crests of the Sakalave Mounts between 18° and 19°S are also covered by basaltic breccia (Fig. 8). Irregular beds of basaltic breccia are cemented in a bioclastic matrix rich in Middle Eocene nannoplancton and benthic and planctonic foraminifera (84DR13, 600 mbsl). Basalt clasts, up to 1 cm, are composed of diopsidic clinopyroxene, Kfeldspar, and later hematite. They are oxidized and give a reddish color to the rock. Further south and downdip, soft blocks of altered basaltic breccia are cemented in a chalk matrix containing few fresh dark-green vesicular clinopyroxene-phyric basalt fragments (84DR14, 1,130 mbsl). Nannoplanctons of Middle Eocene (NP15-17) dated the matrix of these breccia. Nannofauna shows some dissolution and slight recrystallization. These

70

Crystalline basement

breccia, as those from the top of the Mounts (84DR13), correlate with those from distinct horizons of DSDP Site 245 (Unit II) of Middle Eocene age.

Metamorphism, uplift, and erosion The crystalline basement rocks crop out at the median parts of the ridge. Basalts were not encountered below pelagic sediments at these latitudes, confirming the absence of magnetic signature.10 As erosion products of crystalline provinces, these rocks could be an intimate part of the basement, having been deposited during the early rifting which preceded the southwards drift of Madagascar along the DFZ. These rocks are comparable with several formations from the African basement and related Karoo facies known in Tanzania and the Malagasy craton.

Oil & Gas Journal | Sept. 7, 2015

Whoosh. Or as we call it: 1580 mbar, 35.47 °C, and 0.13 l/s

TECHNOLOGY

BATHYMETRY, SAKALAVE MOUNTS 41°E

FIG. 7

42°E

ridge and their imprint is often recognizable as lenses-forms on the seismic above the major unconformity. Paleocene is absent on the ridge and was not drilled by Glomar Challenger Leg 25, thus the major unconformity has to be considered of Cretaceous to Paleocene age.

Sedimentation, volcanic activity

From fracture zone to ridge Local distensions along the DFZ during Cretaceous induced either the first Cretaceous pelagic sedimentation or hypabyssal to subaerial volcanic activity with intense hydrothermalism. A major Cretaceous unconformity developed on both flanks of the ridge, yielding two important features: • The spatial symmetry of the volcanic activity, present at the northern and southern parts of the ridge. • The Late Cretaceous and Eocene sedimentation, prominent at the median and southern parts of the ridge. These features suggest that during Late Cretaceous and Eocene the local distensions accompanying lithospheric fissuring were transgressive southwards while the northern part of the ridge remained close to sea level for a long period. Eocene outcrops are, in fact, better exposed at the southern parts of the ridge. The products of this erosion settled on the flanks of the

72

Variations of the Cretaceous sedimentary environments are well documented at 18°E the median parts of the ridge (SU7704, SU7720, 84DR06, 84DR09). The oldest known pelagic sediments of the Davie Ridge are Late Cretaceous oozes. These sediments locally cover the eroded crystalline basement and in two cases were dated of Middle Coniacian (SU7720) and Upper Campanian to Maastrichtian (SU7704). They are particularly soft, ing the hypothesis that subsidence associated with overlying sediments was limited at the median parts of the ridge. The volcanics are present in both northern and southern parts of the ridge below Eocene pelagic sediments and above eroded crystalline basement, consistent with the presence of magnetic signatures. Basalts are alkaline aphyric or phenocrystic rocks 19°E emplaced under hypabyssal, and in some cases, subaerial conditions. The absence of mylonitic texture in the basalts may suggest absence of stress and low-temperature deformation during emplacement and absence of transform fault movements. The absence of pillow features and of ultrabasic rocks discounts transition between oceanic and continental crust, indicating that the volcanic activity of the ridge appeared on a continental setting after cessation of the southwards movement of Madagascar. The geochemistry of the volcanics shows mixing between a differentiated basaltic melt situated in shallow depths and a sialic component, suggesting the influence of subcontinental lithosphere.8 These volcanics are chemically and petrogenetically comparable with the Early Cretaceous volcanism along the southeastern margin of Africa and penecontemporaneous with the Late Cretaceous volcanic activity of western Madagascar which preceded or accompanied local distensions. They coincide with the initiation of the transcurrent motion between India and Madagascar at 83 Ma (Anomaly 34) and with the subsequent northwards movement of India.

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY

SEISMIC LINE MD40-03, BASALTIC SAMPLES

FIG. 8

Basaltic conglomerates and breccia cemented in a Middle Eocene (NP15-17) calcareous matrix comprising few thin fragments of arkosic origin (84DR14).

Photomicrograph of 84DR14. Matrix is dated by coccolithes of Upper Eocene (NP15-17) and contains late zeolithes (phillipsites) that crystallize on dissolution channels.

84DR13

NW

84DR14

Basaltic breccia are cemented in a bioclastic carbonate matrix (84DR13). These breccia form irregular beds up to 40 cm thick. Middle Eocene matrix with coccolithes (NP15-17) and planctonic foraminifers.

SE

Basalt above crystalline basement

Submarine hydrothermalism under reducing conditions variously affected the basalts. This period was associated with or followed by brecciation and tuffs sedimentation. Basalt samples collected are variously affected by sea water and have alteration features such as oxidation colors and vesicles filled with either carbonate or green-layered lattice silicate minerals. Pressures were probably lower than 3 kilobar and temperatures between 150° and 200° C.

Miocene-Pliocene time gap The Miocene bioclastic limestones rich in planktonic fauna are commonly found on the crests of the ridge, where they enclose basaltic fragments and lie between Mn-oxide layers. These formations were probably exposed to subaerial alteration. The breccia from the western flank are composed of rounded fragments and this suggests deposition at some distance from the source while those from the crest consist of

Oil & Gas Journal | Sept. 7, 2015

angular fragments and suggest in situ deposition. The missing Oligocene, equally absent in several sites of the Indian Ocean, may represent this unconformity, recognizable on the seismic by a strong and thin reflector. The fact that Miocene bioclastic limestones and breccia from the crests of the ridge are locally karstified, fractured, and directly covered by younger Pleistocene chalks, suggests fault-controlled tilting, emersion, and erosion along the ridge during Miocene and records an important stratigraphic hiatus which might be related with a large tectonic activity or mersion before the sedimentation of the Pleistocene chalks. The Upper Pleistocene oozes (NN 19/20) from the flanks of the ridge contain significant proportions of reworked Upper Eocene nannofauna, suggesting that the Miocene-Pliocene time gap on the crests is a period of non-consolidation where sediments were reworked several times due to tilting and differential subsidence.

73

TECHNOLOGY A generalized pelagic sedimentation is established after this late erosion and the ridge is covered by white, soft oozes and lumashelic chalks. These formations are rich in debris of gastropods and echinoids as well as in benthic and planktonic foraminifers cemented in a Pleistocene nannoplankton matrix.

ridge seems to be localized and the presence of well-defined depositional channels in the Tertiary is not readily apparent, most likely because a good part of the DFZ was emergent for a long time.

Acknowledgments Updated correlation This article shows the need for major correlation changes, on both the eastern (Malagasy) portion and the western (Mozambican) portion of the DFZ, and yields the following conclustions:. • Mio-Pliocene is thinner than expected. • Oligocene may be absent (probably on the Malagasy side). • Eocene is thin and may be absent on certain portions of the DFZ. • Upper Cretaceous is thicker than expected. • Turonian and Albian are apparently present on all parts of the DFZ. • The Albian sands which are producing in western Madagascar (West Manambolo-1) seem to be well developed (500-850 m) and constitute a major objective. The DFZ appears to have assumed its structural character mostly during Late Cretaceous (Coniacian, Santonian) which was followed by a long hiatus. The erosion of the

This information is a compilation of reports, publications and studies on 63 piston cores and 15 dredge hauls, among 119 samples, recovered during the R/V Marion Dufresne cruise (MD39) in 1984 and the R/V Suroit cruise (SU2) in 1979. Cruise MD39 was funded by the Territoire des Terres Australes et Antarctiques Francaises in 1984. More than one ton of dredged rocks from the Davie Ridge are preserved in the Lithotheque Marine of the National Museum of Natural History in Paris. Seismic was courtesy of CNRS-IPGS/GeoAzur. This synthesis completes previous work of one of the authors, Yannis Bassias, on the crystalline basement and the Cretaceous volcanism of the DFZ.

References 1. Heirtzler, J.R., and Burroughs, R.H., “Madagascar’s paleoposition: New data from the Mozambique Channel,” Science, Vol. 174, No. 4008, October 1971, pp. 488-490. 2. Segoufin, J., “Anomalies magnétiques mésozoïques dans

Iím responsible for my

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74

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY le bassin de Mozambique,” Comptes Rendus de l’Académie des Sciences, Vol. 287, 1978, pp. 109-112. 3. Segoufin, J., and Patriat, P., “Existence d’anomalies mésozoïques dans Ie bassin de Somalie. Implications pour les relations Afrique- Antarctique-Madagascar,” Comptes Rendus de l’Académie des Sciences, Vol. 291, 1980, pp. 85-88. 4. Simpson, S.W., Schlich, R., et al, “Site 242: Initial Reports of the Deep Sea Drilling Project,” Vol. 25, May 1974. 5. Segoufin, J., Leclaire, L., and Clochiatti, M., “Les structures du canal de Mozambique. Le problème de la ride de Davie,” Annales de la Societe geologique du Nord, Vol. 97, Fourth quarter, 1978, pp. 309-314. 6. Fellah, N., “Nannofossiles calcaires et stratigraphie de la couverture sédimentaire des rides de Davie et du Mozambique dans l’océan Indien,” Thèse 3eme cycle, University of Paris VI, Vol. 228, 1981, p. 18. 7. Leclaire, L., “Late Cretaceous and Cenozoic pelagic deposits. Paleoenvironment and Paleo-oceanography of the Central Western Indian Ocean,” Initial Report of the Deep Sea Drilling Project, Vol. 25, May 1974, pp. 481-512. 8. Bassias, Y., and Leclaire, L., “Crystalline basement and intraplate mesozoic magmatism of the Davie Fracture Zone,” Neues Jaarbuch fur Geologie und Palaontologie Mh., Vol. 2, 1990, pp. 67-90. 9. Mougenot, D., Recq, M., Virlogeux, P., and Lepvrier, C., “Seaward extension of the East-African rift,” Nature, Vol. 321, June 1986, pp. 599- 803. 10. Segoufin, J., and Patriat, P., “Reconstruction de l’Océan Indien occidental pour les époques des anomalies M-21, M-2 et M-34: Paléo-position de Madagascar,” Bulletin de la Societe Geologique de , XXIII, No. 6, 1981, pp. 603-607.

The authors Yannis Bassias ([email protected]) is president of Amphore Energy Inc., Houston. Before ing the petroleum industry he was associate professor in the National Museum of Natural

History, Paris. He holds a PhD (1984) from the University Pierre et Marie Curie, Paris VI. He is a member of the American Association of Petroleum Geologists, the Society of Exploration Geophysicists, the Petroleum Exploration Society of Great Britain, and the Association of International Petroleum Negotiators.

Robert Bertagne ([email protected]) is president of Marex Inc., Houston. Prior to ing Marex, he served in various technical and managerial positions with several majors and independent oil companies.

TECHNOLOGY

UBD creates wellbore instability in horizontal wells Shiming He Wei Wang Ming Tang Southwest Petroleum University, Chengdu

Ruifeng Zhang

DRILLING & PRODUCTION

PetroChina, Renqiu

Combining circumferential stresses with additional stresses produced by fluid seepage creates a new model which can be combined with the conventional model to fully describe in-situ stress regimes’ influence on wellbore stability during underbalanced drilling (UBD) of horizontal wells. This article finds the effects of in-situ stress regimes on

wellbore stability by comparing them with a conventional model that does not take fluid seepage into consideration. It then demonstrates how fluid seepage creates greater wellbore instability and that different in-situ stress regimes impact wellbore stability in both models.

MECD CHANGE: NORMAL-FAULTING STRESS REGIME

FIG. 1

0.84

0.76 0.72 0.68

Maximum ECD, g/cc

0.80

0.63 0.59 90

76

75

60 Inclina

45 tion an gle, de 30 grees

15

0

90

15 30 45 s e re g 60 gle, de 75 uthal an im z a e Relativ

0

Oil & Gas Journal | Sept. 7, 2015

Conventional model limitations Data demonstrating the impact of in-situ stresses in UBD of horizontal wells are often overlooked using conventional models. Researchers have looked at the effects of in-situ stresses on the wellbore and, based on the data, conducted studies to reveal the mechanism of wellbore collapse during overbalanced drilling (OBD).1 2 Studies of UBD operations have established a coupled reservoir-geomechanics model that simulates the interaction between reservoir flow and deformation.3 The model can determine wellborestability design and sandproduction risk evaluation in the formation during production or UBD.4 The model offers a practical technique to evaluate UBD of a horizontal well in a depleted reservoir. The conventional model is limited, however, because it does not take into fluid seepage.

Circumferential stresses

EQUATIONS

Z v xx = v H cos2 icos2 a + v v cos2 isin2 a + v v sin2 i ] ] v yy = v H sin2 a + v h cos2 a ] ] v zz = v H sin2 icos2 a + v h sin2 isin2 a + v v cos i [ ] x xy = -v H cosicosa sin a + v h cosicosa sin a ] x yz = -v H sin icosa + v h sin icosa sin a ]] 2 2 \ x zx = v H cosisin icos a + v h cosisin isin a -v v cosisin i

(1)

Z v r = Pm ud ] ] v i = -Pm ud + Qv xx + v yyV -2 Qv xx -v yyV cos2i -4x xy sin 2i ] [ v z = v zz -v!2 Qv xx -v yyV cos2i + 4x xy sin 2i$ ] x = 2x cosi -2x sin i yz xy ] iz ] \ x zr = x ri = 0

(2)

2

G

v = v i cos2 b + 2x iz cosb sin b + v z sin2 b x = 0.5 Qv z -v iV sin 2b + x iz cos2 b

Z v = P -a P m ud e p ]] r [ v i m ax = 0.5 Qv i + v zV + 0.5 Qv i -v zV2 + 4x 2 iz -a e Pp ] v = 0.5 Qv + v V -0.5 Qv -v V2 + 4x 2 -a P z z e p i i iz \ i m in

(4)

dP QPpo -PiV 1 Fs = dr = 1nQre /R V r

(5)

2 2 2 Z rR ) ] v fr = re Qr -R V!2 (12 -2v)(P2op -Pm ud)+ Pop -Pm ud$ - (Pop -Pm ud)1n (/ 2 (1 -v)1n (re /R ) 2r (re -R )(1 -v) ] ] r2e Qr2 -R 2V!2 (1 -v)(Pop -Pm ud)+ Pop -Pm ud$ (Pop -Pm ud)[1n (/ rR )+ 2v -1] [ v if = 2 (1 -v)1n (re /R ) 2r2 (r2e -R 2)(1 -v) ] ] f r2e v!2 (1 -v)(Pop -Pm ud)+ Pop -Pm ud$ v(Pop -Pm ud)[21n (/ rR )+ 2v -1] ] vz = 2 (1 -v)1n (re /R ) (1 -v)(r2e -R 2) \

(6)

Z v fz = 0 ] ]] f r2e v!2 (1 -v)(Pop -Pm ud)+ Pop -Pm ud$ (Pop -Pm ud)[2v -1] vi = 2 (1 -v)1n (re /R ) (r2e -R 2)(1 -v) [ 2 ] re v!2 (1 -v)(Pop -Pm ud)+ Pop -Pm ud$ v(Pop -Pm ud)[2v -1] f ] vz = 2 (1 -v)1n (re /R ) (1 -v)(r2e -R 2) \

(7)

Z v er = Pm ud -a Pe ] ]] e r2e v!2 (1 -v)(Pop -Pm ud)+ Pop -Pm ud$ (Pop -Pm ud)[2v -1] P v i m ax = 0.5 (v i + v z)+ 0.5 Qv i -v zV2 + 4x 2 iz + -a 2 (1 -v)1n (re /R ) e (r2e -R 2)(1 -v) [ 2 ] ( )( ) + 2 1 r v v P P P P ( )[ ] 2 1 v P P v ! $ op m ud op m ud e op m ud ] v iem ax = 0.5 (v i + v z)-0.5 Qv i -v zV2 + 4x 2 iz + -a Pe 2 (1 -v)1n (re /R ) (1 -v)(r2e -R 2) \ m ud

m ud

(8)

m ud

v 1e =

1 + sin { e 2C cos{ v + 1 -sin { 3 1 -sin {

In-situ stress regimes fall into five categories: Normal faulting (NF) (σv > σH> σh), a regime between normal faulting stress and strike-slip stress (NF-SS) (σv=σH> σh), strike-slip stress (SS) (σH > σv > σh), a regime between strike-slip stress and reverse-faulting stress (SS-RF) (σH> σh=σv), and reverse-faulting stress (RF) (σH> σh> σv).5 6 In-situ stresses (vertical stress, σv; maximum horizontal stress, σH; and minimum horizontal stress, σh) ) are continuously acting on wellbore rocks during the drilling process as the wellbore changes from vertical to deviated and finally horizontal. Equation 1 expresses virgin formation stresses in the Cartesian coordinate (x, y, z),7 where i is the inclination angle in degrees and α is the relative azimuthal angle (an angle from the direction of maximum horizontal stress

Oil & Gas Journal | Sept. 7, 2015

(3)

(9)

ROCK MECHANICS, WELL DATA Original pore pressure coefficient (Pop), MPa External boundary radius (re), m Horizontal section TVD, m Borehole radius (R), m Poisson’s ratio (ν) Cohesion strength (C), MPa Internal friction angle(φ), degrees Effective stress coefficient (α¬e)

Table 1

0.93 100 2,514 0.108 0.23 20.71 34.5 0.9

to the well axis measured in degrees). Looking at the effects of in-situ stresses and effective fluid column pressure (Pmud) in the borehole, applying Equation 1’s six stress components to the wellbore can determine the

77

TECHNOLOGY

MECD CHANGE: NORMAL, STRIKE-SLIP FAULTING REGIME

FIG. 2

0.84

0.76 0.72 0.68

Maximum ECD, g/cc

0.80

0.63 0.59 90

75

60 Inclina

45 tion an gle,

30 degree s

–– STRESS REGIMES Regime type NF NF-SS SS SS-RF RF

15

0

Table 2

Maximum Minimum horizontal horizontal Vertical stress stress stress ––––––––––––––––— MPa/100m —–––––––––––––––– 2.15 2.15 1.85 1.65 1.65

1.85 2.15 2.15 2.15 2.15

1.65 1.65 1.65 1.65 1.85

redistribution of circumferential stresses Since the greatest concern for wellbore stability is at the borehole wall, stress components in Equation 1 at that location can be re-expressed by Equation 2 in the cylindrical coordinate (τ, θ, z), where θ is the angular position around the wellbore circumference measured in degrees and ν is Poisson’s ratio. From Equation 2, we find that σθ, σz, and τθ z are connected to θ, showing that the stress state of an inclined borehole varies with the spatial position of wellbore rocks. Because τθ z is usually not 0, whereas σθ and σz are not the principal stresses of wellbore rocks, στ is a principal stress. Equation 3 shows the principal stress, σ, and shear stress, τ, consisting of the stress components in Equation 2. When dσ/dβ = 0, another two principal stresses (σθmax and σθmin) emerge (Equation 4). Here the principle of effective stress is taken into where αe is Biot’s coeficient, and Pp is pore pressure, MPa.

78

90

15 30 45 es re g e d , 60 al angle 75 azimuth Relative

0

Fluid seepage stresses Compared with conventional overbalanced drilling, effective fluid column pressure is lower than the formation pressure during UBD, showing that formation fluid will flow into the wellbore and seepage force will be exerted on wellbore rocks during UBD operations in horizontal wells (Equation 5). Researchers have already devised the model and boundary conditions to study the effects of fluid seepage on wellbore during UBD of horizontal wells.8 Building on this allows determination of additional stresses induced by fluid seepage (radial stress, σfr; tangential stress, σfθ; and axial stress, σfz). Equation 6, where R is the borehole radius, m; r is the radial distance from the center of wellbore to a point in the formation, m; Pop is the original pore pressure, MPa; and re is the radius of external boundary, m, shows the additional stresses. At the wellbore wall (r=R), Equation 7 expresses the stress components (σfr, σfθ, σfz) produced by fluid seepage. The principal stresses on wellbore rocks are found by linear addition of Equation 4 and Equation 7, further described in Equation 8.9

Wellbore-collapse model For an easier calculation, maximum principal stress, intermediate principal stress, and minimum principal stress are assumed to be σe θmax, σe θmin, and σer respectively, in Equation 8. Using the Mohr-Coulomb mathematical model (expressed in Equation 9, which considers the principle of effective stress) yields a new wellbore-collapse model where σe1 and σe3 denote effective maximum principal stress and Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY

MECD CHANGE: STRIKE-SLIP FAULTING STRESS REGIME

FIG. 3

0.84

0.76 0.72 0.68

Maximum ECD, g/cc

0.80

0.63 0.59 0

15

30 Inclina

45 tion an gle, de 60 grees

75

90

effective minimum principal stress, MPa, and φ and C represent the internal friction angle of rock mass and the cohesion strength of rock, respectively. The conventional model can also be leveraged by using the Mohr-Coulomb model when maximum principal stress, intermediate principal stress, and minimum principal stress are σθmax, σθmin, and σr respectively, in Equation 4.

Model testing Data collected from a gas field in China where UBD of horizontal wells is ongoing tested the models. Table 1 lists rock mechanics data, well data, and in-situ stress data for the five stress regimes listed in Table 2. Both tables present the five stress regimes’ (NF, NF-SS, SS, SS-RF, and RF) effects. Figs. 1-5 show the maximum equivalent collapse density’s (MECD) change with both inclination angles and relative azimuthal angles. MECD occurs at a certain inclination angle and relative azimuthal angle when θ changes from 0 to 90°. The new model calculated the figures’ smooth area, with the mesh area calculated by the conventional model. The figures show that the changing trends of both models are the same, but MECD when fluid seepage is taken into is greater than when it is ignored. The mud-weight window is also narrower and the wellbore is more unstable. Fig. 1 shows the changing trend of MECD with inclination angles and relative azimuthal angles in the NF stress regime.

Oil & Gas Journal | Sept. 7, 2015

0

75 60 es 45 re g e d , 30 al angle 15 azimuth Relative

90

MECD increases with the increase of inclination angles and weakens with the increase of relative azimuthal angles for both the new model and the conventional model. The variation of MECD is sensitive to inclination angles. When the inclination angle is fixed, the impact from the change of relative azimuthal angles on MECD is small. When drilling in the horizontal section of a well (i=90º), MECD is always large at a random relative azimuthal angle, showing that the wellbore is easier to collapse. Fig. 2 illustrates the changing trend of MECD with inclination angles and relative azimuthal angles in the NF-SS regime. The horizontal section of the wellbore is most stable when it is drilled in the direction of minimum horizontal stress (α=90º) where the highest production rates are obtained.10 The wellbore is most unstable when the inclination angle is 0-45º. To keep the wellbore stable in the kick-off section, UBD should only be applied in the horizontal section. Fig. 3 illustrates how MECD decreases with the increase of inclination angles in the SS stress regime when the relative azimuthal angle is random. MECD reaches the minimum value and the mud-weight window is the widest in the horizontal section. Fig. 4 shows that MECD obtains maximum value when i=0º (vertical section) or α=90º in the SS-RF stress regime. The wellbore is most unstable at this time. Fig. 5 indicates that MECD in the RF stress regime is much smaller at a higher inclination angle (i=60-90º) when it is drilled in the direction of maximum horizontal stress (α=0º).

79

TECHNOLOGY

MECD CHANGE: STRIKE-SLIP, REVERSE-FAULTING STRESS REGIME

FIG. 4

0.84

Maximum ECD, g/cc

0.80 0.76 0.72 0.68 0.63 0.59 0

15

30 Inclina

45 tion an gle, de 60 grees

75

90

0

75 60 45 grees e d , 30 le g al an 15 azimuth Relative

90

MECD CHANGE: REVERSE-FAULTING STRESS REGIME

FIG. 5

0.84

0.76 0.72 0.68

Maximum ECD, g/cc

0.80

0.63 0.59 0

15

30 Inclina

45 tion an gle,

60 degree s

75

90

The combined results of Figs. 3, 4, and 5 advise drilling at α=30-60º in the horizontal section to keep both a stable wellbore and high productivity.

80

0

75 60 45 rees g e d 30 , le al ang 15 azimuth Relative

90

Acknowledgments The authors would like to acknowledge the of the National Natural Science Foundation of China, Project No. 51474186, the 12th 5-Year Plan of China, Project No. 2011ZX05045-03-01WX, and the 11th 5-Year Plan of China, Project No. 2008ZX050450307HZ.

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY

References 1. Zare-Reisabadi, M.R., Kaffash A., and Shadizadeh S.R., “Determination of optimal well trajectory during drilling and production based on borehole stability,” International Journal of Rock Mechanics and Mining Sciences, Vol. 56, pp. 77-87, December 2012. 2. Aadnoy, B.S. and Hansen, A.K., “Bounds on in-situ stress magnitudes improve wellbore stability analyses,” IADC/ SPE Drilling Conference, Dallas, Mar. 2-4, 2004. 3. Wang, Y. and Lu, B., “A coupled reservoir-geomechanics model and applications to wellbore stability and sand prediction,” SPE International Thermal Operations and Heavy Oil Symposium, Porlamar, Venezuela, Mar. 12-14, 2001. 4. Qiu, K., Gherryo, Y., Tan, C.P., and Marsden, R., “Underbalanced drilling of a horizontal well in depleted reservoir: A wellbore stability perspective,” SPE Middle East Oil & Gas Show and Conference, Manama, Bahrain, Sept. 25-28, 2007. 5. Al-Ajmi, A.M. and Zimmerman, R.W., “A new well-path optimization model for increased mechanical borehole stability,” Journal of Petroleum Science and Engineering, Vol. 69, No. 1-2, pp. 53-62, 2009. 6. Peng, S. and Zhang, J., “Engineering geology for underground rocks,” Springer Science and Business, Berlin, 2007. 7. Fjaer, E., Holt, R.M., Horsrud, P., Raaen, A.M., and Risnes, R., “Petroleum related rock mechanics,” Elsevier, Oxford, UK, 2008. 8. He, S.,Wang, W., Tang, M., Hu, B., and Xue, W., “Effects of fluid seepage on wellbore stability of horizontal wells drilled underbalanced,” Journal of Natural Gas Science and Engineering, Vol. 21, pp. 338-347, November 2014. 9. He, S. Wang, W., Shen, H., Tang, M., Liang, H., and Lu, J., “Factors influencing wellbore stability during underbalanced drilling of horizontal wells-When fluid seepage is considered,” Journal of Natural Gas Science and Engineering, Vol. 23, pp. 80-89, March 2015. 10. Rabaa, W.E., “Experimental study of hydraulic fracture geometry initiated from horizontal wells,” SPE Annual Technical Conference and Exhibition, San Antonio, Oct. 8-11, 1989.

The authors Shiming He ([email protected]) is a professor at Southwest Petroleum University of China and the vice director of the Oil and Gas Well Drilling Technology Center at Southwest Petroleum University, Chengdu. He specializes in underbalanced drilling, wellbore stability, well control, and other areas concerning drilling technologies. He holds a PhD in oil and gas drilling technology from Southwest Petroleum University. Oil & Gas Journal | Sept. 7, 2015

Wei Wang ([email protected]. cn) manages the department of exploration at Huabei Oil Field Co., PetroChina. He holds a PhD in petroleum engineering from the Chinese Academy of Geological Sciences, Beijing.

Manuscripts welcome Oil & Gas Journal editors are happy to consider for publication manuscripts about exploration and development, drilling, production, pipelines, LNG, and processing (refining, gas processing, and basic petrochemicals). These papers may be highly technical in nature and appeal or they may analyze oil and natural gas supply, demand, and markets. OGJ accepts manuscripts submitted exclusively to it or those adapted from oral and poster presentations. An Author Guide is available at www.ogj.com; click “Home,” then “Submit an article.” Or, Managing Editor—Technology ([email protected]; 713/963-6211; or, fax 713/963-6282), Oil & Gas Journal, 1455 West Loop South, Suite 400, Houston TX 77027 USA.

81

TECHNOLOGY

DRILLING & PRODUCTION

Biocides in fracing fluid mitigate formation damage Robert Fowles Kenneth Worsley

STUDIED BOICIDES’ CHEMISTRY

FIG. 1

Weatherford International PLC Edmonton

Clayton Smith Weatherford International PLC Houston

Microbial formation damage Hydraulic fracturing fluids are mostly water-based, though oil and emulsionbased fluids are also used. The success of a fracturing program depends on its design, including using a fluid that matches the requirements of the formation. Guar-based fracing fluids’ (where a guar bean powder is added to water to form a gel) low cost and ease of handling makes them preferred, but managing fluid degradation and environmental clean-up may be difficult.2 Fresh-water microbes are a ma-

82

Chlorine dioxide

Hypochlorus acid

Hydantoin

2,2-dibromo3-nithrilopropionamide

BIOCIDE TESTING, BACTERIA-BROTH BOTTLES

FIG. 2

100 80 1,000 CFU

Fresh water used in hydraulic fracturing contains microbes that can proliferate in storage tanks under the right conditions.1 These microbes degrade guar-based fracing fluids, creating biofilms that can lead to formation damage and lower production. This article looks at the effects of biocides on fracing fluid to mitigate potential formation damage and address environmental concerns.

60 40 20 0 APB anaerobic

Thioglycolate anaerobic

Control 100 ppm 200 ppm 100 ppm 200 ppm 100 ppm 400 ppm

API SRB anaerobic Bacteria bottles

Phenol red aerobic

API aerobic

hypochlorous acid biocide hypochlorous acid biocide hydantoin derivative biocide hydantoin derivative biocide 2,2-dibromo-3-nitrilopropionamide biocide 2,2-dibromo-3-nitrilopropionamide biocide

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY

Oil & Gas Journal | Sept. 7, 2015

VISCOSITY PROFILE, HEATED HYDRAULIC FRACTURING GEL 1.80

FIG. 3

Chlorine dioxide

FIG. 3a

100 80

1.40 1.20

60

1.00 0.80

40

0.60 0.40

Temperature, °C

Viscosity 1,000

1.60

20

0.20 0

0.00 0

20

40

60

80

100

120

Time, min Control

20 ppm

100 ppm

10 ppm

50 ppm

Temperature

Biocides

FIG. 3b

100

1.75

1.55

80

60 1.15 Control 200 ppm hypochlorous acid

0.95

100 ppm hydantoin derivative

40

Temperature, °C

1.35

Viscosity 1,000

jor concern when using a guar-based fluid. Among these microbes are acid-producing bacteria (APB), sulfurreducing bacteria (SRB), and generalheterotrophic bacteria (GHB). These can be free-floating, attached to a surface, or dormant.3 A guar-based fluid without biocides can lead to biofilms that can damage a formation through bioclogging (caused by GHB), microbially-induced corrosion (caused by APB and SRB), or H2S production (caused by SRB), and reduce output. This bioclogging may require biofilm treatment or more hydraulic fracturing to increase production, either of which raise both cost and environmental concerns about possible excessive use of chemicals.4 Biocides can be added to stored water or as part of the pad: a high-viscosity fluid containing water, polysaccharide derivatives, pH control additives, surfactants, crosslinking chemicals, breakers, and other additives.5 Treatment concentration depends on the type of biocide, the method of application, time available, and costs. This article evaluates chlorine dioxide solutions and three biocides containing hypochlorous acid, hydantoin derivatives, and 2,2-dibromo3-nitrilopropionamide. Testing used APB anaerobic, thioglycolate anaerobic, API SRB anaerobic, phenol red aerobic, and API aerobic microbial broth bottles (Fig. 1) to determine the biocide concentration needed to achieve a 100% and immediate kill of microbes, minimizing the risk of bacterial proliferation in a formation during fracturing. This level and rate of kill is difficult to achieve with commonly used biocides. The article also looks at the effects of biocides on the viscosity of hydraulic-fracturing gels and slick water at elevated temperature and pressure. Biocides can affect the structure of fracturing fluids, rendering them ineffective.6 Total kill may not be achieved by some biocides because of low efficacy

100 ppm 2,2-Dibromo3-nitrilopropionamide

0.75

Temperature

20

0.55

0

0.35 0

20

40

60

80

100

120

Time, min

83

TECHNOLOGY

SLICK-WATER VISCOSITY

was tightened for a closer fit to prevent air suction during operation. At least 2 FIG. 4a Chlorine dioxide ml of the water was collected into the 5.0 4.6 syringe, gas bubbles removed, any re4.5 maining gas and some water displaced 3.8 4.0 to 1 ml remaining, and injected into 3.5 3.2 the first broth bottle. 3.0 Filling and re-injecting 3 ml of the 2.5 fluid a few times without removing 2.0 the syringe from the bottle vigorously 1.6 mixed the broth-water. Serial dilutions 1.5 then moved 1 ml of inoculated broth 1.0 from Bottle 1 to Bottle 2, 2 to 3, 3 to 0.5 4 and 4 to 5, after mixing each bot0.0 tle. These dilutions were the control Anionic friction reducer Cationic friction reducer group.7 Control 10 ppm chlorine dioxide Researchers determined the microbial demand and remaining free (reBiocides 4.8 FIG. 4b 5 sidual) chlorine dioxide to be tested. 4.6 4.2 The biocides (10-400 ppm) were in4.3 4.2 jected in 100 ml of lake water and 1 3.8 4 ml of the treated water was placed into 3.3 different types of broth bottles. 3 2.7 Serial dilutions followed the same procedures as the control group above. 2 The broth bottles were left at room temperature and observed for 2 hrs-2 1 weeks. Color changes, an increasingly cloudy appearance, and the number of colony-forming units (CFU) indicated 0 Anionic friction reducer Cationic friction reducer microbial growth. The control group exhibited about Control 100 ppm hydantoin 105 CFU/ml in thioglycolate anaerobic, 100 ppm 2,2-dibromo200 ppm API SRB anaerobic, phenol red aerobic, 3-nithrilopropionamide hypochlorus acid and API aerobic broths. The APB anaerobic broth showed up to 104 CFU/ ml. Chlorine dioxide (residual concentration of 10 ppm plus or the need for a higher concentration, significantly increas27.5 ppm microbe demand, total 37.5 ppm) prevented all ing costs or negatively affecting the gel or slick water. bacterial growth, rapidly reaching 100% kill. The biocide broths containing hypochlorous acid, hydantoin derivatives, Antimicrobial efficacy test and 2,2-dibromo-3-nitrilopropionamide did not reach 100% Water for the antimicrobial test came from a lake in Central kill. In some cases, however, they decreased the number of Alberta, Canada. Efficacy tests were done in the previously CFU/ml-1 as shown in the accompanying table. mentioned bacteria broth bottles: APB anaerobic, thioglycolate anaerobic, API SRB anaerobic, phenol red aerobic, and Frac gel, slick-water test API aerobic. Samples were tested quickly to ensure accurate The viscosity profile of frac fluid and slick water when heatresults. ed shows if these components are affected by a biocide. Researchers arranged each type of nutrient broth bottle To prepare a test frac gel, potassium chloride (KCl) (4g, in a dilution series of five bottles. The metal stoppers of the 2% solution) is added to tap water (200 ml) in a Waring broth bottles were sterilized with ethanol in order to prevent blender and mixed at 500 rpm to dissolve the KCl. The contamination of the media during inoculation. Presterilblending speed is reduced to 300 rpm and biocide, a buffer, ized 3-ml syringes were removed from their packaging withand a gelling agent are added and mixed for 30 min. Adding out contamination of the tips. The needle of each syringe a cross-linker precedes determination of vortex closure and Viscosity,

Viscosity,

FIG. 4

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Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY

BIOCIDE TESTING, BACTERIA-BROTH BOTTLES Control APB anaerobic Thioglycolate anaerobic API SRB anaerobic Phenol Red aerobic API aerobic

2,2-Dibromo-3 Chlorine Hypochlorous acid Hydantoin derivative nitrilopropionamide Dioxide biocide biocide biocide 10 100 200 100 200 100 400 –––––––––––––––––––––––––––––––––––––––––– ppm –––––––––––––––––––––––––––––––––––––––––––––––––

104

—

104

104

104

1,000

104

103

105

—

105

104

105

105

105

103

5

—

10

4

3

3

1

4

105 105

— —

105 105

10

10

10

10

10

103

105 104

105 104

104 10

105 105

103 102

crowning time. A rheometer measures stability of the gel (25 ml) held at at 80° C. and 200 psi for 2 hr. For a slick-water test, tap water (200 ml) is placed in a Waring blender and mixed at 300 rpm. The biocide and an anionic or cationic friction reducer (0.4 ml) are then blended for 5 min. A viscometer collects viscosity data at room temperature to 60° C. for 30 min. We maintained control group (biocide-free) gel integrity at 350-500 . With 10 ppm free chlorine dioxide, the gel was also maintained between 350-500 at 80° C. As the concentration of chlorine dioxide increased, however, viscosity decreased. The gel broke quickly in chlorine dioxide concentrations of more than 100 ppm (Fig 2a). An unbroken gel containing a compatible biocide is viscous with good lipping behavior. An incompatible biocide or a biocide at too high a dosage causes low viscosity and poor lipping behavior or rapid breaking of the gel. Testing of selected concentrations of the other biocides determined their effects on gel integrity. Viscosity was maintained between 350-500 at 80° C., u to 200 ppm hypochlorous acid biocide and 100 ppm 2,2-dibromo3-nitrilopropionamide and hydantoin derivative biocides. Hydantonin demonstrated the largest decrease in viscosity compared with the control group (Fig. 2b). Fig. 3a-b shows the biocides’ effect on selected anionic and cationic slick water. Viscosity decreased more than 30% when chlorine dioxide at 10 ppm was added to anionic slick water. A more than 50% viscosity decrease occurred when chlorine dioxide was added to cationic slick water. These results suggest that chlorine dioxide biocides will reduce the performance of some slick-water systems (Fig. 3a). The other biocides studed had no significant effect on anionic slick water. Viscosity of cationic slick water, however, increased in the hypochlorous acid biocide. The hydantoin derivatives and 2,2-dibromo-3-nitrilopropionamide biocides decreased viscosity and therefore may affect the performance of some cationic friction reducers (Fig. 3b).

Untreated water’s effect A proppant and Barea sandstone cores were put into three conductivity cells to determine the effects of untreated wa-

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ter. Baseline testing used a solution of KCl (2%) a breaker, a friction reducer, and a non-emulsifier. The cell stack was slowly ramped up to a closure stress of 2,000 psi and then heated to 112.8° C. The stack was left at temperature and pressure for 12 hr before baseline readings were taken. About 200-250 ml of treatment fluid then flowed through each of the proppant packs at temperature and pressure. Regain-conductivity measurements were taken after flushing the packs with about 200-250 ml of 2% KCl brine. Permeability was reduced less in source water with a biocide (11.3% of baseline) than in untreated source water with bacteria (32.2% of baseline). Permeability was not affected in KCl-only solutions.

References 1. Struchtemeyer, C.G., Morrison, M.D., Elshahed, M.S., “A critical assessment of the efficacy of biocides used during the hydraulic fracturing process in shale natural gas wells,” International Biodeterioration & Biodegradation, Vol. 71, , July 2012, pp. 15-21. 2. Dawson, J.C., Cramer, D.D., Le, H.V., “Reduced Polymer Based Fracturing Fluid: Is Less Really More?” SPE Annual Technical Conference and Exhibition, Houston, Sept. 26-29, 2004. 3. Dawson, J., Wood, M., “A New Approach to Biocide Application Provides Improved Efficiency in Fracturing Fluids,” SPE/EAGE European Unconventional Resources Conference and Exposition, Vienna, Mar. 20-22, 2012. 4. Ezeuko, C.C., Sen, A., Gates, I.D., “Modelling biofilminduced formation damage and biocide treatment in subsurface geosystems,” Microbial Biotechnology Vol. 6, No. 1, January 2013, pp. 53–66. 5. Fink, J., “Oil Field Chemicals,” Gulf Professional Publishing, 2003, Houston, pp. 233-275. 6. Williams, D.A., Newlove , J.C., Horton, R.L., “Hydraulic Fracturing with Chlorine Dioxide clean up,” US Patent 4,964,466, 1990. 7. “Field Monitoring of Bacterial Growth in Oil and Gas Systems,” National Association of Corrosion Engineers (NACE) International, NACE Standard TM0194-2004, 2004.

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY The authors Robert Fowles ([email protected]. com) has been a research and development scientist at Weatherford for 4 years. He has been project manager for different research projects involving biocides, hydrates, scale inhibitors, and heavy oil. Fowles has a PhD in chemistry from the University of the West Indies, St. Augustine, and was a postdoctoral researcher at the University of Alberta, Edmonton. He is a member of the Association of the Chemical Profession of Alberta.

Clayton Smith ([email protected]) is the global director of research, development and engineering for Weatherford. He has more than 18-years’ experience in the oil and gas industry and has spearheaded the development of over 500 unique chemical products spanning drilling fluids, cementing, fracturing, acid stimulation, formation remediation, and production chemicals. Clayton holds a PhD in analytical chemistry from the University of the West Indies, St. Augustine.

Kenneth Worsley (kenneth.worsley@ ca.weatherford.com) is a technical service manager ing Weatherford’s R&D group in development of new products and field applications. He is involved in coordinating global projects obtaining field operating parameters used in developing lab testing to simulate production chemicals and fracturing chemicals. He holds a BS in chemistry from University of Alberta.

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TECHNOLOGY AFPM Q&A—2

Discussion expands to include hydroprocessing This second of three articles presenting selections from the 2014 American Fuel and Petrochemical Manufacturers Q&A and Technology Forum (Oct. 6-8, Denver) continues a discussion of safety and also addresses issues of mechanical integrity and profitability related to hydroprocessing. The first installment, based on edited transcripts from the 2014 event (OGJ, Aug. 3, 2015, p. 52), addressed gasoline processing operations, with a focus on safety, blending, and reforming issues. The final installment (OGJ, Oct. 5, 2015) will highlight discussion surrounding processes associated with fluid catalytic cracking. The session included four ists comprised of industry experts from refining companies and other technology specialists responding to selected questions and then engaging attendees in discussion of the relevant issues (see accompanying box). The only disclaimer for ists and attendees was that they discuss their own experiences, their own views, and the views of their companies. What has worked for them in their plants or refineries might not be applicable to every situation, but it can provide sound guidelines for what would work to address specific issues.

