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WIRELINE AND PERFORATING

Cased Hole Associate Field Professional Course Manual Volume I

WPS-TD-20002 Revision A

All information contained in this publication is confidential and proprietary property of Halliburton Company. Any reproduction or use of these instructions, drawings, or photographs without the express written permission of an officer of Halliburton Company is forbidden. © Copyright 2008 Halliburton Company All Rights Reserved. Printed in the United States of America This document was created in of the Halliburton Wireline and Perforating Associate Field Professional development program delivered at the Halliburton Training Center. For more information : Halliburton Energy Services Training Center 1128 Everman Parkway Fort Worth, Texas 76140

Photo: Foreground: Dual Well Completion performed in Rock Springs, Wyoming (Courtesy Larry Klein) Background: Well completion performed in 1956 (Courtesy John Jennings)

Compiled and written by Ameet Agnihotri, Joshua Demond and Shawn McCafferty *Multiple sources were used to create this document. See bibliography for full accredidation.*

Revision Record Cased-Hole Associate Field Professional Course Manual Vol. I WPS Training Date: August 2008 Description Cased-Hole Associate Field Professional Course Manual Volume I

Table of Contents Table of Contents..........................................................................................................................1

Chapter 4 Basic Petroleum Geology and Open Hole Log Analysis ........................13 Preface........................................................................................................................................15

Basic Petroleum Geology ...........................................................................................18 Introduction .................................................................................................................................18 Objectives ...................................................................................................................................19 Earth—An Evolving Planet..........................................................................................................20 Geology Basics ........................................................................................................................................ 21 Three Basic Rock Types.......................................................................................................................... 23 Petroleum-Bearing Rocks .................................................................................................................. 23 The Rock Cycle........................................................................................................................................ 24 Geologic Time.......................................................................................................................................... 25 Age Dating.......................................................................................................................................... 25 Basic Age-Dating Principles ............................................................................................................... 26 Geologic Time Scale................................................................................................................................ 28 Distribution of Oil and Gas Fields Based on Geologic Age ..................................................................... 29 Basic Classification and Types of Sedimentary Rocks............................................................................ 30 Clastic Sedimentary Rocks ................................................................................................................ 30 Chemical or Biochemical Sedimentary Rocks ................................................................................... 30 Sandstones......................................................................................................................................... 30 Carbonates ......................................................................................................................................... 30 Shales................................................................................................................................................. 31 Evaporites........................................................................................................................................... 31 Source Rock and Hydrocarbon Generation............................................................................................. 31 Migration of Hydrocarbons ................................................................................................................. 32 Basic Hydrocarbon Chemistry............................................................................................................ 32 Five Major Types of Hydrocarbons of Interest to Petroleum Exploration ................................................ 33 Kerogen/Bitumens .............................................................................................................................. 33 Crude Oil ............................................................................................................................................ 34 Asphalt................................................................................................................................................ 34 Natural Gas ........................................................................................................................................ 34 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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Condensates ...................................................................................................................................... 35 Temperature Gradient ........................................................................................................................ 35 Pressure Gradient .............................................................................................................................. 37

Reservoir Geology ......................................................................................................................39 Abundance and Production of Sedimentary Formations ......................................................................... 40 Physical Characteristics of a Reservoir ................................................................................................... 41 Depth .................................................................................................................................................. 41 Area and Thickness............................................................................................................................ 41 Porosity .................................................................................................................................................... 43 Controls on Porosity ........................................................................................................................... 46 Permeability ............................................................................................................................................. 49 Examples of Variations in Permeability and Porosity ......................................................................... 50 Fluid Distribution within a Reservoir ........................................................................................................ 51 The “Fluids First” Revolution .............................................................................................................. 51 Reservoir Fluid Mechanics ...................................................................................................................... 53 Capillary Pressure.................................................................................................................................... 55 Irreducible Water Saturation .................................................................................................................... 56 Basic Geological Conditions that Create Petroleum Traps ..................................................................... 57 Hydrocarbon Traps............................................................................................................................. 57 Structural Traps .................................................................................................................................. 57 Anticlinal and Dome Traps ................................................................................................................. 58 Salt Dome or Salt Plug Traps ............................................................................................................. 59 Fault Trap ........................................................................................................................................... 60 Stratigraphic Traps ............................................................................................................................. 62 Lenticular Traps.................................................................................................................................. 62 Pinch-out or Lateral Graded Traps..................................................................................................... 63 Angular Unconformtiy Traps............................................................................................................... 63 Exploration and Mapping Techniques ..................................................................................................... 64 Subsurface Mapping........................................................................................................................... 64 Geophysical Surveys.......................................................................................................................... 65 Structural Contour Maps..................................................................................................................... 67 Cross-Sections ................................................................................................................................... 68 Isopach Maps ..................................................................................................................................... 69 Lithofacies Maps ...................................................................................................................................... 70 Surface Geology ...................................................................................................................................... 73 Subsurface Geology and Formation Evaluation ...................................................................................... 74