Safety As more refiners consider installing zeolite catalyst in their hydrotreating units, what are your recommendations for a depressuring system? Blackwell I am going to discuss both the emergency depressurization system (EDS), which is a manual depressurization system, and the automated depressurization system (ADS). I will start with the EDS since the ADS piggybacks on this manual system. All hydroprocessing units have an EDS. The EDS valve(s) must be capable of activation by a dedicated button in two locations: one on the control and one in a safe field location. There is little difference in EDS sizing criteria between Chevron Lummus Global (CLG) and Chevron Corp. (CVX). For CLG, we provide two equally-sized valves in parallel, with each valve sized to reduce the pressure to 25% of normal in 20-30 min. The CVX standard is depressurization to 50% of normal in 15 min and depressurization to nitrogen header pressure in 30 min. The CLG standard is two redundant and equally-sized

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The ists Derek Blackwell, senior staff engineer for hydroprocessing technology, Chevron Lummus Global LLC Sergio Robledo, hydroprocessing catalysts technical manager, Haldor Topsoe Inc. Kathy Wu, senior hydroprocessing technologist, Shell Global Solutions (US) Inc. Rick Manner, hydroprocessing specialist, KBC Advanced Technologies Inc. The respondents Jeff Bull, Valero Energy Corp. Michael Adkins, KP Engineering LP Steven Zaritsky, Axens North America Inc. Kevin Proops, Solomon Associates Inc. Ray Hansen, Sinclair Wyoming Refining Co. Danna Sharpe, Flint Hills Resources LLC

valves installed in parallel. The primary activation is one valve, but the operator has control of the second valve. So you can effectively double the depressurization rate if your relief system is sized accordingly and if the situation warrants it. When both PROCESSING valves are utilized, the CLG system will depressurize at a rate similar to the CVX standard. Finally, the failsafe design condition is for the EDS valves to “Fail Open” with loss of signal. With EDS activation, the makeup hydrogen flow is reduced to 25% of normal to ensure that depressurization occurs as rapidly as expected. CLG will trip the heater to pilots. CVX trips the heater to a full chop. Now I will discuss the ADS system. I mentioned that EDS is required for all hydroprocessing units. The current practice for ADS is that it is not required for hydrotreating service using hydrotreating catalysts only, but it is required for any unit utilizing hydrocracking catalyst, including mild hydrocrackers. We are currently reviewing the newest generation of high-activity hydrotreating catalysts. There are some extremely active hydrotreating catalyst options available now, and we are considering adding these catalysts to the list for

Oil & Gas Journal | Sept. 7, 2015

A California superior court recently cleared the way for Chevron Corp. to proceed with its long-planned, $1-billion project to modernize operations at its 257,000-b/d refinery in Richmond, Calif. (OGJ Online, Apr. 22, 2015). The project will replace some of the refinery’s oldest processing equipment with technology meeting the broad spectrum of US air quality standards without changing the basic operation or amount of crude the refinery can process. A main project component is replacement of the refinery’s existing 1960s-era hydrogen plant to enable more efficient and reliable processing of higher-quality hydrogen. Photograph from Chevron.

ADS inclusion. No decision has been rendered yet, but you might keep this in mind if you think you may use these high-activity catalysts. We currently apply one exception to our ADS guidelines. The decision process for ADS inclusion is really based around the activation energy, as well as the operating temperature and its proximity to the onset of thermal cracking, which is 850° F. We currently utilize a very mild, amorphous-like hydrocracking catalyst system to increase volume swell in diesel hydrotreating service. The activation energy of this system is extremely low. In this case, ADS is optional as long as the expected operating temperature is also low, relative to 850° F. Next I will discuss ADS activation. ADS triggers are designed to provide the console operator sufficient time and notification to gain control of the unit or manually initiate depressurization. Time, in this case, is not a fixed clock time. Rather, it is the effective time created between the alarm and trip set points. Based on experience with early implementations, we have a concern with false trips, so we utilize redundant voting. One of our ADS triggers is loss of

Oil & Gas Journal | Sept. 7, 2015

recycle gas flow. For this, we use two-out-of-three voting. High outlet-line temperature is another trigger. This is based on two-out-of-two voting. For catalyst bed temperatures, we only trigger the ADS from catalyst beds containing hydrocracking catalyst and only from the bed outlet temperatures. For these locations, any two high temperature indicators (TIs) at the same bed outlet will trigger the ADS. Finally, ADS functionality: When the ADS trips, it will depressurize the unit until all permissives are clear. For CLG, the permissive for pressure is reducing the system to 50% of design. The CVX permissive for pressure is reducing to 25% of design. We use a 50° F. bandwidth on hightemperature trips, so TIs have to drop 50° F. below their trip temperature before the permissive will clear. Finally, 5 min of continuous recycle compressor operation is required to clear the associated permissive. If all of the permissives are clear, then the ADS will stop depressurization. If all permissives do not clear, depressurization will continue down to the nitrogen header pressure. My last point on ADS: The operator is generally in control of the depressurization process. Once all permissives

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TECHNOLOGY are clear, the operator can continue or discontinue depressurization at his or her option. It is also possible to discontinue depressurization with the system pressure above 50% of design as long as all other permissives are clear. Wu Derek had an extensive answer on this question, so I will just add a few points regarding what we do at Shell. All of Shell’s hydrotreating units are equipped with both lowrate and high-rate depressuring systems, and both systems are manually activated. The low-rate depressuring systems are sized so they depressure from a normal operating pressure to around 100 lb over 1 hr. The low-rate depression valve closes when the high-rate depression valve opens. The high-rate depression valve is normally used only when there is a major unit upset or an emergency situation, such as a big fire or a large leak. The valve is normally sized to depressure from a normal operating pressure to 100 lb in 15 min. When the high-rate depression valve is opened, it normally trips the feed pumps, charge heaters, makeup gas, recycled gas compressors, and wash oil or washwater pumps. The unit is essentially shut down. For the hydrocracking unit, the depression system is designed slightly differently compared with the hydrotreating unit. For the hydrocracking unit, the low-rate depression valve can be either manually or automatically activated, and it can be tripped losing the recycle gas compressor. Also for the cracking bed, if there is a 50° F. above-grade change in the per-minute average temperature for the two TIs in the bottom bed, the low-rate depression valve will be automatically opened. It can also be tripped on the top bed TIs if the temperature is anywhere from 15-25° F. above the rate of temperature change per minute. The low-rate depression valve can also trip any single TI exceeding the designed temperature. The high-rate depression system in the hydrocracker is designed very similarly to the hydrotreaters. It is manually activated when there is both a major emergency on the unit and when temperature discretion occurs, which is often in the hydrocracker and not the hydrotreaters. At Shell, if the zeolite catalyst is utilized in the hydrotreating unit, we would require the hydrotreater to follow the same depressuring system as the hydrocrackers. Robledo Derek and Kathy covered a lot, so I will now give Haldor Topsoe’s view on this scenario. Just recognize that any zeolite-containing material is going to possess an inherent ability to crack hydrocarbons; therefore, you will have the potential for a temperature excursion to take place, especially in the loss of recycle gas flow. When Haldor Topsoe designs a hydrotreater, we specify a fast-depressurization system based on the American Petroleum Institute (API) Recommended Practice (RP) 521. We usually set that at 100 psi/min. The goal is to reduce the pressure to 50% in a matter of 15 min. That is usually

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achievable when you have a unit operating below 800 lb. Once you get above an operating pressure of 800 lb, the depressurization rate is increased above 100 psi/min to fall within the recommended practice of reducing pressure to 50% in 15 min. For a hydrocracker, we specify two emergency depressurization systems: a low-rate and a high-rate system. These systems are designed to depressure at rates of 100 psi/min and 300 psi/min, respectively. The low-rate depressurization system opens on a loss of recycle gas. Since the recycle gas flow provides the means for temperature control in the reactors, Haldor Topsoe’s philosophy requires that depressurization be initiated at a low rate upon stoppage of the recycle gas compressor. This moves the reactor in a safe direction, but you can still stop the depressurization if the compressor is restarted and the catalyst temperatures are normal. The high-rate depressurization system opens up at the onset of a temperature runaway. A temperature runaway is classified as any reactor skin temperature exceeding the reactor design temperature. If the temperature rise is 55° F. above the normal operating temperature level, then the bed is severely upset, and the unit should be fully depressured. A rate of 300 psi/min will usually exceed the 50% reduction requirement. Part of the question was about endpoint or cold-flow improvement. Refiners are often considering adding these catalysts into their hydrotreaters. The operating procedures must be revised to reflect the differences in operation, and the operators should be trained for this new operation. At a minimum, Haldor Topsoe recommends that the unit meets API RP 521 of reducing the pressure 50% in 15 min. This is lower than what we would specify for a grassroots design. Haldor Topsoe believes, however, that this is a reasonable compromise for a revamp if: 1. A careful analysis is made of the new operation. 2. The operating procedures are reviewed and properly modified. 3. The operators are properly trained for the new operation. 4. Confirmation is made that the unit instrumentation is adequate to identify the scenarios requiring depressurization. Again, when you are using catalysts which contain zeolite, a review of the unit’s control and shutdown systems is imperative. When considering any of these catalysts for use in your hydrotreater, consult your experienced licensor or catalyst vendor, both of whom should be able to provide guidelines. Bull Kathy, can you define what you meant by decaying average temperature? Wu Basically, it just means looking at individual TIs and comparing their rates of change per minute. The damped decaying average value for a set of radial thermocouples is

Oil & Gas Journal | Sept. 7, 2015

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TECHNOLOGY calculated each minute as a moving weighted average and incorporates the value each second by adding one sixtieth of the latest value to the weighted average over the previous 59 sec. Bull If that rate of change is 50° F. or above in 1 min, then you trigger? Wu Yes. Adkins I am wondering if you have any specific recommendations on the type of instrumentation for thermometry inside the reactors, both from the hydrotreating and hydrocracking standpoints. Blackwell There are differences, but we have had good experience with high-temperature, high-pressure thermometry provided by both of the vendors represented and showing exhibits here today.

Mechanical Integrity What are your criteria for retiring a hydroprocessing reactor? What kind of failures have you seen? What are the inspection techniques you use and your frequency of inspection? Wu This is a complicated question. In general, there is no need to retire a reactor unless there is an active degradation mechanism identified. So if there is one identified, inspection plans need to be in place to the degree of degradation and identify the mechanisms in the corrosion review documenting it. At Shell, we use a risk-based inspection technology to establish the required extent for inspection and frequency of the inspection, as well as the assessment of the reactor’s remaining life. Here is one example. There is a soon-to-be retired reactor in naphtha hydrotreating service that was made in 1958, so it is quite old. The reactor was made of C-½ moly material with stainless-steel 304 overlays. There are two corrosion concerns with this reactor. One is the high-temperature hydrogen attack which has been managed through the inspection program and Ensure Safe Production (ESP) practices with regard to operating temperature and hydrogen partial pressure. With the recent industry experience on high-temperature hydrogen attack and the expected new API curves for this type of metal service, it is possible the Shell inspection program and the ESP practices may not be acceptable for this type of service. As a result, the refinery is considering replacing the reactor. The second corrosion concern on this reactor is the sulfidation. Because if the stainless-steel 304 is detached from the reactor wall, there will be a concern of sulfidation corrosion. The corrosion rate can be as high as 10-15 mils/year.

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This type of corrosion can only be inspected through video. Doing repairs is also an option, but only for the small areas, as this would also require extensive shutdown and cost. Based on all these factors, the refinery has decided to retire this reactor. The fitness-for-service (FFS) assessment can be used also to evaluate the structure integrity of in-service reactors. If inspection reveals issues with a reactor’s mechanical integrity and the reactor is not retired, you can use API 579 guidelines to make assessments on its suitability for continued service. API 579 was developed for equipment in the refining industry for quantitative engineering evaluations on structural integrity. It also can be applied to make run, repair, and replacement decisions. Is your reactor still safe in service today? The FFS assessment can be used for projecting the remaining life of the equipment. It also can be applied for certain damages like general localized corrosion and the presence of cracks or creep and fire damages, as well the other items on the list. If the FFS assessment results show the reactor is still suitable for current operating conditions, an appropriate monitoring and inspection program will still need to be in place to ensure its mechanical integrity in service. If the assessment result shows that it is not suitable for service, you could consider rerating the equipment if you do not want to retire the reactor; or, you could consider retiring the reactor. What kind of reactor failures have we seen in the industry? We have seen hydrotreaters, hydrocrackers, and even a pyrolysis gasoline (pygas) hydrotreater’s reactor fail where a reactor was damaged with a hole. Many times, reactor failure was caused by a temperature excursion where the reactor was operated above the designed temperature. There are also other types of failures that are caused by corrosion, such as high-temperature hydrogen attack or cracking when reactors are exposed to too low a temperature while still under pressure. The reactor failure can also be caused by hydrogen embrittlement when the reactors are cooled down too quickly and the hydrogen dissolved into the reactor wall could not get out right away. Temper embrittlement was affected mostly on primarily 2.25Cr-1Mo material. Failures were also observed due to poor toughness of the material and mechanical or thermal fatigue. The inspection techniques commonly used for reactor inspection are the nondestructive examinations (NDEs). Some of them have already been mentioned by Derek for their plant use, including UT, magnetic particle, penetrant, and radiographic. The infrared thermometry was actually used mostly for the cold-wall reactor design. There are also advanced nondestructive examinations such as automatic ultrasonic testing, advanced ultrasonic backscattering technique, time-offlight diffraction, and angle beam spectral analysis for walls. Some of the tests have required a sample be extracted into a boat or scoop for the test. The inspection frequency normally is determined by the

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY risk-based assessment. You can reference the API guidelines for this type of inspection methodology. For the risk-based inspection (RBI) methodology, one can establish the failure probabilities and risks and then rank the equipment. Based on the ranking, the inspection frequency can be determined. It is normally recommended to focus inspection on the highrisk equipment. The cost associated with that can be high but can be offset by reducing the inspection effort on lowrisk equipment. Blackwell Our view on reactor replacement is that we have experienced very few failures. We do not expect reactors to fail. We expect to be able to repair them as needed and operate them indefinitely. We are operating reactors that we have had in service since the mid 1960s. In one case, we are considering a replacement, but this would be an economic replacement. Generally, even for older reactors, we do not manage them as though they have a fixed end of life. We replaced two reactors that were affected by adjacent fires. We do not have much of a case history where a reactor incident or defect caused us to remove it from service. In fact, we have repaired significant cracks, bulges, and other defects. While issues are uncommon, they are generally with older reactors. We have no expectation of issues with newer reactors. Reactor age is not just calendar age. Cycles can significantly affect a reactor’s condition. We have some ongoing issues associated with high-cycle reactors. In addition, older calendar-age reactors can be less reliable and may require ongoing repairs to keep them in service due to material quality, design, and fabrication issues. However, improvements in each of these areas have significantly improved reliability for newer reactors. There have also been design improvements. For example, nozzle design and location has improved. On older reactors, nozzles are considered to be a potential weak point and are closely monitored. We seem to have fewer concerns with newer nozzles. There have been significant improvements in materials technology such as cladding, for example. Bonding methods and the degree to which cladding is bonded to the base metal is significantly superior in newer reactors. Fabrication methods have also improved. Welds are an example. Historically, the heat-affected zone around the weld has been an area of concern. Now, welds are implemented and geometrically designed to minimize the heataffected zone, which has improved reliability. For full-disclosure purposes, I mentioned that I am not a trained materials engineer. I also have no specific training in pressure vessel mechanical design, so treat my comments for this next slide as an informed third party. Unfortunately, for those who are responsible for pressure vessel inspection and reliability, there is no industry standard that specifically addresses reactor retirement. There are standards around high-pressure equipment; most notably, the FFS engineer-

Oil & Gas Journal | Sept. 7, 2015

ing assessment. However, there is not a one-stop checklist that you can use to determine whether a reactor should be repaired or retired. There may be some reprieve on the horizon, but not as near-term as you might hope. I understand that API 934-I and API 934-H covering an inspection standard and a repair standard are actively in the works. While these documents are under development, I understand that they are not imminent, and the timeframe suggested to me may be another 2 or 3 years. Also, they will likely be issued as a technical report rather than a recommended practice. We do not expect failure, but reactors can degrade if not operated and maintained correctly. On my next slide, I introduce the concept of reactor life management. Through life management, we are trying to accomplish two things. First, we are trying to limit thermal cycles, which is a fatigue issue. The intent is to maximize plant reliability and extend cycles, where possible, in order to extend the life of reactors and other pressure vessels. If you have to pull a unit offline, you should try to minimize the thermal cycling. The second issue to be managed is minimizing post-weld heat-treating cycles because this can lead to derating. Minimizing post-weld heat-treating is accomplished by managing crack and defect repairs. We use the following process to manage repairs. Cracks and defects are evaluated by highly trained specialists who make a determination about whether these cracks can be left and monitored or require immediate repair. I understand that cracks within the cladding do not generally represent a serious risk and can usually be left and monitored for propagation. Cracks and defects in the base metal will raise a higher level of concern. However, even these can sometimes be left in place. Usually they are not left as a crack; rather, they are ground out to transform them into a local thin area rather than a high-stress crack. This is how we approach reactor life management. While we have not had many failure or forced retirement issues, we are currently evaluating the economic replacement of one reactor. We have a 1960s-vintage reactor that has recurring cracks in the closure ring grooves and in the internal attachment welds, and these are all time-consuming to repair. They have added work and extended every recent shutdown. So there is an ongoing cost associated with the condition of this reactor. However, this cost is not sufficient to justify replacement. We can repair each of the defects so that the overall condition is still good enough for it to an FFS engineering assessment. We are now in the process of developing additional economic incentives to determine if replacement is justified. For example, the reactor we are evaluating is old, and older reactors tend to have a high minimum pressurizing temperature (MPT). High MPT translates into startup-shutdown risk and time, so there is an economic value that can be assigned to replacement with a lower-MPT vessel. The design of the reactor internals is dated,

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TECHNOLOGY and we know that performance can be significantly improved, in of catalyst utilization, yield, and cycle length. Finally, there are some configuration and throughput limitations. We do not yet know whether this will provide sufficient justification, but our experience suggests that economic replacement is more likely than forced retirement. I will make a final point about derating. While derating avoids forced retirement, it may provide sufficient justification for economic replacement, especially if the derated reactor can no longer meet the minimum process requirements for the service. Zaritsky If there is a crack in the cladding which is considered to be a nonissue, does that not leave the reactor more susceptible to corrosion on the base metal?

ing out for the carbon-½ moly type of reactors’ metallurgy. Based on that information, we are evaluating those reactors which have high risk and considering replacing those reactors with improved metallurgy. Hansen Okay, because we are looking at the same situation. We have a carbon-½ moly naphtha reactor which we are considering making bigger and replacing metallurgy with one constructed of 2.25% chrome -½ moly.

Driving Profitability What strategies have you utilized to balance available catalyst life in hydroprocessing units with scheduled

turnaround times, and how can this be optimized to increase profitability? Wu To balance the hydroprocessing catalyst life, we set turnaround timing where we can consider two scenarios. One is the instance where excess activity is available for the catalyst before the turnaround timing is reached; the other is when there is not enough catalyst activity available, causing the unit to have a hard time reaching the projected turnaround schedule. In this case, if there is excessive pressure drop built in the reactor, it also could impact the turnaround schedule. For the scenarios where there is excess activity available

NELSON-FARRAR COST INDEXES1 Refinery construction (1946 basis) Explained in OGJ, Dec. 30, 1985, p. 145.

Wu I believe so, yes. That particular reactor is one of the concerns for our Shell refinery. They were worried that if there is a crack or if the overlay detaches from the base material, there might be additional corrosion caused by the crack or detachment. Proops Adding to Derek’s comments, I am surprised that you did not add, “Put in a bigger reactor” to increase catalyst volume and lower your startof-run temperature to extend life. Hansen I just want to make sure I understand the changes in the Nelson curves years back; specifically, the removal of the carbon half-moly line. It sounds like Shell is saying that they are evaluating our reactors based on carbon-½ moly, and Chevron is saying that they are looking at the whole picture. However, we feel like we will not replace reactors that are carbon-½ moly based on the Nelson curves. My question is more to Kathy from Shell. Regarding the part of your naphtha reactor that you reviewed, was the replacement based on being in the zone of a carbon-½ moly? Wu Yes. Nelson Curves will be com-

94

1962 Pumps, compressors, etc. 222.5 Electrical machinery 189.5 Internal-comb. engines 183.4 Instruments 214.8 Heat exchangers 183.6 Misc. equip. average 198.8 Materials component 205.9 Labor component 258.8 Refinery (inflation) index 237.6

1980

2012

2013

2014

May 2014

Apr. 2015

May 2015

777.3

2,170.6

2,221.1

2,271.9

2,272.7

2,313.3

2,313.3

394.7

514.8

516.7

515.8

515.0

516.8

517.7

512.6

1,047.0

1,046.8

1,052.9

1,050.8

1,064.1

1,062.2

587.3

1,477.0

1,509.9

1,533.6

1,528.6

1,553.2

1,565.9

618.7

1,220.9

1,293.3

1,305.0

1,305.0

1,305.0

1,305.0

578.1

1,286.1

1,317.5

1,335.8

1,334.4

1,350.5

1,352.8

629.2

1,579.7

1,538.7

1,571.8

1,574.9

1,456.5

1,448.6

951.9

3,055.6

3,123.4

3,210.7

3,206.3

3,269.2

3,267.6

822.8

2,465.2

2,489.5

2,555.2

2,553.7

2,544.1

2,540.0

Refinery operating (1956 basis) Explained in OGJ, Dec. 30, 1985, p. 145.

Fuel cost Labor cost

1962

1980

2012

2013

2014

May 2014

Apr. 2015

May 2015

100.9

810.5

968.1

1,123.7

1,264.8

1,314.0

893.0

885.3

93.9

200.5

287.9

308.3

312.8

307.2

317.1

307.8

123.9

439.9

1,407.5

1,506.4

1,541.3

1,520.9

1,582.8

1,560.8

131.8 Invest., maint., etc. 121.7 Chemical costs 96.7 Operating indexes2

226.3

489.4

489.1

493.1

495.1

499.1

507.0

324.8

896.5

905.3

939.4

938.9

945.8

944.2

229.2

517.2

502.6

472.3

468.5

430.3

430.3

312.7

637.5

661.8

688.5

690.2

655.8

650.9

457.5

739.0

802.6

865.3

880.6

738.7

732.7

Wages Productivity

Refinery

103.7

Process units

103.6

1

These indexes are published in the first of each month and are compiled by Gary Farrar, OGJ Contributing Editor. Add separate index(es) for chemicals, if any are used. Indexes of selected individual items of equipment and materials are also published on the Quarterly Costimating page in first issues for January, April, July, and October. 3 For correct values to March 2013 refinery construction and refinery operating indexes, see OGJ, Dec. 1, 2014, p. 87. 2

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY before you reach the catalyst cycle life, you could minimize unused catalyst activity by processing more barrels of difficult feed; for example, processing more light cycle oil or coker gas oil to allow for the utilization of additional catalyst activity with more difficult feed. This type of feed may also create a higher deactivation rate, thereby allowing you to reach endof-run faster. Another way is to look at increasing the distillation endpoint of your feed, which will allow you to upgrade the lower value of feed to a higher value product and increase the profitability of the unit. This is particularly applicable for an ultralow-sulfur diesel (ULSD) unit based on the feed type. For the FCC pretreating unit, you can consider processing more barrels of feed containing higher metal contaminants since the higher metal contaminants will poison the catalyst and then cause more catalyst deactivation while utilizing the activity. Also, you can consider changing the operating mode of the FCC pretreating unit by changing from hydrodesulfurization to hydrodearomatic [and then] to a maximum aromatic saturation mode, improving the feed quality to the FCC unit, which leads to yield improvement. For instance, where there is not sufficient activity left to meet the projected turnaround schedule, several options exist to extend the catalyst cycle life. These options may have economic penalties that need to be weighed against the cost of changing the turnaround date. For a hydrotreating unit,

if your end-of-run temperature was constrained by the feed heater and the reactors were operating in the flat temperature profile, you could switch over to ascending temperature profile to get more wraparound heat in the front of the reactor in order to run the reactor hotter to extend the cycle life. If you are already operating the unit at the end-of-run temperature and want to extend the run cycle, then consider diverting some of the difficult feed to other units, or even reducing the feed rate to still be able to meet the product specification. Another way to look at this is to relax the product qualities specification. For instance, for the ULSD unit, you might consider increasing your sulfur specification in diesel product and then rebalancing the refinery’s overall sulfur specification by looking at other ULSD producers and allowing them to run a more severe operation and produce a diesel product lower in sulfur. Overall, there are many options that can be considered. The best solutions could be different for every refinery and each particular situation, depending on the refinery configuration, capability, and economics. Sharpe We have used metal dispersant chemical when we had high delta-P (pressure differential) at end-of-run conditions in our hydrocracker. It is very expensive in some of our units, but it will help you get to the turnaround. So that is just one other option to consider that is not listed on the slide.

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TECHNOLOGY

FIRST-H A LF 2015

Infrastructure issues slow first-half 2015 ethylene production Petral Consulting Co. Houston

US OLEFINS

Dan Lippe

markets absorb the additional production when the first two of five planned propane dehydrogenation (PDH) plants come on stream in fourth-quarter 2015 and second-half 2016.

In this era of tumult and constant change in the US petroleum sector, the mundane matters of infrastructure Ethylene production served as a reminder that a focus on Petral Consulting Co. tracks US ethgritty day-to-day details remains imylene production via the results of a portant to US Gulf Coast olefins promonthly survey of operating rates and ducers. feed slates. Results of the monthly Ethylene markets in Louisiana are surveys show ethylene production was chronically short, with three pipelines 150.7 million lb/day in first-quarter transporting needed supplies from 2015, down by 318 million lb (2.3%) storage in Mont Belvieu, Tex., and from fourth-quarter 2014. For secondproducers on the Upper Texas Coast. quarter 2015, survey results showed Evangeline pipeline, a Texas-to-Louethylene production at 155.8 million isiana ethylene pipeline operated by lb/day, which was an increase of 614 Boardwalk Pipeline Partners LP, was out of service million lb (4.5%) from the previous quarter. from early January to mid-June 2015. As was the Compared with the same quarter during 2014, case during the September 2013-May 2014 outage US ethylene production during first-quarter 2015 of the line, the pipeline’s operator discovered inwas up by 97 million lb (0.7%), while production tegrity problems that required many segments to during second-quarter 2015 was 1.05 billion lb be replaced before it could return to service safely. (8.0%) more than during the same period in 2014. PROCESSING With Evangeline—the largest of the three ethylProduction losses in first-quarter 2015 due to ene pipelines—out of service, the remaining pipeturnarounds and unplanned maintenance problines operated at near full-capacity, and ethylene lems stood at 1.2 billion lb, 0.9 billion lb higher prices at Choctaw Dome, the primary pricing point for eththan the same quarter in 2014. Production losses during secylene in southeast Louisiana, spiked to significant s ond-quarter 2015, however, were down 0.35 billion lb from vs. spot prices in Mont Belvieu. Alongside the pipeline’s outthe previous quarter and were 0.67 billion lb less compared age, a few Louisiana ethylene plants also experienced opwith second-quarter 2014 (Table 1). erating problems during first-half 2015, which exacerbated Compared with the final quarter of 2014, ethylene plants Louisiana’s chronic supply shortfall during second-quarter in Texas during first-quarter 2015 raised production by 2015. Despite the Evangeline pipeline’s return to full service ETHYLENE PRODUCTION Table 1 in June, ethylene production from plants in Louisiana will Heavy Light remain insufficient to meet demand, and Louisiana buyers feed feed Total 2015 ––––––––––––––– million lb/month ––––––––––––––– will remain vulnerable to future supply disruptions due to problems with ethylene pipeline infrastructure. January 372.7 4,290.3 4,663.0 February 343.7 3,864.0 4,207.8 While all major elements of industry infrastructure funcMarch 410.4 4,284.3 4,694.7 April 393.1 4,141.3 4,534.4 tioned as intended on the US Gulf Coast propylene market May 394.6 4,412.7 4,807.3 during first-half 2015, a growing inventory surplus emerged June 376.0 4,461.4 4,837.4 as the primary problem. This propylene inventory surplus Source: Petral Consulting monthly survey prompts an important question: How will US propylene

FIRST-HALF 2015

96

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY

Price, ¢/lb

Production, million lb/d

0.8 million lb/day, while first-quarUS ETHYLENE PRODUCTION* FIG. 1 ter production from Louisiana plants 200 declined by 0.9 million lb/day. The drop in production during first-quarter 2015 contributed to an increase 150 in Louisiana’s fundamental ethylene shortfall and compounded problems 100 resulting from reduced pipeline capacity following Boardwalk Midstream’s Light feeds Heavy feeds Capacity January 2015 shutdown of Evangeline 50 Jan. Apr. July Oct. Jan. Apr. pipeline for additional repairs. 2014 2015 *Cracker production from fresh feed. While Texas ethylene producers inSource: Petral Consulting Co. creased production by 4.7 million lb/ day in second-quarter 2015, producers in Louisiana boosted output by only ETHYLENE PRICES FIG. 2 0.3 million lb/day and made no mea80 surable impact on the supply shortfall. 70 Fig. 2 shows trends in ethylene pro60 duction. 50 Spot prices for crude oil and feed40 stocks fell to their recent historic lows 30 in first-quarter 2015, but by second20 quarter 2015, crude oil prices had 10 Spot Contract staged a bear-market correction. 0 Jan. Apr. July Oct. Jan. Apr. Spot prices for West Texas Interme2014 2015 diate (WTI) were $57.84/bbl in secSource: PetroChem Wire, Petral market research ond-quarter 2015, which was 19.1% higher compared with the previous quarter. Dated Brent increased by 14.8% from first-quarter ETHYLENE FEED SLATE DEMAND Table 2 2015 to average $61.92/bbl during the second quarter. The Naphtha, Ethane Propane n-Butane gas oil Organization of Petroleum Exporting Countries’ Reference 2015 ––––––––––––––––– 1,000 b/d ––––––––––––––––––– Basket for second-quarter 2015 averaged $59.90/bbl, an inJanuary 1,010.5 401.3 70.8 151.4 February 1,033.7 371.1 67.8 160.9 crease of 19.1% on the quarter. March 1,033.8 358.6 75.1 164.3 Spot prices for unleaded regular gasoline and naphtha April 1,063.3 327.6 75.1 160.0 May 1,080.4 340.0 85.2 154.6 tracked the rally in crude prices during second-quarter June 1,103.5 398.2 83.7 153.1 2015, but NGL prices generally continued to weaken. ProSource: Petral Monthly Ethylene Feedslate Survey pane prices in Mont Belvieu in the second quarter declined by 6¢/gal, or 11.5%, from first-quarter 2015. Spot prices for non-TET normal butane declined by 8.8¢/gal and were 12.8% less than in first-quarter 2015. Spot prices for purity Contract settlements for purity butadiene were essentialethane were almost unchanged during second-quarter 2015 ly unchanged during first-half 2015, averaging 31.0-31.5¢/ vs. the previous quarter. “TET” is short for “Texas Eastern lb. As spot prices for motor gasoline increased and octane Transmission” and refers to petroleum products in Texas values strengthened, spot prices for aromatics increased by Eastern storage at Mont Belvieu, Tex., now owned and op20-22% from first-quarter to second-quarter 2015. erated by Lone Star NGL LLC, an operating unit of Energy Ethylene production costs based on purity-ethane feeds Transfer Partners. “Non-TET” refers to product at Mont Belwere 10¢/lb in first-half 2015. Production costs based on vieu but in other owners’ facilities. ethane for first-quarter 2015 were only 0.25¢/lb less than in From first-quarter to second-quarter 2015, spot prices for fourth-quarter 2014 but 5¢/lb less compared with the same propylene declined by 16% (polymer-grade propylene) and quarter a year earlier. 23% (refinery-grade propylene). Contract settlements for In first-quarter 2015, purity ethane provided a cost savpolymer-grade propylene were 41.7¢/lb in second-quarter ings of 11¢/lb vs. natural gasoline, with those cost savings 2015 vs. 49.7¢/lb during the previous quarter. Spot prices for rising to 20¢/lb during the second quarter. While producrefinery-grade propylene were 29.9¢/lb in the second quartion costs for ethane and propane were the same from Febter vs. 38.8¢/lb in the first quarter. ruary through April, purity ethane lost its cost advantage

Oil & Gas Journal | Sept. 7, 2015

97

TECHNOLOGY

Margin, ¢/lb

ETHYLENE PROFIT MARGINS* 70 60 50 40 30 20 10 0 –10

Jan.

Apr.

*Spot price less cash cost. Source: Petral Consulting analysis

July 2014

Oct.

ETHYLENE PRODUCTION COSTS 2015 January February March April May June July

Jan.

Table 3

Natural Ethane Propane n-Butane gasoline ––––––––––––––––––––– ¢/lb –––––––––––––––––––––– 10.1 9.7 9.9 9.4 10.2 10.1 9.8

4.6 9.3 8.9 10.9 6.2 2.4 5.9

4.5 3.4 3.6 5.3 2.6 0.6 2.5

13.9 24.8 23.9 30.0 30.8 27.5 28.2

Source: Petral Consulting estimates

vs. propane in May-June due to a crash in propane prices. Ethane’s cost disadvantage was 4¢/lb in May and 7.5-8.0¢/ lb in June. Production costs for purity propane averaged 7.6¢/lb in first-quarter 2015 before falling to 6.5¢/lb in the second quarter. Production costs for purity propane in first-quarter 2015 were just 3¢/lb less vs. fourth-quarter 2014 but 26¢/lb less vs. first-quarter 2014. In first-quarter 2015, production costs for propane provided producers with a cost savings of 13¢/lb less vs. natural gasoline, with propane’s cost advantage rising to 23¢/lb during the second quarter. Production costs for natural gasoline dipped to 14¢/lb in January but rallied in February-March to average 24-25¢/lb for first-quarter 2015. Production costs for natural gasoline during second-quarter 2015 were almost 30¢/lb (Table 3).

Ethylene pricing, profit margins PetroChem Wire daily reports (www.petrochemwire.com) showed spot prices for ethylene in the Williams Hub averaged 36¢/lb in first-quarter 2015, some 18¢/lb (33%) less than in fourth- quarter 2014. Spot prices stabilized in second-quarter 2015 to average 35-36¢/lb. Even though the Evangeline pipeline remained out of service during first-quarter 2015, spot prices at Choctaw Dome declined by 16¢/lb (January 2015 vs. October 2014). Consistent with the loss of Evangeline pipeline capacity, however, s at Choctaw Dome vs. Williams Hub jumped

98

to 10¢/lb in January 2015 vs. 0.4¢/lb in October 2014 and increased to 16.8¢/ Purity ethane lb in March. During second-quarter Natural gasoline 2015, spot prices at Choctaw Dome inGas oil creased to 51¢/lb, while s vs. Williams Hub were 14¢/lb in April and May before spiking to almost 20¢/lb in June. Net transaction prices (NTP) in first-quarter 2015 averaged 34.75¢/ Apr. lb, 10¢/lb less than in fourth-quarter 2015 2014. Even though production costs for high-cost feedstock increased during this year’s second quarter, NTP was almost unchanged, averaging 34.2¢/lb for the quarter. NTP did not dip below 34¢/lb until June, and even then, only to 33.75¢/lb. Margins based on NTP were 23-25¢/lb for purity ethane during first and second-quarter 2015, but margins vs. propane were 27¢/lb in the first quarter before increasing to almost 28¢/lb in the second quarter. Margins for natural gasoline and light naphtha of similar quality were 14¢/lb in first-quarter 2015 but fell to 5¢/lb in the following quarter. Fig. 2 shows historic trends in ethylene prices (spot prices and NTP). Fig. 3 shows profit margins based on spot ethylene prices and variable production costs. FIG. 3

Olefin-plant feed slate trends Petral Consulting’s monthly survey of plant operating rates and feed slates showed ethylene industry demand for fresh feed was 1.65 million b/d in first-quarter 2015 and 1.70 million b/d in second-quarter 2015. Demand for fresh feed in first-quarter 2015 was 6,600 b/d (0.4%) more than in fourth-quarter 2014 and 25,700 b/d (1.6%) more than in first-quarter 2014. Demand for NGL feeds (ethane, propane, and normal butane) was 1.49 million b/d in first-quarter 2015 and 1.54 million b/d in second-quarter 2015. Demand for NGL feed in first-quarter 2015 was 1,500 b/d (0.1%) less than in fourth-quarter 2014 and 25,400 b/d (1.7%) more than in first-quarter 2014. Demand for NGL feed in second-quarter 2015 was 45,700 b/d (3.1%) more than in first-quarter 2015 and 124,300 b/d (8.8%) more than in second-quarter 2014. NGL feeds ed for 90-91% of fresh feed in first-half 2015 (Table 2). Fig. 4 shows historical trends in ethylene feed.

US propylene production Coproduct propylene supply depends primarily on the use of propane, normal butane, naphtha, and other heavy feeds. The monthly survey shows demand in first-quarter 2015 was 380,700 b/d for propane, 72,900 b/d for normal butane, and 162,000 b/d for heavy feeds. In second-quarter 2015, demand for propane was 357,000 b/d, demand for normal butane was 83,300 b/d, and demand for heavy feeds was 160,800 b/d.

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY

COPRODUCT PROPYLENE FROM ETHYLENE PLANT 2015 January February March April May June

Table 4

From From light feeds heavy feeds Production (est.) –––––––––––––– Million lb/month ––––––––––––––––– 530.3 452.4 500.3 455.9 498.1 530.5

181.2 172.2 196.1 186.9 185.0 178.6

711.5 624.6 696.4 642.8 683.1 709.1

Source: EIA Petroleum Supply Monthly

Total demand for feeds with high propylene yield was 615,600 b/d in first-quarter 2015, 34,100 b/d (5.9%) more than in fourth-quarter 2014. Total demand for these feeds in second-quarter 2015 was 601,100 b/d, 14,500 b/d (2.4%) less than in first-quarter 2015. As economic incentives for propane and normal butane compared with ethane improved during second-quarter 2015, ethylene producers maintained demand for heavy feeds and increased their use of propane and butane during May and June. Demand for feedstocks with high propylene yields was 641,400 b/d in June and was 34,700 b/d more than in March. Petral Consulting estimates coproduct supply was consistently above 22 million lb/day throughout first-half 2015. Coproduct supply was 22.6 million lb/day in first-quarter 2015 and 22.4 million lb/day in second-quarter 2015. Coproduct supply for first-quarter 2015 was 195 million lb (10.6%) more than in first-quarter 2014, while coproduct supply during this year’s second quarter was 163 million lb (8.7%) more than in second-quarter 2014. Coproduct supply from light feeds averaged 16.5 million lb/day in first-quarter 2015 and 16.3 million lb/day in second-quarter 2015. Production from light feeds in firstquarter 2015 was 199 million lb (15.5%) more than in firstquarter 2014, while production from light feeds in secondquarter 2015 was 169 million lb (12.8%) more compared with the same period last year. The key factor for the increase in coproduct supply in first-quarter 2015 was the increase in demand for propane compared with demand the previous year. Demand for propane in first-quarter 2015 was 74,800 b/d (24.4%) more than in first-quarter 2014. In second-quarter 2015, demand for all light feeds increased by 45,700 b/d, while demand for propane and butane declined by 13,400 b/d. The increase in total light feed demand offset the decline in demand for propane and normal butane (Table 4).

PDH plant, refineries According to PetroChem Wire, the PDH plant in the Houston Ship Channel operated at full capacity in first-quarter 2015 but had some downtime for maintenance in April and June. Downtime reduced propylene production by 1.2-1.3 million lb/day in April 2015 and by 0.7-0.8 million lb/day in June 2015.