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Halliburton Energy Services Well Cuttings............................................................................................................................................ 75 Cores ....................................................................................................................................................... 76 Logging While Drilling .............................................................................................................................. 77 Formation Testing .................................................................................................................................... 77 Wireline Well-Logging Techniques .......................................................................................................... 77 Borehole Environment ............................................................................................................................. 79 The Basis of Log Analysis ....................................................................................................................... 81 Log Data ............................................................................................................................................. 82 Porosity............................................................................................................................................... 82 Resistivity ........................................................................................................................................... 82 Water Saturation ...................................................................................................................................... 83 Important Terminology and Symbols.................................................................................................. 84 A Note on Water Saturation ............................................................................................................... 87 Review of Permeability ............................................................................................................................ 87 Reserve Estimation.................................................................................................................................. 89 How Much Hydrocarbon can be Recovered from the Reservoir?...................................................... 89

Glossary ......................................................................................................................................92 References..................................................................................................................................94

Open-Hole terpretation for Cased-Hole Field Professionals.........................95 Logging and the Reservoir ..........................................................................................................95 Fundamental Formation Properties ......................................................................................................... 96 Lithology ............................................................................................................................................. 97 Porosity............................................................................................................................................... 97 Fluid Saturations................................................................................................................................. 98 Permeability........................................................................................................................................ 99 The Logging Environment...................................................................................................................... 100 Depth of Investigation Limitations .................................................................................................... 101 The Role of Inference and Assumption ................................................................................................. 103

Understanding Resistivity Logs .................................................................................................104 Formation Water Resistivity................................................................................................................... 104 Porosity .................................................................................................................................................. 105 Pore Tortuosity....................................................................................................................................... 106

Fluid Saturations .......................................................................................................................109 Putting It All Together................................................................................................................112 R T Versus R XO ....................................................................................................................................... 113 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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Archie Water Saturation......................................................................................................................... 114 Limitations of the Archie Approach................................................................................................... 115 Water-Wet Formation ....................................................................................................................... 115 Determining Tortuosity Factor and Cementation Exponent................................................................... 116 Determining Formation Water Resistivity (R W ) ...................................................................................... 118 The Danger in Calculating Water Saturation ......................................................................................... 119

Understanding Porosity Logs....................................................................................................120 Two Porosities are Better than One....................................................................................................... 121 Two Porosities? ................................................................................................................................ 121 Photoelectric Factor (P e ) ....................................................................................................................... 122 Starting Out Simple................................................................................................................................ 122 Lithology Indicators ................................................................................................................................ 125 Gamma Ray Indicators..................................................................................................................... 125 Resistivity Indicators......................................................................................................................... 125 Neutron-Density Indicators ............................................................................................................... 126 Other dicators ......................................................................................................................... 126 After Lithology, What Next? ................................................................................................................... 127 Porosity Estimates from Logs ................................................................................................................ 127 Total Porosity versus Effective Porosity ........................................................................................... 128 Density Porosity (Φ D ) Estimates ...................................................................................................... 129 Neutron Porosity (Φ N ) Estimates ..................................................................................................... 130 Combined Neutron-Density Porosity Estimates ............................................................................... 131 Acoustic Porosity (Φ S ) Estimates ..................................................................................................... 135 Summarizing Porosity Logs ................................................................................................................... 137

Appendix A................................................................................................................................139 Chemical Properties of Hydrocarbons ......................................................................................139 The Paraffin Series........................................................................................................................... 139 The Naphthene (Cycloparaffin) Series ............................................................................................. 140 The Aromatic (Benzene) Series ....................................................................................................... 140 NSO Compounds ............................................................................................................................. 140

Chapter 2 Cased Hole Basics................................................................................... 143 Preface......................................................................................................................................145

Introduction to Cased-Hole Services....................................................................... 147 The Legend of Halliburton.........................................................................................................147

Cased Hole Services ................................................................................................. 153 Cement Evaluation/Pipe Inspection....................................................................................................... 153 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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Halliburton Energy Services Cement Evaluation ........................................................................................................................... 153 Pipe Inspection ................................................................................................................................. 154 Cased-Hole Formation Evaluation......................................................................................................... 155 Chemical Source Tools .................................................................................................................... 155 Pulsed-Neutron Tools....................................................................................................................... 156 Natural Gamma-Ray Tools............................................................................................................... 157 Mechanical Services .............................................................................................................................. 157 Plugs................................................................................................................................................. 157 Packers............................................................................................................................................. 158 Setting Tools..................................................................................................................................... 158 Perforating ............................................................................................................................................. 159 Stim Gun/Sleeve............................................................................................................................... 160 Pipe Recovery........................................................................................................................................ 160 Production Logging ................................................................................................................................ 161

Cased-Hole Cables ....................................................................................................163 Cable Properties .......................................................................................................................163 Mechanical Strength .............................................................................................................................. 164 Electrical Continuity ............................................................................................................................... 165 Temperature Rating ............................................................................................................................... 166 Anti-Corrosion Properties ...................................................................................................................... 167 No ts (Seamless)............................................................................................................................. 167

Cable Care and Operational Considerations ............................................................................169 Installation.............................................................................................................................................. 169 Tension During Installation............................................................................................................... 169 Logging Operations Concerns.......................................................................................................... 170 Basic Cable Care ................................................................................................................................... 170 Seasoning New Cable ...................................................................................................................... 174 Identifying Cable Damage ..................................................................................................................... 177 Compression Gap............................................................................................................................. 177 Cable Kinks ...................................................................................................................................... 177 Corrosion and Wear Indicators......................................................................................................... 178 Location of an Electrical Leak .......................................................................................................... 179

Cased-Hole Depth and Tension................................................................................183 Depth Systems..........................................................................................................................183 Stand-Alone Depth Display (SDDP-A/B)..................................................................................... 184 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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Benchmark (Wayne-Kerr) Measurement System.................................................................................. 185 AM5K Measuring System ................................................................................................................. 185 AM3K Measuring System ................................................................................................................. 186 AMS4A044 Hoistman’s Touch-Screen ................................................................................... 187 AMS4A040/AMS4A041 Winch Operators .............................................................................. 187 Signal Processing .................................................................................................................................. 188

Depth Control Basics ................................................................................................................190 Measurement Principle .......................................................................................................................... 191 Cable Properties .................................................................................................................................... 192 Measuring Head with Built-in Load Cell................................................................................................. 193 External Cable-Tension Measuring System .......................................................................................... 194 Load Cell Calibration.............................................................................................................................. 194 Transportation, Handling, and Storage.................................................................................................. 198

Depth-Measurement Encoders .................................................................................................199 Optical Encoder ..................................................................................................................................... 199 Back-up Encoders.................................................................................................................................. 200 Measuring Wheels ................................................................................................................................. 200 Straight-Line Depth Measurement System............................................................................................ 201 Example............................................................................................................................................ 203

Cased-Hole Depth Control Procedures ....................................................................................203 First Run Procedures ............................................................................................................................. 204 Zeroing the Logging Tool String ............................................................................................................ 204 Example............................................................................................................................................ 204 Rig-Up Length at Surface (RULS) ......................................................................................................... 205 Example............................................................................................................................................ 205 Rig-Up Line at Bottom of Well (RULB) .................................................................................................. 205 Example............................................................................................................................................ 206 Logging-Up Procedures ......................................................................................................................... 206 Final Check....................................................................................................................................... 206 Subsequent Runs/Trips ......................................................................................................................... 206 Total Depth Logger/Bottom terval................................................................................................ 208 Total Depth (TD)............................................................................................................................... 208 Plug-Back Total Depth (PBTD) ........................................................................................................ 208 Total-Depth Logger........................................................................................................................... 208 Bottom-terval .......................................................................................................................... 209