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TECHNOLOGY Statistics from the US Energy Information istration (EIA) indi2.0 cate US refineries operated FCCUs at 4.5 million b/d in first-quarter 2015 1.5 and an estimated 4.9-5.1 million b/d in second-quarter 2015. Feed rates 1.0 for all FCCUs in first-quarter 2015 were 401,000 b/d (8.2%) less than in 0.5 fourth-quarter 2014 and 93,300 b/d Ethane Propane Others (2.0%) less than in first-quarter 2014. 0.0 Jan. Apr. July Oct. Jan. Apr. The drop in FCCU feed rates in first2014 2015 quarter 2015 was consistent with seaSource: Petral Consulting Co. sonal patterns in refinery crude runs. Regionally, EIA statistics showed feed rates for FCCUs in the US Gulf PROPYLENE PRODUCTION, SALES FIG. 5 Coast and Midcontinent were 3.36 mil100 lion b/d in first-quarter 2015, 268,300 80 b/d (7.4%) less than in fourth-quarter 2014. Feed rates for these FCCUs were 60 3.65-3.75 million b/d in second-quarter 2015, 365,000 b/d (10.9%) more 40 than in first-quarter 2015. 20 EIA reported propylene production Refinery merchant sales Coproduct supply from all US refineries was 46.5 mil0 Jan. Apr. July Oct. Jan. Apr. lion lb/day in first-quarter 2015 before 2014 2015 increasing to 50.3 million lb/day in Source: US Energy Information istration, Petral estimates April. Petral Consulting estimates refinery-grade propylene was 52.0-52.5 million lb/day in May and June and was 51.5-51.7 million lb/ Feedstock prices, coproduct values, and ethylene plant yields day for second-quarter 2015. US production in first-quarter determine ethylene production costs. Petral Consulting maintains 2015 was 772 million lb (15.6%) less than in fourth-quardirect with the olefin industry and tracks historic trends in ter 2014 and 378 million lb (8.3%) less than in first-quarter spot prices for ethylene and propylene. We use a variety of sources to track trends in feedstock prices. 2014. Some ethylene plants have the necessary process units to convert Refineries in the Gulf Coast and Midcontinent are the priall coproducts to purity streams. Some ethylene plants, however, do mary supply sources of refinery-grade propylene for cheminot have the capability to upgrade mixed or crude streams of varical markets in the Gulf Coast. EIA reported production from ous coproducts and sell some or all their coproducts at discounted refineries in the Gulf Coast and Midcontinent was 40.2 milprices. We evaluate ethylene production costs in this article based on all coproducts valued at spot prices. lion lb/day in first-quarter 2015 and 44.0-45.0 million lb/ day in second-quarter 2015. Production from Gulf Coast and Midcontinent refineries in first-quarter 2014 was 667 Petral estimates propylene supply from the PDH plant million lb (15.6%) less than in fourth-quarter 2014 and 362 was 3.8-3.9 million lb/day in first- quarter 2015 and 2.9-3.1 million lb ( 9.1%) less than in first-quarter 2014 (Table 5). million lb/day in second-quarter 2015. Refinery propylene sales into the merchant market are a Propylene economics, pricing function of: EIA statistics for refinery-grade propylene and Petral Con• Fluid catalytic cracking unit (FCCU) feed rates (most sulting’s estimates for coproduct supply indicate total US propylene supply was 73.0 million lb/day in first-quarter important variable). 2015 and 76.5-77.5 million lb/day in second-quarter 2015. • FCCU operating severity (important but not directly While the increase in coproduct supply for first-half 2015 vs. measurable). first-half 2014 was significant, the decline in refinery supply • Economic incentive to sell propylene rather than use it reduced total supply by 1.6 million lb/day. as alkylate feed. Fig. 5 shows trends in coproduct and refinery merchant Variations in FCC unit feed rates are the most important propylene sales, as reported by EIA. parameter. Economic factors affect operating severity and Two factors greatly influence propylene pricing. Refineryare generally of secondary importance. FIG. 4

Volume, million lb/day

Feed, million b/d

US ETHYLENE PLANT FEED SLATE

100

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY grade propylene supply tracks seasonal variations in refinery crude runs and FCCU feed rates. Seasonal variations in refinery crude runs and FCCU feed rates are reasonably predictable, and propylene supply-demand balances are usually tighter in winter than in summer. Propylene price relationships vs. unleaded regular gasoline vary directly with seasonal variations in the propylene supply-demand balance. Under normal market conditions, propylene in reportable US Gulf Coast storage facilities varies by ±25% of the midrange of long-term historic inventory levels. Occasionally, however, inventory levels fall outside the historic range. When inventory in reportable storage at the Gulf Coast increases to more than 770 million lb, spot prices for refinerygrade propylene tend to decline and s vs. unleaded regular gasoline weaken. In October 2014, propylene inventory in reportable storage was 455 million lb, which was at the bottom of the historic range. According to EIA statistics, during the next 6 months, inventory of refinery-grade propylene in Gulf Coast storage increased by 415 million lb to stand at 870 million lb on May 1, about 100 million lb above the historic range. EIA’s weekly statistics indicate propylene inventory in reportable Gulf Coast storage increased to 950-980 million lb during May-June and was 960-975 million lb as of July 1. At this level, propylene inventory was about 180-200 million lb (25%) more than the high end of the historic range. Since refinery grade propylene production was at its seasonal peak and inventory was already near its historic record high of 1 billion lb, bearish pressures on propylene prices increased. According to PetroChem Wire, spot prices for refinerygrade propylene were 41¢/lb in February 2015 vs. 40¢/lb in December 2014 and 36¢/lb in January 2015. As production of refinery-grade propylene recovered and inventory continued to rise, spot prices fell by about 10¢/lb during MarchJune and by an additional 4-5¢/lb in July. Refinery-grade propylene prices were 29¢/lb in June and 23-24¢/lb in July. During first-quarter 2015, refinery-grade propylene prices were 14¢/lb more than unleaded regular gasoline prices before falling 2¢/lb below parity to unleaded regular gasoline prices in May and to a discount of 4.5¢/lb below gasoline in June. The swing from a of 15¢/lb in January to a discount of almost 5¢/lb in June was the result of the seasonal increase in supply and the growing inventory surplus. In first-quarter 2015, the contract benchmark for polymer-grade propylene was 49.7¢/lb. Contract settlements fell by 9¢/lb during second-quarter 2015 to 40¢/lb in June and to 36.5¢/lb in July. s for contract polymer-grade propylene prices vs. refinery-grade propylene were 9-13¢/ lb in first-quarter 2015, with an average of 10.9¢/ lb for the quarter. Contract polymer-grade propylene’s price to refinery-grade propylene rose to 13¢/lb in April before weakening to 10.8¢/lb in June.

Oil & Gas Journal | Sept. 7, 2015

REFINERY PROPYLENE PRODUCTION 2015

Table 5

Texas South Other Gulf Coast Louisiana areas Total ––––––––––––––––– Million lb/month –––––––––––––––––

January February March April May June

599.7 525.5 573.6 600.0 575.4 602.2

566.2 454.1 372.9 486.5 593.6 582.3

377.4 325.0 391.9 423.3 443.5 379.3

1,543.3 1,304.7 1,338.3 1,509.7 1,612.5 1,563.8

Source: EIA Petroleum Supply Monthly, Petral estimates

Polymer exports The most important end-use markets for ethylene and propylene are production of polyethylene and polypropylene. US production of polyethylene and polypropylene has been surplus to domestic demand for at least 30 years, and export markets have always absorbed the surplus in US supplies. Export sales, however, were generally 20-25% of domestic production for polyethylene and 15-20% for polypropylene. With this article, we expand the scope of the series to include an overview of US exports of the industry’s primary polymers. As petrochemical companies expand ethylene and PDH plant capacities, the US will triple or quadruple its polyethylene exports to destinations other than Canada and Mexico, as well as double or triple its polypropylene exports. Braskem Idesa SAPI, a 75-25 t venture of Braskem SA, Sao Paulo, and Groupo Idesa SA de CV, Mexico City, is nearing completion of its long-planned Etileno XXI petrochemical complex in the Coatzacoalcos-Nanchital region of the Mexican state of Veracruz (OGJ, July 7, 2014, p. 90; July 1, 2013, p. 90; OGJ Online, May 12, 2015). The ethane-based complex, which is scheduled to be commissioned in September 2016, will expand Mexico’s ethylene and polyethylene production capacity by 2 billion lb/year. While US exports of polyethylene to Mexico in 2014 averaged 2.3 billion lb/year, once Etileno XXI reaches full-production capacity, Mexico’s supply shortfall will shrink by up to 90%. The Braskem-Idesa venture will be the first in a series of new polyethylene production capacity increases that will radically transform the US petrochemical industry’s market scope.

Polyethylene According to US International Trade Commission (ITC) statistics, US exports of polyethylene (high-density polyethylene, low-density polyethylene, and linear low-density polyethylene) during 2010-14 were relatively constant within a range of 18-20 million lb/day, with 45-50% of those exports moving to Canada and Mexico. US polyethylene exports during 2013 averaged 19.4 million lb/day.

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TECHNOLOGY Due to various US ethylene plant outages in 2014, polyethylene exports last year averaged 18.1 million lb/day, which was down by 1.3 million lb/day (6.5%) compared with 2013. Exports were 20.2 million lb/day in first-quarter 2014 but fell to 15.9 million lb/day in fourth-quarter 2014. Polyethylene exports in first-quarter 2015 rose by 1.9 million lb/day (12%) from the last quarter of 2014 to 17.8 million lb/day before climbing to 21.4 million lb/day in April and 22.5 million lb/day in May. In April, combined polyethylene exports to Canada and Mexico were 10.2 million lb/ day, while exports to those same destinations in May were down slightly at 9.4 million lb/day. US polyethylene exports to all other rest-of-world (ROW) destinations averaged 7.2 million lb/in both fourth-quarter 2014 and first-quarter 2015 before rising to 11.3 million lb/ day in April and 13.9 million lb/day in May.

Propylene, polypropylene ITC statistics show US exports of propylene monomer were 2.1 million lb/day in 2007 but declined steadily during 2008-14 to only 0.6 million lb/day in 2014. During 2008-13, shipments to Colombia ed for 75-95% of monomer exports. In 2007 and 2008, monomer exports to Colombia averaged 1.25 million lb/day and 1.21 million lb/day, respectively, before falling below 1 million lb/day in 2010 and 0.4 million lb/day in 2014. Shipments to Colombia in 2014 ed for just 65% of total exports. Total US polypropylene exports were 12.1 million lb/day in 2007 but declined steadily during 2008-14 to just 5.9 million lb/day in 2014, according to ITC data. Similar to the geographic disposition of US polyethylene exports, Mexico and Canada were the primary destinations for US polypropylene exports, which averaged 5.6 million lb/day in 2007 and ed for 46.6% of total exports. During the past 10 years, exports to Mexico averaged 2.5-3.5 million lb/day, while exports to Canada were 1.5-2.0 million lb/day. In 2014, exports to Mexico and Canada were 4.5 million lb/day, which ed for 76% of US polypropylene exports, according to ITC statistics. Exports to ROW destinations were 4.0-6.0 million lb/day during 2006-2009 but declined steadily during 2010-14 to only 1.4-1.5 million lb/day in 2013-14. Polypropylene exports to all destinations were 5.5 million lb/day in first-quarter 2015, and Petral Consulting estimates exports averaged 6.4-6.5 million lb/day in second-quarter 2015. US exports to Mexico and Canada were 4.3 million lb/ day in first-quarter 2015, with estimated exports of 4.2-4.5 million lb/day during second-quarter 2015.

Second-half 2015 The outlook for ethylene during second-half 2015 depends on trends in production costs and demand for derivatives. The increase in exports of polyethylene during second-quar-

102

ter 2015 is a positive indicator for ethylene demand in second-half 2015. Petral Consulting forecasts polyethylene exports for second-half 2015 will mirror second-quarter levels and may increase further. The increase in ethylene demand will require an increase in ethylene production, as well as limit an accumulation of ethylene inventory. This leads to a positive market outlook for ethylene in the near term. The economic outlook for ethylene is a function of feedstock and coproduct prices, with trends in crude oil prices determining price trends for both feedstock and coproducts. Crude oil price forecasts are always subject to uncertainty, and forecasts for second-half 2015 are no exception. The conclusion of negotiations between Iran and the world’s major powers on development of nuclear weapons resolved one major source of uncertainty for second-half 2015 and first-half 2016. These negotiations concluded with a formal agreement that, if approved, will result in an end to economic sanctions and oil export embargoes against Iran imposed by the US and European Union. Even though timetables for the ending of economic sanctions against Iran remained sources of uncertainty in late June, crude oil markets responded bearishly immediately following formal announcement of the agreement. At some point in the next 6-12 months, sanctions will be lifted and Iran will increase both production and exports of crude oil by as much as 1 million b/d. In the first few weeks following announcement of the agreement, spot prices for WTI, dated Brent, and OPEC Reference Basket declined 10-15%, with crude prices during July testing the low levels of first-quarter 2015. Petral Consulting’s forecasts for second-half 2015 are based on prices for dated Brent in the range of $45-55/bbl and prices for WTI in the range of $42-48/bbl. The primary consequence of weaker crude oil prices will be weaker prices for heavy feeds. Prices for light feeds (propane and butane), however, were unduly depressed during May and June and are likely to rebound in fourth-quarter 2015 as seasonal factors result in tighter supply-demand balances. During first-half 2015, US Gulf Coast ethylene producers operated in an environment in which production costs for natural gasoline were 10-20¢/lb more than costs for ethane. Differences between production costs for natural gasoline and ethane moved from the lower end of the range in first-quarter 2015 to the higher end of the range in secondquarter 2015. Based on a crude oil price forecast similar to that of firstquarter 2015, differentials in production costs between ethane and natural gasoline (and light naphtha of similar quality) most likely will be 5-10¢/lb. The same logic will apply to differentials in production costs between propane and natural gasoline. While differentials in production cost will be less than in first-half 2015, light feeds will remain the

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY low-cost feedstocks and ethylene producers will continue to operate with maximum light feeds. Production costs for heavy feeds will be lower in second-half 2015, but the decline in spot ethylene prices during first-half 2015 squeezed margins for natural gasoline to 5-8¢/lb in second-quarter 2015 vs. 25-30¢/lb in second-half 2014. In the best case scenario, spot ethylene prices will remain steady at 30-35¢/lb during second-half 2015. If ethylene inventory reaches a surplus level, however, spot prices may fall as low as 20-25¢/lb. The outlook for propylene is bleaker. Refinery crude runs and FCCU feed rates in the US Gulf Coast and Midcontinent will decline in September or October but will rebound in November and December. Refinery-grade propylene production will remain near peak-seasonal levels until firstquarter 2016. At the same time, coproduct supply likely will be 1.0-1.5 million lb/day less in fourth-quarter 2015 compared with the third quarter, but propylene inventory in reportable Gulf Coast storage will remain above the normal range. Based on these considerations, Petral Consulting fore-

casts spot prices for refinery-grade propylene will average 21-24¢/lb, while polymer-grade propylene spot prices will average 32-35¢/lb.

The author Daniel L. Lippe ([email protected]) is president of Petral Consulting Co., which he founded in 1988. He has expertise in economic analysis of a broad spectrum of petroleum products including crude oil and refined products, natural gas, natural gas liquids, other ethylene feedstocks, and primary petrochemicals. Lippe began his professional career in 1974 with Diamond Shamrock Chemical Co., moved into professional consulting in 1979, and has served petroleum, midstream, and petrochemical industry clients since. He holds a BS (1974) in chemical engineering from Texas A&M University and an MBA (1981) from Houston Baptist University. He is an active member of the Gas Processors Suppliers Association and serves on GPA’s NGL Market Information Committee.

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TECHNOLOGY

DELEK REFINERY E X PANSION —1

Nontraditional approach to refinery revamp cuts time, adds flexibility James W. Jones Turner, Mason & Co. Dallas

Frank Simmons

TRADITIONAL DEVELOPMENT

FIG. 1

NONTRADITIONAL DEVELOPMENT

Refiner conceives project

Consultant, EPC firm conceive project

Refiner establishes design basis

Refiner authorizes process study

Refiner awards process design work

Consultant, EPC firm perform process study, process design

Engineering firm completes process design

Consultant prepares project economics

Refiner prepares preliminary project cost estimates, economics

Consultant, EPC firm, and refiner establish design basis

Consultant reviews project economics

EPC firm completes infrastructure review, process design

FIG. 2

Delek Refining Inc. Tyler, Tex.

Tony D. Freeman KP Engineering LP Tyler, Tex.

Delek Refining Inc., a subsidiary of Delek US Holdings Inc., Brentwood, Tenn., used a nontraditional project development and execution approach to expand crude oil processing capacity by 20% at its refinery in Tyler, Tex. This article, the first of a two-part series, discusses project planning and execution. Delek collaborated with its refining consultant, Turner, Mason & Co. (TM&C), and preselected engineering, procurement, and construction (EPC) contractor KP Engineering LP (KPE), to implement the new approach. A fundamental feature of the nontraditional approach used for the Tyler refinery expansion project was the belief that refineries should not be bottlenecked by low-cost process units. This approach additionally emphasized identification of high-return modifications leveraging the refinery’s existing process units and ing installations before determining the eventual design basis.

Based on a presentation to the 2015 AFPM Annual Meeting, Mar. 22-24, 2015, San Antonio, Tex.

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Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY The Delek refinery expansion’s basic concept specifically followed TM&C’s experience that bottlenecks in distillation and hydrotreating units should not cause low utilization of refinery conversion units. Growth in light domestic crude oil production has exacerbated this phenomenon. Part 2 of this article will describe the specific modifications made at the refinery, which in addition to expanding overall capacity, simultaneously improved the refinery’s rates of distillate recovery and its ability to process lighter feedstock.

Project conception, development TM&C and KPE conceived the preliminary proposal for the expansion project in early 2013. Delek approved a phased study for the project based on principles TM&C and KPE used in previous collaborations, leading over 10 months to the reconfiguration used for the Tyler expansion. The approved expansion project involved modifications to the atmospheric and vacuum distillation units, naphtha hydrotreater (NHT), diesel hydrotreater (DHT), and saturate gas unit, as well as a minor but important modification to the delayed coker’s fractionator. Detailed design on the project was developed in collaboration with Delek staff and was based on the TM&CKPE team’s focus on debottlenecking distillation and low-to-medium hydroprocessing operations instead of more costly modifications to conversion units such as fluidized catalytic crackers (FCCs), hydrocrackers, continuous catalytic reformers (CCRs), and delayed cokers. Since its acquisition by Delek in 2005, crude rates at the refinery have steadily climbed in response to the growth in domestic light crude oil volumes and widening crack spreads. The refinery, which historically was constrained by FCC capacity, also became limited by the NHT, DHT, saturate gas,

Oil & Gas Journal | Sept. 7, 2015

and crude units as its Permian basin crude supply became lighter. While its extra coking capacity processed a sister refinery’s excess vacuum bottoms, the refinery’s CCR became underused. The FCC remained full, but more than 25% of its feed was distillate boiling-range material. TM&C and Delek believed overall refining capacity could be increased by improved recovery of distillate boilingrange material from the atmospheric (AGO), light vacuum (LVGO), and heavy coker gas oil (HCGO) streams and the resultant indirect increase in FCC capacity. To validate this concept, TM&C approached KPE, with whom it had previously collaborated on a similar expansion project featuring a high-incremental distillate yield at a refinery in Wynnewood, Okla., for its perspectives on the possibility of increasing distillate recovery at the Tyler plant. In addition to its experience on the Wynnewood project, which involved installation of a new vacuum unit equipped with an upper-fractionation zone, KPE had previously designed the revamp of an existing vacuum tower for increased distillate recovery at a refinery in Cheyenne, Wyo. The distillate present in Delek’s AGO and LVGO streams stemmed from simple equilibrium and not subpar fractionation in the crude unit’s atmospheric tower, and KPE concluded that much of the distillate being left in the Tyler refinery’s FCC feed could be recovered by modifying the vacuum tower. An expansion of the crude unit’s overall capacity with the addition of a preflash tower appeared feasible, and was logical given the increasingly lighter feed. Assuming NHT and DHT capacity increases could be made in a cost-effective manner, a refinery expansion on the order of 15-25% was obtainable for a reasonable cost. Further, the combination of improved distillate recovery and robust distillate crack spreads offered potentially favorable project economics.

TRADITIONAL EXECUTION

FIG. 3

Refiner submits process design for FEED package bids

Refiner reviews bids, awards FEED package preparation

Engineering firm prepares FEED package, improved cost estimate

FEED package submitted to EPC firms for bids

EPC firms prepare bids based on FEED package

Refiner reviews EPC bids, awards project

The entire project, however, rested on distillate recovery from the FCC feed.

Phases 1, 2, and 3 The next step was to obtain funding for a process study. Delek wanted assurances of feasibility before commit-

105

TECHNOLOGY

NONTRADITIONAL EXECUTION

FIG. 4

EPC firm advances design to point required for LSTK proposal

Refiner, consultant update project cost estimate, economics

Refiner accepts LSTK proposal (or elects to pursue FEED package under traditional approach)

ting to a significant design effort, so a phased approach to the process study was proposed. The initial phase would solely focus on the degree of distillate recovery that could be obtained and how much expansion that would allow in of additional space in the FCC. As much as 3,000 b/cd of distillate could be recovered from the refinery’s typical 62,000-b/cd charge rate of 41°

API crude. This recovery would require a vacuum tower top replacement similar to that used at the Cheyenne refinery, which would yield as much as 2,000 b/cd of additional straightrun diesel from the AGO and LVGO streams. Another 1,000-b/cd of distillate could be recovered from the HCGO stream via additional heat removal in the upper sections of the coker fractionator. This volume of distillate recovery suggested that another 12,000b/cd of crude runs were possible when only considering the FCC capacity limit. Based upon its own outlook for long-term prices, TM&C developed proforma refinery economics for a 75,000-b/cd operation, which indicated a potential increase in pretax net refinery margin of about $40 million/ year following project completion. This economic potential prompted a second, more detailed process study to identify cost-effective modifications to the crude tower and downstream units geared toward increasing overall refinery capacity to as much as 75,000 b/d. Aware of the potential for the refinery to face even lighter feedstock options, Delek requested that any new additions and modifications accommodate crude oil with a gravity up to 42.5º API. Delek, TM&C, and KPE

PROJECT SCHEDULE, DELEK TYLER REFINERY EXPANSION Task

2013 1st 2nd Phase 1, conceptual review Phase 2, conceptual design Phase 3; detailed design, cost estimate Detailed engineering Procurement, delivery; long-lead equipment Procurment, delivery; all other equipment Field construction, diesel hydrotreating Mechanical completion, diesel hydrotreating Field construction, naphtha hydrotreating Mechanical completion, naphtha hydrotreating Field construction, crude and vacuum distillation

Mechanical completion, crude and vacuum distillation Turnaround

106

3rd

4th

2014 1st 2nd

FIG. 5 3rd

4th

2015 1st

also recognized that a number of other improvements could be implemented at a reasonable cost as part of the proposed project. Phase 2 identified the most costeffective modifications needed at each process unit and confirmed the project’s design basis. This approach, which placed much of the design work ahead of establishing the basis for design, deviated from traditional project methodology and can be troubling for some refiners. It, however, led to the most cost-effective design for revamp and debottlenecking, especially with the refiner’s staff working in collaboration. Delek allowed employees from across a broad spectrum of responsibilities to contribute to project development and design, maximizing the project’s overall economic return. Fig. 1 shows the traditional approach to project development. Fig. 2 shows the nontraditional approach TM&C, KPE, and Delek used for the Tyler expansion project. The Phase 2 study considered the potential impact of infrastructure limitations and constructability issues. These steps typically occur later in the traditional project approach, but tailoring the eventual process modifications to the constraints presented by the refinery’s plot plan and ancillary units was the only way to achieve costeffective design. In order to limit spending, Phase 2’s scope took in only fundamental process design. Upon completion and review of the Phase 2 process design in August 2013, Delek approved a third and final study phase to flesh out the project to the extent needed for a go-or-no-go decision. Phase 3 included: • Piping and instrumentation diagram development. • Equipment sizing and quotations. • Identification of bulk civil, piping, structural, and electrical needs. • Final plot plans.

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY • Utility balances. • Outside battery limits (OSBL) needs. • Project schedule. • Cost estimate.

PROJECT BUDGET, DELEK TYLER EXPANSION

A few long-lead items had been ordered, on an item-by-item basis, during fourth-quarter 2013, prior to full completion of the Phase 3 study. Engineering Because Delek had a and procurement activiturnaround (T/A) schedties continued for several uled to begin end-January months. Following formal 2015, the detailed design approval of the project, OSBL 8% work needed to incorporate Delek and KPE agreed to Owner’s costs 6% the ability to bring certain execute the pre-T/A inside Contingency 12% modifications on-stream battery limits (ISBL) work Coker expansion 1% independently of the exon an LSTK basis. An upDHT expansion 38% isting units in the event dated scheduled for the Crude, vacuum distillation equipment deliveries and project followed Delek’s forexpansion 18% ISBL, 73% the construction schedule mal approval (Fig. 5). The NHT, saturate gas didn’t allow completion by revised scheduled called expansion 8% the end of the T/A. for initial site construction Owner improvements* 8% Final design included activities to begin in July * The final detailed design for the Tyler expansion project was structured for Delek to bring forward nonexpantwo parts: pre-T/A and T/A. 2014, with pre-T/A modifision-related modifications and improvements under the LSTK package ahead of the refinery’s scheduled turnTo limit cost and ensure cations to the crude, vacaround in January 2015. good control of the project, uum, NHT, and saturate final design maximized the gas units due for mechaniamount of pre-T/A work that could be Tyler refinery project differed considcal completion by end-2014. executed independent of refinery operably from the traditional route taken The DHT work, which determined erations, avoiding the more intense atby operators. Under the more tradithe project’s path, carried into Febmosphere (and higher cost) associated tional approach, operators establish a ruary 2015, but still finished before with T/A activity. This approach would design basis and prepare a process decompletion of the refinery’s scheduled also maximize the amount of work sign package, after which they obtain T/A. Project work that could only be that could be executed, if desired, on a a front-end engineering and design performed during the T/A would be lump-sum turnkey (LSTK) basis. (FEED) package, develop a more deexecuted on a reimbursable basis by The design effort also sought to finitive cost estimate, and finally solicDelek’s T/A contractors under the diminimize the burden a 20% capacity it competitive bids. rection of Delek’s in-house project increase would have on the refinery’s Fig. 3 shows the traditional apteam. The required OSBL modificaexisting utility provider and infraproach. tions were to be executed under the structure, bearing in mind how exBy obtaining an LSTK proposal same approach but by contractors that ceeding the tipping point on ancillary from KPE for the pre-T/A portion of Delek typically employed for small equipment could significantly increase the work, which was something KPE jobs. OSBL costs. agreed to submit upon completion of TM&C continued to act on Delek’s the Phase 3 study, Delek shortened the behalf throughout project execution Project execution schedule needed to execute the projby assisting Delek’s in-house project From project inception, TM&C enect while retaining sufficient cost cermanagement team, resolving certain couraged Delek to sole-source an tainty. project issues with KPE, participating LSTK agreement with KPE because of TM&C advocated that there was in hazard and operability reviews, and the companies’ collaborative experigreater potential economic benefit to assisting in the design and execution ences with each other on several simiDelek by shortening the schedule than of the OSBL work. lar projects at the Wynnewood refinexecuting the project in a traditional TM&C also helped Delek: ery, one of which was executed on a manner. This fast-track, nontradition• Update its operating procedures. sole-source basis. Based on the success al approach also allowed for comple• Train employees on of that project, TM&C was convinced tion of any relevant tie-in work needed changes. that this would be the most cost-effecahead of the T/A (Fig. 4). • Commission and start-up posttive approach for Delek. The placing of purchase orders folproject. The execution plan chosen for the lowed tentative project approval.

108

FIG. 6

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY

POST-EXPANSION INCREMENTAL PRODUCTION YEILDS FIG. 7 Gasoline 17% Coke, sulfur, and refinery offgas 2% Other liquids, 6%* NGLs 4%

ULSD, 71% *This can include FCC-clarified oil and summer pentanes.

This continued presence minimized scope creep.

Project cost, economics The project’s budget was $70 million, of which about 65% went toward ISBL additions and modifications associated with the refinery’s actual expansion. Another 8% went toward owner-driven ISBL improvements not specifically related to the expansion project. About 80% of that collective ISBL amount involved work executed by KPE and included under the LSTK agreement. OSBL work constituted only 8% of the budget, with the remainder going toward owner’s costs and contingency. Fig. 6 shows the budget for the Tyler refinery expansion project. The project’s final cost met the budget amount. The refinery’s increased crude processing capacity will also yield a large volume of ultralow-sulfur diesel on an incremental basis (Fig. 7). Based on May 2015 crude oil and refined products future prices, the project’s anticipated economic benefits currently appear more attractive than projected and should result in a

Oil & Gas Journal | Sept. 7, 2015

simple pretax payback period of 15-18 months. The second installment of this article will provide details of the specific modifications made to achieve processing improvements included as part of the refinery’s expansion.

The authors James W. Jones (jwjones@turnermason. com) is a senior vicepresident with Turner, Mason & Co. He leads assignments that involve refinery process technology studies, project management, and petroleum economics. Jones ed the firm in 1994 after 18 years with La Gloria Oil & Gas Co., where he held numerous positions at their Tyler, Tex., refinery, including 8 years as operations manager. He holds a BS in chemical engineering from the University of Texas, Austin, and an MBA from the University of Texas, Tyler. Jones is a licensed professional engineer in Texas.

Frank Simmons (frank. simmons@delekrefining. com) is vice-president of refining best practices for Delek Refining Ltd., where he works with both the Tyler and El Dorado, Tex., refineries to identify and implement best practices in all areas of operations. He previously served as manager of Delek’s Tyler refinery, before which he worked as a process engineer with La Gloria Oil & Gas Co. Simmons holds a BS (1985) in chemical engineering from the University of Texas, Austin. Tony Freeman ([email protected]) is principal process engineer at KP Engineering LP, Tyler, Tex., with 27 years of experience in refinery process design. He holds a BS in chemical engineering from the University of Arkansas and is a ed professional engineer in Texas and Oklahoma.

OIL & GAS JOURNAL REPRINTS Reprints of any article appearing in Oil & Gas Journal may be purchased by ing Rhonda Brown, Reprint Marketing Manager, Foster Printing Co. 4295 Ohio St., Michigan City, IN 46360, 1-866-879-9144 (ext. 194) 219-561-2023 (fax) [email protected] www.marketingreprints.com

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TECHNOLOGY

Oil pipelines lead way in strong 2014 Christopher E. Smith

NATURAL GAS PIPELINE PERFORMANCE

FIG. 1

Managing Editor, Technology Operating revenues

30 15 0 2005 6

2006

2007

2008

2009

2010

2011

2012

2013

2014

2007

2008

2009

2010

2011

2012

2013

2014

Net incomes

5 $ billion

US oil pipeline operators’ net incomes increased more than 37% in 2014, reaching a new record of more than $9.5 billion on revenues of roughly $19.3 billion. Investment in oil pipeline carrier property also continued to climb in 2014, rising roughly $17 billion after climbing nearly $14 billion the year before. Natural gas pipeline operators’ net income also returned to growth following 3 years of decline, but failed to match the rate of either their own revenue growth or the net improve-

$ billion

45

4 3 2 1 0 2005

2006

Source: US FERC Forms 2 and 2A, gas pipeline company reports

TRANSPORTATION

SPECIAL

REPORT IN THIS REPORT . . . US interstate mileage

110

Pipeline revenues, incomes—2014

Investment in US oil pipelines

US pipeline costs

10 years of land construction costs

US pipeline costs: estimated vs. actual

Top 10 interstate oil lines

US compressor construction costs

Top 10 interstate gas lines

US compressor costs: estimated vs. actual

Oil pipeline companies Gas pipeline companies

Oil & Gas Journal | Sept. 7, 2015

TOP 10 US INTERSTATE OIL PIPELINE COMPANIES—2014 Company 1 2 3 4 5 6 7 8 9 10

Mileage

Trunkline traffic, million bbl-miles

Company

852,749 582,341 209,833 154,120 137,023 133,396 119,974 93,324 79,560 64,902

Company TransCanada Keystone Pipeline LP Enbridge Energy LP Enterprise Crude Pipeline LLC BreitBurn Operating LP Chevron Pipe Line Co. Plains Pipeline LP Shell Pipeline Co. LP Magellan Pipeline Co. LP Sunoco Pipeline LP Colonial Pipeline Co.

Income, $1,000

Magellan Pipeline Co. LP . . . . . . . . . . . . 10,415 Mid-America Pipeline Co. LLC . . . . . . . . . 8,068 Plains Pipeline LP . . . . . . . . . . . . . . . . . . 7,830 Sunoco Pipeline LP . . . . . . . . . . . . . . . . . 5,923 Colonial Pipeline Co. . . . . . . . . . . . . . . . . 5,586 Phillips 66 Pipeline LLC . . . . . . . . . . . . . . 5,137 ExxonMobil Pipeline Co.. . . . . . . . . . . . . . 4,958 Enterprise TE Products Pipeline Co. LLC . 4,668 Enterprise Crude Pipeline LLC . . . . . . . . . 4,661 Enbridge Energy LP . . . . . . . . . . . . . . . . . 4,486

Colonial Pipeline Co. Enbridge Energy LP TransCanada Keystone Pipeline LP Magellan Pipeline Co. LP Plantation Pipe Line Co. Explorer Pipeline Co. Plains Pipeline LP Mid-America Pipeline Co. LLC Marathon Pipe Line LLC ConocoPhillips Transporation Alaska Inc.

665,532 642,833 598,050 520,674 442,856 416,324 373,021 348,364 346,433 322,262

Total . . . . . . . . . . . . . . . . . . . . . . . . . . 61,732 Part of all companies . . . . . . . . . . . . . . .38 .46%

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,427,222 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57 .89%

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $4,676,349 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48 .85%

Top 10 totals-2013 . . . . . . . . . . . . . . . . 60,108

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,257,053

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,493,549

Source: US FERC Form 6: Annual Report of Oil Pipeline Companies, Dec. 31, 2014

TOP 10 US INTERSTATE GAS PIPELINE COMPANIES—2014 Company* 1 2 3 4 5 6 7 8 9 10

Transmission mileage

Volumes moved for fee, MMcf

Company*

Company*

Net income, $1,000

Northern Natural Gas Co. . . . . . . . . . . . . . . . 14,781 Tennessee Gas Pipeline Co. . . . . . . . . . . . . . . 11,917 El Paso Natural Gas Co.. . . . . . . . . . . . . . . . . 10,222 Columbia Gas Tranmission LLC . . . . . . . . . . . . 9,641 Texas Eastern Transmission LP . . . . . . . . . . . . 9,592 Transcontinental Gas Pipe Line Corp.. . . . . . . . 9,183 Natural Gas Pipeline Co. of America . . . . . . . . 9,122 ANR Pipeline Co.. . . . . . . . . . . . . . . . . . . . . . . 8,082 Southern Natural Gas Co. . . . . . . . . . . . . . . . . 7,033 Gulf South Pipeline Co. LP. . . . . . . . . . . . . . . . 6,540

Transcontinental Gas Pipe Line Corp. . . . .4,655,090 Tennessee Gas Pipeline Co. . . . . . . . . . . .2,990,155 Texas Eastern Transmission LP . . . . . . . . .2,610,451 ANR Pipeline Co. . . . . . . . . . . . . . . . . . . .1,785,336 Natural Gas Pipeline Co. of America . . . . .1,417,903 Columbia Gas Transmission LLC . . . . . . . .1,379,418 El Paso Natural Gas Co. . . . . . . . . . . . . . .1,318,671 Texas Gas Transmission LLC . . . . . . . . . . .1,154,029 Dominion Transmission Inc. . . . . . . . . . . .1,151,691 Northern Natural Gas Co. . . . . . . . . . . . . .1,025,465

Tennessee Gas Pipeline Co. . . . . . . . . . . . . . .331,768 Texas Eastern Transmission LP . . . . . . . . . . . .318,519 Dominion Transmission Inc. . . . . . . . . . . . . . .308,512 Transcontinental Gas Pipe Line Corp. . . . . . . .289,463 Florida Gas Transmission Co. LLC . . . . . . . . . .234,412 Columbia Gas Transmission LLC . . . . . . . . . . .200,271 Northern Natural Gas Co. . . . . . . . . . . . . . . . .150,275 Southern Natural Gas Co. . . . . . . . . . . . . . . . .146,469 ETC Tiger Pipeline LLC . . . . . . . . . . . . . . . . . .130,851 Kinder Morgan Louisiana Pipeline LLC . . . . . .130,678

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96,113 Part of majors . . . . . . . . . . . . . . . . . . . . . . . . 50 .76% Part of all companies . . . . . . . . . . . . . . . . . . . 49 .24%

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19,488,209 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .43 .07% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .42 .10%

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,241,218 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 .71% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46 .92%

Total—2013 Top 10 . . . . . . . . . . . . . . . . . . . 97,279

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17,444,840

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2,080,550

Source: US FERC Forms 2 & 2A: annual reports for natural-gas companies, Dec. 31, 2013

ments experienced by oil operators. Gas pipeline operators, however, also expanded planned additions to their systems. A $1.3-million/mile slide in pipeline construction costs helped increase operators’ desite to add mileage. Compression costs also eased.

Details

US INTERSTATE PIPELINE MILEAGE

Table 1

Year

–––––––––––– Miles ––––––––––– Gas1 2 Oil Total1

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

188,847 189,012 192,189 192,384 192,673 190,305 192,203 191,195 189,087 189,366

131,334 140,407 147,235 146,822 148,622 147,524 149,571 151,912 152,016 160,521

1

320,181 329,419 339,424 339,206 341,295 337,829 341,774 343,107 341,103 349,887

FERC-defined major gas pipelines only; transmission

els after slipping in 2013, on a more than 15% increase in revenues. (Fig. 1). Proposed new-build natural gas mileage was more than four times 2014’s announced build, while planned horsepower additions exceeded 1.6-million, more than doubling the 705,604 proposed last year. Labor remained the most expensive construction component, but was only marginally more costly on a per mile basis than the miscellaneous costs category of which contingencies make up a large part. Both categories were substantially cheaper per mile than the

mileage.See GAS COMPANIES table for definition of Oil pipeline operators’ record profits major and nonmajor companies and details of compaoutstripped their 22.6% 2014 revenue nies reporting mileage for 2013. Revised from initial publication. Source: US FERC annual reports: Form 6, increase, and came despite acceleratoil pipelines; Forms 2 & 2A, gas pipelines ing their expansion rate. Natural gas pipeline operators’ return to income growth, meanwhile, was accompanied by a slowed rate of system growth. year before. The slower growth rate in oil pipeline revenues as comThe roughly $1.3-million decrease in estimated $/mile pared with profits resulted in new record earnings as a land pipeline construction costs brought them to $5.24 milpercent of revenue of 49.65%, eclipsing the 2011 mark of lion per mile, 20% lower than 2014. Pipeline labor prices 48.63%. Natural gas pipeline operators saw their profits remained the single most expensive per-mile item at $2 milclimb 11% to roughly $4.8 billion, returning to 2012 levlion/mile, but were 28% lower than last year. Both material 2

Oil & Gas Journal | Sept. 7, 2015

111

TECHNOLOGY

OIL PIPELINE INVESTMENT

FIG. 2

Crude oil

Products Line pipe and fittings Pipeline construction 23.75% 41.85%

Line pipe and fittings 27.44%

Pipeline construction 34.50%

Land and ROW 3.39%

Land and ROW 4.40% Misc.* 2.79% Pump station and equipment 23.52%

Misc.* 5.88% Pump station and equipment 32.48%

US pipeline data

*Generally includes delivery systems, communications, office furniture and equipment, vehicles and other work equipment, and other property. Source: US oil pipeline company annual reports (Form 6) to FERC for 2014

PIPELINE COMPANY REVENUES, INCOMES

Table 2

Operating Net income, revenues, $1,000 $1,000 ––––––––––––––– Gas ––––––––––––––––– 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

16,375,921 17,122,586 21,736,725 19,797,663 18,953,292 19,790,011 20,545,763 20,969,959 21,273,449 24,514,239

Operating Net income, revenues, $1,000 $1,000 –––––––––––––––– Oil –––––––––––––––

3,863,331 4,015,253 4,765,815 5,104,772 4,657,340 5,210,388 4,888,125 4,764,796 4,302,305 4,776,194

7,917,176 8,516,563 8,996,329 9,243,677 9,986,799 11,219,154 12,562,252 14,007,060 15,733,837 19,281,113

3,076,476 3,743,115 3,756,749 3,931,602 4,131,409 4,582,285 6,109,055 6,423,112 6,980,508 9,572,871

Source: US FERC annual reports (Forms 2, 2A, and 6) by regulated interstate natural gas and oil pipeline companies

PIPELINE CONSTRUCTION COSTS—ESTIMATED Materials 19.34%

Labor 37.77%

ROW and damages 7.22%

Misc.* 35.66% *Generally includes surveying, engineering, supervision, istration and overhead, interest, contingencies and allowances for funds used during construction (AFUDC), and regulatory filing fees. Source: US FERC construction permit filings, July 1, 2013, to June 30, 2014

112

costs and ROW costs increased on a per mile basis. Actual land pipeline construction costs for projects completed in the 12 months ending June 30, 2015, were roughly $400,000/mile less than estimated costs. Lower than expected miscellaneous costs more than made up for higher than estimated labor and ROW charges. Actual compressor station costs were more than $100/hp less than estimated costs for projects completed by June 30, 2015.

FIG. 3

At the end of this article, two large tables p. 123 offer a variety of data for US oil and gas pipeline companies: revenue, income, volumes transported, miles operated, and investments in physical plants. These data are gathered from annual reports filed with FERC by regulated oil and natural gas pipeline companies for the previous calendar year. Data is also gathered from periodic filings with FERC by those regulated natural gas pipeline companies seeking FERC approval to expand capacity. OGJ keeps a record of these filings for each 12-month period ending June 30. Combined, these data allow an analysis of the US regulated interstate

pipeline system. • Annual reports. Companies that, in FERC’s determination, are involved in the interstate movement of oil or natural gas for a fee are jurisdictional to FERC, must apply to FERC for approval of transportation rates, and therefore must file a FERC annual report: Form 2 or 2A, respectively, for major or nonmajor natural gas pipelines; Form 6 for oil (crude or product) pipelines. The distinction between “major” and “nonmajor” is defined by FERC and appears as a note at the end of the table listing all FERC-regulated natural gas pipeline companies for 2014 at the end of this article. The deadline to file these reports each year is April 1. For a variety of reasons, a number of companies miss that deadline and apply for extensions, but eventually file an annual report. That deadline and the numerous delayed filings explain why publication of this OGJ report on pipeline economics occurs later in each year. Earlier publication would exclude many companies’ information. • Periodic reports. When a FERC-regulated natural gas pipeline company wants to modify its system, it must apply

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY

INVESTMENT IN OIL PIPELINES—2014

Table 3

A B C D E –––––––––––––––––––––––– Company and investment, $ –––––––––––––––––––––––– CRUDE PIPELINES Land Right of way Line pipe Line pipe fittings Pipeline construction Buildings Boilers Pumping equipment Machine tools and machinery Other station equipment Oil tanks Delivery facilities Communication systems Office furniture and equipment Vehicles and other work equip. Other property Total investment-2014 Total carrier property—2014 Total investment-2013

26,732,371 424,505,326 2,802,872,783 101,509,489 4,297,164,352 193,205,673 — 282,425,258 — 1,212,285,970 385,346,800 9,318 10,994,346 22,222,098 47,889,595 11,545,376 $9,818,708,755 $10,972,918,421 $6,244,970,262

120,398 945,777 23,369,478 1,579,699 44,912,270 5,518,523 — 11,094,160 — 31,657,079 7,817,441 14,454 1,150,282 507,431 596,922 2,456,718 $131,740,632 $145,179,507 $106,440,324

6,388 300,181 7,069,114 2,861,066 8,623,572 2,439,857 — 9,745,032 — 8,037,073 — — — 1,163,809 523,570 — $40,769,662 $42,876,235 $40,147,659

2,602,778 24,067,794 52,343,232 19,384,424 216,808,223 16,412,388 — 36,763,881 32,353 266,296,384 43,775,354 16,807 1,886,928 751,011 2,941,394 207,758,024 $891,840,975 $970,477,136 $803,541,369

5,559,457 11,641,957 53,628,119 30,548,037 152,879,178 25,784,883 — 17,272,361 — 78,479,207 19,289,078 — 867,943 299,043 — 976,182 $397,225,445 $463,159,594 $359,871,176

PRODUCT PIPELINES Land Right of way Line pipe Line pipe fittings Pipeline construction Buildings Boilers Pumping equipment Machine tools and machinery Other station equipment Oil tanks Delivery facilities Communication systems Office furniture and equipment Vehicles and other work equip. Other property

6,938,223 — 418,171,371 159,159,265 1,275,826,929 49,315,639 — 122,875,858 — 429,925,501 256,716,747 — 7,247,987 46,104,962 21,018,059 3,666,306

9,669,624 23,182,416 83,746,862 62,474,285 225,465,380 17,071,485 — 40,100,630 — 187,115,601 96,416,739 — 1,719,837 2,028,036 5,150,830 —

1,139,188 64,013,598 679,110,478 92,839,985 646,268,309 14,713,578 — 247,028,126 — 146,141,472 8,459,201 12,152,740 3,634,331 35,657,550 18,523,370 29,155,751

5,491,738 11,982,800 97,744,898 5,941,006 147,477,216 20,808,488 — 38,001,695 — 130,244,038 54,734,076 32,913,997 13,248,603 6,764,200 17,985,507 —

25,133,257 132,220,505 285,820,663 77,034,591 555,601,474 52,169,570 — 79,967,216 — 368,535,639 323,335,309 176,726,106 30,284,323 3,607,205 11,932,142 6,284,246

Total investment-2014 Total carrier property—2014 Total investment-2013

$2,796,966,847 $2,841,287,811 $2,566,453,713

$754,141,725 $810,900,247 $726,753,037

$1,998,837,677 $2,036,156,840 $1,408,474,647

$583,338,262 $594,793,536 $560,304,899

$2,128,652,246 $2,194,841,164 $1,781,210,380

Total, $

%

35,021,392 0.31% 461,461,035 4.09% 2,939,282,726 26.06% 155,882,715 1.38% 4,720,387,595 41.85% 243,361,324 2.16% — 0.00% 357,300,692 3.17% 32,353 0.00% 1,596,755,713 14.16% 456,228,673 4.04% 40,579 0.00% 14,899,499 0.13% 24,943,392 0.22% 51,951,481 0.46% 222,736,300 1.97% $11,280,285,469 100.00% $7,554,970,790 48,372,030 231,399,319 1,564,594,272 397,449,132 2,850,639,308 154,078,760 — 527,973,525 — 1,261,962,251 739,662,072 221,792,843 56,135,081 94,161,953 74,609,908 39,106,303

0.59% 2.80% 18.94% 4.81% 34.50% 1.86% 0.00% 6.39% 0.00% 15.27% 8.95% 2.68% 0.68% 1.14% 0.90% 0.47%

$8,261,936,757 100.00% $7,043,196,676

Sources: US FERC Forms 6, Annual Report of Oil Pipeline Companies, Dec. 31, 2013, and 2014

Land construction costs (est.), %

for a “certificate of public convenience MAJOR COST COMPONENTS—10 YEARS FIG. 4 and necessity.” This filing must explain in detail the planned construc100 tion, justify it, and—except in certain 90 instances—specify what the company 80 estimates construction will cost. 70 Not all applications are approved. 60 Not all that are approved are built. 50 But, assuming a company receives its Labor certificate and builds its facilities, it 40 must—again, with some exceptions— 30 report back to FERC how its original 20 Material cost estimates compared with what it 10 actually spent. 0 OGJ spends the year July 1 to June 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 30 monitoring these filings, collecting Source: US FERC them, and analyzing their numbers. OGJ’s exclusive, annual Pipeline Economics Report began tracking volumes of gas transported for a fee by major interstate pipeVolumes of natural gas sold by pipelines have been steadilines for 1987 (OGJ, Nov. 28, 1988, p. 33) as pipelines moved ly declining, so that, beginning with 2001 data in the 2002 gradually after 1984 from owning the gas they moved to report, the table only lists volumes transported for others. mostly providing transportation services. The company tables also reflect asset consolidation and

Oil & Gas Journal | Sept. 7, 2015

113

TECHNOLOGY

US PIPELINE COSTS, ESTIMATED Size, in.

Location1

Length, miles

Table 4

ROW & Material Labor Misc.2 damages Total –––––––––––––––––––––––––––––––––––– $ –––––––––––––––––––––––––––––––––––––

$/mile

LAND PIPELINES 8 South Carolina Nevada (lat.)

28 35.2

2,762,509 6,914,341

20,896,941 17,232,716

9,088,522 2,227,106

2,903,245 590,999

35,651,217 26,965,162

1,273,258 766,056

12

West Virginia (lat.) Tennessee

9.29 10

3,137,352 2,228,422

14,606,491 20,841,396

6,698,659 19,647,280

2,499,750 6,563,628

26,942,252 49,280,726

2,900,135 4,928,073

14, 20

Kentucky (R)

22.5

19,070,199

64,658,263

32,547,975

3,159,048

119,435,485

5,308,244

16

Massachusetts (lat.) Pennsylvania (L)3 Delaware (L)

1.2 7.2 10.1

521,934 2,251,504 4,267,743

6,873,406 7,085,000 11,864,160

9,054,585 17,413,496 13,870,597

1,545,988 3,000,000 2,075,000

17,995,913 29,750,000 32,077,500

14,996,594 4,131,944 3,175,990

20

Pennsylvania (R) Nebraska (lat.) Kentucky-Indiana (lat.) Pennsylvania (R)

3.00 11.70 29.90 34.00

1,824,188 4,517,914 10,828,000 16,252,000

10,649,200 18,854,141 45,469,000 2,456,000

5,674,019 12,472,523 10,959,000 103,714,000

— 5,084,742 6,800,000 13,586,000

18,147,407 40,929,320 74,056,000 136,008,000

6,049,136 3,498,232 2,476,789 4,000,235

24

New York (R) Washington (lat.) Virginia West Virginia Oklahoma (lat.) New York

3.05 3.1 4.33 5 16.20 96.65

2,229,383 3,439,619 4,274,263 8,258,014 8,750,000 54,319,820

6,415,769 11,802,419 10,776,945 17,025,549 17,300,400 184,405,412

5,286,168 7,514,667 13,167,263 17,767,354 2,637,075 82,781,766

1,330,920 — 753,716 2,233,250 1,726,000 14,199,645

15,262,243 22,756,705 28,972,187 45,284,167 30,413,475 335,706,643

5,004,014 7,340,873 6,691,036 9,056,833 1,877,375 3,473,426

24, 36

Mass.-Conn.-NY (L) Ala.-Ga.-Fla.

7.97 509.00

13,933,400 494,920,613

31,533,543 758,984,318

30,157,597 1,130,069,320

10,045,640 287,597,204

85,670,180 2,671,571,455

10,749,082 5,248,667

24-42

WV-Penn.-Ohio (lat.)

238.4

210,874,734

488,310,024

290,213,258

40,450,405

1,029,848,421

4,319,834

26, 30

Ohio (R)

10.08

11,053,668

31,624,946

16,881,461

7,304,060

66,864,135

6,633,347

30

Virginia (R) West Virginia-Ohio Pennsylvania

2.52 34 57.39

1,702,333 23,970,811 66,127,550

20,147,514 127,430,716 208,544,686

10,637,702 55,613,786 164,575,712

1,323,128 20,244,687 40,264,277

33,810,677 227,260,000 479,512,225

13,416,935 6,684,118 8,355,327

30, 36

Kentucky (R) Louisiana (lat.)(L) Penn.-WV-Ohio

1.57 34.1 160.5

1,731,081 37,200,000 149,256,811

9,119,216 125,100,000 45,222,976

7,889,022 48,000,000 354,369,658

162,125 8,300,000 22,113,596

18,901,444 218,600,000 570,963,041

12,039,136 6,410,557 3,557,402

36

Nevada (R) Pennsylvania (L) Louisiana Kentucky (L) Pennsylvania (L) Florida

1.56 2.92 7 7.6 8.1 126

2,159,100 6,937,323 19,979,382 6,934,400 13,454,639 123,709,840

198,500 22,730,527 34,304,232 19,651,900 28,715,152 202,444,408

6,165,200 16,598,611 31,696,084 12,598,728 27,094,081 240,028,000

1,876,000 895,300 4,254,448 1,938,800 2,117,189 154,812,983

10,398,800 47,161,761 90,234,146 41,123,828 71,381,061 720,995,231

6,665,897 16,151,288 12,890,592 5,411,030 8,812,477 5,722,184

42

Alabama (L) Alabama (L) Alabama (L) Alabama (L) Alabama (L) Alabama (L) Alabama (L) Pennsylvania (L) Ohio-Michigan Pennsylvania Ohio

2.55 3.92 5.30 5.48 6.73 7.48 7.60 8.56 100.00 126.31 374.50

3,074,371 5,216,183 7,130,148 7,259,668 10,169,367 11,160,824 8,376,390 13,562,275 123,459,549 257,662,581 425,249,569

6,270,566 9,878,888 11,474,600 12,487,780 14,877,056 15,630,559 16,329,370 43,040,380 247,877,937 445,246,498 858,157,116

7,530,655 9,112,561 12,731,923 14,315,443 14,792,394 18,170,090 16,799,572 31,372,342 162,188,148 409,789,868 569,290,020

210,591 308,730 418,087 489,613 978,557 676,407 586,244 2,207,986 18,108,943 67,467,112 65,573,601

17,086,183 24,516,362 31,754,758 34,552,504 40,817,374 45,637,880 42,091,576 90,182,983 551,634,577 1,180,166,059 1,918,270,306

6,700,464 6,254,174 5,991,464 6,305,201 6,064,989 6,101,321 5,538,365 10,535,395 5,516,346 9,343,410 5,122,217

48

Alabama (L)

4.6

7,883,221

11,410,485

12,421,154

418,087

32,132,947

6,985,423

2,192.16 522.63

$2,219,997,036 $467,303,829

$4,335,957,101 $1,453,757,512

$4,093,624,445 $1,331,452,115

$829,195,731 $179,706,214

$11,478,774,316 $3,432,219,670

$5,236,285 $6,567,208

— 2,192.16 522.63

— $2,219,997,036 $467,303,829

— $4,335,957,101 $1,453,757,512

— $4,093,624,445 $1,331,452,115

— $829,195,731 $179,706,214

— $11,478,774,316 $3,432,219,670

— $5,236,285 $6,567,208

Total projects—land Total land-2014 report OFFSHORE PIPELINES Total projects—offshore TOTAL—all project 2014-report total, all projects 1

L = loop; R = replacement; lat. = lateral. 2Generally includes surveys, engineering, supervision, interest, istration, overheads, contingencies, allowances for funds used during construction (AFUDC), and FERC fees. 3Includes 3,550 hp of replacement compression. Source: US FERC construction-permit applications, July 1, 2014, to June 30, 2015

merger activity among companies in their efforts to improve transportation efficiencies and bottom lines.

Reporting changes The number of companies required to file annual reports with FERC may change from year-to-year, with some com-

114

panies becoming jurisdictional, others nonjurisdictional, and still others merging or being consolidated out of existence. Such changes require care be taken in comparing annual US petroleum and natural gas pipeline statistics. Institution by FERC of the two-tiered (2 and 2A) classifi-

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY

US COMPRESSOR-CONSTRUCTION COSTS, ESTIMATED

Table 5

Equipment material Labor Land Misc.1 Total –––––––––––––––––––––––––––––––––––––– $ –––––––––––––––––––––––––––––––––––––––

Location

Horsepower

$/hp

Pennsylvania-Maryland Texas New York Virginia2 Maryland2 Virginia2 Texas Texas2 Pennsylvania2 Louisiana2 Kentucky2 West Virginia Indiana2 Louisiana Ohio2 West Virginia2 Louisiana Louisiana2 Pennsylvania2 Indiana3 Illinois West Virginia Maryland2 Texas Alabama2 Alabama2 Kentucky Pennsylvania2 Pennsylvania2 Alabama2 West Virginia Florida Florida Florida Georgia Georgia Georgia Pennsylvania2 Kentucky2 Ohio Virginia New York Ohio Virginia2 Ohio Maryland2 Pennsylvania Tennessee New Jersey Alabama Kentucky2 Kentucky2 Louisiana Louisiana2 Florida Pennsylvania Louisiana Alabama WV-Penn.-Ohio Ohio Ohio Texas West Virginia-Ohio

4,000 5,280 5,350 6,000 7,000 8,000 8,400 8,400 8,715 9,688 10,771 10,771 10,915 10,915 10,915 12,252 12,500 12,500 13,220 13,230 15,000 15,000 15,900 15,900 16,000 16,000 16,000 16,000 16,000 20,500 20,500 20,500 20,500 20,500 20,500 20,500 20,500 20,500 20,500 21,000 21,830 22,214 23,877 25,000 25,830 30,000 30,000 30,000 30,500 32,000 32,000 32,000 32,000 32,000 36,400 40,000 64,000 71,000 72,645 82,000 114,945 121,750 143,000

8,372,310 13,185,836 13,610,565 7,922,272 9,452,088 12,752,958 19,619,358 15,512,379 17,229,823 13,680,737 13,876,400 16,257,741 14,407,000 14,416,000 14,070,293 17,240,461 17,800,000 15,902,839 20,242,472 14,746,000 18,985,208 17,492,088 18,737,040 13,906,547 18,673,121 21,206,061 23,491,600 20,523,854 16,862,516 18,788,660 21,550,959 23,127,876 19,867,561 20,107,212 26,005,620 19,867,558 20,107,211 27,284,153 20,115,998 25,170,900 29,141,500 27,701,596 28,192,665 20,453,040 40,768,292 27,984,502 35,418,722 58,922,000 23,263,556 38,662,930 26,678,500 42,338,309 36,489,980 35,975,876 44,083,859 39,121,785 80,561,300 65,915,515 133,306,605 105,547,600 202,901,251 149,729,000 131,083,228

9,492,113 6,341,458 9,137,961 11,724,279 12,954,320 16,149,075 11,033,491 7,911,412 18,432,666 350,000 3,380,800 11,453,586 12,905,000 500,000 15,940,023 14,119,472 13,600,000 6,655,755 18,059,220 1,323,000 5,262,510 11,134,250 10,629,425 8,364,752 4,235,790 4,843,740 12,561,500 8,999,832 5,579,627 3,971,280 13,598,002 8,039,004 7,815,283 7,952,281 10,306,934 7,815,283 7,952,281 25,054,227 7,617,278 13,570,000 18,141,416 12,088,900 462,713 16,487,424 11,357,239 22,992,885 29,616,585 19,768,600 11,643,208 15,041,970 11,460,100 15,402,505 13,100,210 13,677,357 10,771,176 29,368,354 33,517,300 19,421,902 45,764,725 52,729,600 52,982,823 53,896,000 74,317,641

88,840 1,206,508 — 153,000 — — 182,500 105,000 — — 9,500 1,132,632 53,000 553,000 — — 100,000 207,040 — — 739,200 460,000 — — — — 532,437 90,379 90,379 — 1,247,068 23,408 1,000,000 — — 900,000 — 255,990 10,500 660,000 38,600 — 651,514 50,810 435,176 135,022 1,564,870 1,506,640 1,453,278 809,900 28,000 30,500 1,267,470 444,888 2,966,680 1,929,968 2,301,600 2,013,500 1,683,538 7,149,200 1,944,345 1,753,000 3,641,528

6,508,169 23,060,767 5,618,582 14,049,506 8,211,781 16,265,073 22,045,951 20,646,159 17,542,989 18,236,312 5,202,473 17,091,618 7,896,000 17,848,732 11,164,742 24,491,089 9,400,000 30,867,997 19,396,181 27,304,000 913,535 8,310,895 14,407,045 4,991,601 13,386,744 9,665,220 22,872,598 13,703,156 10,668,158 12,923,728 20,944,571 25,865,413 19,400,714 18,205,728 13,108,356 19,555,539 18,207,665 25,868,163 16,348,408 13,517,759 20,807,203 10,365,535 38,087,974 30,730,483 8,839,867 21,838,196 44,518,976 43,672,032 33,779,973 27,247,590 12,740,731 18,135,132 22,677,804 23,141,747 38,331,166 43,957,085 36,514,900 47,395,069 33,996,608 60,441,254 45,151,811 178,444,000 133,501,181

24,461,432 43,794,569 28,367,108 33,849,057 30,618,189 45,167,106 52,881,300 44,174,950 53,205,478 32,267,049 22,469,173 45,935,577 35,261,000 33,317,732 41,175,058 55,851,022 40,900,000 53,633,631 57,697,873 43,373,000 25,900,453 37,397,233 43,773,510 27,262,900 36,295,655 35,715,021 59,458,135 43,317,221 33,200,680 35,683,668 57,340,600 57,055,701 48,083,558 46,265,221 49,420,910 48,138,380 46,267,157 78,483,033 44,112,684 52,939,659 68,128,719 50,156,031 67,394,866 67,721,757 61,400,574 72,950,605 111,119,153 123,869,272 70,140,015 81,762,390 50,907,331 75,906,446 73,535,464 73,239,868 96,152,881 114,377,192 152,895,100 134,745,986 214,751,476 225,867,654 302,980,230 383,822,000 342,543,578

6,115 8,294 5,302 5,642 4,374 5,646 6,295 5,259 6,105 3,331 2,086 4,265 3,231 3,052 3,772 4,559 3,272 4,291 4,364 3,278 1,727 2,493 2,753 1,715 2,268 2,232 3,716 2,707 2,075 1,741 2,797 2,783 2,346 2,257 2,411 2,348 2,257 3,828 2,152 2,521 3,121 2,258 2,823 2,709 2,377 2,432 3,704 4,129 2,300 2,555 1,591 2,372 2,298 2,289 2,642 2,859 2,389 1,898 2,956 2,754 2,636 3,153 2,395

Total, land projects 2014-report total, land projects

1,701,613

$2,126,410,886

$970,777,543

$43,600,408

$1,600,029,434

$4,740,880,271

$2,786

705,604

$866,208,257

$492,928,721

$18,756,851

$667,881,533

$2,045,775,362

$2,899

TOTAL, ALL PROJECTS 2014-report total, all projects

1,701,613

$2,126,410,886

$970,777,543

$43,600,408

$1,600,029,434

$4,740,880,271

$2,786

705,604

$866,208,257

$492,928,721

$18,756,851

$667,881,533

$2,045,775,362

$2,899

1

Generally includes surveys, engineering, supervision, interest, istration, freight, taxes, overheads, contingencies, allowances for funds used during construction (AFUDC), and FERC fees. 2 Addition. 3Replacement. Source: US FERC construction-permit applications, July 1, 2014, to June 30, 2015

cation system for natural gas pipeline companies after 1984 further complicated comparisons (OGJ, Nov. 25, 1985, p. 55).

Oil & Gas Journal | Sept. 7, 2015

Only major gas pipelines are required to file miles operated in a given year. The other companies may indicate miles operated, but are not specifically required to do so.

115

TECHNOLOGY

10 YEARS OF LAND CONSTRUCTION COSTS 1

Table 6

Size

Year

ROW Material Labor Misc. Total ––––––––––––––––––––––––––– Average cost, $/mile ––––––––––––––––––––––––––––––

Low High ––––– Range, $/mile –––––

8 in.

2015 2014 2013 2012 2011 2010 2009 2008 2007 2006

55,289 17,717 71,443 — — — — 17,438 — —

153,115 608,268 188,261 — 132,884 — — 378,698 — —

603,317 119,685 69,541 — 917,910 — — 199,342 — —

179,045 988,189 1,533,654 — 582,952 — — 114,617 — —

990,765 1,733,8582 1,862,899 — 1,633,7462 — — 710,0952 — —

766,056 — 1,762,637 — — — — –– — —

1,273,258 — 4,246,500 — — — — –– — —

12 in.

2015 2014 2013 2012 2011 2010 2009 2008 2007 2006

469,849 772,578 64,313 75,246 — — — 178,757 — 45,944

278,164 721,073 319,004 213,859 — — — 195,406 — 160,618

1,837,630 4,777,695 784,464 612,119 — — — 566,193 — 243,104

1,365,782 4,263,874 380,252 419,950 — — — 466,159 — 174,207

3,951,424 10,535,2212 1,548,0332 1,321,1732 — — — 1,406,515 — 623,873

2,900,135 — — — — — — 541,392 — 515,091

4,928,073 — — — — — — 4,186,636 — 1,159,683

16 in.

2015 2014 2013 2012 2011 2010 2009 2008 2007 2006

357,891 574,745 81,810 126,033 278,231 263,135 226,517 421,484 — 181,184

380,604 483,528 286,739 302,558 305,235 222,719 417,899 1,182,666 — 192,998

1,395,814 2,911,085 533,749 748,967 1,004,152 885,769 1,480,926 1,689,992 — 398,048

2,180,469 2,807,562 636,324 302,760 1,328,691 966,447 586,626 1,552,542 — 111,888

4,314,779 6,776,920 1,538,623 1,480,3182 2,916,309 2,338,0692 2,711,9682 4,646,6842 — 884,118

3,175,990 6,471,863 1,005,653 — 2,007,514 — — –– — 601,274

14,996,594 7,325,147 5,882,153 — 3,885,413 — — –– — 948,857

20 in.

2015 2014 2013 2012 2011 2010 2009 2008 2007 2006

324,055 473,329 103,333 8,941 97,553 64,198 164,377 23,219 — 99,125

425,218 632,417 338,025 275,292 402,232 1,194,239 820,867 869,178 — 233,125

985,093 2,264,767 998,560 69,647 1,208,048 1,663,457 1,993,079 941,096 — 796,688

1,689,816 2,142,928 701,317 1,349,884 816,998 1,504,568 1,061,331 491932 — 478,406

3,424,182 5,513,441 2,141,235 1,703,7652 2,524,831 4,426,4612 4,039,654 2,325,4252 — 1,607,3442

2,476,789 2,723,642 — — 1,773,309 — 3,866,474 –– — ––

6,049,136 11,975,448 — — 7,970,976 — 7,528,043 –– — ––

24 in.

2015 2014 2013 2012 2011 2010 2009 2008 2007 2006

157,746 231,155 73,560 181,741 283,312 — 65,567 –– 25,467 126,822

633,298 523,863 623,116 701,303 409,840 — 530,093 –– 351,083 263,200

1,930,386 1,516,691 805,886 1,910,324 1,603,609 — 1,085,736 –– 324,023 584,428

1,006,423 1,075,740 912,622 1,143,928 1,482,417 — 663,240 –– 453,737 577,136

3,727,853 3,347,449 2,415,184 3,937,296 3,779,177 — 2,344,636 –– 1,155,030 1,551,586

1,877,375 1,469,338 1,922,659 2,254,386 1,873,984 — 1,975,000 –– 830,872 1,248,916

9,056,833 6,181,322 4,681,258 4,481,436 11,877,953 — 3,399,653 –– 4,301,932 4,883,022

30 in.

2015 2014 2013 2012 2011 2010 2009 2008 2007 2006

658,419 268,605 — 290,807 390,263 160,922 384,467 83,016 156,303 135,337

977,539 690,850 — 1,020,108 745,675 769,453 624,980 1,091,147 1,371,819 589,703

3,792,172 2,155,315 — 3,218,952 3,648,578 1,601,563 912,342 356,539 1,328,831 960,760

2,457,962 2,036,710 — 3,242,493 2,276,889 966,007 113,283 472,278 922,647 650,255

7,886,092 5,151,482 — 7,772,360 7,061,405 3,497,9442 2,035,073 2,002,981 3,779,600 2,336,055

6,684,118 4,600,017 — 6,356,657 6,384,345 — 1,955,746 1,684,461 1,546,833 1,131,419

13,416,935 8,873,792 — 35,732,500 7,177,507 — 3,917,264 2,264,167 4,715,909 6,791,954

36 in.

2015 2014 2013 2012 2011 2010 2009 2008 2007 2006

1,083,005 —3 93,529 —519,369 107,000 499,329 170,489 97,746 233,258

1,130,531 1,106,103 1,400,946 — 937,500 1,641,171 1,083,073 994,375 869,995 844,583

2,010,998 3,061,029 2,182,912 — 2,864,358 1,544,020 1,084,429 1,098,096 628,204 1,141,388

2,181,621 1,683,401 1,938,652 — 3,059,234 1,051,506 892,446 511,589 893,293 1,349,079

6,406,155 5,760,613 5,616,040 — 7,380,462 4,343,6972 3,559,276 2,774,549 2,489,238 3,568,308

5,411,030 346,243 3,461,864 — 7,072,552 — 3,284,505 2,427,457 1,857,468 1,900,376

16,151,288 5,876,636 79,188,232 — 7,848,259 — 3,600,324 9,013,608 4,056,369 8,066,15706

1

Estimates; based on FERC construction-permit applications for a 12-month period ending June 30 of each year. 2Only one project proposed during this period for this diameter. 3One of the projects of this diameter did not list ROW as a discrete category.

For several years after 1984, many non-majors did not describe their systems. But filing descriptions of their systems has become standard, and most provide miles operated.

116

Reports for 2014 show an increase in FERC-defined major gas pipeline companies: 93 companies of 165 filing for 2014, from 92 of 163 for 2013.

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY The FERC made an additional change to reporting requirements for 1995 for both crude oil and petroleum products pipelines. Exempt from requirements to prepare and file a Form 6 were those pipelines with operating revenues at or less than $350,000 for each of the 3 preceding calendar years. These companies must now file only an “Annual Cost of Service Based Analysis Schedule,” which provides only total annual cost of service, actual operating revenues, and total throughput in both deliveries and barrel-miles. In 1996 major natural gas pipeline companies were no longer required to report miles of gathering and storage systems separately from transmission. Thus, total miles operated for gas pipelines consist almost entirely of transmission mileage. FERC-regulated major natural gas pipeline mileage rose marginally in 2014 (Table 1), final data showing an increase of 279 miles, or 0.15%.

COMPRESSOR CONSTRUCTION COSTS—ESTIMATED1 Misc.2 34.08%

FIG. 5

Equipment and material 44.59%

Land 0.90% Labor 20.43% 1Onshore only. 2Generally includes surveying, engineering, supervision, istration and overhead, interest, contingencies and allowances for funds used during construction (AFUDC), and regulatory filing fees. Source: US FERC construction permit filings, July 1, 2014, to June 30, 2015

Rankings; activity Natural gas pipeline companies in 2014 saw operating revenues rise by more than $3.2 billion or roughly 15% from 2013, continuing the gains seen the past few years. Net incomes also returned to growth, climbing more than $473 million (about 11%), to roughly the levels seen in 2012. Oil pipelines fared even better, with earnings rising nearly $2.6 billion (37.1%) on the back of a more than $3.6 billion (22.6%) increase in revenues (Table 2). Crude deliveries for 2014 increased by roughly 1.2 billion bbl or 14.4%, while product deliveries rose 409 million bbl (6.3%). OGJ uses the FERC annual report data to rank the top 10 pipeline companies in three categories (miles operated, trunkline traffic, and operating income) for oil pipeline companies and three categories (miles operated, gas transported for others, and net income) for natural gas pipeline companies. Positions in these rankings shift year to year, reflecting normal fluctuations in companies’ activities and fortunes. But also, because these companies comprise such a large portion of their respective groups, the listings provide snapshots of overall industry trends and events. For instance, the growth in overall oil pipeline earnings was larger than that for the top 10 companies (34%), suggesting ongoing strength for the smaller companies in this particular transport segment. The top 10 companies’ share of the segment’s total earnings was roughly 49% in 2014 compared with 50% a year earlier. Net income as a portion of natural gas pipeline operating revenues slipped to 19.48% in 2014, continuing the fall from the record highs seen in 2010 to the lowest levels seen in more than 11 years. The percentage of income as operating revenues for oil pipelines rebounded sharply to 49.64%, ing its own 2011 record of 48.63%. Net income as a portion of gas-plant investment rose to 3.19%, rebounding from a 17-yr low of 2.93%, in 2013. Net income as a portion of investment in oil pipeline carrier

Oil & Gas Journal | Sept. 7, 2015

property rose to 11.3%, following a 10.3% drop in 2013. Income as part of investment in carrier property in 2004 stood at 11.4%, having risen steadily toward that level from 6.8% in 1998. Major and nonmajor natural gas pipelines in 2014 reported an industry gas-plant investment of roughly $152 billion, the highest levels ever, up from about $147 billion in 2013, more than $142 in 2012, $138.6 billion in 2011, $124.7 billion in 2010, almost $121.3 billion in 2009, nearly $105.8 billion in 2008, and $95.5 billion in 2007. Investment in oil pipeline carrier property continued to surge in 2014, to more than double the values seen just 7 years before, reaching nearly $85 billion after hitting $68 billion in 2013, topping $54 billion in 2012, hitting roughly $49 billion in 2011, more than $45 billion in 2010, roughly $42 billion in 2009, $39 billion in 2008, almost $36 billion in 2007, and beginning its current upward momentum in 2006, rising to $32.7 billion from the lowest level seen since at least 1997, $29.5 billion in 2005. OGJ for many years has tracked carrier-property investment by five crude oil pipeline and five products pipeline companies chosen as representative in of physical systems and expenditures (Table 3). In 2003, we added the base carrier-property investment to allow for comparisons among the anonymous companies. The five crude oil pipeline companies in 2014 increased their overall investment in carrier property by more than $3.7 billion (49.3%), accelerating the smaller gains seen in 2013 and 2012 and reflecting the activity seen in the segment as a whole. All of the companies increased investment in carrier property, but nearly all ($3.6 billion) of the overall gain came from a single operator. The five products pipeline companies also saw their over-

117

TECHNOLOGY

US PIPELINE COSTS: ESTIMATED VS. ACTUAL, 2014-15 1 Size, in.

Location

Length, miles

Land pipelines 8 Virginia-WV (L) Estimated Actual

12.6

8

Tennessee Estimated Actual

0.50

Texas (lat.) Estimated Actual

16.50

Tennessee Estimated Actual

6.50

Virginia (L) Estimated Actual

3.30

Nebraska-Iowa Estimated Actual

6.09

Iowa

0.41

16

16

16

20

20

Estimated Actual 24

24

24

24, 30

30

36

36

36

36

36

36

36

42

Pennsylvania (R) Estimated Actual

18.52

Colorado (lat.) Estimated Actual

7.75

Virginia (R) Estimated Actual

5.70

Mississippi-Alabama Estimated Actual

$/mile

2,223,504 1,423,409

276,542 567,923

19,505,427 21,901,415

705,750 913,259

22,711,223 24,806,006

1,802,478 1,968,731

246,364 246,437

636,532 902,746

1,133,453 926,527

232,296 131,745

2,248,645 2,207,455

4,497,290 4,414,910

6,645,200 6,086,600

12,590,000 16,215,800

4,442,600 3,632,600

2,665,400 3,550,100

26,343,200 29,485,100

1,596,558 1,786,976

3,111,132 3,281,856

20,150,126 19,846,539

20,145,261 13,245,412

4,206,935 3,991,353

47,613,454 40,365,160

7,325,147 6,210,025

1,726,152 1,481,399

7,308,669 7,662,895

10,277,800 4,301,480

2,044,528 870,085

21,357,149 14,315,859

6,471,863 4,338,139

812,058 881,771

1,577,075 1,223,790

871,469 409,105

177,650 48,151

3,438,252 2,562,817

564,573 420,824

1,833,491 1,834,817

7,267,880 6,390,123

4,440,164 2,351,287

1,492,970 1,041,597

15,034,505 11,617,824

36,669,524 28,336,156

18,183,522 15,293,639

2,424,337 628,988

80,585,174 70,685,849

2,775,000 8,616,589

103,968,033 95,225,065

5,613,825 5,141,742

6,958,560 6,773,822

8,751,808 8,335,512

8,367,446 4,316,913

939,600 697,676

25,017,414 20,123,923

3,228,053 2,596,635

3,904,565 2,545,386

12,073,131 11,995,478

15,879,445 6,179,144

3,376,394 1,082,278

35,233,535 21,802,286

6,181,322 3,824,962

54,578,000 42,941,000

97,651,000 112,753,000

35,770,000 24,314,000

13,149,000 13,426,000

201,148,000 193,434,000

2,873,543 2,763,343

737,200 1,188,955

942,904 1,774,810

709,965 1,152,498

14,033 16,227

2,404,102 4,132,490

6,868,863 11,807,114

56,595,557 46,940,034

57,415,279 79,294,447

82,922,654 50,571,279

7,316,510 6,409,535

204,250,000 183,215,295

3,404,167 3,053,588

6,465,914 6,266,691

22,022,266 22,884,726

18,081,185 11,462,654

2,502,701 2,176,921

49,072,066 42,790,992

6,058,280 5,282,839

5,677,095 5,419,244

19,709,928 24,477,040

15,940,496 12,262,878

2,220,100 2,862,331

43,547,619 45,021,493

6,133,467 6,341,055

5,816,022 4,516,931

18,716,125 18,087,287

15,876,296 10,259,913

2,242,313 2,330,586

42,650,756 35,194,717

6,365,784 5,252,943

5,947,902 5,887,013

20,596,350 17,278,984

15,870,159 8,170,782

2,374,558 2,269,283

44,788,969 33,606,062

7,342,454 5,509,190

5,799,872 5,508,335

19,752,386 24,532,426

15,824,462 11,414,601

3,169,698 4,939,275

44,546,418 46,394,637

7,954,718 8,284,757

1,700,160 1,544,871

10,452,686 6,573,076

11,650,966 7,938,715

869,540 1,409,134

24,673,352 17,465,796

57,379,888 40,618,130

1,246,681 966,483

6,249,698 6,173,705

9,833,304 9,815,039

75,000 201,456

17,404,683 17,156,683

42,450,446 41,845,568

$190,208,951 $161,028,693

$346,564,722 $387,599,295

$388,127,726 $275,312,091

$52,549,976 $56,983,581

$977,451,375 $880,923,660

$4,028,070 $3,630,280

70.00

California (R) Estimated Actual

0.35

Arizona Estimated Actual

60.00

Pennsylvania (L) Estimated Actual

8.10

Pennsylvania (L) Estimated Actual

7.10

Pennsylvania (L) Estimated Actual

6.70

Pennsylvania (L) Estimated Actual

6.10

Pennsylvania (L) Estimated Actual

5.60

Florida (R) Estimated Actual

0.43

Pennsylvania (R) Estimated Actual

0.41

Total, miles

Table 7

ROW & Materials Labor Misc. damages Total –––––––––––––––––––––––––––––––––––– $ ––––––––––––––––––––––––––––––––––––– 2

242.66 Estimated Actual

1

Actual cost data must be filed within 6 months following final hydrostatic test of pipeline. Not all projects proposed (estimated costs) are built (actual costs). L = loop, lat. = lateral, R = replacement. 2Generally includes surveys, engr., supvervision, interest, freight, taxes, istration and overheads, contingencies,allowances for funds used during construction (afudc), and regulatory fees. Source: US FERC; for completed-project costs filed between July 1, 2014, and June 30, 2015, under CFR Section 157.20(c)(4)

118

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY all investment in carrier property accelerate in 2014, adding more than $1.2 billion, or 17.3%, with all companies increasing their investment here as well. Comparisons of data in Table 3 with previous years’ must be done with caution as mergers, acquisitions, and sales can make comparisons with previous years’ data difficult. Fig. 2 illustrates the investment split in the crude oil and products pipeline companies.

ESTIMATED, ACTUAL COST TRENDS—10 YEARS* 9,400 9,000 8,600 8,200 7,800

Construction mixed

7,400

Applications to FERC by regulated interstate natural gas pipeline companies to modify certain systems must, except in certain instances, provide estimated costs of these modifications in varying degrees of details. Tracking the mileage and compression horsepower applied for and the estimated costs can indicate levels of construction activity over 2-4 years. Tables 4 and 5 show companies’ estimates during the period July 1, 2014, to June 30, 2015, for what it will cost to construct a pipeline or install new or additional compression. These tables cover a variety of locations, pipeline sizes, and compressor-horsepower ratings. Not all projects proposed are approved. And not all projects approved are eventually built. Applications filed in the 12 months ending June 30, 2015, jumped after falling last year. • Nearly 2,200 miles of pipeline were proposed for land construction, the highest level since more than 2,700 miles were proposed in 1998. No new offshore work was submitted. The land level was up from the 523 miles proposed for land construction in 2014, a drop from the 820 miles of pipeline were proposed for land construction in 2013. • New or additional compression proposed by the end of June 2015 measured more than 1.7-million hp, more than doubling the high of roughly 706,000 hp proposed the year before, itself up from the 450,000 hp proposed in 2013. Putting the uptick in US gas pipeline construction in perspective, Table 4 lists 46 land-pipeline “spreads,” or mileage segments, compared with: • 31 land and 0 marine projects (OGJ, Sept. 1, 2014, p. 122). • 26 land and 2 marine projects (OGJ, Sept. 2, 2013, p. 117). • 11 land and 0 marine projects (OGJ, Sept. 3, 2012, p. 118). • 31 land and 0 marine projects (OGJ, Sept. 5, 2011, p. 97). • 8 land and 0 marine projects (OGJ, Nov. 1, 2010, p. 108). • 21 land and 0 marine projects (OGJ, Sept. 14, 2009, p. 66). • 19 land and 0 marine projects (OGJ, Sept. 1, 2008, p. 58) • 25 land and 1 marine project (OGJ, Sept. 3, 2007, p. 51)

7,000

Oil & Gas Journal | Sept. 7, 2015

FIG. 6

6,600

Costs, $1,000/mile

6,200 5,800 5,400 5,000 4,600 4,200

Actual

3,800 3,400 3,000 2,600

Estimated

2,200 1,800 1,400 1,000 600 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 *Land and offshore pipeline construction as of June 30 of each year for the previous 12 months. Source: US FERC

• 42 land and 1 marine project (OGJ, Sept. 11, 2006, p. 46). • 56 land and 4 marine projects (OGJ, Sept. 12, 2005, p. 50). Seven of the spreads in 2015 measured 100 miles or more, as proposed large transmission lines returned, one measuring 374.5 miles and another 509 miles. For the 12 months ending June 30, 2015, the 46 land projects would cost an estimated $11.5 billion, as compared with 31 land projects for $3.43 billion a year earlier. It is helpful to that these statistics cover only FERC-regulated pipelines. Many other pipeline construction projects were announced in the 12 months ending June 30, 2015, but as mentioned earlier, many involved connecting developing natural gas shale plays such as Eagle Ford and Marcellus to already operating transportation infrastructure and may have lied outside of FERC’s jurisdiction.

119

TECHNOLOGY

US COMPRESSOR-STATION COSTS: ESTIMATED VS. ACTUAL, 2014-15 1 Location

Size, hp

Pennsylvania3 Estimated Actual

1,460

Mississippi

2,415 Estimated Actual

Nebraska

Table 8

Materials Labor Misc.2 Land Total –––––––––––––––––––––––––––––––––– Cost, $ –––––––––––––––––––––––––––––––––

$/hp

10,452,370 6,031,214

122,367 208,808

7,196,653 9,312,767

— 386,605

17,771,390 15,939,394

12,172 10,917

4,636,000 6,439,000

4,942,000 9,118,000

3,848,000 1,684,000

265,000 248,000

13,691,000 17,489,000

5,669 7,242

7,719,337 7,283,775

5,876,537 6,393,686

4,259,253 2,666,801

161,000 140,394

18,016,127 16,484,656

3,833 3,507

357,620 2,157,637

68,780 436,734

1,351,800 364,435

— —

1,778,200 2,958,806

356 592

2,040,669 1,408,936

451,720 444,778

838,606 413,580

— —

3,330,995 2,267,294

617 420

17,981,191 15,210,362

13,575,546 21,165,203

11,804,077 10,745,745

— —

43,360,814 47,121,310

6,630 7,205

13,695,850 11,136,919

14,626,357 17,081,490

12,282,555 7,789,508

1,050,000 251,087

41,654,762 36,259,004

5,410 4,709

16,343,485 16,835,582

10,136,202 12,683,771

6,179,638 4,761,114

265,650 172,135

32,924,975 34,452,602

3,466 3,627

17,315,000 17,324,000

6,664,000 11,460,000

5,688,000 2,472,000

425,000 238,000

30,092,000 31,494,000

1,893 1,981

18,048,000 18,720,000

6,739,000 12,202,000

6,321,000 2,936,000

430,000 487,000

31,538,000 34,345,000

1,984 2,160

18,491,862 16,885,044

14,772,750 15,352,462

11,767,118 7,909,545

753,000 780,982

45,784,730 40,928,033

2,880 2,574

27,438,000 15,996,412

17,287,000 27,084,484

15,156,151 12,675,030

1,208,000 1,099,413

61,089,151 56,855,339

3,818 3,553

24,730,040 23,755,445

14,900,726 14,284,506

18,306,359 13,323,191

47,000 81,126

57,984,125 51,444,268

3,204 2,842

36,232,308 35,463,647

26,570,011 23,456,561

28,910,985 15,548,487

61,400 36,776

91,774,704 74,505,471

4,412 3,582

28,320,797 27,507,334

15,104,379 15,513,752

19,233,788 15,222,387

47,000 120,889

62,705,964 58,364,362

2,412 2,245

45,509,999 48,121,284

21,144,291 29,971,220

34,240,803 29,288,120

47,000 388,315

100,942,093 107,768,939

1,941 2,072

$289,312,528 $270,276,591

$172,981,666 $216,857,455

$187,384,786 $129,203,165

$4,760,050 $4,430,722

$654,439,030 $628,677,478

$2,950 $2,834

4,700 Estimated Actual

New Jersey3

5,000 Estimated Actual

New Jersey3

5,400 Estimated Actual

Pennsylvania3 Estimated Actual

6,540

Pennsylvania3 Estimated Actual

7,700

Nebraska

9,500 Estimated Actual

Mississippi

15,900 Estimated Actual

Mississippi

15,900 Estimated Actual

New York

15,900 Estimated Actual

Maryland

16,000 Estimated Actual

Pennsylvania3 Estimated Actual

18,100

New York

20,800 Estimated Actual

Pennsylvania3 Estimated Actual

26,000

Pennsylvania3 Estimated Actual

52,000

Total

221,855 Estimated Actual

1 Actual cost data must be filed within 6 months following commissioning of installed compression equipment. Not all projects proposed (estimated costs) are built (actual costs). 2Generally includes surveys, engr., supervision, interest, freight, taxes, istration and overheads, contingencies, allowances for funds used during construction (AFUDC), and FERC fees. 3Addition. Source: US FERC; for completed-project costs filed between July 1, 2014, and June 30, 2015, under CFR Section 157.20(c)(4).

A report released in March 2014 on behalf of the Interstate Natural Gas Association of America concluded that the United States and Canada will require annual average midstream natural gas, crude oil, and NGL infrastructure investment of $30 billion/year, or $641 billion (in real 2012 dollars) total, over the 22-year period from 2014 to 2035 to accommodate

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new supplies, particularly from the prolific shale plays, and growing demand for gas in the power-generation sector. Included in the $30 billion/year are: • $10 billion/year for new oil and gas lease equipment. • Nearly $9 billion/year for expanded gas and liquids mainline capacity.