Calculation Examples ...............................................................................................................210 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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Halliburton Energy Services Example #1 ............................................................................................................................................ 210 Example #2 ............................................................................................................................................ 210 Example #3 ............................................................................................................................................ 211 Example #4 ............................................................................................................................................ 211 Example #5 ............................................................................................................................................ 211 Example #6 ............................................................................................................................................ 211 Example #7 ............................................................................................................................................ 212 Wheel Diameter Error ............................................................................................................................ 212

Cased-Hole Weak Points ..........................................................................................213 Construction ..............................................................................................................................213 Step 1: Preparing the Cable .................................................................................................................. 213 Step 2: Securing the Cable.................................................................................................................... 214 Step 3: Wrapping the Cable................................................................................................................... 215 Step 4: Installing the Brass Core ........................................................................................................... 217 Step 5: Building the Weak Point Assembly ........................................................................................... 218 Step 6: Removing the Inner Armor ........................................................................................................ 225 Step 7: Sliding the Stinger over the Cone ............................................................................................. 226 Step 8: Installing the Cone Retainer ...................................................................................................... 227 Step 9: Installing the Cable Head Sleeve .............................................................................................. 228 Step 10: Cutting the Insulated Conductor Wire ..................................................................................... 229 Step 11: Threading the Boot.................................................................................................................. 230 Step 12: Connecting the Conductor Wire .............................................................................................. 231 Step 13: Final Assembly of the Cable Head.......................................................................................... 232 Step 14: Greasing the Cable Head........................................................................................................ 234 Summary................................................................................................................................................ 235

Weak Point Calculations ...........................................................................................................236 Determining Maximum Weak-Point Value............................................................................................. 236 Weak-Point Construction Calculations .................................................................................................. 238 Determining Weak-Point Strength ......................................................................................................... 239 Maximum Safe Pull and Maximum Pull ................................................................................................. 239

Chapter 3 LOGIQ-CH, Telemetry, Filters, Delays ....................................................243 Preface......................................................................................................................................246

Telemetry ...................................................................................................................247 Basic Telemetry ........................................................................................................................247 Measuring Output .................................................................................................................................. 247 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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Recording Output................................................................................................................................... 247 Analysis of Recorded Data (DAS Software) .......................................................................................... 248

Wireline Telemetry Forms.........................................................................................................250 Analog Telemetry................................................................................................................................... 250 Bi-Polar Pulses ...................................................................................................................................... 251 Multiple Sensors/Acoustic Tools............................................................................................................ 253 Digital Telemetry .................................................................................................................................... 255 Basic Digital Telemetry .......................................................................................................................... 256 How Binary Works ............................................................................................................................ 256 Hybrid Telemetry.................................................................................................................................... 260

Filters ......................................................................................................................... 263 Electronic Filters .......................................................................................................................263 Software Filters .........................................................................................................................265 Section 3 ...................................................................................................................................271