Oil & Gas Journal | Sept. 7, 2015

TECHNOLOGY

1

Oil & Gas Journal | Sept. 7, 2015

Costs, $/hp

Costs, $1,000/mile

• More than $3 billion/year for COMPONENT COSTS: ESTIMATED VS. ACTUAL1 FIG. 7 new oil and gas gathering lines. Pipelines Compressors • More than $2 billion/year for 1,400 1,800 new laterals. 1,304 1,300 • Roughly $2 billion/year for new 1,597 1,599 1,218 1,600 1,200 LNG export plants. 1,428 1,100 The report also forecasted the need 1,400 977 1,000 for about 850 miles/year of new gas 1,200 1,135 900 transmission mainline, more than 800 845 miles/year in new natural gas later800 1,000 780 als to-from power plants, processing 700 800 784 582 plants, and storage fields, almost 700 600 664 miles/year of new NGL transmission 500 600 line, and more than 730 miles/year in 400 new oil transmission line.1 400 300 Against this backdrop, estimated 200 217 235 200 $/mile costs for new projects as filed 100 21 20 by operators with FERC remained his0 0 Materials Labor Misc.2 ROW Materials Labor Misc.2 Land torically high. For proposed onshore US gas pipeline projects in 2014-15 Estimated Actual the average cost was $5.2 million/mile, Onshore only. For construction cost filings made before July 1, 2015. Generally includes surveying, engineering, supervision, istration and overhead, interest, contingencies and allowances for funds used during construction (AFUDC), and regulatory filing fees. down from the 2013-14 average cost of Source: US FERC $6.6 million/mile, but still well above most recent pricing. In 2012-13 the average cost was $4.1 million/mile as compared with $3.1 • ROW and damages—$378,255/mile, up from million/mile in 2011-12; $4.4 million/mile in 2010-11; $5.1 $343,850/mile for 2013-14. million/mile in 2009-10; $3.7 million/mile in 2008-09; and Table 4 lists proposed pipelines in order of increasing size $3.4 million/mile in 2007-08. (OD) and increasing lengths within each size. The average cost-per-mile for the projects rarely shows Cost components clear-cut trends related to either length or geographic area. Variations over time in the four major categories of pipeIn general, however, the cost-per-mile within a given diameline construction costs—material, labor, miscellaneous, and ter decreases as the number of miles rises. Lines built nearer right-of-way (ROW)—can also suggest trends within each populated areas also tend to have higher unit costs. group. Additionally, road, highway, river, or channel crossings Materials can include line pipe, pipe coating, and cathodand marshy or rocky terrain strongly affect pipeline conic protection. struction costs. “Miscellaneous” costs generally cover surveying, engiFig. 3, derived from Table 4, shows the major cost-comneering, supervision, contingencies, telecommunications ponent splits for pipeline construction costs. equipment, freight, taxes, allowances for funds used during Labor costs fell as a portion of land construction costs, construction (AFUDC), istration and overheads, and but remained the single most expensive category. Labor’s regulatory filing fees. portion of estimated costs for land pipelines slipped to ROW costs include obtaining rights-of-way and allowing 37.77% from 42.36% in 2014, 38.84% in 2013, 44.61% in for damages. 2012, 44.27% in 2011, 44.61% in 2010, and 37.95% in 2009. For the 46 land spreads filed for in 2014-15, cost-per-mile Material costs for land pipelines, meanwhile, rebounded projections rose in material and ROW and fell in labor and to 19.34% from 13.6% in 2014, 23.2% in 2013, 15.99% in miscellaneous. In 2011 miscellaneous charges ed mate2012, and 14.54% in 2011. rial to become the second most expensive cost category and Fig. 4 plots a 10-year comparison of land-construction they retained this position through 2015: unit costs for the two major components, material and labor. • Material—$1,012,698/mile, up form $894,139/mile Fig. 5 shows the cost split for land compressor stations 2013-14. based on data in Table 5. • Labor—$1,977,938/mile, down from $2,781,619/mile Table 6 lists 10 years of unit land-construction costs for for 2013-14. natural gas pipeline with diameters ranging from 8 to 36 • Miscellaneous—$1,867,393/mile, down from in. The table’s data consist of estimated costs filed under $2,547,600/mile for 2013-14. dockets with FERC, the same data shown in Tables 4 and 5. 2

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TECHNOLOGY Table 6 shows that the average cost per mile for any given diameter may fluctuate year to year as projects’ costs are affected by location, terrain, population density, or other factors.

Completed projects’ costs In most instances, a natural gas pipeline company must file with FERC what it has actually spent on an approved and built project. This filing must occur within 6 months after the pipeline’s successful hydrostatic testing or the compressor’s being put in service. Fig. 6 shows 10 years of estimated vs. actual costs on costper-mile bases for project totals. Tables 7 and 8 show actual costs for pipeline and compressor projects reported to FERC during the 12 months ending June 30, 2015. Fig. 7 depicts how total actual costs ($/mile) for each category compare with estimated costs. The spike in both categories for 2014 stems from a larger than usual proportion of the pipeline mileage completed that year being in high-cost urban northeast US settings. Actual labor costs for pipeline construction were nearly $400,000/mile lower than estimated costs for the same proj-

ects. Overall actual costs were nearly 10% lower than projected costs for the 12 months ending June 30, 2015, despite higher labor and ROW costs. Some of these projects may have been proposed and approved much earlier than the 1-year survey period. Others may have been filed for, approved, and built during the survey period. If a project was reported in construction spreads in its initial filing, that’s how projects are broken out in Table 4. Completed projects’ cost data, however, are typically reported to FERC for an entire filing, usually but not always separating pipeline from compressor-station (or metering site) costs and lumping various diameters together. The 12 months ending June 30, 2015, saw nearly 222,000 hp completed, up from recent levels. Actual compression costs were 116/hp (3.9%) lower than estimates (Table 8).

References 1. ICF International, “North America Midstream Infrastructure Through 2035; Capitalizing on Our Energy Abundance,” Mar. 17, 2014.

NOW FOR THE SEG INTERNATIONAL EXPOSITION AND 85TH ANNUAL MEETING

Save $100 by ing Now online at www.seg.org/am 18 – 2 3 OCTOBER 2015 • ERNEST N. MORIAL CONVENTION CENTER

WWW.SEG.ORG / AM

Oil & Gas Journal | Sept. 7, 2015

123

Alpine Transportation Co. . . . . . . . . . . . . . . . . . Arrowhead Louisiana Gathering LLC. . . . . . . . . . Arrowhead Offshore Pipeline LLC . . . . . . . . . . . . Bakken Pipeline Co. LP . . . . . . . . . . . . . . . . . . . Bakkenlink Pipeline LLC . . . . . . . . . . . . . . . . . . Baton Rouge Pipeline LLC . . . . . . . . . . . . . . . . . Belle Fourche Pipeline Co.. . . . . . . . . . . . . . . . . Belle Rose NGL Pipeline LLC . . . . . . . . . . . . . . . Bengal Pipeline Co. . . . . . . . . . . . . . . . . . . . . . . Black Lake Pipeline Co. . . . . . . . . . . . . . . . . . . . Blue Racer NGL Pipelines LLC (new) . . . . . . . . . BOE Pipeline LLC (new). . . . . . . . . . . . . . . . . . . BP Oil Pipeline Co. . . . . . . . . . . . . . . . . . . . . . . BP Pipelines (Alaska) Inc.1. . . . . . . . . . . . . . . . . BP Pipelines (North America) Inc. . . . . . . . . . . . BP Transportation (Alaska) Inc. . . . . . . . . . . . . . BreitBurn Operating LP . . . . . . . . . . . . . . . . . . . Bridger Pipeline LLC . . . . . . . . . . . . . . . . . . . . . Buckeye Linden Pipe Line Co. LLP (new). . . . . . Buckeye Pipe Line Co. LP . . . . . . . . . . . . . . . . . Buckeye Pipe Line Transportation LLC . . . . . . . . Butte Pipe Line Co. . . . . . . . . . . . . . . . . . . . . . . Calnev Pipe Line Co. . . . . . . . . . . . . . . . . . . . . . CS Transportation LLC . . . . . . . . . . . . . . . . . . Cenex Pipeline LLC . . . . . . . . . . . . . . . . . . . . . . Centennial Pipeline LLC . . . . . . . . . . . . . . . . . . . Centurion Pipeline LP . . . . . . . . . . . . . . . . . . . . Chaparral Pipeline Co. LLC . . . . . . . . . . . . . . . . Chevron Pipe Line Co. . . . . . . . . . . . . . . . . . . . . Chicap Pipe Line Co. . . . . . . . . . . . . . . . . . . . . . Chisholm Pipeline Co. . . . . . . . . . . . . . . . . . . . . Chunchula Pipeline Co. LLC. . . . . . . . . . . . . . . . Citgo Pipeline Co.. . . . . . . . . . . . . . . . . . . . . . . . Citgo Products Pipeline Co. . . . . . . . . . . . . . . . . Coffeyville Resources Crude Transportation LLC Collins Pipeline Co. . . . . . . . . . . . . . . . . . . . . . . Colonial Pipeline Co. . . . . . . . . . . . . . . . . . . . . . Conoco Offshore Pipe Line Co.. . . . . . . . . . . . . . ConocoPhillips Transportation Alaska Inc.1 . . . . . Cypress Interstate Pipeline LLC . . . . . . . . . . . . . D Sand Hills Interstate Pipeline LLC. . . . . . . . D Southern Hills Pipeline LLC . . . . . . . . . . . . D Wattenberg Pipeline LLC . . . . . . . . . . . . . . Delaware Pipeline Co. LLC . . . . . . . . . . . . . . . . . Dixie Pipeline Co.. . . . . . . . . . . . . . . . . . . . . . . . DryTrails Midstream Energy LLC. . . . . . . . . . . . . El Dorado Pipeline Co. LLC . . . . . . . . . . . . . . . . Ellwood Pipeline Inc. . . . . . . . . . . . . . . . . . . . . . Enable Bakken Crude Services LLC . . . . . . . . . . Enbridge Energy LP . . . . . . . . . . . . . . . . . . . . . Enbridge Pipelines FSP (new) . . . . . . . . . . . . . . Enbridge Pipelines (Ozark) LLC . . . . . . . . . . . . . Enbridge Pipelines (Patoka) LLC . . . . . . . . . . . . Enbridge Pipelines (Southern Lights) LLC. . . . . . Enbridge Pipelines (Toledo) Inc.. . . . . . . . . . . . . Endicott Pipeline Co. . . . . . . . . . . . . . . . . . . . . . Energy XXI Pipeline LLC. . . . . . . . . . . . . . . . . . . EnLink NGL Pipeline LP (formerly Crosstex NGL Pipeline LP). . . . . . . . . Enterprise Crude Pipeline LLC . . . . . . . . . . . . . . Enterprise Lou-Tex NGL Pipeline LP . . . . . . . . . . Enterprise TE Products Pipeline Co. LLC . . . . . . EPL Pipeline LLC (new) . . . . . . . . . . . . . . . . . . . Excel Pipeline LLC . . . . . . . . . . . . . . . . . . . . . . . Explorer Pipeline Co. . . . . . . . . . . . . . . . . . . . . . Express Pipeline LLC . . . . . . . . . . . . . . . . . . . . . ExxonMobil Pipeline Co.1 . . . . . . . . . . . . . . . . . .

Company

oil pipelines

5,610 6,431 1,248 19,811 18,413 1,198 24,068 1,115 39,233 8,077 -85 -2,124 -1,933 -17,212 -21,120 -42,862 520,674 62,650 -3,492 107,517 12,123 14,728 24,185 48,313 14,488 -28,676 92,144 17,570 442,856 2,591 2,109 -2,262 30,284 11,565 — 2,804 322,262 1,674 78,158 9,995 -21,750 48,051 7,016 6,608 31,159 153 1,611 8,782 -4,723 642,833 72,868 18,628 1,555 212,995 8,293 1,406 3,794

37,238 598,050 22,159 61,759 — 3,018 84,657 49,285 239,376

20,111 10,174 2,386 30,565 29,842 2,525 79,856 3,085 65,898 12,668 3,213 2,034 3,078 438,110 141,136 529 3,021 158,049 2,185 316,563 46,969 53,627 51,943 117,328 29,581 17,520 227,025 48,519 188,779 15,820 6,154 1,864 53,662 26,742 17,436 11,897 1,171,694 2,708 517,236 14,206 10,584 94,170 13,238 9,505 87,956 785 7,009 7,099 4,632 1,596,912 38,771 63,277 912 183,871 49,693 12,585 24,514

69,393 625,984 36,732 432,611 — 4,995 339,785 113,981 435,243

759 — — 4,000 6,056 — 55,832 93 4,033 3,506 155,597 49,338 — — 1,265 -108,391 — 119,861 — 51,667 7,121 738 8,421 35,335 9,164 2,168 242,135 15,295 -30,599 5,576 187 1,254 4,077 933 11,556 -49 112,896 — — 24 5,458 145,978 1,183 512 12,491 — — 76 90,984 1,837,848 1,146,652 46,662 1,134 15,854 7,317 61 534

-69 517,619 8 3,146,988 — — 55,295 5,560 26,122

104,011 7,631 3,120 111,161 154,195 14,900 195,623 32,180 203,936 45,654 155,597 49,338 11,183 — 463,160 — 6,691 358,973 — 881,030 266,881 35,725 357,478 370,208 87,657 304,526 1,171,693 158,749 683,147 83,241 22,834 19,810 36,284 45,320 60,087 25,448 2,841,288 — — 38,722 5,459 992,903 39,611 17,748 164,943 2,133 2,124 2,055 162,189 10,972,918 2,747,663 236,703 5,308 1,444,293 253,217 64,260 115,874

254,707 2,011,456 118,419 2,862,571 — 9,824 810,900 429,549 577,867

641 — 115 1,102 1,342 418 3,862 371 11,094 4,020 47 — 2,008 54,109 19,411 1 55 — 42 36,697 7,046 14,248 8,574 39,398 5,085 961 23,912 22,464 7,814 1,778 2,249 66 3,433 2,141 1,029 4,920 852,749 401 64,902 2,070 2,491 23,405 3,144 433 21,925 — 828 — — 582,351 4,464 31,594 1 36,045 3,113 86 —

3,746 31,177 7,024 50,558 — 735 133,396 29,599 59,121

— — — — — 418 78 371 11,094 4,020 47 — — — 5,261 — — — 42 36,697 7,044 — 8,574 — 5,085 961 — 22,464 930 — 2,249 66 6 2,141 — 4,920 852,749 — — 2,070 2,491 23,405 3,144 433 21,925 — 782 — — — — — — — — — —

3,746 — 7,024 50,558 — — 133,396 — 8,882

641 — 115 1,102 1,342 — 3,784 — — — — — 2,008 54,109 14,150 1 55 — — — 2 14,248 — 39,398 — — 23,912 — 6,884 1,778 — — 3,427 — 1,029 — — 401 64,902 — — — — — — — 46 — — 582,351 4,464 31,594 1 36,045 3,113 86 —

— 31,177 — — — 735 — 29,599 50,239

18,649 — 5,002 18,117 20,957 13,946 36,410 7,727 184,759 12,842 810 — 4,226 67,609 192,173 56 2,965 — 8,257 338,194 66,785 49,382 38,092 67,798 16,622 1,321 163,909 41,238 135,035 40,145 12,197 657 170,604 16,723 28,658 38,878 915,301 3,580 82,509 19,834 3,774 24,873 7,081 18,742 44,676 — 4,864 — — 767,589 9,487 72,949 10,207 44,242 41,962 3,430 —

25,438 959,130 24,996 281,165 — 14,366 221,803 71,360 707,307

— — — — — 13,946 1,008 7,727 184,759 12,842 810 — — — 29,524 — — — 8,257 338,194 66,753 — 38,092 — 16,622 1,321 — 41,238 9,459 — 12,197 657 5,714 16,723 — 38,878 915,301 — — 19,834 3,774 24,873 7,081 — 44,676 — 3,229 — — — — — — — — — —

25,438 — 24,996 281,165 — — 221,803 — 311,955

18,649 — 5,002 18,117 20,957 — 35,402 — — — — — 4,226 67,609 162,649 56 2,965 — — — 32 49,382 — 67,798 — — 163,909 — 125,576 40,145 — — 164,890 — 28,658 — — 3,580 82,509 — — — — 18,742 — — 1,635 — — 767,589 9,487 72,949 10,207 44,242 41,962 3,430 —

— 959,130 — — — 14,366 — 71,360 395,352

35 25 23 64 97 30 2,951 48 158 313 58 40 945 800 3,394 — 85 1,439 — 2,778 1,334 373 562 581 684 797 3,800 822 1,447 234 185 144 133 344 — 124 5,586 183 819 104 660 912 444 23 1,320 45 270 — 44 4,486 594 433 — 816 88 43 —

— 4,661 281 4,668 — 49 1,833 509 4,958 — — 281 4,668 — — 1,833 — 2,504

— 4,661 — — — 49 — 509 1,969

— — — — — — — — 485

––––––––––– Fiscal data, $1,000 –––––––––– Carrier Property Operating property change revenue Income

–––– Total trunkline traffic, –––– –––– million bbl–miles –––– Crude Products Total

— — — — — 30 80 48 158 313 58 — — — 1,638 — — — — 2,778 1,334 — 562 — 684 797 — 822 7 — 185 144 — 344 — 124 5,586 — — 104 660 912 356 23 1,320 — — — — — — — — — — — —

Total

35 — 23 64 97 — 835 — — — — 40 945 800 1,756 — 19 464 — — — 373 — 581 — — 2,430 — 1,265 234 — — 128 — — — — — 819 — — — — — — — 270 — — 4,486 594 433 — 816 88 43 —

Products

–––– Deliveries, 1,000 bbl ––––

Crude

— 25 — — — — 2,036 — — — — — — — — — 66 975 — — — — — — — — 1,370 — 175 — — — 5 — — — — 183 — — — — 88 — — 45 — — 44 — — — — — — — —

–––––––––––– Miles of pipeline –––––––––––– ––––––– Trunk ––––––– Crude Products Total

Gathering

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Oil & Gas Journal | Sept. 7, 2015

Front Range Pipeline LLC . . . . . . . . . . . . . . . . . Frontier Pipeline Co . . . . . . . . . . . . . . . . . . . . . . Frontier Pipeline LLC . . . . . . . . . . . . . . . . . . . . . FW GOM Pipeline Inc . (formerly Apache GOM Pipeline Inc .) . . . . . . . . GEL Offshore Pipeline LLC . . . . . . . . . . . . . . . . . Genesis Pipeline USA LP . . . . . . . . . . . . . . . . . GNB NGL Pipeline LLC . . . . . . . . . . . . . . . . . . . Hardin Street Holdings LLC . . . . . . . . . . . . . . . . Hawthorn Oil Transportation (North Dakota) Inc . Hawthorn Oil Transportation (Oklahoma) Inc . . . . Heartland Pipeline Co . . . . . . . . . . . . . . . . . . . . . Hiland Crude LLC . . . . . . . . . . . . . . . . . . . . . . . Hilcorp Pipeline Co . LLC . . . . . . . . . . . . . . . . . . Holly Energy Partners - Operating LP . . . . . . . . . IMTT-Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . Independent Trading and Transportation LLC . . . Inland Corp . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Jayhawk Pipeline LLC . . . . . . . . . . . . . . . . . . . . Keystone Pipeline Co . LLC . . . . . . . . . . . . . . . . . Kiantone Pipeline Corp . . . . . . . . . . . . . . . . . . . . Kinder Morgan Cochin LLC . . . . . . . . . . . . . . . . Kinder Morgan Wink Pipeline LLC . . . . . . . . . . . Koch Pipeline Co . LP . . . . . . . . . . . . . . . . . . . . . Kuparuk Transportation Co . . . . . . . . . . . . . . . . . Laclede Pipeline Co . . . . . . . . . . . . . . . . . . . . . . Legacy Reserves Operating LP (new) . . . . . . . . . LOCAP LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lone Star NGL Pipeline LP . . . . . . . . . . . . . . . . . Magellan Pipeline Co . LP . . . . . . . . . . . . . . . . . . Magnolia Pipeline Co . LLC . . . . . . . . . . . . . . . . . Marathon Pipe Line LLC . . . . . . . . . . . . . . . . . . . Marketlink LLC (new) . . . . . . . . . . . . . . . . . . . . . MarkWest Liberty Ethane Pipeline LLC . . . . . . . . MarkWest Michigan Pipeline Co . LLC . . . . . . . . . Mars Oil Pipeline Co . . . . . . . . . . . . . . . . . . . . . . Medallion Pipeline Co . LLC (new) . . . . . . . . . . . . Mid-America Pipeline Co . LLC . . . . . . . . . . . . . . Mid-Valley Pipeline Co . . . . . . . . . . . . . . . . . . . . Milne Point Pipeline LLC . . . . . . . . . . . . . . . . . . Minnesota Pipe Line Co . LLC . . . . . . . . . . . . . . . Mobil Eugene Island Pipeline Co . . . . . . . . . . . . . Mobil Pipe Line Co . . . . . . . . . . . . . . . . . . . . . . . MOEM Pipeline LLC . . . . . . . . . . . . . . . . . . . . . . Muskegon Pipeline LLC . . . . . . . . . . . . . . . . . . . Mustang Pipe Line LLC . . . . . . . . . . . . . . . . . . . NORCO Pipe Line Co . LLC . . . . . . . . . . . . . . . . North Dakota Pipeline Co . LLC . . . . . . . . . . . . . . Northstar Pipeline Co . LLC . . . . . . . . . . . . . . . . . Nova Chemicals Inc . . . . . . . . . . . . . . . . . . . . . . NuStar Logistics LP (including the former NuStar Crude Oil Pipeline LP) . . . . . . . . NuStar Pipeline Operating Partnership LP . . . . . Nutaaq Pipeline LLC (new) . . . . . . . . . . . . . . . . Ohio River Pipe Line LLC . . . . . . . . . . . . . . . . . . Ohio River Valley Pipeline LLC (including the former Ohio Oil Gathering II LLC) Olympic Pipe Line Co . . . . . . . . . . . . . . . . . . . . . ONEOK Arbuckle North Pipeline LLC . . . . . . . . . ONEOK Bakken Pipeline LLC . . . . . . . . . . . . . . . ONEOK NGL Pipeline LLC . . . . . . . . . . . . . . . . . ONEOK North System LLC . . . . . . . . . . . . . . . . . Osage Pipe Line Co . LLC . . . . . . . . . . . . . . . . . . Overland Pipeline LLC . . . . . . . . . . . . . . . . Paline Pipeline Co . LLC . . . . . . . . . . . . . . . . . . . Parkway Pipeline LLC . . . . . . . . . . . . . . . . . . . . . Phillips 66 Carrier LLC . . . . . . . . . . . . . . . . . . . .

Company

oil pipelines (ConTinUeD)

8,763 7,530 -16,802 — 622 5,828 1,654 42,237 745 566 1,704 52,153 — 144,032 -1,075 7,618 9,216 1,642 308 -1,297 62,966 26,936 60,535 9,204 302 — 16,025 146,241 348,364 12,770 147,233 -99,536 4,180 -212 89,839 -1,899 319,063 11,691 453 22,821 976 -26,157 7,192 2,744 31,282 -960 181,558 -2,179 —

70,481 145,896 2,144 36,779 6,632 10,736 2,984 50,547 -91,640 46,833 6,340 52,583 1,115 16,136 103,969

28,310 12,985 892 — 3,296 27,189 4,595 65,967 2,654 2,249 6,816 106,005 — 102,442 2,854 1,383 34,845 22,548 4,298 4,431 71,223 47,292 92 28,288 1,469 — 42,053 211,450 967,379 16,119 427,317 221,916 15,170 5,003 161,094 1,994 557,819 72,715 9,564 192,441 2,933 40,790 12,533 7,734 45,730 1,862 258,410 11,816 —

268,142 139,532 3,974 64,059 13,028 70,967 149,870 99,055 82,598 129,873 12,406 92,440 9,590 31,298 128,031

564,010 585 479 — 1,564 36,950 407 — 18 21 31 500,779 — 33,816 994 — 22,087 3,998 — 2,594 99,830 39,005 — 2,598 -110 — 6,705 49,064 48,902 1 76,011 196,629 2,945 972 -1,347 102,217 696,666 15,855 -5,801 4,758 — 9,310 -119 575 -1,654 529 441,312 -12,490 —

195,958 5,110 1,710 5,118 45,073 9,515 132 104,720 40,865 10,454 9,725 16,411 — 5,006 28,692

520,327 79,649 6,859 — 22,138 153,451 27,318 19,981 9,739 15,434 13,111 1,040,436 — 260,697 25,980 3,158 60,353 82,813 — 16,138 371,411 133,187 22,127 215,234 6,354 — 174,857 1,244,580 2,194,841 7,595 970,477 196,629 130,453 24,137 301,267 105,959 2,036,157 145,180 49,046 641,955 9,001 201,860 27,232 29,776 57,857 32,929 1,361,332 76,848 —

1,015,803 628,612 1,710 217,414 48,210 247,807 82,085 677,520 785,499 309,073 35,731 984,844 56,295 264,552 384,254

6,390 3,869 26 — 337 1,012 302 38,809 — — 1,837 1,520 — 12,452 227 — 4,065 4,374 719 1,651 13,814 10,178 1 2,247 — — 20,859 43,148 154,120 1,213 79,560 48,245 — 110 — — 93,324 57,703 77 35,728 188 4,687 966 1,768 6,722 195 15,461 59 —

32,217 19,806 — 3,328 — 19,097 2,549 7,694 36,392 13,566 7,005 17,986 2,175 2,128 15,698

6,390 — 26 — — — 302 — — — 1,837 — — 11,802 227 — 4,065 — 719 — 13,814 — — — — — — 43,148 109,978 — 19,373 — — — — — 93,324 — — — — 845 — 1,768 — 195 — — —

19,038 19,806 — 3,328 — 19,097 2,549 7,694 36,392 13,566 — 17,986 — 2,128 14,762

— 3,869 — — 337 1,012 — 38,809 — — — 1,520 — 650 — — — 4,374 — 1,651 — 10,178 1 2,247 — — 20,859 — 44,142 1,213 60,187 48,245 — 110 — — — 57,703 77 35,728 188 3,842 966 — 6,722 — 15,461 59 —

13,179 — — — — — — — — — 7,005 — 2,175 — 936

Total

15,626 12,387 6,465 — 2,364 19,232 9,435 72,994 — — 6,038 56,269 — 75,363 28,381 — 53,201 45,547 2,863 — 19,018 44,594 368 77,938 — — 365,834 77,120 696,142 15,851 655,953 99,357 11,580 3,525 — — 282,171 116,532 7,084 129,032 1,192 173,220 27,543 10,422 32,389 3,753 117,325 3,475 —

256,053 65,867 — 44,495 3,170 104,180 44,713 13,518 125,712 50,684 51,889 37,236 11,693 15,199 213,047

Products

15,626 — 6,465 — — — 9,435 — — — 6,038 — — 61,477 28,381 — 53,201 — 2,863 — 19,018 — — — — — — 77,120 485,474 — 275,808 — — — — — 282,171 — — — — 20,579 — 10,422 — 3,753 — — —

101,019 65,867 — 44,495 — 104,180 44,713 13,518 125,712 50,684 — 37,236 — 15,199 127,975

Crude

— 12,387 — — 2,364 19,232 — 72,994 — — — 56,269 — 13,886 — — — 45,547 — — — 44,594 368 77,938 — — 365,834 — 210,668 15,851 380,145 99,357 11,580 3,525 — — — 116,532 7,084 129,032 1,192 152,641 27,543 — 32,389 — 117,325 3,475 —

155,034 — — — 3,170 — — — — — 51,889 — 11,693 — 85,072

449 290 3 — 197 376 32 730 12 18 49 1,259 — 2,535 10 29 352 652 — 78 1,245 438 8 37 40 — 57 810 10,415 77 3,042 — 33 238 163

8,068 1,043 11 975 157 1,157 56 170 211 316 875 17 — 3,754 2,342 — 533 — 414 57 766 3,231 1,637 135 1,041 186 140 938

449 — 3 — — — 32 — — — 49 — — 1,554 10 — 352 — — — 1,245 — — — 40 — — 810 9,172 — 1,381 — — — — — 8,068 — — — — 84 — 170 — 316 — — —

2,778 2,342 — 533 — 414 57 766 3,231 1,637 — 1,041 — 140 926

— 85 245 — 730 12 18 — 313 — 232 — 2 — 652 — 78 — 422 8 37 — — 57 — 1,243 — 1,661 — 33 152 163 88 — 1,043 11 975 157 979 56 — 211 — 727 17 —

976 — — — — — — — — — 135 — 186 — 12

— 112 131 — — — — — 946 — 749 — 27 — — — — — 16 — — — — — — — 77 — — — 86 — — — — — — — 94 — — — — 148 — —

— — — — — — — — — — — — — — —

––––––––––– Fiscal data, $1,000 –––––––––– Carrier Property Operating property change revenue Income

–––– Total trunkline traffic, –––– –––– million bbl–miles –––– Crude Products Total

— 290 —

–––– Deliveries, 1,000 bbl ––––

— — —

–––––––––––– Miles of pipeline –––––––––––– ––––––– Trunk ––––––– Gathering Crude Products Total

Oil & Gas Journal | Sept. 7, 2015

125

89,663 87,452 56,375 49,974

14,571 14,590

2014 Totals . . . . . . . . . . . . . . . . . . . . . . . . . . 2013 Totals . . . . . . . . . . . . . . . . . . . . . . . . . .

192,658 81,410 — — 905,310 25,040 — 97,144 — 1,401 31,669 — — — 13,585 — — 69,434 8,193 — 398,237 — — 8,664 238,475 72,938 — 27,260 — — 5,114 21,137 526,855 8,371 — 23,630 — — — 196,231 52,364 — — 931 52,823 83,025 — — 874 2,934 4,186 252 — 36,267 — 136,745 — — 30,702 — — — — 5,671 — 129,991

160,521 9,288,693 152,016 8,122,168

5,137 2,220 563 137 7,830 — 3,123 931 47 28 166 55 60 83 804 46 249 1,892 613 — — 1,248 2,470 135 514 121 572 93 716 755 31 313 5,923 699 155 775 1,104 593 14 1,869 64 167 427 22 73 17 24 30 55 80 56 — — 610 710 532 2,179 43 1,052 41 50 30 628 1,367 698 446

Crude

357,529 107,916 19,714 6,842 905,310 25,040 229,801 97,144 — 1,401 31,669 547 — — 13,585 94,273 4,614 69,434 27,706 — 398,237 76,242 395,627 8,664 266,184 72,938 6,799 27,260 64,576 87,470 5,114 21,137 671,875 8,371 — 23,630 22,102 34,640 — 196,231 52,364 14,351 6,410 931 71,289 83,025 101,217 10,941 14,594 2,934 4,186 252 — 152,929 6,671 136,745 94,946 — 30,702 358 586 12,227 143,632 65,437 36,724 129,991

Total

2,133,547 4,192,863 2,053,479 3,800,065

85,925 17,920 872 -4,241 857,390 3,607 21,275 6,899 — 628 137 -744 — — 6,367 18,335 2,777 13,825 2,781 2,200 2,772,587 5,501 44,611 71 259,418 — 4,233 67 8,924 13,180 — 46,406 2,159,647 1,341,189 264 122,907 5,105 16,836 — 663,894 1,287 123 -208 7,307 313 2,088 -3,034 181 740 70,922 67,855 — — 17,686 7,121 5,486 5,900 6,412 177,546 126 32,189 975 7,797 27,470 18,724 17,549

365,647 93,521 32,248 2,012 780,260 4,972 284,096 146,213 28,370 2,375 14,369 1,265 3,261 3,327 28,339 3,466 11,952 73,555 22,651 3,465 387,233 87,706 285,474 7,144 254,332 25,399 22,913 17,854 38,610 118,906 5,992 32,005 555,499 28,343 15,206 61,303 39,586 72,957 1,341 1,095,777 19,466 21,841 28,371 1,159 11,596 28,789 22,407 4,603 7,899 1,050 6,489 — — 71,058 8,060 65,182 96,653 2,493 160,369 6,508 1,230 4,867 94,741 46,432 41,211 98,892

$84,910,293 $20,226,648 $19,281,113 $9,572,871 $67,890,464 $14,521,008 $15,733,837 $6,980,508

993,341 169,638 103,845 41,814 3,232,739 — 594,794 269,258 89,120 302,976 42,876 21,942 9,153 20,845 43,860 32,428 57,513 260,896 55,673 12,632 2,906,988 409,239 1,847,304 39,168 689,652 45,414 97,537 253,607 340,111 223,857 38,415 200,259 3,550,099 1,341,189 33,500 268,973 315,795 982,528 361 8,880,904 49,672 180,019 344,714 12,424 58,134 123,571 84,795 33,626 3,811 70,922 67,855 — — 117,322 40,788 113,460 270,985 80,456 535,008 30,744 150,254 25,302 180,145 449,497 105,851 383,248

167,671 45,125 12,854 23,227 416,324 -4,851 56,551 75,546 12,833 -13,500 8,664 12,674 60,644 5,491 9,860 2,126 4,874 24,724 8,011 723 296,427 23,660 177,132 1,885 373,021 6,342 9,903 10,392 10,602 87,600 2,379 4,765 346,433 33,317 11,072 16,571 -2,127 32,452 502 665,532 10,266 6,662 6,477 268 3,832 20,200 15,202 3,212 4,258 202 568 — — 25,030 52,049 25,179 39,566 1,905 124,264 4,584 5,085 2,178 33,800 13,535 13,184 66,574 23,897 2,866 4,165 63 — — 137,023 — — — — 7 — — — — 1,029 — 312 — — 46,771 63,875 — 117 — 3,891 — 2,941 15,593 — — 10,334 — 2,366 — 24,400 19,123 — — — 2,169 2,511 — 152 — 695 328 480 — — — — 12,026 2,154 — 37,451 — — 15 29 367 10,772 10,955 7,438 —

41,517 15,156 4,165 63 119,974 1,014 137,023 51,069 — 39 5,257 7 — — 1,268 — 1,029 6,352 5,203 — 59,976 46,771 63,875 400 18,432 4,029 3,891 2,364 2,941 15,593 148 3,602 52,436 5,834 2,366 12,926 24,400 19,123 287 209,833 2,226 2,169 2,511 20 2,900 1,411 695 328 555 261 234 2 — 12,156 2,154 45,223 37,451 — 22,878 15 29 367 10,772 11,039 7,438 18,251 17,620 12,290 — 119,974 1,014 — 51,069 — 39 5,257 — — — 1,268 — — 6,352 4,891 — 59,976 — — 400 18,315 4,029 — 2,364 — — 148 3,602 42,102 5,834 — 12,926 — — 287 209,833 2,226 — — 20 2,748 1,411 — — 75 261 234 2 — 130 — 45,223 — — 22,878 — — — — 84 — 18,251

––––––––––– Fiscal data, $1,000 –––––––––– Carrier Property Operating property change revenue Income

–––– Total trunkline traffic, –––– –––– million bbl–miles –––– Crude Products Total

6,880,818 16,169,511 2,059,316 6,471,431 14,593,599 1,759,533

164,871 26,506 19,714 6,842 — — 229,801 — — — — 547 — — — 94,273 4,614 — 19,513 — — 76,242 395,627 — 27,709 — 6,799 — 64,576 87,470 — — 145,020 — — — 22,102 34,640 — — — 14,351 6,410 — 18,466 — 101,217 10,941 13,720 — — — — 116,662 6,671 — 94,946 — — 358 586 12,227 143,632 59,766 36,724 —

Products

–––– Deliveries, 1,000 bbl ––––

Crude and total mileages represent 818 miles of Trans-Alaska Pipeline, operated by Alyeska Pipeline Service Co ., Anchorage . This figure is included in column total only once to avoid duplication . Sources: US FERC Form No . 6: Annual Report of Oil Pipelines, Dec . 31, 2014 .

1

2,482 514 563 137 — — 3,123 — 47 — — 55 — — — 46 249 — .— — — 1,248 2,470 — 45 — 572 — 716 755 — — 1,801 — 155 — 1,104 593 — — — 167 427 — 20 — 24 30 54 — — — — 610 710 — 2,179 — — 41 50 30 628 1,367 698 —

2,111 840 — — 4,860 — — 928 — 28 166 — — — 736 — — 1,631 .— — — — — — 469 121 — 93 — — 31 — 3,578 699 — 547 — — 14 1,869 64 — — 22 53 17 — — 1 80 56 — — — — 532 — 43 1,052 — — — — — — 446

544 866 — — 2,970 — — 3 — — — — 60 83 68 — — 261 613 — — — — 135 — — — — — — — 313 544 — — 228 — — — — — — — — — — — — — — — — — — — — — — — — — — — — — —

–––––––––––– Miles of pipeline –––––––––––– ––––––– Trunk ––––––– Gathering Crude Products Total

Phillips 66 Pipeline LLC . . . . . . . . . . . . . . . . . . . Phillips Texas Pipeline Co . Ltd . . . . . . . . . . . . . . . Pioneer Pipe Line Co . . . . . . . . . . . . . . . . . . . . . Plains LPG Services LP . . . . . . . . . . . . . . . . . . . Plains Pipeline LP . . . . . . . . . . . . . . . . . . . . . . . Plains Southcap Inc . (new) . . . . . . . . . . . . . . . . Plantation Pipe Line Co . . . . . . . . . . . . . . . . . . . . Platte Pipe Line Co . . . . . . . . . . . . . . . . . . . . . . . PMI Services North America Inc . . . . . . . . . . . . . Point Arguello Pipeline Co . . . . . . . . . . . . . . . . . . Portland Pipe Line Corp . . . . . . . . . . . . . . . . . . . Premcor Pipeline Co . . . . . . . . . . . . . . . . . . . . . . QEPM Gathering I LLC . . . . . . . . . . . . . . . . . . . . Razorback LLC . . . . . . . . . . . . . . . . . . . . . . . . . Red Butte Pipe Line Co . . . . . . . . . . . . . . . . . . . . Regency Liquids Pipeline LLC . . . . . . . . . . . . . . Rio Grande Pipeline Co . . . . . . . . . . . . . . . . . . . . Rocky Mountain Pipeline System LLC . . . . . . . . SALA Gathering Systems LLC . . . . . . . . . . . . . . . San Pedro Bay Pipeline Co . . . . . . . . . . . . . . . . . Seaway Crude Pipeline Co . . . . . . . . . . . . . . . . . Seminole Pipeline Co . . . . . . . . . . . . . . . . . . . . . SFPP LP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shamrock Pipe Line Corp . . . . . . . . . . . . . . . . . Shell Pipeline Co . LP . . . . . . . . . . . . . . . . . . . . . Ship Shoal Pipeline Co . . . . . . . . . . . . . . . . . . . . Skelly-Belvieu Pipeline Co .LLC . . . . . . . . . . . . . . SLC Pipeline LLC . . . . . . . . . . . . . . . . . . . . . . . . Sorrento Pipeline Co LLC . . . . . . . . . . . . . . . . . . SouthTex 66 Pipeline Co . Ltd . . . . . . . . . . . . . . . SP 49 Pipeline LLC . . . . . . . . . . . . . . . . . . . . . . Suncor Energy (USA) Pipeline Co . . . . . . . . . . . . Sunoco Pipeline LP . . . . . . . . . . . . . . . . . . . . . . Tallgrass Pony Express Pipeline LLC (new) . . . . . Targa NGL Pipeline Co . LLC . . . . . . . . . . . . . . . . Tesoro High Plains Pipeline Co . . . . . . . . . . . . . . Tesoro Logistics Northwest Pipeline LLC . . . . . . . Texas Express Pipeline LLC . . . . . . . . . . . . . . . . Total Petrochemicals Pipeline USA Inc . . . . . . . . TransCanada Keystone Pipeline LP . . . . . . . . . . Trans Mountain Pipeline (Puget Sound) LLC . . . Tri-States NGL Pipeline LLC . . . . . . . . . . . . . . . . UNEV Pipeline LLC . . . . . . . . . . . . . . . . . . . . . . USG Wheatland Pipeline LLC (new) . . . . . . . . . . Valero MKS Logistics LLC . . . . . . . . . . . . . . . . . . Valero Partners Lucas LLC . . . . . . . . . . . . . . . . . Valero Partners PAPS LLC . . . . . . . . . . . . . . . . . Valero Partners Wynnewood LLC (new) . . . . . . . Valero Terminaling and Distribution Co . . . . . . . . Vantage Pipeline US LP (new) . . . . . . . . . . . . . . Victoria Express Pipeline LLC (new) . . . . . . . . . . Wesco Pipline LLC . . . . . . . . . . . . . . . . . . . . . . . WesPac Pipelines - Memphis LLC . . . . . . . . . . . West Shore Pipe Line Co . . . . . . . . . . . . . . . . . . . WestTex 66 Pipeline Co . . . . . . . . . . . . . . . . . . . . West Texas Gulf Pipe Line Co . . . . . . . . . . . . . . . West Texas LPG Pipeline LP . . . . . . . . . . . . . . . . Western Refining Pipeline LLC . . . . . . . . . . . . . . White Cliffs Pipeline LLC . . . . . . . . . . . . . . . . . . Wildcat Liquids Caddo LLC (new) . . . . . . . . . . . . Williams Ohio Valley Pipeline LLC (new) . . . . . . . WILPRISE Pipeline Co . LLC . . . . . . . . . . . . . . . . Wolverine Pipe Line Co . . . . . . . . . . . . . . . . . . . . Wood River Pipe Lines LLC . . . . . . . . . . . . . . . . Yellowstone Pipe Line Co . . . . . . . . . . . . . . . . . . Zydeco Pipeline Co . LLC (new) . . . . . . . . . . . . . .

Company

oil pipelines (ConTinUeD)

126

Oil & Gas Journal | Sept. 7, 2015

Algonquin Gas Transmission LLC1 . . . . . . . . . . . Alliance Pipeline LP1 . . . . . . . . . . . . . . . . . . . . American Midstream (AlaTenn) LLC . . . . . . . . . American Midstream (Midla) LLC . . . . . . . . . . . ANR Pipeline Co .1 . . . . . . . . . . . . . . . . . . . . . . . ANR Storage Co .1 . . . . . . . . . . . . . . . . . . . . . . . Arlington Storage Co . LLC . . . . . . . . . . . . . . . . . Bear Creek Storage Co .1 . . . . . . . . . . . . . . . . . . Big Sandy Pipeline LLC1 . . . . . . . . . . . . . . . . . . Bison Pipeline LLC1 . . . . . . . . . . . . . . . . . . . . . . Black Marlin Pipeline Co . . . . . . . . . . . . . . . . . . Blue Lake Gas Storage Co . . . . . . . . . . . . . . . . . Bluewater Gas Storage LLC . . . . . . . . . . . . . . . . Boardwalk Storage Co . LLC . . . . . . . . . . . . . . . . Bobcat Gas Storage . . . . . . . . . . . . . . . . . . . . . Cadeville Gas Storage LLC . . . . . . . . . . . . . . . . . Caledonia Energy Partners LLC . . . . . . . . . . . . . Cameron Interstate Pipeline LLC . . . . . . . . . . . . Carolina Gas Transmission Corp .1 . . . . . . . . . . . Centra Pipelines Minnesota Inc . . . . . . . . . . . . . Central Kentucky Transmission Co . . . . . . . . . . . Central New York Oil and Gas Co . LLC . . . . . . . Chandeleur Pipe Line Co .1 . . . . . . . . . . . . . . . . Cheniere Creole Trail Pipeline LP . . . . . . . . . . . . Cheyenne Plains Gas Pipeline Co . LLC1 . . . . . . . Clear Creek Storage Co . LLC . . . . . . . . . . . . . . Colorado Interstate Gas Co .1 . . . . . . . . . . . . . . . Columbia Gas Transmission LLC1 . . . . . . . . . . . Columbia Gulf Transmission Co .1 . . . . . . . . . . . . Crossroads Pipeline Co . . . . . . . . . . . . . . . . . . . Destin Pipeline Co . LLC1 . . . . . . . . . . . . . . . . . . Discovery Gas Transmission LLC1 . . . . . . . . . . . Dominion Cove Point LNG LP1 . . . . . . . . . . . . . Dominion South Pipeline Co . LP . . . . . . . . . . . . Dominion Transmission Inc .1 . . . . . . . . . . . . . . . Duke Energy Kentucky Inc .1 . . . . . . . . . . . . . . . Duke Energy Ohio Inc .1 (new) . . . . . . . . . . . . . East Cheyenne Gas Storage LLC . . . . . . . . . . . . East Tennessee Natural Gas LLC1 . . . . . . . . . . . Eastern Shore Natural Gas Co . . . . . . . . . . . . . . Egan Hub Storage LLC . . . . . . . . . . . . . . . . . . . El Paso Natural Gas Co .1 . . . . . . . . . . . . . . . . . . Elba Express Co . LLC1 . . . . . . . . . . . . . . . . . . . . Empire Pipeline Inc .1 . . . . . . . . . . . . . . . . . . . . Enable Gas Transmission LLC1 . . . . . . . . . . . . . Enable Mississippi River Transmission LLC1 . . . . Energy West Development . . . . . . . . . . . . . . . . . Equitrans LP1 . . . . . . . . . . . . . . . . . . . . . . . . . . ETC Tiger Pipeline LLC1 . . . . . . . . . . . . . . . . . . . Fayetteville Express Pipeline LLC1 . . . . . . . . . . . Florida Gas Transmission Co . LLC1 . . . . . . . . . . Freebird Gas Storage LLC . . . . . . . . . . . . . . . . . Garden Banks Gas Pipeline LLC1 . . . . . . . . . . . Gas Transmission Northwest Corp .1 . . . . . . . . . Golden Pipeline LLC1 . . . . . . . . . . . . . . . . Golden Triangle Storage Inc . . . . . . . . . . . . . . . . Granite State Gas Transmission Inc . . . . . . . . . . Great Lakes Gas Transmission LP1 . . . . . . . . . . Guardian Pipeline LLC1 . . . . . . . . . . . . . . . . . . . Gulf Crossing Pipeline LLC1 . . . . . . . . . . . . . . . . Gulf LNG Pipeline LLC . . . . . . . . . . . . . . . . . . . Gulf Shore Energy Partners LP . . . . . . . . . . . . . Gulf South Pipeline Co . LP1 . . . . . . . . . . . . . . . . Gulf States Tranmission Corp . . . . . . . . . . . . . . . Gulfstream Natural Gas System LLC1 . . . . . . . . . Hampshire Gas Co . . . . . . . . . . . . . . . . . . . . . . . Hardy Storage Co . . . . . . . . . . . . . . . . . . . . . . . . High Island Offshore System LLC1 . . . . . . . . . . . High Point Gas Transmission LLC1 . . . . . . . . . . . Honeoye Storage Corp . . . . . . . . . . . . . . . . . . . . Horizon Pipeline Co . LLC . . . . . . . . . . . . . . . . . Iroquois Gas Transmission Systems LP (IPOC agent)1 . . . . . . . . . . . . . . . . Jackson Prairie Underground Storage Project . . Kern River Gas Transmission Co .1 . . . . . . . . . . .

Company

GAS PIPELINES

7 10 2 — 44 — — — 1 — — — — — — — — — 4 — — — — — 3 — 24 66 12 1 2 — 2 — 68 — — — 21 — — 54 1 1 48 15 — 4 4 1 28 — — 13 — — — 14 3 4 — — 36 — 3 — — — — — 1 7 — 12

416 — 1,718

— 1 —

— — 1 — — 3 2 — 28 — — 1 — — — — — — — — — — — 5 — — 1 1 — — — —

— — — — 9 3 — 1 — — — 1 — — — — — — — — — — — — — — 7 24 — — — 2 — — 54 — — —

7 1 12

7 10 2 — 53 3 — 1 1 — — 1 — — — — — — 4 — — — — — 3 — 31 90 12 1 2 2 2 — 122 — — — 21 — — 55 1 1 51 17 — 32 4 1 29 — 0 13 — — — 14 3 4 — — 41 — 3 1 1 — — — 1

––––––– Total compression stations –––––––– Transmission Other Total

1,129 967 295 370 8,882 16 — — 69 302 52 — — — — — — 37 1,481 — 30 — 215 94 413 — 4,225 9,641 3,500 203 273 259 136 — 3,842 — — — 1,515 442 — 10,222 191 250 5,902 1,557 — 900 196 185 5,324 — 50 1,354 70 — 86 2,115 262 374 — — 6,540 10 745 18 — 66 405 — 28

Transmission system, miles

312,285 — 835,307

718,789 698,940 18,291 47,238 1,785,336 — — — 35,211 62,365 11,658 — — — — — — — 138,380 5,137 4,940 408,904 15,544 2,375 95,589 — 839,291 1,379,418 626,736 16,894 314,603 142,427 92,710 782 1,151,691 7,604 — — 281,332 43,117 — 1,318,671 89,913 218,602 913,254 275,491 — 635,883 340,851 453,704 902,592 — 119,904 708,497 3 1,773 17,142 545,055 91,077 440,121 — — 994,007 9,809 414,195 — — 990 113,047 — 31,398

Volumes trans. for others, MMcf

1,274,535 106,417 2,820,261

2,039,268 2,063,397 31,066 50,988 3,615,623 146,141 — 171,783 213,397 671,041 22,837 105,306 — — — — — 195,715 346,367 5,336 1,023 532,602 57,203 584,791 431,892 26,972 1,495,196 5,624,648 1,207,158 38,615 517,270 238,334 1,241,702 — 5,395,031 435,893 1,853,582 — 1,070,009 243,339 — 3,529,386 635,048 468,558 2,399,549 688,393 881 1,097,706 1,106,225 971,410 6,265,092 — 100,782 1,716,180 742,029 — 39,226 2,074,859 646,747 1,711,933 — 1,895 3,798,235 3,058 2,066,518 37,767 164,542 468,839 270,889 13,629 98,399 13,436 1,833 21,225

19,394 9,244 832 194 153,384 1,187 — 6,894 152 1,328 — 2,201 — — — — — — 22,268 225 — 6,514 — 1,106 219 184 9,327 528,993 22,611 56 4,255 15,193 17,945 — 354,449 9,048 97,496 — 26,099 17,346 — 48,125 337 1,158 21,070 18,409 — 95,039 2,328 244 88,077 — — 5,200 1,830 — 4,931 4,849 682 22,618 — 55 355,662 — 10,096 4,700 583 39 305 64 155 28,058 4,070 48,356

66,555 90,537 2,325 4,201 365,327 10,728 — 7,110 5,532 6,968 1,156 3,149 — — — — — 726 23,699 997 114 13,139 6,253 13,170 12,036 1,922 157,607 638,419 70,980 1,450 21,055 16,236 75,966 104 351,930 83,385 218,587 — 44,334 13,293 — 189,530 3,746 7,707 249,946 65,738 43 61,986 11,400 7,647 149,613 — 5,876 33,884 10,758 — 1,748 43,200 12,012 88,806 — 158 148,972 357 23,636 2,244 2,616 22,005 7,528 1,612 3,421

199,900 — 354,256

296,548 293,098 2,355 3,494 516,449 20,594 — 30,345 41,259 81,123 1,190 30,460 — — — — — 7,948 64,872 1,005 190 53,988 7,269 165 101,706 2,114 402,882 1,116,715 154,568 2,627 50,189 12,340 296,555 259 1,042,755 488,724 2,036,787 — 160,407 42,235 — 577,604 89,710 81,825 494,067 97,685 337 268,052 279,299 167,664 795,990 — 12,628 188,170 92,606 — 6,041 145,667 67,578 245,356 — 1,052 409,112 614 274,711 5,630 23,599 16,365 23,181 3,785 12,003

52,165 –4,070 85,597

83,882 71,437 –848 –1,897 29,871 18,324 — 14,563 16,708 28,940 683 16,027 — — — — — 473 14,742 –82 26 17,896 –660 –29,558 38,680 –1,168 108,983 200,271 27,519 5 854 –20,942 97,654 2,224 308,512 35,302 –495,116 — 46,399 9,875 — 113,429 40,214 28,376 93,115 4,570 132 92,036 130,851 66,876 234,412 — 4,167 54,554 48,864 — 1,148 25,117 20,944 58,492 — 416 69,392 58 83,329 1,080 6,357 –7,718 6,213 1,025 2,515

––––––––––––––––––––––– Fiscal data, $1,000 ––––––––––––––––––––––––––– Operating & Gas maintenance Operating Net plant Additions expenses revenue income

Oil & Gas Journal | Sept. 7, 2015

127

(CONTINUED)

Kinder Morgan Illinois Pipeline LLC . . . . . . . . . . Kinder Morgan Louisiana Pipeline LLC1 . . . . . . . Kinetica Energy Express LLC1 . . . . . . . . . . . . . . KO Transmission Co . . . . . . . . . . . . . . . . . . . . . KPC Pipeline LLC . . . . . . . . . . . . . . . . . . . . . . . LA Storage LLC . . . . . . . . . . . . . . . . . . . . . . . . . Lake Charles LNG Co . LLC1 (new) . . . . . . . . . . Leaf River Energy Center LLC . . . . . . . . . . . . . . Maritimes & Northeast Pipeline LLC1 . . . . . . . . . MarkWest New Mexico LP1 . . . . . . . . . . . . . . . . MarkWest Pioneer LLC1 . . . . . . . . . . . . . . . . . . . Midcontinent Express Pipeline LLC1 . . . . . . . . . Midwestern Gas Transmission Co .1 . . . . . . . . . . MIGC Inc .1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . Millennium Pipeline Co . LLC1 . . . . . . . . . . . . . . Mississippi Canyon Gas Pipeline LLC1 . . . . . . . . Mississippi Hub LLC . . . . . . . . . . . . . . . . . . . . . MoGas Pipeline LLC . . . . . . . . . . . . . . . . . . . . . Mojave Pipeline Co .1 . . . . . . . . . . . . . . . . . . . . Monroe Gas Storage Co . LLC . . . . . . . . . . . . . . . National Fuel Gas Supply Corp .1 . . . . . . . . . . . . National Grid LNG LLC . . . . . . . . . . . . . . . . . . . Natural Gas Pipeline Co . of America1 . . . . . . . . Nautilus Pipeline Co . LLC1 . . . . . . . . . . . . . . . . NGO Transmission Inc . . . . . . . . . . . . . . . . . . . . North Baja Pipeline LLC1 . . . . . . . . . . . . . . . . . Northern Border Pipeline Co .1 . . . . . . . . . . . . . . Northern Natural Gas Co .1 . . . . . . . . . . . . . . . . . Northwest Pipeline LLC1 . . . . . . . . . . . . . . . . . . OkTex Pipeline Co . LLC . . . . . . . . . . . . . . . . . . . Ozark Gas Transmission LLC1 . . . . . . . . . . . . . . Paiute Pipeline Co . . . . . . . . . . . . . . . . . . . . . . Panhandle Eastern Pipe Line Co . LP1 . . . . . . . . Panther Interstate Pipeline Energy LLC . . . . . . . Perryville Gas Storage LLC . . . . . . . . . . . . . . . . Petal Gas Storage LLC1 . . . . . . . . . . . . . . . . . . . PGPipeline LLC . . . . . . . . . . . . . . . . . . . . . . . . . Pine Needle LNG Co . LLC . . . . . . . . . . . . . . . . . Pine Prairie Energy Center LLC . . . . . . . . . . . . . Point Arguello Natural Gas Line Co . . . . . . . . . . Portland Natural Gas Transmission System1 . . . Questar Overthrust Pipeline Co .1 . . . . . . . . . . . . Questar Pipeline Co .1 . . . . . . . . . . . . . . . . . . . . Questar Southern Trails Pipeline Co . . . . . . . . . . Rager Mountain Storage Co . LLC . . . . . . . . . . . . Raton Gas Transmission Co . Inc . . . . . . . . . . . . . Red River Energy LLC . . . . . . . . . . . . . . . . . . . . Rendevous Pipeline Co . LLC (new) . . . . . . . . . . Rockies Express Pipeline LLC1 . . . . . . . . . . . . . Ruby Pipeline LLC1 . . . . . . . . . . . . . . . . . . . . . . Ryckman Creek Resources LLC . . . . . . . . . . . . Sabine Pipe Line LLC1 . . . . . . . . . . . . . . . . . . . . Saltville Gas Storage Co . LLC . . . . . . . . . . . . . . . Sea Robin Pipeline Co . LLC1 . . . . . . . . . . . . . . . SG Resources Mississippi LLC . . . . . . . . . . . . . . Sieritta Gas Pipeline LLC1 (new) . . . . . . . . . . . . Southeast Supply Header LLC1 . . . . . . . . . . . . . Southern LNG Co . LLC1 . . . . . . . . . . . . . . . . . . . Southern Natural Gas Co .1 . . . . . . . . . . . . . . . . Southern Star Central Gas Pipeline Inc .1 . . . . . . Southwest Gas Storage Co . . . . . . . . . . . . . . . . . Southwest Gas Transmission Co . LP . . . . . . . . . Steckman Ridge LP . . . . . . . . . . . . . . . . . . . . . Stingray Pipeline Co .LLC1 . . . . . . . . . . . . . . . . . Tallgrass Interstate Gas Transmission LLC1 . . . . TC Offshore LLC1 . . . . . . . . . . . . . . . . . . . . . . . Tennessee Gas Pipeline Co .1 . . . . . . . . . . . . . . . Texas Eastern Transmission LP1 . . . . . . . . . . . . Texas Gas Transmission LLC .1 . . . . . . . . . . . . . . Trailblazer Pipeline Co .1 . . . . . . . . . . . . . . . . . . . Trans–Union Interstate Pipeline LP . . . . . . . . . . TransColorado Gas Transmission Co .1 . . . . . . . . Transcontinental Gas Pipe Line Co . LLC1 . . . . . . Transwestern Pipeline Co . LLC1 . . . . . . . . . . . . .

Company

GAS PIPELINES

3 136 1,204 — 1,021 — — — 346 8 50 513 400 262 253 45 — — 468 — 1,513 — 9,122 101 — 86 1,408 14,781 3,890 116 526 861 5,998 55 — 59 — — — 27 296 259 1,891 488 — — — — 1,712 683 — 140 — 1,050 — 61 286 — 7,033 5,654 — 9 — 370 4,654 232 11,917 9,592 5,766 436 — 312 9,183 2,596

Transmission system, miles — — — — 1 — — — 7 — 2 5 7 4 3 — — — 1 — 20 — 49 — — 1 18 46 44 1 4 6 23 — — 1 — — — — — 3 15 4 — — — — 14 4 — 4 — 2 — — 3 — 38 32 — — — — 21 1 76 59 26 3 — 8 50 32

— — — — — — — — — — — — — 1 — — — — — — 15 — 12 — — — — 5 1 — — — — — — 4 — — — — — — 6 — — — — — 5 — — — — — — — 2 — 1 9 4 — — 2 2 — 3 6 7 — — — 4 —

— — — — 1 — — — 7 0 2 5 7 5 3 0 — — 1 — 35 — 61 — — 1 18 51 45 1 4 6 23 — — 5 — — — — — 3 21 4 — — — — 19 4 — 4 — 2 — — 5 0 39 41 4 — — 2 23 1 79 65 33 3 — 8 54 32

––––––– Total compression stations –––––––– Transmission Other Total 6,754 2,803 196,674 56,241 11,808 — — — 111,753 36,489 — 868,070 244,243 24,696 470,910 70,942 — 12,194 131,605 — 535,519 — 1,417,903 132,214 5,077 117,323 977,143 1,025,465 686,974 42,893 40,932 33,637 625,560 — — 95,252 3,258 — — 750 60,132 490,995 320,489 27,178 — 1,039 — 98,880 789,454 331,307 — 76,707 — 59,942 — 180 344,588 — 961,725 338,025 — — — — 138,723 209,748 2,990,155 2,610,451 1,154,029 248,143 46,460 82,172 4,655,090 459,694

Volumes trans. for others, MMcf 19,869 1,039,417 797,639 20,510 84,072 — 1,297,326 — 1,163,940 6,217 157,956 2,322,598 246,292 52,467 1,247,684 57,356 — 104,633 248,627 — 1,197,704 52,368 3,984,762 128,673 27,461 199,755 2,577,692 3,630,212 3,281,074 8,781 239,255 209,232 1,904,785 22,591 — 439,332 5,830 117,117 — 150,777 493,832 454,976 1,181,428 121,177 — 1,268 — — 6,925,171 3,723,305 — 74,211 120,022 665,844 — 171,577 1,253,438 685,780 3,540,320 1,490,033 220,316 2,168 — 297,590 693,205 481,369 7,443,591 8,831,427 2,959,990 348,724 — 441,570 9,349,545 2,310,951

— –91 2,131 137 260 — 868 — 464 — 55 14,954 4,656 2,520 58,818 2 — 95 1,279 — 105,139 3,608 89,667 225 1,361 2,603 21,752 258,205 94,041 8 982 5,325 84,853 — — 1,012 34 20 — 316 — 870 52,421 1,653 — 5 — — 113,585 7,080 — 19 2,576 5,855 — 171,577 14,325 972 40,661 71,852 9,800 — — 1,892 14,766 4,934 218,248 585,742 27,644 13,234 — 196 231,602 52,921

1,543 4,569 28,813 452 6,430 — 22,197 — 18,621 276 2,054 29,527 11,521 4,240 14,872 2,928 — 4,451 2,685 — 67,190 4,851 366,111 3,508 2,925 4,765 49,537 350,651 133,792 1,610 11,462 17,447 173,276 112 — 9,367 277 6,404 — 1,849 7,577 11,764 56,342 9,309 — 1,294 — — 135,903 27,203 — 12,704 8,573 16,482 — 247 9,427 26,231 169,332 98,271 12,196 46 — 11,524 67,641 24,127 290,581 417,826 109,644 15,934 — 7,396 627,785 67,875

3,291 265,334 71,206 1,754 10,486 — 216,247 — 164,746 1,182 10,242 258,338 36,589 9,098 99,211 6,877 — 13,728 18,704 — 204,232 8,230 651,548 7,293 4,998 39,267 293,318 749,039 470,050 3,469 16,959 33,244 357,245 — — 57,208 1,090 18,011 — 1,967 73,620 71,828 175,185 8,347 — 1,249 — — 805,485 345,587 — 5,010 22,039 36,365 — 5,952 108,400 165,779 577,037 248,573 45,946 414 — 19,403 111,186 29,377 1,192,621 1,165,248 406,562 38,920 — 42,865 1,413,206 228,185

447 130,678 14,139 669 177 — 92,236 — 53,846 341 –25,614 55,680 9,168 1,331 60,161 2,429 — 2,610 5,764 — 53,071 644 116,693 –1,773 13 14,452 85,546 150,275 107,172 867 668 4,976 –17,627 –64 — 17,027 196 3,824 — –1,719 17,048 24,372 58,822 –4,286 — 1 — — 116,630 63,886 — –6,150 5,517 7,828 — 6,501 28,502 73,797 146,469 48,493 15,086 169 — 2,377 28,216 –246 331,768 318,519 97,237 7,913 — 10,548 289,463 35,785

––––––––––––––––––––––– Fiscal data, $1,000 ––––––––––––––––––––––––––– Operating & Gas maintenance Operating Net plant Additions expenses revenue income

October 27-29, 2015 | Lafayette,Louisiana USA

Oil & Gas Exposition

LAGCOE G proudly p y celebrates b 60 years e ing pp p ng g the o oil and gas industry n tryy nd through u world-class o a expositions, x o technical presentations, and a commitment to industry educationÖ and weíre Still Climbing.

Attendees enjoy one of the most culturally inspiring areas in the U.S., Lafayette, Louisiana - gateway to Americaís Energy Corridor.

now at: lagcoe.com/.

$4,697,575 $4,244,350 $23,916,417 $20,682,018 $24,514,239 $21,273,449

$6,967,716 $6,441,416 $7,474,131 $6,907,150

$4,466,596 $5,676,483 $4,542,395 $6,567,730

$147,219,957 $141,194,194 $151,986,076 $146,652,283

45,216,247 41,940,528 46,293,010 42,831,851

1,438 1,451 1,482 1,494

234 226 256 247

1,204 1,225 1,226 1,247

189,366 189,087 195,194 195,902

2014 Totals-majors (93) . . . . . . . . . . . . . . . . . 2013 Totals-majors (92) . . . . . . . . . . . . . . . . .

2014 Totals–all . . . . . . . . . . . . . . . . . . . . . . 2013 Totals–all . . . . . . . . . . . . . . . . . . . . . .

1

Major natural gas pipeline companies as defined above (and in FERC ing and Reporting Requirements for Natural Gas Companies, para . 20–011, effective Feb . 2, 1985, beginningwith 1984 reporting year) . Beginning with 1996, major companies were required to file mileage for transmission systems only . NR = not reported .Source: FERC Forms 2 and 2A for major and nonmajor natural gas pipeline companies . Under criteria established for the 1984 reporting year (OGJ, Nov . 25, 1985, p . 80), major pipeline companies are those whose combined gas sold for resale and gas transported for a fee exceeded 50 bcf at 14 .73 psi (60[degree sign] F .) in each of the 3 previous calendar years .Nonmajors are natural gas pipeline companies not classified as majors and whose total gas sales of volume transactions exceeded 200 MMcf at l4 .73 psi (60° F .) in each of the 3 previous calendar years .

$4,776,194 $4,302,305

— 45,920 10,088 — — –1,007 18,449 –1,504 2,420 15,440 15,271 1,046 51 4,392 132 48,099 1,594 — 167,284 27,525 — — 593 94,690 6,325 27,210 92,563 171,255 2,296 185 11,064 8,045 150,343 8,569 — 45,901 5,628 — — 1,085 14,469 2,254 14,724 36,870 136,484 861 79 1,674 5,978 35,078 3,836 — 22,660 126 — — — 5,020 118 13,595 37,381 8,287 55 39 162 907 2,914 208 — 1,420,086 205,695 — — 5,550 826,946 87,630 217,853 572,608 151,073 8,377 724 57,815 118,331 945,317 48,726 — 693,566 42,812 — 9,018 2,071 535,738 18,069 87,373 233,483 10,280 5,417 3,646 482,322 37,892 922,062 — — 17 4 — — — 5 0 8 34 — — — — 15 11 1 — — — — — — — — — 9 — — — — 14 — —

— 17 4 — — — 5 — 8 25 — — — — 1 11 1

— 2,923 305 — — 16 333 125 674 3,452 758 236 11 11 246 849 11

––––––––––––––––––––––– Fiscal data, $1,000 ––––––––––––––––––––––––––– Operating & Gas maintenance Operating Net plant Additions expenses revenue income

Tres Palacios Gas Storage LLC1 . . . . . . . . . . . . . Trunkline Gas Co . LLC1 . . . . . . . . . . . . . . . . . . Tuscarora Gas Transmission Co . . . . . . . . . . . . UGI LNG Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . UGI Storage Co . . . . . . . . . . . . . . . . . . . . . . . . . USG Pipeline Co . LLC . . . . . . . . . . . . . . . . . . . . Vector Pipeline LP1 . . . . . . . . . . . . . . . . . . . . . Venice Gathering System LLC1 . . . . . . . . . . . . . Viking Gas Transmission Co .1 . . . . . . . . . . . . . . WBI Energy Transmission Inc .1 . . . . . . . . . . . . . West Texas Gas Inc . . . . . . . . . . . . . . . . . . . . . . Western Gas Interstate Co . . . . . . . . . . . . . . . . . WestGas InterState Inc . . . . . . . . . . . . . . . . . . . . White River Hub LLC1 . . . . . . . . . . . . . . . . . . . . WTG Hugoton LP . . . . . . . . . . . . . . . . . . . . . . . Wyoming Interstate Co . Ltd .1 . . . . . . . . . . . . . . . Young Gas Storage Co . Ltd . . . . . . . . . . . . . . . . .

Volumes trans . for others, MMcf

Global o Collaboration l r o Local Resources c Re ca R u ur

––––––– Total compression stations –––––––– Transmission Other Total

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Years

Company

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W H AT ’ S N E W F O R O N S H O R E & O F F S H O R E : U P S T R E A M , M I D S T R E A M , D OW N S T R E A M O P E R AT I O N S

“What’s News In Upstream, Midstream & Downstream

Instrumentation, Controls, Automation New vibration meter helps reduce oil, gas, petrochem pipework failure Pipe Vibration Meter 330 is new to reduce premature failures on offshore and onshore oil, gas, and petrochem plant pipework. PVM 330 combines accelerometer, data cable, and analyzer to deliver easy assessment of vibration-induced pipework fatigue. Its accelerometer is placed onto one of a number of predetermined pipework positions to measure vibration amplitude and frequency. Readings are fed into the analyzer. It uses FFTs and industry standard acceptance criteria to identify whether there is an operational risk. Output is configured as a simple ‘traffic light’ message: ‘OK’ no action is needed; ‘concern’ or ‘problem’ to prompt remedial action. Doosan Babcock: West Sussex UK For FREE Information, select #1 at ogpe.hotims.com

Double block and bleed ball valves serve calibration up to 15,000 psi Trunnion style block and bleed ball valves are new for calibration applications to 15,000 psi. The full port, quarter turn designs deliver double positive isolation to block and bleed high pressure hydraulic and pneumatic systems used for pressure monitoring and test, chemical injection, or drain line isolation. High Pressure Equipment Company: Erie PA For FREE Information, select #3 at ogpe.hotims.com

Portable multigas detectors unveiled T4 portable multigas detectors are announced to provide advanced worker protection and ensure safety standards compliance. They note unsafe CO, O2, H2S levels plus a range of flammable gases with +ve Safety ‘traffic light’ status indicator for at-a-glance status checks without having to read and interpret data shown on the display screen. Crowcon Detection Instruments: Oxfordshire UK

For FREE Information, select #2 at ogpe.hotims.com

‘Virtual flow metering’ pump control and monitor is new New PCS550 Pump Controller & Monitor employ “virtual flow metering” technology with stroke-counting and (patent pending) currentsensing features. Models sense pump-compression stroke-current and count positive displacement strokes for precise flowbased delivery — regardless of pump motor speed or well pressure. They are almost the same cost as traditional pump timers that do not allow remote control or monitoring. Remote Automation Monitoring USA Inc.: Houston For FREE Information, select #4 at ogpe.hotims.com

BONUS

DISTRIBUTION

AAPG International Pipeline Week European Gas Processing Rio Pipeline Society of Petroleum Engineers ATCE

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“What’s New In Equipment, Products, Systems & Services

FROM

THE

OG&PE

EDITOR

Thank you for opening this all-products-and-services OG&PE within Oil & Gas Journal. We are pleased to offer you a truly broad array of petroleum equipment and related specialties this month. Our annual Oil & Gas Instrumentation Report starts on the front page and, as always, announces some of the newest products with important applications ranging from pipework failure prevention to distributed acoustic sensing, pig tracking, and remote I/Os for the Industrial Internet of Things — about which we are hearing more and more. To that IoT point, MOXA, one of our media partners has written an article on Page 10-11 “Defining the Industrial Internet of Things (Industrial IoT)” It is an excellent overview of the seamless integrated machinery with networked sensors and software that comprises IoT. I hope you will find it informative. We are also pleased to have a followup to the recent Pipeline + Energy Expo in Tulsa highlighting some of the exhibitor specialties. It begins on Page 15 The balance of this September OG&PE (all of which will post on OGPE.com, highlights upstream, midstream, and downstream developments including new sucker rod couplings, software to better view reservoir data, pipeline temperature regulation and freeze protection, and a free Thermal Management Solution white paper. For all of our audience ‘on the go’ — OG&PE’s new mobile app is now available for iPad, Android, and Kindle. Search “OGPE” in your app store to stay updated on product information no matter where you are working. And don’t forget — you always have access to free information on every product announcement and ad in this issue: Go to OGPE.com, click the yellow button on the right top of the site — make your requests. J.B. Avants, Publisher & Editor [email protected] / 918 832 9351 / OGPE.com

Copyright 2015 by PennWell Corporation. Established: November 1954.

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AD INDEX

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Oil, Gas & Petrochem Equipment makes every reasonable effort to its content. However, neither Oil, Gas & Petrochem Equipment nor our parent firm, PennWell Corporation, assume responsibility for validity of manufacturer claims or statements made in published items.

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September 2015

Need Reprints of your ad or recent editorial? Foster Printing for a quote: 866 879 9144 / [email protected]

Medium Voltage Outdoor Drive

Medium Voltage Drive

WPII 6800 Frame Medium Voltage Motor

ONE CALL. ONE SOLUTION. Toshiba International Corporation is proud to be a single-source solution for your application demands, offering a complete product lineup of electric motors, adjustable speed drives, and motor starters. By pairing the P9 adjustable speed drive with the EQP Global motor, we have set new pump control standards in technology, efficiency, and ease-of-use that go beyond the competitive demands of the evolving pump industry. For FREE Information, select #401 at ogpe.hotims.com

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Instrumentation Special Report

INCREASE PERFORMANCE & EFFICIENCY

OF YOUR OPERATIONS

Upstream distributed acoustic sensing, data collection, analysis Adelos 2.0 fiber optic sensor system is introduced as a “distributed acoustic sensor solution for upstream oil and gas.” For applications including hydraulic fracturing, the system is designed to “bring smarter, real-time downhole data collection and analysis to the oil patch.” Features include signal fidelity and accuracy enabling Adelos 2.0 as a customized solution for direct sale to clients or an intellectual property portfolio for licensing in commercial sectors. The acoustic sensor technology uses fiber optics to measure a variety of surface, subsurface, and airborne phenomena. It detects very subtle changes in pressure as acoustic sound waves interfere with light in the fiber. Adelos 2.0 uses dynamic signal processing and a range of analytical detection, classification, and fusion algorithms to convert interference data into high fidelity signals. Adelos Incorporated: Polson MT For FREE Information, select #5 at ogpe.hotims.com

RFID line expands with large-memory transponders The Simatic RF600 RFID products line is expanding with new RF622T and RF622L UHF RFID transponders. As large memory capacities and a compact mobile read/write devices, they offer 4 KB capacities and store large data volumes while rapidly accessing tagged objects. The carriers are for production control, asset management, and intra-logistics distributed configurations. Ferroelectric random access memory (FRAM) of each transponder enables high-speed writing as well as unlimited number of write cycles. Siemens: Norcross GA For FREE Information, select #6 at ogpe.hotims.com

Combined analysis solutions designed for reservoirs Five petrophysical analysis and reservoir intelligence solutions are newly combined and integrated to provide a comprehensive and evolving reservoir picture. This is across the entire life cycle of an asset through screening five areas of expertise: petrophysics, core analysis, completion engineering, reservoir mapping and modeling, and reservoir engineering. NULOOK, POROLABS, NUSTIM, NUVIEW, and NUVISION draw insights, interpret data and research to determine full potential and true value of wells. NUTECH: Houston For FREE Information, select #7 at ogpe.hotims.com

Pig tracking transmitters, sensors

[email protected] www.nylacast.com/offshore For FREE Information, select #403 at ogpe.hotims.com OGPE.com

September 2015

SPY Pig Tracking transmitters and sensors are described and illustrated in this free four-page brochure to serve refining, processing, mainline transmission, gathering lines, and subsea lines. SPY PT pig transmitter is declared to offer “the most reliable signal available” as it uses low-frequency signals to effectively and consistently penetrate steel pipe walls. SPY PTR pig tracker receiver and wand s changing magnetic field produced by SPY transmitter so you obtain audio and visual output. SPY PTS pig tracker sensors attach directly to exposed pipe to provide a nonintrusive pig age indicator. Pipeline Inspection Company Ltd.: Houston For FREE Literature, select #250 at ogpe.hotims.com

For FREE Information, select #404 at ogpe.hotims.com

By any measure, AMETEK knows your process. TRULY PORTABLE BTU ANALYZER FOR NATURAL GAS IN PRODUCTION AND AT CUSTODY TRANSFER

The new AMETEK Chandler Engineering Model 292B portable natural gas chromatograph is compact and light weight, yet it includes fully integrated sample handling and onboard storage for up to 1,000 sample runs. raw and calibration data, analytical reports and real-time chromatograms. Advanced software accurately calculates heating value, relative density, and compressibility using industry standard methods. Precise monitoring and control yields exceptional sensitivity and peak performance. Connectivity includes USB and Ethernet, plus compatibility with HP printers. AMETEK Chandler Engineering. Tel: 412-8289040. www.ametekpi.com

#406 at ogpe.hotims.com

SPOOL PIECE–MOUNTED WATER CUT MONITOR

MODEL 5100 GAS ANALYZER MEASURES MOISTURE IN BULK GAS, HYDROCARBON STREAMS

Using tunable diode laser absorption spec #"# ## # # # # # # # # # $# ! #

# # cells are available in a wide range of path lengths, and a reference cell for laser line-lock eliminates measurement errors caused by laser wavelength shifting as ambient temperature varies. Gas sampling accessories allow customization, the back lit LCD displays four 20-character lines of data, and a membrane keypad makes parameter input and display selection easy. The unit weighs only 11 lb., has a battery life of eight hours, and a USB 2.0 interface. The 5100 is factory calibrated and calibration is NIST traceable. AMETEK Process Instruments. Tel: 412-828-9040. www.ametekpi.com

#408 at ogpe.hotims.com

NEW WAVE GUIDE OPTION ELIMINATES SIGNAL INTERFERENCE FROM TANK NOZZLES

The new Universal IV™ CM water cut monitor from AMETEK Drexelbrook has been designed specifically to make highaccuracy water-in-oil measurements. Spoolpiece mounting allows the sensing element to extend into the main process line so it measures the fluid’s capacitance over its entire length for smoother, more accurate response, regardless of the fluid’s mixture characteristics. Drexelbrook’s exclusive Cote-Shield™ technology ignores coating buildup on the probe and onboard electronics continuously compute the relationship between capacitance change and water cut. The extremely durable sensing rod needs no epoxy coatings and no gaskets, so servicing requirements are substantially reduced compared to competitive systems, and the element will not wear out even in well fluids that include a large amount of sand. AMETEK Drexelbrook. www.drexelbrook.com

#407 at ogpe.hotims.com

INTRINSICALLY SAFE PRESSURE TRANSMITTER OPERATES IN HAZARDOUS LOCATIONS

AMETEK PMT Model IDT intrinsically safe pressure transmitters offer superior accuracy (±0.2% full-scale) for critical applications, and all meet FM US, FM Canada, ATEX and IECEx standards for worldwide acceptance. Pressure ranges are available from vacuum to 5,000 psi, including exclusive 0–1, 0–3 and 0–6 psi units. Factory calibration eliminates the need for field calibration for plug-and-play reliability, and EN61326-1 RFI/EMI protection enables the Model IDT’s use in high-noise environments. Standard units include Type 316SS housing and all wetted materials. Hastelloy and Monel diaphragms are available as options. Yet, in spite of their many advantages, PMT Model IDT intrinsically safe transmitters remain surprisingly economical. www.ametekpmt.com

#410 at ogpe.hotims.com

THE NEW THERMOX® WDG-V COMBUSTION ANALYZER OFFERS IMPROVED CONTROL PLUS UNPARALLELED PROCESS SAFETY

The WDG-V measures excess oxygen, hydro & & &&& & & & & ImpulseÆ wave-guided radar level systems & &&& & & from AMETEK Drexelbrook generate total lev- safety. Logs of historical operating data can help operators decide when preventive by variations in process material electri- &&& && cal characteristics. Adding the Wave Guide && && & & option eliminates nozzle interference, mak- dirty gas applications, probes are available at

& & & (& !"& & & negating the need for more expensive coaxial & '#$& !#%"& & & (& '"& & probe systems. Reliable and accurate to ±3 temperatures to 3000∞F (1760∞C). The WDG-V mm, Impulse series transmitters provide con- also features automatic calibration, analog tinuous level measurement of liquids to ranges outputs, multiple alarms, self-diagnostics, up to 50 ft. (15 m) at operating temperatures and local or remote interface as well as a ranging from ñ40∞ to 392∞F (-40∞ to 200∞C) variety of network communications protocols. and pressures up to 580 psig (40 bar). Five dif- AMETEK Thermox. Tel: 412-828-9040. ferent sensor types are available, constructed www.ametekpi.com of Type 316SS or Hastelloy C for Class I, Div #411 at ogpe.hotims.com 1 hazardous environments requiring either intrinsically safe or explosionproof installation. AMETEK Drexelbrook. Tel: 800-334-2748 or 215-674-1234. www.drexelbrook.com

#409 at ogpe.hotims.com

© 2015 AMETEK Inc. All rights reserved.

ALL-WELDED PROCESS GAUGE & SEAL FOR ECONOMY, RELIABILITY

Instrumentation Special Report

P7

New cellular remote I/O modules built for IoT

AMETEK U.S. Gauge all-welded process than gauges and seals purchased separately. In addition, the combination unit reduces the number of potential leak paths, increas gauge with PET case, Type 316L SS socket and seamless Bourdon tube is mounted and welded onto an M&G diaphragm seal, available with either Type 316L SS or HastelloyÆ C $" " $" " !