LOGIQ-CH .................................................................................................................. 271 Cased-Hole Interface (CHIP)..........................................................................................272 Front ............................................................................................................................................ 273 Back ............................................................................................................................................. 274 Internal Components.............................................................................................................................. 275 Tool Power Supply ........................................................................................................................... 275 USB 44 ............................................................................................................................................. 276 SDSDSP (Digital Signals Processor) ............................................................................................... 276 DSP Aux ........................................................................................................................................... 276 CBL1D .............................................................................................................................................. 277 CBL02............................................................................................................................................... 277 Analog-Switch Interface Board (ANASW) ........................................................................................ 277 Applied Free-Point Card ................................................................................................................... 277 Pre-Relays Board (Prelays).............................................................................................................. 277 CCL Board ........................................................................................................................................ 278 TELA R6 Board ................................................................................................................................ 278 Power Supply Auxiliary Board (PSXD)............................................................................................. 278 Audio Board...................................................................................................................................... 278 USBHUB Board ................................................................................................................................ 279 Ultra-Link Module Board (ULLM)...................................................................................................... 279 Telemetry Processing ............................................................................................................................ 279 CCL (Non-SDDP Equipped Systems) .............................................................................................. 282 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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Halliburton Energy Services Bi-Polar Telemetry (Gamma-Ray Neutron) ...................................................................................... 285 Cement Bond Log Telemetry ........................................................................................................... 286 MUXB2 (Uplink)................................................................................................................................ 287 MUXB2 (Downlink) ........................................................................................................................... 288 Ruggedized Rack-Mounted Portable Computer (RMPC)...................................................................... 289 Printrex 840 DL/G .................................................................................................................................. 289 Flat Monitor.................................................................................................................................. 290 Cable Shooting (CSP) ................................................................................................................. 290 Design and Features ........................................................................................................................ 290 Safe Mode ........................................................................................................................................ 293 Shoot Mode ...................................................................................................................................... 294 Log Mode.......................................................................................................................................... 297 CCL Mode ........................................................................................................................................ 298 Multi-Conductor Shooting ....................................................................................................... 299

Delays.........................................................................................................................301 Software Offsets (Delays) .........................................................................................................304


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Cased-Hole Associate Field Professional Course Manual Volume I Chapter 1 Basic Petroleum Geology and Open-Hole Logging Analysis Revision (A) (August 2008) Reference No. WPS-TD-20002


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Preface This WPS Training manual provides information on basic petroleum geology and openhole terpretation for the Cased-Hole Associate Field Professional. Study the manual to develop a through understanding of the tool before operating or servicing it for the first time. Observe all notes, cautions, and warnings to minimize the risk of personal injury or damage to the equipment. Section 1 Basic Petroleum Geology—This section provides an overview of geological concepts and processes essential to the petroleum industry. Section 2 Open-Hole Interpretation for Cased-Hole Field Professionals—This section focuses on techniques for interpreting various open-hole logs for the purpose of determining the presence of hydrocarbons and base-formation properties. Appendix A Chemical Properties of Hydrocarbons—Discussion of the four classifications of hydrocarbons.


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Section 1 Basic Petroleum Geology Introduction Geology is the science that deals with the history and structure of the earth and its life forms, especially as recorded in the rock record. A basic understanding of its concepts and processes is essential in the petroleum industry because it is used to predict where oil accumulations might occur. It is the job of the petroleum geologist to use his or her knowledge to reconstruct the geologic history of an area to determine whether the formations are likely to contain petroleum reservoirs. It is also the job of the geologist to determine whether the recovery and production of these hydrocarbons will be commercially profitable. Important concepts that are vital to the production and recovery efforts of any exploration or energy service include: the physical characteristics of a reservoir, how petroleum originated and in what type of rock, types of fluids present in the reservoir, how hydrocarbons become trapped, and basic well log.




Objectives After completing this section, you should be able to:                  

Define Geology and how it applies to the petroleum industry. Define and describe the three basic layers of Earth. Differentiate between weathering processes and erosional processes. Name the three rock types. List the components of the rock cycle. Explain the three basic principles of relative age dating. Define and explain a rock formation. Explain the origin of hydrocarbons. Define porosity. List the controls on porosity. Define permeability. Define a reservoir. List the two most common reservoir rock types and give some general characteristics of each type. Explain fluid distribution in a petroleum reservoir. List and describe the basic hydrocarbon traps. Name the different geological mapping techniques used in petroleum exploration. Explain the difference between surface and subsurface exploration. Explain the basic concepts of well log analysis.


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Earth—An Evolving Planet About 4.6 billion years ago, Earth began to evolve from a conglomeration of chunks of matter into a differentiated planet with continents, oceans, and an atmosphere. The primitive planet grew and began to heat up due to the collision of in-falling material striking other accreted material at high velocities. There were three general processes that contributed to the heating of the planet: collision, compression by the weight of the accreted material, and radioactive decay.

Fig. 1.1.1—Collision of Material onto Primative Earth.

Fig. 1.1.2—Compression of Material.