# Tel: 215-293-4100. www.ametekusg.com

#412 at ogpe.hotims.com

MINIVAP ON-LINE VAPOR PRESSURE ANALYZER—FOR ALL STANDARDS

The GrabnerÆ MINIVAP ON-LINE process analyzer monitors vapor pressure of gasoline, gasóall automatically. It is the only vapor pressure analyzer to fully comply with all relevant ASTM and US EPA specs: ASTM D6378/D5191/D5188 for gasoline, D6897 for LPG, and D6377 plus EPA Title 40 CFR for the measurement of crude oil. The ATEX handle two sample streams, both controlled by an automatic sample conditioning system. AMETEK Grabner Instruments. Tel: +43 1 282 16 27-0. www.grabner-instruments.com

#413 at ogpe.hotims.com

NEW TAIL GAS ANALYZER OFFERS AUTO FLOW CONTROL

The newest of the ioLogik devices group: 2542-HSPA and 2512-HSPA cellular remote I/O modules — built for the Industrial Internet of Things. Both modules feature High-Speed Packet Access five-band cellular in addition to Ethernet and serial ports for reliable remote field devices access. The I/O designs help avoid such common issues as unstable connectivity and high data usage fees, declares the maker. They comprise Dual SIM Failover that automatically switches to a secondary SIM when communications over the primary SIM fails. There is also a three-step cellular reconnection function to further enhance communications reliability. Don’t miss this manufacturer’s “Defining the Industrial Internet of Things” feature and definitions: Page 10-11. MOXA: Brea CA For FREE Information, select #9 at ogpe.hotims.com

New resistivity sensor system = better surface data view, movement of fluids within reservoir GroundMetrics resistivity sensor system is announced to “give oil and gas companies a better view of subsurface data and the movement of fluids within a reservoir.” The technology has both conventional and unconventional applications. With or without deploying instrumentation downhole — the new technology gathers data between and far beyond wellbores at reservoir depths at the surface, declares the manufacturer. This improves subsurface visibility and allows drill location optimization with a boost in rate of drilling success. GroundMetrics Incorporated: San Diego CA For FREE Information, select #10 at ogpe.hotims.com

Alarm horns, loudspeakers, integrated warning units range announced D1x alarm horns, loudspeakers, and integrated alarm horn/Xenon strobe warning units are on the market. They employ the latest electronic technology and acoustic engineering in marinegrade, LM6 aluminum enclosures — for both compactness and corrosion resistance. D1x creates effective warning signals for Class I/II Division 1, Zone 1 & Zone 20 environments. The UL/cULsapproved alarm horns and combined units are available with traditional directional flare horns or the maker’s omnidirectional radial horns that generate a uniform 360° sound dispersion. E2S Warning Signals: London and Houston For FREE Information, select #11 at ogpe.hotims.com

The new AMETEK Model 888 analyzer mounts directly in the pipe, has smart diagnostics and a flange temperature alarm that warns of bad steam quality or failed steam trap. This compact, rugged analyzer features improved thermal management to extend the life of the electronics up to 75%, and auto control to prevent sulfur entrainment during process slowdown. AMETEK Process Instruments. www.ametekpi.com

#414 at ogpe.hotims.com

Coming In October: • •

Two Special Products & Services Reports: Up/Mid/Downstream Valves & Actuators and Oil & Gas Software

OG&PE / OGPE.com — All Products — All The Time

September 2015

OGPE.com

P8

Products

High-pressure pump for RO systems

IP66/4x, EX d temperature transmitters

SALINO Pressure Center is a new highly efficient technology high-pressure pump for seawater desalination via reverse osmosis. It combines into a single, compact RO system of highpressure pump, energy recovery device, booster pump, and electric motor. This suits SALINO for decentralized use in small and medium-size containerized systems. KSB Incorporated: League City TX

7501 temperature transmitters offer rugged design to serve a broad range of demanding oil and gas applications. Field-mounted, they offer local operator interface for easy programming, review, and diagnostics on onshore and offshore rigs, and in petrochemical or refining operations. PR electronics A/S: Roende Denmark

Offshore motion control encoders

Valve open-close w/o power supply

IXA 648 absolute rotary encoders are ATEX and IECEx Zone 1/21-certified for offshore motion control duties. The inductive absolute encoder avoids magnets and glass to measure in high temperatures, shock, and vibration. Leine & Linde: Schaumburg IL

FQM fail-safe units on this company’s actuators enable valve open-and-close without power supply. For use in hazardous oil and gas applications and emergencies, the specialist devices operate automatically — even in disrupted power. They incorporate patent pending constant force spring motor and provide virtually constant torque. AUMA Riester GmbH & Co. KG: Müllheim

For FREE Information, select #13 at ogpe.hotims.com

For FREE Information, select #14 at ogpe.hotims.com

Oilfield Improvements® WHEELED ROD GUIDE® COUPLINGS For Deviated, Directional and Horizontal Wells Used Successfully for Over 27 Years by Over 90% of Major Oil & Gas Companies in Over 40 Countries — Onshore and Offshore Wheels are Field-replaceable

Call 800-537-9327 or Your Oilfield Supply Store www.rodguides.com ®

1902 N. Yellowood Ave. Broken Arrow, Oklahoma 74012 U.S.A. PHO 918-250-5584 • FAX 918-250-4666

For FREE Information, select #416 at ogpe.hotims.com OGPE.com

September 2015

For FREE Information, select #15 at ogpe.hotims.com

For FREE Information, select #16 at ogpe.hotims.com

Accurate, repeatable viscosity analysis High-accuracy, repeatable dynamic liquid viscosity measurement is delivered by this new viscometer. It’s designed for a range of petroleum products including lube oils, lube oil stocks, biodiesel, and fuel oil — and also calculates kinematic viscosity. ATEX, IECEx, and TIIS (Japan) certified, the instrument calculates viscosity, measuring differential pressure across a capillary tube held at a constant temperature. Precise temperature control is achieved by immersing the measuring capillary in a small stirred heated oil bath. Models accommodate a wide range of pressures and temperatures at the inlet and can return sample direct to the process, it’s noted. Icon Scientific Limited: Bath UK For FREE Information, select #17 at ogpe.hotims.com

Pipeline temp regulator & freeze protector blankets Powerblanket is designed to help you better manage your pipelines — via temperature regulation and freeze protection. Powerblanket valve, manifold, or instrumentation heaters monitor temperature, power consumption, and voltage as well as for gas leaks, moisture levels, and system movement or impact. They offer continuity with existing systems and SCADA. Models also feature a “new cutting edge controller” on which you may request additional information. Powerblanket: Salt Lake City UT For FREE Information, select #18 at ogpe.hotims.com

For FREE Information, select #417 at ogpe.hotims.com

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Feature

Defining the Industrial Internet of Things (Industrial IoT)

T

he industrial internet refers to a reality of seamless integrated machinery with networked sensors and powerful software. The industrial Internet combines fields once separate; including big data, machine-to-machine communication, cyber security and more. As of March 2014, the Industrial Internet Consortium (IIC) was founded by AT&T, Cisco, General Electric, IBM, and Intel to bring together industry players, from global corporations to academia, to accelerate the development, adoption and wide-spread use of Industrial Internet technologies. Moxa Inc. was one of the early participants in this organization and serves on the Board of the Energy Charter. Whether you call it the Industrial Internet, Industrial Internet of Things or Industrie 4.0; it’s all the same thing. Today, automation and IT are coupling their advancements of the last 20 years to tackle some of the world’s biggest problems in energy, mass transportation, city infrastructure and manufacturing. Bringing these concepts into a reality across various vertical applications is certainly easier said than done, but there are four design attributes that define Industrial IoT and transcend vertical application: Connectivity: The industrial IoT is dependent upon pervasive and fluid connectivity between devices, sensors and operations. In the past, the division between Fieldbus networks, control networks and the application layers of comprehensive industrial operations were heavily divided. Protocol division guaranteed that connecting an oil refinery’s DCS system, for example, to the corporation’s global control network would be difficult, expensive and limited in functionality. The amount of data generated by various sensors and meters in a midsized refinery can produce terabytes of largely uninteresting data each day. Advancements in sensor resiliency, wireless transmission and network infrastructure have allowed for these industrial applications to the growing stream of data at costs far lower than traditional Fieldbus infrastructures. Data-to-Information Conversion: As mentioned, the industrial world is not lacking in data production. The challenge rests in putting those data to work. For years, enterprise data companies utilizing distributed databases have searched for the best way to implement data-driven operational solutions into

OGPE.com

September 2015

heavy industry and automation, but usability has been hard to achieve. With the huge surge of data that a h network of flow meters can produce in one day, for example, the transfer and storage of those data have been seen as too comprehensive to in an industrial network. However, with the advancement of embedded computing and industrial wireless networks, the processing and storage of stream data are allowing small to large-scale oil and gas operations to log years of production data with ease — quickly alerting central control of anomalies in the process in real-time. Benefits of this “Data-to-Information” capability at the edge of industrial networks have allowed companies to maximize capital equipment service by years, while shedding light on potential system failures before they occur. Cyber Security Shift: The cyber level of the Industrial IoT movement is what fundamentally differentiates Industrial IoT from IoT. In the Industrial Internet, the cyber level serves as a central information hub where all data from field assets and sensors exist. It is at the cyber level where customized analytics are performed and reside for the purpose of allowing machines to engage in self-learning processes and machine-to machine comparisons over time. In simple , network data are being distributed among the various devices within a local area network, placing much of the burden of computation and security evenly among the devices in that network. Bandwidth bottlenecks are reduced, as well as potential areas of network vulnerability. This is because the cyber level of the Industrial IoT architecture, by its very nature, flips traditional cyber security and management models on their head by shifting traffic away from large corporate networks to a network of edge and perimeter

Feature

devices. In this model, each device has a role to play in the security of the greater network. Cloud: While much of the current critical infrastructure in heavy industry is controlled by a a web of interconnecth ed control systems, such as distributed control systems e (DCS) or supervisory control and data acquisition (D ((SCADA), the application of control is moving toward the cloud. Whether we are talking about w oil and gas SCADA systems or power grid o ccontrol networks, each network is unique. SCADA systems have largely involved a great deal of customization and commisgr sioning time before going operational. This si is a huge disadvantage when it comes to scalability and safety. Contrary to early proponents of Inscalabilit dustrial IoT, the future of an industrial internet does not rest in the cloud, but the development of SCADA systems might. Utilizing the cloud to provide the application layer of data acquisition and control to the cloud allows for a more decentralized state of SCADA development, customization and intrusion control in greater rapidity. Oil and Gas - Industrial IoT with Moxa In order to make the Industrial IoT movement a reality on a massive scale, many disparate technologies and industries must learn to work more cohesively with one another. One of the verticals that Moxa is leading the way in Industrial IoT applications is oil and gas. With oil prices dropping to historic lows, the upstream oil sphere is heavily vested in long-term cost-cutting measures that still provide safety and security assurances to the many mission-critical applications. In simple , there are three ways to lower the bottom-line when it comes to oil and gas production: increase production efficiency, decrease production labor costs and – of course – halt production altogether. Moxa has been in the business of helping oil and gas companies with the first two of these three options. The Moxa approach to Industrial IoT in oil and gas has been the same as it has been in all verticals. We

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place an emphasis on combining advanced networking technology with industrial quality. In upstream oil and gas applications, specifically in offshore applications, Moxa’s embedded computing and wireless product offering has provided the industry with the ability to combine PLC functionality at the edge of the network with wireless accessibility. Outside of providing the customer with a huge initial cost-savings, the Moxa approach to industrial computing and wireless accessibility allows offshore networks to conduct analytics in real-time on the platform itself. Conventionally, oil platforms can produce up to two-four terabytes of operational data in a single day. This inflow of data is very difficult to transfer via satellite to central control onshore for analytics, often taking days to process. Of course, this process of data extraction and transfer does not provide daily operational value to some of the mission critical aspects of any offshore rig operation. With Moxa’s UC-8100, and other embedded computers, Moxa is enabling oil and gas customers to capitalize on all benefits the industrial internet can provide onsite. Instead of waiting days to gain insights from production scales and capital equipment status updates, operators can gather the information in seconds. Production or equipment anomalies can be recognized immediately so corrective action can be taken. The life of rotating equipment, piping and drilling systems can be extended with less controller resources. Lastly, the risk of system failure and network intrusion can be further mitigated. Outside of Moxa’s product line of embedded computers and AWK wireless modules, it can further empower offshore upstream operations by bringing the control room to the fingertips of the operational staff onboard. EXPC-1519 touchscreen PC is ideal for any mission-critical operation where onsite control and visibility are imperative. The anti-scratch, 19-inch sunlight viewable LCD capacitive multi-touch screen can be operated with rigger’s gloves, offering dexterity of a consumer tablet, while enduring the most extreme environments. The high performance Intel® 3rd generation Core™ i7-3555LE or Celeron 1047UE U and up to 2.5GHz processor guarantees high visibility and usability in nearly all circumstances. The fanless design is operable in temperatures -40° to 70°C. Like most of Moxa’s products, the EXPC-1519 works anywhere and everywhere. Moxa is a leading industrial networking connectivity company that has grown out of its success in providing connectivity solutions, no matter the vertical market. With over 35 million devices connected to the Internet, Moxa has seen the power that is bringing data-driven decision making to the field or offshore rig floor. MOXA: Brea CA — Moxa.com For FREE Information, select #300 at ogpe.hotims.com

September 2015

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New Products & Services

Free Thermal Management Solutions white paper

Rental refinery and petrochem-grade heat exchangers

Rittal’s Thermal Management Solutions white paper outlines the impact of increasing temperatures on the lifespan of electronics housed in enclosures. The average lifespan of semiconductors is reduced by roughly 50% every time the operating temperature rises 20°F. / 10°C. over its maximum operating temperature. The failure of a single electronic component may lead to the complete shutdown of an entire production line. Resulting costs add up quickly. Unfortunately high temperatures in enclosures can be difficult to control because electronic equipment such as transformers, power distribution components, drives, PLCs, and PCs all generate heat. Air conditioners currently are the only practical standalone device in the market that can cool an environment below ambient temperature. This white paper provides useful tips and techniques on sizing an air conditioning unit for a specific enclosure application, guidance on how to interpret an air conditioner’s performance chart, tips on comparing specifications, and insights into the impact of humidity. Rittal’s TopTherm roof-mounted and wall-mounted unit options are described, as are various mounting options and controllers. A feature/benefit comparison chart makes it easy to evaluate the latest TopTherm units in contrast with earlier Rittal offerings and competitive A/C units. Rittal Corporation: Schaumburg IL

Mitigate the consequences of heat exchanger failure with this rental fleet of refinery and petrochemical-grade exchangers — including shell and tube, shell and plate, or fin/fan. Designed to also turnarounds, debottlenecking projects, emergencies, seasonal tasks, or process improvement purposes — rapid response is assured with a group of experienced process engineers. They properly design and size all heat exchanger applications based on field experience, simulation software, and stream physical properties. AGGREKO: Houston

For FREE Literature, select #252 at ogpe.hotims.com

New sucker rod couplings introduced Newly introduced ToughMet 3 Sucker Rod Couplings are “designed to maximize production output and significantly reduce the costs of artificial lift operations.” The patent pending designs are alternatives to those made of conventional materials. They cut frequency of sucker rod couplings and producing tubing damage — the leading cause of well failure. ToughMet 3 comprises a temper of copper-nickel-tin spinodal alloy engineered by this firm specifically to resist mechanical wear, thread damage, corrosion, or erosion. The couplings are nongalling to prevent damage to production tubing. Materion: Mayfield Heights OH For FREE Information, select #20 at ogpe.hotims.com

OGPE.com

September 2015

For FREE Information, select #21 at ogpe.hotims.com

Higher-precision pressure transmitter added in product line extension Sitrans P310 & P410 basic and advanced pressure transmitters plus Sitrans P500 extend this company’s product portfolio. The higher-precision instruments are declared “to cover any conceivable measurement need.” All models are simple to operate using three pushbuttons. They offer long-term 0.125% stability over 5 years to allow extended calibration cycles and reduced maintenance. Siemens: Munich For FREE Information, select #22 at ogpe.hotims.com

New asset integrity service includes working-at-height A newly launched asset integrity service offers working-at-height for repair, maintenance, and decommissioning of onshore and offshore structures. Skilled IRATA-approved rope access technicians are utilized for welding, pipe and plate nondestructive testing, painting, crane inspection, blade repair, or fabric maintenance. The service also covers detailed offshore surveys, risk assessments and design as well as implementation of structural and piping modifications along with redundant equipment decommissioning. All are offered to make certain assets are effectively maintained for safe, reliable, efficient operation within corrosion, structural fatigue, impact damage, or general wear and tear conditions. 3sun Group: Norfolk UK For FREE Information, select #23 at ogpe.hotims.com

P13

New Products & Services

New block/bleed manifold measures FPSO vessel equipment

Anchored tool tethers offer 300% stretch for safety

A monoflange with dual double block and bleed function has been developed for measuring equipment on FPSO vessels. Designed to offer reduced weight, the manifold, originally developed for a well known energy sector company, provides a way of mounting six valves — and therefore dual double block and bleed function — into one valve body. The arrangement of valves and design of connecting flow paths was optimized. This provided a monoflange with six integral valves which weighs only only slightly more than a normal standard flange. And, only one valve body is required to lower the risk of leaks. AS-Schneider: Nordheim

Gear Keeper Anchored Tool Tethers deliver 20-ft diameter working area with a 4-ft retraction length. Designed for heavy tools up to 25 lb, the ergonomic tethers are designed with a low-force polyurethane elastic core. It has a 3:1 stretch factor for “the shortest retracted length combined with the longest extension length,” declares the maker. TL1-4021 and TL1-4025 anchor tethers’ polyurethane elastic cores employ a very low stretch force to minimize arm fatigue at full extension yet still provide proper degree of comfortable recoil. Hammerhead Industries Incorporated: Ventura CA

For FREE Information, select #24 at ogpe.hotims.com

Device protects UTI tape circuitry: free pamphlet PetroGuard is presented in this free pamphlet to protect ullage temperature interface tape circuitry. The device takes impact off the tape and lead so it returns to the hermetic housing without damage. This help you avoid sending a hermetic device out for repair — costing you money and a valuable piece of equipment for field personnel, notes the literature. Companies throw away money to repair the hermetic device while PetroGuard can save up to 50% or more if correctly used by field personnel, it’s declared. PetroFunnels: Houston

For FREE Information, select #26 at ogpe.hotims.com

Dry deluge testing helps justify HSE, regulatory compliance Siron Dry Deluge Testing offers you justification needed to provide to the HSE and regulatory bodies that your deluge system remains in fit for purpose condition between mandatory wet testing. Among Siron DDT benefits: efficient testing with no disruption of normal platform activities plus considerably less preparation time for DDT. Complete Siron DDT specifics are yours free. Clearwater Fire Solutions: Aberdeen For FREE Information, select #27 at ogpe.hotims.com

Non-bloom-technology-based pitting repair material newly introduced

Powerlink Bolt Cutters are announced to deliver cutting power with 30% less effort. The new 18 and 24-in. models cut up to 9/32 and 5/16-in. HRC 48 materials respectively, with double-compound action. Powerlink’s high-performance steel handles provide extra strength and power for each cut. The precision-ground, induction-hardened cutting blades are easily used on bolts, screws, chain, strapping steel, or wrought iron — and they deliver extreme durability, it’s declared. H.K. Porter Apex Tool Group: Sparks NV

Belzona 1511 Super HT-Metal is presented as “next gen pitting repair material.” It incorporates non-bloom technology where frost blasting of the applied material prior to application of protective lining is no longer required. The 100% solids epoxy material can operate in immersed conditions at up to 160°C. / 320°F. Super HT-Metal’s application is also simplified with mixing and use at temperatures as low as 10°C./50°F. Rubbery domains used in Belzona 1523 and 1593 linings have also been incorporated in 1511’s polymer matrix. This improves adhesion, flexibility, and toughness. Tensile shear adhesion has increased 46% regardless of cure time; pull off adhesion has increased 34% Belzona Polymerics Limited: Harrogate UK

For FREE Information, select #25 at ogpe.hotims.com

For FREE Information, select #28 at ogpe.hotims.com

For FREE Literature, select #253 at ogpe.hotims.com

Bolting cutting with less effort

September 2015

OGPE.com

P14

New Products & Services

Safe offshore corrosive liquids, chemicals transport and storage

Hard metal slurry pumps for fracing, drilling mud duties

Horizontal and vertical offshore acid tanks like this deliver safe corrosive liquids and chemicals transport and storage. Constructed using carbon steel for the vessel, piping, valves, instruments, and welds, models withstand offshore service, with corrosion-resistant carbon steel on the tank’s external frame. Each transportable tank is designed and manufactured to meet IMDG UN Portable Tank Type T14, DNV2.7-1, EN12079, ADR/RID, and CFR 49 standards, with frames meeting DNV 27-1. Hoover Container Solutions: Houston

KZE High Capacity Hard Metal Slurry Pumps handle abrasives and slurries to accommodate fracing, drilling mud, sand and gravel, or slurry transport. Models feature oil cooled and lubricated double mechanical seals with Sic vs. Sic faces and Buna N elastomers. Permanently lubricated upper and lower bearings offer extended service via high-temperature grease. KZE also comprises high chrome iron agitator, 28% chrome iron wear parts, 403 SS shaft and impeller, 304 SS hardware and fasteners, plus cast iron motor housing. BJM Pumps: Old Saybrook CT

For FREE Information, select #30 at ogpe.hotims.com

Information platform is new offshore decommissioning collaboration tool Announced as “the first online information management system for offshore decommissioning,” is iVISION decommissioning collaboration tool. It connects multi-location, multi-discipline teams and business units through one central point where information is securely stored and accessed. iVISION online platform integrates safety management, technical information, and video to drive continuous improvement, enhance knowledge transfer, and reduce the cost of current and future projects. Exceed: Aberdeen For FREE Information, select #31 at ogpe.hotims.com

No-, high-capacity circulation heaters for oil, gas CAST-X 4000 Circulation Heaters are ‘no ’ designs for oil, gas, energy, and hydrocarbon duties. They deliver high-throughput liquids or gases heating and come in several voltage, wattage, and circuitry configurations. CAST-X 400 features dual 1-in. OD stainless steel spiraled tubes through which liquid or gas flows, cast into an aluminum mass which also contains the heating elements. At up to 60 kW, they up to 36 gpm and 2,500 psi gas pressures. For very high pressures, models are available with Inconel flow-path tubes. Cast Aluminum Solutions: Batavia IL For FREE Information, select #32 at ogpe.hotims.com

OGPE.com

September 2015

For FREE Information, select #33 at ogpe.hotims.com

52-page welding & fabrication catalog This abrasives, power brushes, and maintenance products for surface conditioning provider — has released its new Welding & Fabrication Catalog. Available in print and digital format, it provides information on new Tiger X flap disc and a full line of products including coated abrasives, bonded abrasives, and brushes. All products are emphasized for performance before, during, and after the weld. Weiler Corporation: Cresco PA For FREE Literature, select #255 at ogpe.hotims.com

New intelligent systems cool sensitive electronic hardware iTMS Intelligent Thermal Management Systems cool sensitive electronics hardware. The new custom, self-contained designs are based on liquid cooling system technology developed by the firm for challenging military uses. Systems extend the capabilities of their maker’s rLCS ruggedized liquid cooling system technology, a closed loop liquid cooling design. It includes liquid-to-air heat exchangers, cold plates, pumps, coolant, fluid reservoir, fans, and hydraulic interconnects. rLCS pumps coolant through cold plates to which heat generating components are mounted. Heat is efficiently transferred into the fluid before flowing through the heat exchanger — where the thermal load is rejected. iTMS precise temperature control at optimum levels extends electronics’ life and reliability. Thermacore Incorporated: Lancaster PA For FREE Information, select #34 at ogpe.hotims.com

P15

Followup: The Pipeline + Energy Expo

recently ‘walked’ The Pipeline + Energy Expo in hometown Tulsa. Here are highlights representing some of the 100 equipment manufacturers and service providers. To request free information or literature on products and services of interest: Go to OGPE.com, right hand side of homepage — click “Product Information” — the yellow button. Or you can click the items right here on the pages if you receive OG&PE digitally as a section of Oil & Gas Journal.

Onshore pipeline, utility construction

Nitrogen pumping services for fracing, pipelines

For FREE Information, select #35 at ogpe.hotims.com

OG&PE

With both equipment and items, this company offers pipeline and utility construction equipment to onshore contractors. These include pipelayers, pipelayer attachments, pipe benders, vacuumlifts, pipecarriers, low ground pressure pipe trailers, or hydrotest pumps. items include welding machines, holiday detectors, slings, spreader bars, external clamps, pipe locators, and accessories. Complete details are yours free. Challenger Services, Sol Industries LLC: Tulsa OK

This company’s specialties: hydraulic fracturing and nitrogen services, declares its free pamphlet. Among capabilities shown and described are stimulation treatment designs, foam fracturing, cross linked/gel fracing, slickwater/acid fracs, and remote data transmitting. These primarily serve Oklahoma Texas, Kansas, Arkansas, and eastern Colorado. Eight nitrogen-specific capabilities and equipment are also summarized along with notations on stimulation equipment employed. Gore Nitrogen Pumping Services LLC: Seiling OK

Vegetation management services data

For FREE Literature, select #257 at ogpe.hotims.com

For FREE Literature, select #259 at ogpe.hotims.com

Oil, gas, petrochemical flow valves

Free incinerators, thermal oxidizers, combustors literature

A full range of flow control valve packages for oil, gas, E&P, petrochem, and chemical applications highlight this free 12-page brochure. API, ASME, and international standards-compliant multi- and quarter turn designs are cited to come in a variety of alloys, trims, configurations, sizes, and pressure classes — from general to severe service. Some 20 flow control valves types are shown and summarized to include trunnion-mounted ball, two balls one body, one-piece body trunnion mounted, cryogenic, unibody, flanged split body, API 6D swing check, as well as gate, globe, check, butterfly, needle and gauge, and wellhead API 6A gate valves. GWC USA: Spring TX For FREE Literature, select #258 at ogpe.hotims.com

Safe, efficient, cost-effective vegetation management services are presented in this free six-page brochure. For rights-of-way, utility, or community situations, they comprise aerial lift operations, wood debris management, specialized equipment, storm emergency response, herbicide application, and manual operations. Each service is illustrated with on-site photos and capabilities summaries. ASPLUNDH: Willow Grove PA

A broad range of combustion equipment and services highlight this free four-page brochure. Products are presented to accomplish dehydrator vapor emissions, oil tank or sour water tank vapors, solution gas from production battery, produced water vaporization and recovery, sour vapors from amine processing, refinery tail gas, emergency plant blowdown, shale oil/ gas separation combustion, heavy oil process waste gas, or well testing and cleanup. Heat recovery capabilities and benefits of turning ‘waste’ gas into usable gas are also emphasized to provide payback for environmental compliance including vaporizing produced water for dispersion or distillation. CNC: Coyote North Combustion USA Inc.: Enid OK For FREE Literature, select #260 at ogpe.hotims.com

Free Info or Literature — Click the link — Request — Get Response!

September 2015

OGPE.com

Followup: The Pipeline + Energy Expo

P16

Customized transportation services

Gas & flame detection

Less than Truckload Freight, truckload, expedited heavy haul, multimodal or intermodal transportation services are offered by this company. Founded to “provide cost-effective, customized transportation and supply chain solutions,” the firm also offers warehousing and full truck brokerage. The agency has 12 locations, each organized as a team to work together toward your transportation needs, requirements, and goals. Additional specifics are free upon request. FWF Logistics LLC: Houston

Eight gas and flame detection instruments and systems are presented in this free 12-page brochure. Sixteen sections highlight industrial gas detection wireless or fixed designs as well as display and alarm controllers plus process monitors. GASMAX / TX battery-powered wireless gas monitor is showcased. The single/ dual-channel designs come in ultra-low power microprocessor design and infrared sensor technology for advanced toxic and combustible gas monitoring. GDS Corporation: League City TX

For FREE Information, select #36 at ogpe.hotims.com

Air-cooled heat exchangers This company designs, manufactures, and s air-cooled heat exchangers for refining and processing — declares its free information folder. Smithco designs include gas coolers and condensers, process coolers, or oil coolers. Among eight major exchanger features cited are custom thermal and mechanical designs plus rugged construction from heavy gauge steel for equipment longevity. The firm’s Amercool Division offers generators sets and gas compression-applicable designs, also presented. Smithco Engineering Incorporated: Tulsa OK For FREE Literature, select #261 at ogpe.hotims.com

Oil & gas measuring, control products fabricator This integrator and fabricator of oil and gas measurement and control products offers a free six-page brochure. Among ‘customized solutions’ illustrated and described are LACT units, pipeline pig launchers and receivers, instrument/ control buildings, compressor piping skids, gas measurement packages, production meter skid packages, as well as spool pieces. Also emphasized are manufacturing, assembly, and testing capabilities for safe, efficient large components handling without weather interruptions. The facility includes X-ray with weld map, hydrostatic tests up to 6,000 psi, and in-house quality-control department. DistributionNOW Flow Line: Houston and Cyril OK For FREE Literature, select #262 at ogpe.hotims.com

OGPE.com

September 2015

For FREE Literature, select #263 at ogpe.hotims.com

Air and water treatment services Water treatment solutions for oil and gas are offered in this free information folder from a firm that has been filtering hydrostatic test water at the same rate required for pipeline dewatering — since 1994. Presented are four major service categories: pipeline water treatment, industrial degassing/ vapor control, environmental remediation, and construction water treatment. For pipelines, the firm offers hydrotest water treatment, tank bottom water treating, trench water for new pipeline construction, and tank hydrotest fill/dewatering. ProAct Services Corporation: Ludington MI For FREE Literature, select #264 at ogpe.hotims.com

Portable cofferdams This free pamplet showcases portable cofferdams to solve complex dewatering, diversion, and containment problems. Emphasized to be 60 to 70% more cost effective than traditional earthen fill dams, designs are shown and described to be reusable and environmentally friendly. The cofferdam manufacturer also offers site surveys, consulting installation training, and temporary designs. Dam-It Dams: Harper Woods MI For FREE Literature, select #265 at ogpe.hotims.com

Followup: The Pipeline + Energy Expo

P17

On-site nitrogen for pipelines

Multi-usable/industry gas detectors

Non-cryogenic, on-site membrane type nitrogen generation for pipelines is presented in this free datasheet. The company’s technology and equipment are cited to deliver at 30 50% savings compared to cryogenic nitrogen. They have also effectively eliminated the logistical issues associated with constant transport of liquid nitrogen, it’s noted. In pipeline pigging and purging or drying and testing, this services’ engineers use precise calculations to determine the right nitrogen volume and pressure needs to suit your specific application, it’s declared. Nitro-Lift Technologies LLC: Mill Creek OK

Eight gas detection instruments highlight this four-page brochure. They’re cited to serve 20 broad applications including petrochemical plants, refineries, oil rigs, and chemicals. Each gas detection design is shown and summarized. These include an infrared multi-beam (patented) gas detector — declared reliable and virtually maintenance free. Other gas detection models include dual gas analyzer, signature process gas analyzer, as well as universal or DIN transmitters. Sensor Electronics: Savage MN

For FREE Literature, select #266 at ogpe.hotims.com

Pipeline and terminal waste services Seneca Waste Solutions is cited in this free datasheet as “equipped to handle an array of waste situations for pipelines and terminals.” With qualified and certified personnel they offer scheduled industrial cleaning and unscheduled shutdowns as well as 24-hr emergency spill response plus waste transportation or disposal. With a service goal to “provide you with a prompt, environmentally safe waste removal solution,” the firm also strives “to minimize disruption to your business.” Seneca Companies: Des Moines IA For FREE Literature, select #267 at ogpe.hotims.com

AST manufacturing, install, services A wide range of aboveground storage tank manufacturing and installation services are described and illustrated in this free brochure. Petroleum, ethanol, biodiesel, water, chemicals, and liquid feed ASTs are offered per API 650 new tank erection, API 653 repair and inspection, API 12F (shop tanks), as well as AWWA. This company specializes in turnkey projects and also provides AST-related concrete, piping, coatings, inspections, internal linings and other services. Alliance Tank Service LLC: Cushing OK For FREE Literature, select #268 at ogpe.hotims.com

For FREE Literature, select #269 at ogpe.hotims.com

API 650 welded steel liquid ASTs Building new, welded steel, aboveground liquid storage tanks per API 650 — is this company’s specialty and subject of its free eight-page brochure. With emphasis on cost-efficient construction, the literature emphasizes economical tank dimensions for your storage needs. Safety and quality control are stressed along with global capabilities. Also offered are related inspection, repair and maintenance, secondary containment, dismantle and relocation services. Skinner Tank Company: Yale OK For FREE Literature, select #270 at ogpe.hotims.com

Land, survey, inspection, engineering services, integrity management This company provides project management and execution for multi-state, single county/ parish, or one tract, notes their free datasheet. Skilled teams offer oil and gas, pipeline, and seismic land, survey, inspection, multidiscipline engineering, and integrity management. To meet your needs and requirements, this firm provides a skilled and professional team to assure project scope is properly and completely defined. RSH Energy Land Services: Houston For FREE Literature, select #271 at ogpe.hotims.com

September 2015

OGPE.com

P18

Products Product & Service Followup r

August “r Product & Service Followup” Companies featured here d their equipment, products, systems, or services in August 3 OG&PE within Oil & Gas Journal. These summaries give you an opportunity to receive free information on them and their oil and gas specialties. Go to OGPE.com and use the Click Here for Product Information button on the right. You will receive prompt, complete response from these valued OG&PE clients.

Kobelco centrifugal compressors for your most challenging environments High-efficiency performance in the largest refineries and power applications around the world are served by Kobelco API compliant Integrally Geared and Single Shaft Overhang Centrifugal Compressors. Thousands of Kobelco compressors are in service worldwide for air separation, refining, petrochemical, energy services, and many other applications. Kobelco Compressors America Incorporated: Houston KobelcoCompressors.com For FREE Information, select #40 at ogpe.hotims.com

Working-at-height PROTO SkyHook Tether & transfer systems Because working at 200 ft has its risks — dropping a tool is no longer one of them with PROTO SkyHook Tether and Transfer Systems. PROTO is taking its safety obsession to new heights with its comprehensive tool tethering systems which include SkyHook along with tether-ready tools, lanyards, and tethering accessories. Proto Industrial Tools: Conyers GA ProtoIndustrial.com/tethered For FREE Information, select #41 at ogpe.hotims.com

In-line, on-board diesel filters deliver total engine contamination protection Protect critical engine components with Schroeder InLine Bulk Diesel Fuel Coalescing Filter (ICF) and On-Board Diesel Fuel Coalescing Filter (HDP-BC). Each provides unsured water removal for ULSD and biodiesel fluids along with unmatched ultra high efficiency particulate removal and fuel/water separation. This yields lower operating costs and better engine performance. Schroeder Industries: Leetsdale PA SchroederIndustries.com/products/fuelfiltration/default.aspx

2112-certified outerwear for winter Now’s the time to equip your crew with the Carhartt 2112-certified outerwear to power through winter’s worst. Head to toe, nothing outworks Carhartt. United we outwork them all. Carhartt: Dearborn MI Carhartt.com/query/2112+outerwear For FREE Information, select #44 at ogpe.hotims.com

Oil & gas process safety specialist Consulting, engineering, products, and services are offered by this specialist for process safety in the oil and gas industry worldwide. Request free explosion safety and pressure relief equipment, products, systems, and services information. REMBE GmbH Safety + Control: Brilon Deutschland Rembe.com For FREE Information, select #45 at ogpe.hotims.com

System + telematics = future of gas compressor control and automation DE-3000/3000+ and TE-1000 Integrated Telematics Module are the future of control for gas compressor package automation. They combine Altronic’s vast experience in control system development and production with Enbase Technology’s advanced telematics and software engineering. Together they produce a breakthrough automation platform. It integrates local and remote engine and compressor control, mobile field operations, and control room analytics. Altronic LLC: Girard OH — Altronic-llc.com For FREE Information, select #46 at ogpe.hotims.com

Need a rugged, field-proven solenoid valve for oil, gas, petrochemical?

CENTA flexible couplings for pump and compressor applications are offered in more than 20 unique designs. They come from torsional vibration experts with more than 16-million sold. CENTA Corporation: Aurora IL — Centa.info

Magnatrol high quality, two-way stainless and bronze valves control the flow of oil/fuel oil, biofuel, natural gas, solvents, hot liquids and gases, corrosive fluids, water, steam, or other sediment-free fluids. The solenoid valves handle up to 400°F. and 500 psig with their flanged ends or NPT threads from 3/8 to 3 in. Valve options include manual overrides, position indicators, NEMA 4X explosionproof, and watertight. Magnatrol Valve Corporation: Hawthorne NJ Magnatrol.com

For FREE Information, select #43 at ogpe.hotims.com

For FREE Information, select #47 at ogpe.hotims.com

For FREE Information, select #42 at ogpe.hotims.com

Pump & compressor couplings

OGPE.com

September 2015

P19

r Product & Service Followp

Seismic safety switch ideal for oil & gas Sensonics SA-3 Seismic Safety Switch is ideal for oil and gas applications via high integrity, low-noise piezoelectric seismometers with unique self testing. Switch features include being seismically qualified with robust and weatherproof steel enclosures. This suits the instrument for safety applications up to SIL-2 explosionproof version for hazardous areas. SENSONICS LTD.: Berkhamsted, Hertfordshire UK Sensonics.co.uk For FREE Information, select #48 at ogpe.hotims.com

The Petroleum Industry

“BIG PICTURE” You’ve Been Seeking! NOW AVAILABLE!

D&L knows downhole packers, service tools, multi-stage completion D & L Oil Tools pack a quarter century of know-how into every mechanical or hydraulic set packer, permanent packer, service tool and accessory, or multistage completion equipment. Learn how D & L Oil Tools sets the standard for innovation, quality, and unsured value. D & L Oil Tools: Tulsa OK — DLOilTools.com For FREE Information, select #49 at ogpe.hotims.com

Process gas compressors, condition monitoring, valves, service, training BORSIG reciprocating compressors, compressor valves, BlueLine, and services are based on a 175+ year legacy of innovative solutions. Reciprocating designs are according to API 618, up to 17,000 kW, 1,000 bar, and 115,000 m3/h while integrally geared centrifugal compressors are according to API 617, up to 25,000 kW, 150 bar, and 300,000 m3/h. BORSIG BlueLine combines control system, emergency shutdown, machine protection, and condition monitoring for reciprocating and centrifugal compressors. Besides a range of compressor valves, this manufacturer also offers a variety of related services and training. BORSIG ZM Compression GmbH: Meerane Borsig.de For FREE Information, select #50 at ogpe.hotims.com

MOXA wireless field communication goes faster and further in the oil patch MOXA helps you prepare for a world where even your most remote field equipment can be easily and inexpensively monitored using the most advanced cloud-based software. This is the Industrial Internet of Things which starts with a robust communications infrastructure. Via rugged 900 MHz WLAN radios like AWK-3191, your cloud-connected operations center can establish highly reliable wireless equipment communications up to 30 km away. With MOXA — it’s easier than you think. MOXA: Brea CA — MOXA.com For FREE Information, select #51 at ogpe.hotims.com

332 Pages / Hardcover / 2012 ISBN 978-1-59370-254-0 Price $89.00 US

Joseph Hilyard’s timely book provides a broad perspective on the oil and gas industry, with primary focus on the United States. It takes the reader on a tour of the operations used to fnd and evaluate resources, and then to produce, store, and deliver oil and gas.

ORDER YOUR COPY TODAY!

www.PennWellBooks.com 1.800.752.9764

FIND US! September 2015

OGPE.com

INTEGRATION + INFORMATION + MANAGEMENT

20th International Conference on Petroleum Data Integration, Information and Data Management WWW.PNECCONFERENCES.COM

MAY 17-19, 2016 HOUSTON, TEXAS

MARRIOTT HOUSTON WESTCHASE

SAVE THE DATE For its 20th year, PNEC continues to deliver a power-packed, technical program surrounding changes in key technologies and practical solutions to implement quality, data-driven decisions that meet enterprise-wide technical and fnancial interests when millions of invested dollars are at risk. Network with your peers and exhibitors from leading technology companies at this one-of-a-kind event.

Owned & Produced by:

Presented by:

ed by: Follow us on: ®

SERVICES | SUPPLIERS FUGRO Fugro has extended its integrated survey services to help improve efficiency in coastal management and enable more informed decision-making. A new agreement with global specialist EOMAP enables the creation of integrated bathymetric survey products that comprise elements from Satellite Derived Bathymetry (SDB), Airborne LiDAR Bathymetry (ALB) and traditional acoustic survey technologies. The integrated data and product solutions will provide clients with outstanding value and unmatched coverage. EOMAP’s robust technology platform can process satellite images and deliver global bathymetric and benthic habitat data over the full range of temporal and spatial resolutions through its proprietary, sensor-independent Modular Inversion Processor (MIP). This both complements and augments services already provided by Fugro, to provide even more spatial data solutions to suit a wide variety of budgets and purposes.

SCHLUMBERGER Schlumberger and IBM announced that they have teamed up to provide integrated services to upstream oil and gas customers that will improve the business impact of production operations projects. The offering combines Schlumberger’s production optimization services, upstream expertise, and industry-leading Avocet* production operations software platform with IBM’s enterprise asset management and enterprise services to deliver an end-to-end service for optimizing integrated production operations. Through the service, customers should expect improved productivity, efficiency and cost management across operational areas including production optimization, flow assurance, logistics, scheduling, HSE, human resources, equipment monitoring and maintenance. This new service unifies the decision environment to provide the critical for productivity and efficiency gains in today’s oilfield operations. The combination of production optimization workflows with enterprise business

Oil & Gas Journal | Sept. 7, 2015

processes enables multidisciplinary solution teams to implement customized business offerings spanning asset to enterprise levels.

DRAGON PRODUCTS LTD. In an effort to meet customer demand and expand its line of oil field production equipment, Dragon Products, LTD is currently developing its very first LACT units. Dale Gunderson, LACT Product Manager, says these LACT units will give customers a total well pad solution, making Dragon Products a single source shop for oil producers. LACT units, which are commonly referred to as the “cash ” of the oil industry, are responsible for accurately measuring crude oil as it transfers custody from one entity to another, Gunderson explains. Compared to older manual methods of measurement, the LACT unit is significantly more accurate and safer. Gunderson says he estimates the first LACT units should be available this quarter, and will continue the legacy of Dragon Products as a company that gives its customers the highest-quality equipment at the best value. Dragon Products, LTD manufactures a wide range of quality, durable products for the industrial and energy sectors. Their equipment and inventory include surface production equipment, mobile and workover rigs, double conical, roll off, dump/aggregate and transport trailers, industrial waste and liquid waste containers, and pumps and stimulation equipment.

COHESIVE SOLUTIONS, INC., Cohesive Solutions, Inc., a premiere IBM business partner and leading provider of IBM’s Maximo Enterprise Asset Management solution, announces the opening of new office space in Houston’s Energy Corridor. Cohesive Solutions, Inc. provides business transformation, consulting, and technical services for Enterprise Asset and Performance Management. Cohesive’s Enterprise Asset Management

solutions, powered by IBM’s Maximo, provide a single point of control over all types of assets within organizations, enabling customers to optimize those investments. Cohesive’s complementary Enterprise Performance Management Solution, Propel™, unlocks the potential within enterprise systems and provides businesses with a powerful toolset enabling them to

HALLIBURTON Halliburton announced that it has developed a first-of-its-kind mobile app for the oil and gas industry to help customers identify solutions for their well challenges. The new Solutions app allows oil and gas operators to quickly and easily find and share information about specific solutions for deep water, mature fields, and unconventional resources challenges. In addition to an overview of available solutions for key target areas, the Solutions app allows s to access Halliburton case studies, technical papers, news and product announcements, industry events and awards, as well as to test their knowledge through an oilfield trivia game. One of the app’s key features is the ‘Briefcase.’ When viewing available solutions for a key target area, s can select and share technologies and add them to a digital briefcase. The customized collection of information is saved and may be viewed later or shared electronically via social media. The app also allows customers to a Halliburton expert for further assistance.

CBMM SZMF, the central research company of the Salzgitter Group, will shortly publish the results of this strategically important three-year research project on the welding of X80 high strength pipeline steels. Their systematic work has been carried out in collaboration with Companhia Brasileira de Metalurgia e Mineração (CBMM), the premier supplier of niobium and niobium technology, and makes a significant contribution to our understanding of the weldability

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SERVICES | SUPPLIERS of high strength, low carbon microalloyed linepipe steels with niobium up to 0.10%. This new research builds on an earlier award winning contribution to the literature in which the research team in the Salzgitter pipe mill demonstrated the advantages of the low carbon, niobium concept process route for the production of coiled strip for X80 Helical Submerged Arc Welded (HSAW) pipe production by Salzgitter Mannesmann Großrohr GmbH. Many of the world’s current and planned major pipeline projects often have to operate in extreme environments and are increasingly designed to employ steels at the X80 strength level. The steel used for such projects has to be capable of being consistently fabricated into pipe usually using high heat input Submerged Arc Welding (SAW) and, more importantly, must be able to be field welded successfully using lower heat input welding processes such as Gas Metal Arc Welding (GMAW). The SZMF project has carefully studied the way in which low carbon steels with various levels of niobium react to the application of these relevant processes with the above mentioned welding procedures and the results, which provide data from weld metal and various heat affected zone (HAZ) locations, systematically reveal the influence which niobium microalloying introduces in low carbon steels intended for pipe manufacture. In addition to improving weldability, this advanced metallurgical design philosophy may simplify many aspects of strip or plate production and encourages steelmakers and end s to take full advantage of the low carbon higher niobium metallurgical design philosophy that makes plate or strip manufacture easier. High strength plate intended for pipe manufacture for sour service applications is also increasingly important and the recently completed Salzgitter work also includes a valuable welding evaluation of a newly designed low manganese niobium microalloyed steel which shows significant promise following a comprehensive worldwide evaluation program of

130

an industrial heat of the new alloy. For both projects, it has been demonstrated that all important areas of SAW and GMAW welded ts readily exceed the toughness requirements of the most onerous specifications.

ALTAAQA GLOBAL Altaaqa Global, a global provider of largescale temporary power services, has appointed energy industry veteran, Julian Ford as Chief Commercial Officer (CCO). As the company’s CCO, Ford’s remit is to ensure that Altaaqa Global achieves revenue growth targets and overall commercial success, and to facilitate the formulation and implementation of innovative global commercial strategies. Ford’s career in the industry started at the time when the concept of power plants on a rental basis was just gaining ground. He had a hand in introducing the concept of power project rental to governments of developing economies, which allowed them to hire power capacity to address short term energy issues during times of hydropower shortage or other generation or transmission issues. Ford was instrumental in taking the rental power concept to different regions across the globe, including Middle East and Africa, South America, East Asia and South Asia. Ford also led the way for the development of the gas-fueled temporary power equipment market in the mid-2000s. With keen interest in markets where gas reserves were not vast enough to be commercially developed, Ford pioneered a new business model that allowed countries to monetize their ‘stranded gas’ reserves to generate useful low-cost electricity for the national grid.