It is likely that accretion and compression raised the internal average of about 1,000°C. Radioactive elements also had a profound effect on the evolution of Earth. The decay of these elements contributed to a rise in interior temperature to approximately 2,000°C, the temperature at which iron will melt. This is important because the melting of iron, which makes up about one-third of the planet, initiated the process by which Earth became the planet we know today. Iron is denser than most other elements on Earth. When it melted, the iron sank and formed the planet’s core. The other molten materials were lighter and, therefore, separated and floated upward, creating a layered body. The very lightest materials floated to the top, cooled, and formed Earth’s crust. This differentiation also initiated the escape of lighter gases, which eventually led to the formation of the atmosphere and oceans.

Fig. 1.1.3—Disintegration of Radioactive Elements.




Geology Basics The earth is composed of three basic layers: the core, the mantle, and the crust. The crust is the layer that is of most importance in petroleum geology. Geologists distinguish between oceanic crust and continental crust. Oceanic crust lies under the oceans and is thin—about 5–7 mi (8–11 km)—and is made up primarily of heavy rock that is formed when molten rock (magma) cools. Continental crust is thick—about 10–30 mi (16–48 km)—and is composed of rock that is relatively light as compared to oceanic crust.

Fig. 1.1.4—Cross-Sectional View of the Earth Showing its Internal Structure.


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The crust is continuously changing and moving because of two major forces of nature— orogeny and weathering/erosion. Orogeny, or mountain building, is a process in which the layers of the crust are folded and pushed upward by such processes as plate tectonics and volcanism. Weathering and erosion are the opposing forces in which the sediments are broken down and transported. There are two types of weathering: •

Physical—occurs when solid rock is fragmented by physical processes that do not change the rock’s chemical composition. These processes include wind (aeolian forces), water (freezing, flowing, wave action, etc.), heat, and even glacial movement. Frost wedging is one example of physical weathering.

•

Chemical—occurs when minerals in a rock are chemically altered or dissolved. The weathering of potassium feldspar to form kaolinite, a clay, is an example of chemical weathering.

Fig. 1.1.5—Cross-Sectional View of Weathering and Erosion.

Weathering and erosion are closely interrelated geological processes. As a rock weathers, it becomes susceptible to erosion. Erosion is the removal of weathered debris. These and additional forces and processes have resulted in the creation of subsurface geological formations in which petroleum reservoirs are found.




Three Basic Rock Types The earth’s crust is composed of three basic rock types: igneous, sedimentary, and metamorphic. Igneous rocks are formed from the crystallization of molten rock (magma or lava) from within the earth’s mantle. Common igneous rocks include granite, basalt, and gabbro. Metamorphic rocks are formed from pre-existing rocks by mineralogical, chemical and/or structural changes in response to marked changes in temperature, pressure, shearing stress, and chemical environment. These changes generally take place deep within the earth’s crust. Examples of common metamorphic rocks include slate, marble, and schist. Sedimentary rocks are formed as sediments, either from eroded fragments of older rocks or chemical precipitates, lithify by both compaction, as the grains are squeezed together into a denser mass than the original, and by cementation, as minerals precipitate around the grains after deposition and bind the particles together. Sediments are compacted and cemented after burial under additional layers of sediment. Thus, sandstone is formed by the lithification of sand particles, and limestone is formed by the lithification of shells and other particles of calcium carbonate. These types of rocks are typically deposited in horizontal layers, or strata, at the bottom of rivers, oceans, and deltas. Limestone, sandstone, and clay are typical sedimentary rocks.

Petroleum-Bearing Rocks Sedimentary rocks are the most important and interesting type of rock to the petroleum industry because most oil and gas accumulations occur in them; igneous and metamorphic rocks rarely contain oil and gas. All petroleum source rocks are sedimentary. Furthermore, most of the world’s oil lies in sedimentary rock formed from marine sediments deposited on the edges of continents. For example, there are many large deposits that lie along the Gulf of Mexico and the Persian Gulf.


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The Rock Cycle Igneous, metamorphic, and sedimentary rocks are related by the rock cycle, the circular process by which each is formed from the others. Rocks are weathered to form sediment, which is then buried. During deeper and deeper burial, the rocks undergo metamorphism and/or melting. Later, they are deformed and uplifted into mountain chains, only to be weathered again and recycled.