GEOTERIC The release of GeoTeric 2015.3 marks another major step in the evolution of Cognitive Interpretation. With the advancement of broadband seismic, there is a growing need for high resolution analysis techniques that are compatible with the complex waveforms of broadband data. With the 2015.3 release, GeoTeric

brings ground breaking high resolution frequency decomposition technologies suitable for both broadband & conventional data. High Definition Frequency Decomposition (HDFD) utilizes advanced frequency splitting techniques developed for the complex waveforms of broadband seismic. In line with the rest of the GeoTeric software it is an interactive, example driven tool – designed to work in symbiosis with your cognitive capabilities. This symbiosis encourages progressive thinking and an improved understanding of the geology, before interpreting. The HDFD technique allows you to reveal at seismic resolution, the detail of the geological elements in your data leading to a more precise delineation and extraction of the stratigraphic features.

WEATHERFORD Weatherford International plc announces the acquisition of the assets of Elite Energy Products, a North American oil and gas manufacturing and service company that designs and manufactures rotating control devices (RCD) and other specialty drilling equipment. Elite Energy Products offers an existing infrastructure and manufacturing capacity allowing Weatherford to extend the scope of its land RCD and managed pressure drilling (MPD) technology and services to include original equipment manufacturing (OEM) RCD sales to rigs for permanent installation. Weatherford Secure Drilling Services is the recognized leader in underbalance and MPD technology and services worldwide, and RCDs are a cornerstone technology that enables MPD operations. Traditionally a rental and services business, the MPD market is growing as managed pressure techniques are being adopted as a conventional method to increase productivity and well integrity. As a result, demand is growing for integration of RCD and MPD equipment into rigs. The SafeShield® RCD series will continue to be the primary solution for the Weatherford rental and service business.

Oil & Gas Journal | Sept. 7, 2015

STATISTICS IMPORTS OF CRUDE AND PRODUCTS — Districts 1-4 — — District 5 — 8-21 8-14 8-21 8-14 2015 2015 2015 2015 ––––––––––––––––––––––––— 1,000 b/d

———— Total US ———— 8-21 8-14 8-22* 2015 2015 2014 ––––––––––––––––––––––––—

Total motor gasoline ............. Mo. gas. blending comp..... Distillate............................... Residual .............................. Jet fuel-kerosine .................. Propane-propylene .............. Other ...................................

595 569 79 202 25 53 850

855 833 181 166 75 67 929

35 35 44 20 111 10 25

13 13 19 51 69 23 165

630 604 123 222 136 63 874

868 846 200 217 144 90 1,095

447 417 77 215 34 66 409

Total products ......................

1,804

2,273

245

340

2,048

2,614

1,248

Total crude ...........................

5,972

6,774

1,227

1,264

7,199

8,038

7,632

Total imports ........................

7,776

9,047

1,472

1,604

9,248

10,651

8,880

*Revised. Source: US Energy Information istration Data available at PennEnergy Research Center.

EXPORTS OF CRUDE AND PRODUCTS Finished motor gasoline Jet fuel-kerosine Distillate Residual Propane/propylene Other oils Total products Total crude Total exports NET IMPORTS Total Products Crude

–––––––––––––––– Total US –––––––––––––––– 8-21-15 8-14-15 *8-22-14 ––––––––––––––– 1,000 b/d ––––––––––––––– 419 444 362 133 149 136 1,223 1,293 1,200 414 398 379 505 547 375 1,001 1,053 884 3,695 3,884 3,336 477 576 385 4,172 4,460 3,721 5,075 (1,647) 6,722

6,192 (1,270) 7,462

Additional analysis of market trends is available through OGJ Online, Oil & Gas Journal’s electronic information source, at http://www.ogj.com.

OGJ CRACK SPREAD

5-28-15* 8-29-14* Change Change, ———–—$/bbl ——–—— %

SPOT PRICES Product value Brent crude Crack spread

58.96 115.54 (56.58) (49.0) 43.53 100.54 (57.01) (56.7) 15.43 15.00 0.43 2.9

FUTURES MARKET PRICES One month Product value 60.84 117.39 (56.56) (48.2) Light sweet crude 40.79 94.32 (53.53) (56.8) Crack spread 20.05 23.07 (3.02) (13.1) Six month Product value 57.62 112.46 (54.84) (48.8) Light sweet crude 44.49 92.95 (48.46) (52.1) Crack spread 13.13 19.51 (6.38) (32.7) *Average for week ending. Source: Oil & Gas Journal Data available at PennEnergy Research Center.

5,160 (2,088) 7,248

*Revised. Source: Oil & Gas Journal Data available at PennEnergy Research Center.

CRUDE AND PRODUCT STOCKS —–– Motor gasoline —–– Blending Jet fuel, ————— Fuel oils ————— PropaneCrude oil Total comp. kerosine Distillate Residual propylene ———————————————————————————— 1,000 bbl —————————————————————————

District PADD 1 ..................................... PADD 2 ..................................... PADD 3 ..................................... PADD 4 ..................................... PADD 5 .....................................

15,770 139,198 222,756 21,912 51,125

60,401 47,343 74,523 6,422 25,745

54,686 40,602 64,473 4,596 23,601

11,470 6,535 14,326 664 8,698

54,672 30,643 47,214 3,810 13,497

9,478 1,327 24,099 254 4,561

4,314 26,884 60,684 1 3,842 —

Aug. 21, 2015 .......................... Aug. 14, 2015 ........................... Aug. 22, 20142 ..........................

450,761 456,212 360,475

214,434 212,775 212,315

187,958 187,702 183,266

41,693 42,322 34,718

149,836 148,400 122,794

39,719 39,155 36,249

95,724 93,866 74,709

1

Includes PADD 5. 2Revised. Source: US Energy Information istration Data available at PennEnergy Research Center.

REFINERY REPORT—AUG. 21, 2015 REFINERY –––––– OPERATIONS –––––– Gross Crude oil inputs inputs ––––––– 1,000 b/d ––––––––

District

–––––––––––––––––––––––––––– REFINERY OUTPUT ––––––––––––––––––––––––––– Total motor Jet fuel, ––––––– Fuel oils –––––––– Propanegasoline kerosine Distillate Residual propylene –––––––––––––––––––––––––––––––– 1,000 b/d –––––––––––––––––––––––––––––––

PADD 1 .............................................. PADD 2 .............................................. PADD 3 .............................................. PADD 4 .............................................. PADD 5 ..............................................

1,198 3,569 8,866 636 2,711

1,197 3,567 8,629 642 2,623

3,186 2,585 2,207 328 1,668

87 250 752 37 462

359 959 2,813 200 576

47 67 159 18 87

184 349 948 1 149 —

Aug. 21, 2015 ..................................... Aug. 14, 2015 ..................................... Aug. 22, 20142 ....................................

16,980 17,084 16,768

16,658 16,775 16,542

9,974 10,062 9,865

1,588 1,639 1,675

4,907 5,072 4,948

378 409 411

1,630 1,620 1,562

17,962 Operable capacity 1

94.5 utilization rate

2

Includes PADD 5. Revised. Source: US Energy Information istration Data available at PennEnergy Research Center.

Oil & Gas Journal | Sept. 7, 2015

131

STATISTICS OGJ GASOLINE PRICES

OGJ PRODUCTION REPORT

BAKER HUGHES RIG COUNT

Price Pump Pump ex tax price* price 8-26-15 8-26-15 8-27-14 ————— ¢/gal ————— (Approx. prices for self-service unleaded gasoline) Atlanta .......................... 188.9 234.8 Baltimore ...................... 195.4 241.2 Boston ........................... 199.3 244.2 Buffalo .......................... 186.3 255.2 Miami ............................ 193.1 247.5 Newark .......................... 200.9 233.8 New York........................ 196.3 265.2 Norfolk........................... 188.3 224.0 Philadelphia .................. 201.6 261.8 Pittsburgh ..................... 198.6 258.8 Wash., DC...................... 206.9 248.8 PAD I avg .................. 196.0 246.8

342.9 342.2 356.1 352.8 362.1 342.0 355.5 351.4 363.3 350.8 352.8 352.0

Chicago ......................... Cleveland ...................... Des Moines .................... Detroit ........................... Indianapolis .................. Kansas City ................... Louisville ....................... Memphis ....................... Milwaukee ..................... Minn.-St. Paul ............... Oklahoma City ............... Omaha .......................... St. Louis ........................ Tulsa ............................. Wichita .......................... PAD II avg .................

293.2 217.6 215.6 200.8 204.0 216.9 223.3 223.2 227.0 220.2 192.7 202.9 229.0 191.0 213.4 218.0

350.7 264.0 256.0 261.2 264.2 252.6 274.2 263.0 278.3 267.2 228.1 248.6 264.7 226.4 255.8 263.7

398.9 370.4 350.3 345.4 340.4 341.3 354.4 358.4 356.3 358.3 325.9 328.6 330.7 324.1 345.4 348.6

Albuquerque .................. Birmingham .................. Dallas-Fort Worth .......... Houston ......................... Little Rock ..................... New Orleans .................. San Antonio ................... PAD III avg ................

205.9 195.8 186.8 187.8 195.9 198.7 199.7 195.8

243.1 235.1 225.2 226.2 236.1 237.1 238.1 234.4

333.2 357.8 321.5 328.8 329.5 336.1 331.1 334.3

Cheyenne....................... Denver ........................... Salt Lake City ................ PAD IV avg ................

223.9 240.7 243.2 235.9

266.3 281.1 286.1 277.8

357.9 369.9 362.9 363.6

Los Angeles ................... Phoenix.......................... Portland ........................ San Diego ...................... San Francisco................ Seattle........................... PAD V avg ................. Week’s avg. .................. Aug. avg... ..................... July avg.. ....................... 2015 to date ................. 2014 to date .................

313.0 236.7 253.3 306.0 275.2 257.1 273.5 217.8 217.4 231.4 204.3 305.1

381.1 274.1 302.7 374.2 343.4 313.0 331.4 265.1 264.7 278.7 251.6 352.3

394.8 364.8 374.8 380.0 398.6 363.6 379.4 352.6 350.3 362.8 — —

1

8-28-15

8-29-14

Alabama............................................ Alaska ............................................... Arkansas ........................................... California .......................................... Land................................................ Offshore .......................................... Colorado ............................................ Florida ............................................... Illinois ............................................... Indiana.............................................. Kansas .............................................. Kentucky............................................ Louisiana .......................................... N. Land ........................................... S. Inland waters .............................. S. Land............................................ Offshore .......................................... Maryland ........................................... Michigan ........................................... Mississippi ........................................ Montana ............................................ Nebraska ........................................... New Mexico........................................ New York............................................ North Dakota ..................................... Ohio................................................... Oklahoma .......................................... Pennsylvania ..................................... South Dakota..................................... Texas ................................................. Offshore .......................................... Inland waters .................................. Dist. 1 ............................................. Dist. 2 ............................................. Dist. 3 ............................................. Dist. 4 ............................................. Dist. 5 ............................................. Dist. 6 ............................................. Dist. 7B ........................................... Dist. 7C ........................................... Dist. 8 ............................................. Dist. 8A ........................................... Dist. 9 ............................................. Dist. 10 ........................................... Utah .................................................. West Virginia ..................................... Wyoming............................................ Others NV-1 .......................................

2 13 4 13 13 0 36 0 2 0 13 2 71 29 4 9 29 0 0 3 1 3 50 0 72 19 105 35 0 386 0 0 48 43 19 15 7 21 5 36 153 16 5 18 4 17 25 1

6 7 11 46 44 2 75 2 1 3 25 3 117 29 10 19 59 0 0 13 8 2 94 0 183 41 212 55 1 900 2 0 109 81 67 38 10 36 14 100 321 40 16 66 23 29 56 1

Total US ........................................ Total Canada ................................

877 196

1,914 409

Grand total ................................... US oil rigs.......................................... US gas rigs........................................ Total US offshore ............................... Total US cum. avg. YTD .....................

1,073 675 202 30 1,083

2,323 1,575 338 66 1,835

2 8-28-15 8-29-14 –—— 1,000 b/d —–—

(Crude oil and lease condensate) Alabama ................................. 25 Alaska .................................... 430 California ............................... 600 Colorado ................................. 297 Florida .................................... 5 Illinois .................................... 24 Kansas ................................... 120 Louisiana ............................... 1,285 Michigan ................................ 18 Mississippi ............................. 65 Montana ................................. 78 New Mexico............................. 415 North Dakota .......................... 1,194 Ohio ........................................ 68 Oklahoma ............................... 335 Pennsylvania .......................... 20 Texas ...................................... 3,917 Utah ....................................... 111 West Virginia .......................... 34 Wyoming ................................. 235 Other states ........................... 50 Total 9,326 1 OGJ estimate. 2Revised. Source: Oil & Gas Journal. Data available at PennEnergy Research Center.

US CRUDE PRICES Alaska-North Slope 27° ......................................... Light Louisiana Sweet ........................................... California-Midway Sunset 13° .............................. California Buena Vista Hills 26° ........................... Wyoming Sweet ..................................................... East Texas Sweet ................................................... West Texas Sour 34° .............................................. West Texas Intermediate........................................ Oklahoma Sweet.................................................... Texas Upper Gulf Coast ......................................... Michigan Sour ....................................................... Kansas Common ................................................... North Dakota Sweet ...............................................

Research Center.

WORLD CRUDE PRICES OPEC reference basket

Rotary rigs from spudding in to total depth. Definitions, see OGJ Sept. 18, 2006, p. 46. Source: Baker Hughes Inc. Data available at PennEnergy Research Center.

IHS PETRODATA RIG COUNT 8-21-15 ¢/gal

AUG. 28, 2015 Total supply of rigs

Spot market product prices No. 2 Distillate Motor gasoline Low sulfur diesel fuel (Conventional-regular) New York Harbor ......... 155.60 New York Harbor ......... Gulf Coast .................. 153.10 Gulf Coast .................. Los Angeles ................ Motor gasoline Kerosine jet fuel (RBOB-regular) New York Harbor ......... 186.10 Gulf Coast ..................

145.20 140.20 144.70 132.20

Propane No. 2 heating oil New York Harbor ......... 132.90 Mont Belvieu .............. 37.10

US Gulf of Mexico. . . . . . South America Northwest Europe. . . . . West Africa. . . . . . Middle East. . . . . . . Southeast Asia. . . . . . . Worldwide. . . .

Marketed Marketed supply Marketed utilization of rigs contracted rate (%)

116

76

56

73.7

69

65

59

90.8

103

96

84

87.5

75

70

51

72.9

159

153

135

88.2

97 850

89 762

53 622

59.6 81.6

Wkly. avg.

$/bbl 8-28-15 41.84 –– Mo. avg., $/bbl –– June -15 July -15

OPEC reference basket....................... Arab light-Saudi Arabia ....................... Basrah light-Iraq ................................. Bonny light 37o-Nigeria........................ Es Sider-Libya ...................................... Girassol-Angola.................................... Iran heavy-Iran..................................... Kuwait export-Kuwait ........................... Marine-Qatar........................................ Merey-Venezuela .................................. Murban-UAE ......................................... Oriente-Ecuador ................................... Saharan blend 44o-Algeria ................... Other crudes Minas 34o-Indonesia ............................ Fateh 32o-Dubai ................................... Isthmus 33o-Mexico ............................. Brent 38o-UK ........................................ Urals-Russia ........................................ Differentials WTI/Brent ............................................. Brent/Dubai..........................................

Includes state and federal motor fuel taxes and state sales tax. Local governments may impose additional taxes. Source: Oil & Gas Journal. Data available at PennEnergy Research Center.

8-21-15 ¢/gal

8-28-15 $/bbl* 57.55 40.59 40.65 47.72 37.97 39.00 37.00 42.00 42.00 35.75 34.00 40.75 31.50

*Current major refiner’s posted prices except N. Slope lags 2 months. 40° gravity crude unless differing gravity is shown. Source: Oil & Gas Journal. Data available at PennEnergy

*

REFINED PRODUCT PRICES

24 398 610 216 6 27 136 1,340 20 66 85 340 1,132 38 339 17 3,471 100 17 213 53 8,648

60.21 60.94 58.63 62.19 60.79 63.28 59.86 59.29 61.79 51.74 64.59 56.71 61.69

54.19 54.95 53.10 56.77 55.54 56.46 54.86 53.85 55.36 44.43 57.58 47.78 56.34

60.09 61.76 63.48 61.69 62.52

51.86 56.15 55.62 56.54 55.84

(1.88) (0.07)

(5.37) 0.39

Source: OPEC Monthly Oil Market Report. Data available at PennEnergy Research Center.

US NATURAL GAS STORAGE1 8-21-15

Producing region ................ Consuming region east ...... Consuming region west ...... Total US ............................. Total US2 ............................

8-14-15

8-21-14

–——––—— bcf —––——– 1,110 1,098 810 1,510 1,457 1,394 479 475 415 3,099 3,030 2,619 Change, June-15 June-14 % 2,647

2,005

Change,

% 37.0 8.3 15.4 18.3

32.0

1

Source: EIA Weekly Petroleum Status Report. Data available at PennEnergy Research Center.

132

Source: IHS Petrodata Data available in PennEnergy Research Center

Working gas. 2At end of period. Source: Energy Information istration Data available at PennEnergy Research Center.

Oil & Gas Journal | Sept. 7, 2015

STATISTICS PACE REFINING MARGINS

WORLDWIDE NGL PRODUCTION

June July Aug. Aug. 2015 2015 2015 2014 Change ——––—––––— $/bbl –––––––––—— US Gulf Coast Composite US Gulf Refinery.............. Mars (Coking) .................................. Mars (Cracking) ............................... Bonny Light ...................................... US PADD II Chicago (WTI)................................... US East Coast Brass River ...................................... East Coast Comp ............................. US West Coast Los Angeles (ANS) ............................ NW Europe Rotterdam (Brent) ............................ Mediterranean Italy (Urals) ...................................... Far East Singapore (Dubai) ............................

5 month Change vs. average previous May Apr. –– production –– –––— year —– 2015 2015 2015 2014 Volume ————–—–––— 1,000 b/d ———––———— %

Change, %

15.87 16.74 13.55 13.68

16.50 18.66 15.10 8.81

17.21 18.28 14.24 12.58

13.87 14.21 11.00 8.54

3.33 4.07 3.24 4.04

24.0 28.7 29.4 47.3

19.84

23.51 34.31

18.41

15.90

86.4

17.62 21.63

10.58 14.06 12.74 15.29

9.34 10.08

4.72 5.21

50.5 51.7

16.46

33.40 24.18

11.56

12.62

109.1 611.4

5.79

5.79

7.13

1.00

6.13

6.64

6.02

8.25

0.06

8.18 12,654.6

5.67

2.69

4.02

0.64

3.38

530.2

Source: Jacobs Consultancy Inc. Data available at PennEnergy Research Center.

US NATURAL GAS BALANCE DEMAND/SUPPLY SCOREBOARD June Total YTD June May June 2015-2014 ––– YTD ––– 2015-2014 2015 2015 2014 change 2015 2014 change ——————————— bcf ——————––————— DEMAND Consumption ................... Addition to storage .......... Exports ............................ Canada ......................... Mexico .......................... LNG ............................... Total demand ..................

1,927 427 139 45 91 3 2,493

1,879 541 135 45 87 3 2,555

1,765 506 120 55 65 — 2,391

162 (79) 19 (10) 26 3 102

14,586 14,131 1,686 1,664 845 779 372 428 462 346 11 5 17,117 16,574

455 22 66 (56) 116 6 543

SUPPLY Production (dry gas) ........ Supplemental gas............ Storage withdrawal.......... Imports ............................ Canada.......................... Mexico ........................... LNG................................ Total supply .....................

2,236 4 69 206 203 — 3 2,515

2,289 5 45 204 202 — 2 2,543

2,095 5 44 201 192 — 9 2,345

141 — 25 5 11 — (6) 171

13,396 12,415 28 29 2,171 2,550 1,406 1,384 1,360 1,352 — 1 46 31 17,001 16,378

981 (1) (379) 22 8 (1) 15 623

4,370 2,647 7,017

4,362 2,295 6,657

4,364 1,804 6,168

4,358 2,005 6,363

90 653 323 3,249 213

90 703 311 3,313 213

93 697 334 3,165 213

84 674 364 2,783 213

9 23 (30) 382 —

11.0 3.5 (8.2) 13.7 —

212

229

235

242

(7)

(3.0)

4,740

4,859

4,736

4,359

377

8.6

Norway................................. United Kingdom ................... Other Western Europe ............................... Western Europe .............

325 68

330 71

341 59

311 66

29 (7)

9.4 (10.6)

9 402

9 410

9 409

10 388

(1) 21

(10.0) 5.5

Russia ................................. Other FSU ............................ Other Eastern Europe ............................... Eastern Europe ..............

753 157

753 157

755 156

719 169

36 (13)

5.0 (7.4)

13 923

13 923

13 924

14 902

(1) 23

(6.7) 2.5

Algeria ................................. Egypt ................................... Libya.................................... Other Africa ......................... Africa..............................

340 202 50 83 675

340 202 50 83 675

340 201 50 83 674

340 190 43 82 655

— 11 7 — 19

— 6.0 16.3 0.4 2.9

Saudi Arabia........................ United Arab Emirates .......... Other Middle East ................ Middle East.....................

1,700 400 700 2,800

1,700 400 700 2,800

1,700 400 698 2,798

1,830 400 664 2,894

(130) — 34 (96)

(7.1) — 5.2 (3.3)

Australia.............................. China................................... India .................................... Other Asia–Pacific ............... Asia–Pacific ................... TOTAL WORLD .................

80 — 105 314 499 10,037

85 — 105 314 504 10,170

66 — 104 314 483 10,025

74 — 102 335 511 9,708

(8) — 2 (21) (27) 317

(11.1) — 2.0 (6.4) (5.4) 3.3

372

372

640

373

638

435

640

2,800

–61

643

(3)

–14.1

(0.4)

Totals may not add due to rounding. Source: Oil & Gas Journal. Data available at PennEnergy Research Center.

OXYGENATES June May YTD YTD 2015 2015 Change 2015 2014 Change ———————––—––– 1,000 bbl –––—————————

NATURAL GAS IN UNDERGROUND STORAGE June May Apr. June 2015 2015 2015 2014 Change —————————— bcf —————————— Base gas Working gas Total gas

Brazil ................................... Canada................................ Mexico ................................. United States ...................... Venezuela ............................ Other Western Hemisphere ....................... Western Hemisphere..................

2,477 642 3,119

Source: DOE Monthly Energy Review. Data available at PennEnergy Research Center.

Fuel ethanol Production .................. Stocks .........................

29,684 20,029

29,666 20,120

18 (91)

MTBE Production .................. Stocks .........................

1,549 983

1,634 1,101

(85) (118)

173,292 167,496 20,029 18,664

6,891 983

7,121 883

5,796 1,365

(230) 100

Source: DOE Petroleum Supply Monthly. Data available at PennEnergy Research Center.

US COOLING DEGREE–DAYS July 2015

July 2014

Normal

2015 % change from normal

New England ................................................................ Middle Atlantic ............................................................. East North Central........................................................ West North Central ....................................................... South Atlantic .............................................................. East South Central ....................................................... West South Central....................................................... Mountain ...................................................................... Pacific ..........................................................................

204 275 219 303 462 457 582 328 237

202 245 157 218 412 328 499 404 286

180 247 245 308 425 412 545 341 188

13.3 11.3 (10.6) (1.6) 8.7 10.9 6.8 (3.8) 26.1

315 496 424 568 1,372 1,068 1,501 749 458

280 398 385 511 1,187 879 1,367 820 486

249 387 443 574 1,104 900 1,403 715 344

26.5 28.2 (4.3) (1.0) 24.3 18.7 7.0 4.8 33.1

US average*............................................................

342

308

321

6.5

801

723

696

15.1

Total degree–days ———–– Jan. 1 through July 31 ––——— 2013 2012 Normal

% change from normal

*Excludes Alaska and Hawaii. Source: DOE Monthly Energy Review. Data available at PennEnergy Research Center.

Oil & Gas Journal | Sept. 7, 2015

133

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3-DAY AUCTION: September 16th, 17th and 18th, Closing Daily at 10:00am (MDT) INSPECTION: September 9th, 10th, 11th, 14th & 15th, 10:00am to 4:00pm (MDT) Each Day ASSET LOCATIONS: 5916-36 St, East Nisku AB (Edmonton) • 9319-81 Ave, Grand Prairie AB 2747 North Service Rd, West Swift Current SK DAY 1 Nitrogen Truck Fleet • Coil Tubing Units • Hydro Vac Trucks • Service Trucks • Boom Trucks DAY 2 Vac Trucks • Water Trucks • Pickup Trucks • Pressure Trucks • Tractor Units DAY 3 Trailers • Rough Neck Trailers • Office Trailers • Steer Skid Loaders • Tanker Trailers • Maintenance Shop Equipment • Parts Inventory • Office Furniture

Coil Tubing Fleet as Late as 2007 • Hydro Vac Fleet as Late as 2014 • Nitrogen Fleet as Late As 2014 • Vac Truck Fleet as Late as 2014 • Water Truck Fleet • 100+ Pick Up Trucks • Rough Neck Trailers • Mountain View Trailers • Tanker Trailers • Blow-Out Preventers • Blow Back Tanks • Boom Trucks • Service Trucks • Sour Seal Trucks • Truck Tractors • Motor Graders • Skid Steer Loaders • (3) Complete Maintenance Shops and So Much More!!!

For More Sale Information Please Visit: www.gaauction.com

www.gaauction.com +1 818 340-3134

Auction Powered by:

NORTH AMERICA • SOUTH AMERICA • EUROPE • ASIA • AFRICA • AUSTRALIA Oil & Gas Journal | Sept. 7, 2015

135

MARKET CONNECTION WHERE THE INDUSTRY GOES TO CLASSIFY

The Oil & Gas Journal has a circulation of over 100,000 readers and has been the world’s most widely read petroleum publication for over 100 years P R O DU CT S & E QUI PME N T

L AN D /B US IN ES S OPP O RT UN IT IE S

For more Products and Equipment listings

visit http://www.ogj.com/market-connection.html o r c o n t a c t g ra c e j @ p e n n w e l l . c o m

136

Oil & Gas Journal | Sept. 7, 2015

MARKET CONNECTION WHERE THE INDUSTRY GOES TO CLASSIFY

• • •

Employment? HIRE Services Offered? ACQUIRE Equipment/Products/Land? SELL

SEE RESULTS—Ask me how!

GRACE JORDAN 713-963-6291 [email protected] Twitter: @ogjmarket

The Oil & Gas Journal has a circulation of over 100,000 readers and has been the world’s most widely read petroleum publication for over 100 years L AN D /B US IN E SS O P POR T UN IT IE S SALE OF CORPORATE INTEREST Minimum Bid: $50,000.00. Bidding to increase in $25,000.00 increments. Auction Date: September 16, 2015 : Trustee, Marc H. chneider, 281-4884438 American International Petroleum Corporation (ìAIPCî) was a publicly traded Nevada corporation that was engaged, through its subsidiaries, in petroleum refining and exploration. AIPC filed for Chapter 11 bankruptcy in October 2004, Case No. 04-21332 in the US Bankruptcy Court for the Western District of ouisiana, Lake Charles Division. AIPC operated as Debtor in Possession until August 17, 2006. Pursuant to the Plan of Reorganization, all assets were assigned to a Trust. The Bankruptcy Court has signed an order allowing AIPC to issue additional shares of common stock. The Trustee is auctioning, for the benefit of creditors, the right to issue new shares of common stock, which will result in the successful bidder holding a 49% interest in AIPC and any interest the Trustee or the Trust may have in AIPC. Tax returns for the company have been filed through 2014 indicating a significant Net Operating Loss carryover of more than $70M. AIPC will need to update its corporate filing before issuing the shares. The Trustee assumes no obligation to prepare or file such documents or pay any tax or cost with the state of Nevada or any other jurisdiction. The auction will be held on September 16, 2015, at 10:00 a.m. Central Time. Any competitive bid received must be in an amount of at least $50,000.00. All subsequent bids shall be in increments of $25,000.00. To present a competitive bid, bidders must deliver to the Trustee at least 48 hours prior to the auction documentary evidence acceptable to the Trustee that the bidder has financing for the acquisition. Upon timely notification to the Trustee, bidders will be provided with telephonic meeting instructions. Interested parties should Marc H. Schneider, Trustee, at 281-488-4438 for more information on AIPC or the auction.

E M PL O YM E NT CGG Services (U.S.) Inc.in Houston, Texas seeks Research Geophysicists. Qualified applicants will possess a Master’s degree in Geophysics, Electrical Engineering, Computer Science, Applied Mathematics, Physics or other related technical field and one (1) year of experience in the job offered or one (1) year of experience with abstracting geophysical concepts with mathematical languages; coding with FORTRAN, C/C++. Qualified applicants should send resumes to ATTN: Eve Stoddard, 10300 Town Park Drive, Houston, Texas 77072. Must put job code RGHou2015 on resume. Oil & Gas Journal | Sept. 7, 2015

FOR SALE:

985 acres adjacent to Eleanor, West Virginia. One of the largest continuous tracts of acreage offered for sale in central West Virginia. Expansive parcel is heavily wooded and in vicinity of both Marcellus and Utica Shale deposits. All mineral and surface rights in fee simple included in sale. $1.5 million ($1,523,00 per acre). Please call Dan Corey, (Owner): 304-541-8887 or Mike Thompson, (Realtor): 304- 541-7000

The Department of Interior, Bureau of Indian Affairs, Concho Agency will be conducting an

Oil and Gas Lease Sale at 9 a.m. on October 6, 2015 at Redlands Community College in El Reno, Oklahoma. Indian lands in Blaine, Canadian, Custer, Dewey, Kingfisher, Roger mills and Washita counties in Oklahoma will be available for lease. To obtain the complete text of the sale notice or further information, please call (405)-262-7481.

Woodbine Salt Water Disposal Well Leon County, Texas John McDonald @ 903-391-0342

E MPL OY ME NT Job Opportunities at Ensco PLC Ensco PLC is seeking individuals for the following positions within the US: Chief Engineer(s), Chief Electrician(s), Chief Mate(s), Master(s), Maintenance Supervisor(s), Chief ET(s), Sr. DPO/2nd Mate(s), Toolpusher(s), Sr. Toolpusher(s), OIM(s), Sr. Subsea Engineer(s), Subsea Engineer(s), Electronics Technician(s), Mechanic/Sr. Mechanic(s), Chief Mechanic(s), Assistant Driller(s), Driller(s), 2nd Mate/DPO(s), Electronic Technician(s), Electrician(s), Hydraulic Technician(s), Deck Foreman(s), Crane Operator(s), Welder(s), 3rd Engineer(s), and 3rd Mate DPO(s) For detailed info. & how to apply, visit http:// www.enscoplc.com/Careers/GLOBAL-JOBS/ default.aspx & enter the job title as a keyword.

CGG Services (U.S.) Inc. in Houston, Texas seeks Junior Seismic Developers. Qualified applicants will possess a Master’s degree in Computer Science or other related technical field and one (1) year of experience in the job offered or one (1) year of experience using FORTRAN-95 for batch module programming, C++ or Java for interactive applications and C for infrastructure codes. In lieu of the above, will accept a Bachelor’s degree in Computer Science or other related technical field and five (5) years of experience in the job offered or five (5) years of experience using FORTRAN-95 for batch module programming, C++ or Java for interactive applications and C for infrastructure codes. Qualified applicants should send resumes to ATTN: Eve Stoddard, 10300 Town Park Drive, Houston, Texas 77072. Must put job code JrSDHou2015 on resume. 137

MARKET CONNECTION WHERE THE INDUSTRY GOES TO CLASSIFY

The Oil & Gas Journal has a circulation of over 100,000 readers and has been the world’s most widely read petroleum publication for over 100 years E MPL OY ME NT

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List your

employment opportunities g ra c e j @ p e n n w e l l . c o m

Oil & Gas Journal | Sept. 7, 2015

ADVERTISING SALES US Sales Mike Moss, (713) 963-6221, [email protected]

Australia / New Zealand Mike Twiss, Miklin Business Services, Unit 15, 3 Benjamin Way, Rockingham, Western Australia 6168; Tel +61 8 9529 4466, Fax +61 8 9529 4488 Email: [email protected]

Brazil / South America

RS INDEX COMPANY NAME

PAGE

COMPANY NAME

PAGE

Airbus Helicopters

19

MOL

29

Ametek Aramco Services Company Ariel Corporation

Best Pumpworks

Sicking Industrial Marketing, Kurt-Schumacher-Str. 16, 59872, Freienohl, . Tel: 49(0)2903.3385.70, Fax: 49(0)2903.3385.82; E-mail: wilhelms@pennwell. com; www.sicking.de Andreas Sicking

Italy

P4

Oil & Gas Journal Site License

40

www.ogj.com

C3

Oilfields Improvements, Inc.

P8

www.rodguides.com

63 46-47

PennWell Books

P19

D&L Oil Tools

74

24

PetroBras

5

www.petrobras.com.br/en/

P9

PNEC Conference

P20

www.ppnecconferences.com

www.dloiltools.com

Eaton Partners, LLC

Perupetro S.A. www.perupetro.com.pe

www.circorenergy.com

75

Rembe GMBH Safety + Control

22

www.rembe.de

Emerson Process Management

91

Evonik Industries AG

95 37 49 69 13

Halo Sealing Systems Limited

e.x.press sales division, ICS Convention Design Inc. 6F, Chiyoda Bldg., 1-5-18 Sarugakucho, Chiyoda-ku, Tokyo 101-8449, Japan, Tel: +81.3.3219.3641, Fax: 81.3.3219.3628, Masaki Mori, E-mail: Masaki.Mori@ ex-press.jp

www.halo-seal.com

China / Korea / Singapore / Asia-Pacific

Hornbeck Offshore Services

Michael Yee, 19 Tanglin Road #05-20, Tanglin Shopping Center, Singapore 247909, Republic of Singapore; Tel: 65 9616.8080, Fax: 65.6734.0655; E-mail: yfyee@singnet. com.sg

www.hornbeckoffshore.com

United Kingdom / Scandinavia / Denmark / The Netherlands

www.riopipeline.com.br

15 7

HSBC

TD Williamson

55

Toshiba international Corp.

P3

Vallourec Oil & Gas

23

Valvitalia SPA

41

www.valvitalia.com

25

Waukesha Bearings

20

www.waukbearing.com

www.hiairkorea.co.kr

Honeywell www.honeywellprocess.com/oilandgas

Society of Exploration Geophysicists 122

www.vallourec.com

www.halliburton.com/complete1/illusion

Hi Air Korea, Co., Ltd.

71

www.toshiba.com/tic

www.GIE.com/opportunity

Japan

Siemens AG

www.tdwilliamson.com

www.gwdc.com.cn

Gulf Interstate Engineering

C2

www.seg.org

www.glenguard.com

Greatwall Drilling Company

Ryder System, Inc.

www.siemens.com/processinstrumentation

www.harris.com

Glen Raven, Inc.

85

www.ryder.com

www.evonik.de

Exelis, Inc.

Ruhrpumpen Group www.ruhrpumpen.com

www.emersonprocess.com/Smartfield

Halliburton

1

Weatherford

6, C4

www.weatherford.com

35

Wintershall

18

www.wintershall.com

107

www.us.hsbc.com/globaltrade

IBP

103

Industrial Rubber. Inc.

Graham Hoyle, 10 Springfield Close, Cross, Axbridge, Somerset BS26 2FE, Phone: +44 1934 733871 Mobile: +44 7927 889916, [email protected] or ghms@ btinternet.com

www.iri-oiltool.com

West Africa

www.kbcat.com

Dele Olaoye, Flat 8, 3rd Floor, Oluwatobi House, 71 Allen Ave., Ikeja Lagos, Nigeria; Tel: +234 805 687 2630; Tel: +234 802 223 2864; E-mail: [email protected]

Kimray

JVCKenwood

17 3

www.kenwood.com/usa

KBC Advanced Technologies

39 99

www.kimray.com

KLX Energy Services

11

www.klxenergy.com

Rhonda Brown, Foster Printing Co., Reprint Marketing Manager; 866.879.9144 ext 194, Fax: 219.561.2023; 4295 Ohio Street, Michigan City, IN 46360; [email protected]. www.fosterprinting.com

Kobe Steel, Ltd.

Custom Publishing

Lagcoe 2015

Roy Markum, Vice-President/Custom Publishing, roym@ pennwell.com, Phone: 713-963-6220, Fax: 713-9636228

27

www.carhartt.com

Ferruccio Silvera, Viale Monza, 24 20127 Milano Italy; Tel:+02.28.46 716; E-mail: [email protected]

OGJ Reprints

Nylacast

www.pumpworks610.com

Circor Energy Products

/ Austria / Northern Switzerland / Eastern Europe / Russia / Former Soviet Union

P5

www.nylacast.com/offshore

www.badgermeter.com

Canada

Stefy Picoitti Thompson, Tel: +33(0)4 94 70 82 63; Cell: +33(0)6 21 23 67 02, [email protected]. Daniel Bernard, 8 allee des Herons, 78400 Chatou, ; Tel: 33(0)1.3071.1119, Fax: 33(0)1.3071.1119; E-mail: [email protected]

9

www.arielcorp.com

Badger Meter

Moxa Americas, Inc. www.moxa.com

www.aramco.jobs/ogj

Carhartt

/ Belgium / Spain / Portugal / Southern Switzerland / Monaco

P6, P7

www.ametekpi.com

Jim Klingele, (713) 963-6214, [email protected] 1455 West Loop South, Suite 400, Houston, TX 77027 Stan Terry, (713) 963-6208, [email protected]

www.molgroup.info.com

www.airbushelicoptersinc.com

33

www.kobelcocompressors.com

Kobelco Compressors America, Inc.

61

www.kobelcocompressors.com

128

www.lagcoe.com

LEMO S.A.

21

www.lemo.com

Matrix Service Company

87

www.matrixservicecompany.com

PennWell 1455 West Loop South, Suite 400, Houston, TX 77027 www.ogj.com

Oil & Gas Journal | Sept. 7, 2015

This index is provided as a service. The publisher does not assume any liability for errors or omission.

139

THE EDITOR’S PERSPECTIVE

Obama touts green energy as the UK slashes subsidies by Bob Tippee, Editor US President Barack Obama received more news coverage in the US for his speech promoting renewable fuels than the UK government did for a new step away from green-energy ambition. The comparison offers two lessons: 1. that of the two countries the UK is closer to an inevitable reckoning with physical and economic reality, and 2. that trendy US media won’t acknowledge problems with state-sponsored energy. “For the first time, we can actually see what our clean-energy future looks like,” Obama said Aug. 25 at the National Clean Energy Summit in Las Vegas. In his view, it’s a future in which “consumers have freedom to choose cleaner, cheaper, more efficient energy.” Where politically preferred energy already has been tried, however, results aren’t quite so wonderful. With costs of subsidizing wind and solar energy in the UK exceeding projections and electricity prices punishing consumers, the Department of Energy and Climate Change on Aug. 27 proposed to slash subsidies for new roof-top solar systems and small windmills. The government earlier had announced plans to cut subsidies for onshore wind generation and large solar installations. The DECC said its latest proposal aims “to place policy costs on bills on a sustainable footing, improve bill-payer value for money, and limit the effects on consumers who ultimately pay for renewable energy subsidies.” Experience thus shows “what our cleanenergy future looks like.” It’s intolerably expensive. The ever-confident US president might argue that UK grief results from flaws of program design or implementation. But how can he say his program—based as it is not only on boosting renewable energy but also on displacing commercial energy now in place—would be superior in concept or execution? In fact, he cannot. State manipulation of energy markets always creates havoc in economies and istrative systems. It therefore always fails. Obama’s manipulation is extreme. Consequent problems will be extreme, too. Experience, most recently in the UK but also in US history, makes this clear. It should make the news. (From the subscription area of www.ogj.com, posted Aug. 28, 2015; author’s e-mail: bobt@ ogjonline.com)

140

WATCHING GOVERNMENT

Nick Snow Washington Editor

A North Dakota update When it comes to reporting what’s going on in US oil and gas producing states, even the dimmest Washington, DC, reporter periodically re to start by speaking with people who are actually there. Take North Dakota, for example. There are perceptions that Bakken crude increasingly leaves the state by rail because pipelines are inadequate, that plunging global oil prices in the last year have reduced the Bakken boom to a mild pop, and that gas associated with Bakken crude production continues to be flared. Telephone conversations with state and industry officials in North Dakota revealed that the situation there is anything but static. Progress is being made. “The impact of oil prices and the slowdown is providing a window of opportunity for infrastructure to catch up and get on the leading side of that curve instead of chasing it so hard,” North Dakota Department of Mineral Resources Director Lynn D. Helms said. “All of the large pipeline projects are 2017 and beyond,” he told OGJ. “We’re in a pretty good spot right now because we anticipate production staying pretty flat, between 1.1 million and 1.2 million b/d. Because of oil prices and the inventory of uncompleted wells, we expect that to go on for 1½-2 years. After that, we could go into a higher production mode with new pipeline capacity.” Rail’s share of total Williston basin crude transportation peaked at around 800,000 b/d toward

the end of 2014, and has been falling ever since, North Dakota Pipeline Authority Director Justin J. Kringstad said. Pipelines’ 46% share nearly equaled rail’s 47% in June, he indicted. Two projects with capacity totaling another 675,000 b/d are expected to be operating in 2017, he added. “We’ve seen the rig count drop to 74 rigs now from 190 in 2014,” he told OGJ. “Going forward, the question will be how long these lower prices will be going on and what impacts they will have on production.”

Infrastructure progress “Progress is being made on infrastructure,” North Dakota Petroleum Council Pres. Ron Ness reported. “The legislature put $1.2 billion in surge infrastructure funds in the first 30 days of its 2015 session to assist communities. That almost became a jobs bill when companies had to lay off employees because of low crude prices.” Reduced activity still concerns producers, “but we’re also seeing substantial improvements in efficiency that companies have implemented,” he told OGJ. Producers asked the state’s Industrial Commission for more time to meet Jan. 1, 2016, flaring reduction goals. Helms said the commission agreed to give them another 10 months if they committed to reaching higher goals then and subsequently by Sept. 17.

Oil & Gas Journal | Sept. 7, 2015

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