Fig. 1.1.6—The Rock Cycle.




Geologic Time Geologic time and Earth’s geologic history are concepts that need to be clearly understood in addition to how they relate to the petroleum industry. It takes millions of years and specific conditions for organic and sedimentary materials to be converted to recoverable hydrocarbons. The late eighteenth century is generally regarded as the beginning of modern geology. During this time, James Hutton, a Scottish physician and gentleman farmer, published his Theory of the Earth with Proof and Illustrations (1785), which put forth the principle of uniformitarianism. This principle states that the geologic processes and forces now operating to modify the earth’s crust have acted in much the same manner and with essentially the same intensity throughout geologic time, and that past geologic events can be explained by forces observable today. This is known as the classic concept “the present is the key to the past.”

Age Dating Before radioactive materials were discovered, geologists used an understanding of fossils and some basic geologic principles to determine the relative ages of sedimentary rock layers; that is, how old they are in relation to one another. Relative dating does not tell us how long ago something took place, only that it followed one event and preceded another. Once radioactivity was discovered, geologists used the physics of radioactive decay to pinpoint a rock’s absolute age; that is, how many years ago it formed. Absolute dating did not replace relative dating. Instead, it simply supplemented the relative dating technique. The principle methods that have been used for direct radiochronology of sedimentary rocks are as follows: 1. The Carbon-14 technique for organic materials. 2. The Potassium-Argon and Rubidium-Strontium techniques for glauconites, hornblende, microclines, muscovites, biotites, etc. 3. The Thorium-230 technique for deep ocean sediments and aragonite corals. 4. The Protactinium-231 technique for ocean sediments and aragonite corals. 5. The Uranium-238 technique for apatite, volcanic glass, zircon, etc.


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Fig. 1.1.7—Layered Rock Sequence Illustrating Relative Age and Deposition of Strata in Horizontal Layers.

Basic Age-Dating Principles To establish a relative time scale, a few simple principle or rules had to be discovered and applied. Although they may seem rather obvious to us today, their discovery was a very important scientific achievement. Stratigraphy is the study of the origin, composition, distribution, and sequence of the layers of sedimentary rock, or strata. Stratification is the characteristic layering or bedding of sedimentary rocks. This characteristic is basic to two of the principles used to interpret geologic events from the sedimentary rock record. First, is the principle of original horizontality, which states that most layers of sediment are deposited in a nearly horizontal layer. If a sequence of sedimentary rock layers are folded or tilted, then it is generally understood that these layers were deformed by tectonic events after their initial deposition. Second, is the principle of superposition, which states that each layer of sedimentary rock in a sequence that has not been tectonically disturbed is younger than the layer beneath it and older than the layer above it. Therefore, a series of sedimentary layers can be viewed as a vertical time line. This produces either a partial or complete record of the time elapsed from the deposition of the lower-most bed to the deposition of the upper-most bed. This rule also applies to other surface-deposited materials, such as lava flows or beds of ash from volcanic events. If igneous intrusions or faults cut through strata, they are assumed to be younger than the structures they cut. This is known as the principle of cross-cutting relationships. Paleontology, the study of life in past geologic time based on fossil plants and animals, is an important consideration in the stratigraphic record and is significant in asg ages to rock units. In early geologic endeavors, index fossils (fossils with narrow, vertical stratigraphic ranges) represented the only means for realistic correlation and age assignment of rock sequences. As illustrated in Fig. 1.1.8, correlation is the process of relating rocks at one site with those at another site.




Fig. 1.1.8—Correlation of Strata.

In 1793, William Smith, a surveyor working in southern England, recognized that fossils could be used to date the relative ages of sedimentary rocks. He learned that he could map rock units from coal quarry to coal quarry over a large distance if he characterized the layers by their lithology and fossil content. While mapping the vertical rock sequences, he established a general order of fossils and strata from the oldest at the bottom to the youngest at the top. This stratigraphic ordering of fossils eventually became known as the principle of faunal succession and states that fossil faunas and floras in stratigraphic sequence succeed one another in a definite, recognizable order. Smith was also the first person to define formations within a rock unit. A formation is a rock unit that is mappable over a laterally extensive area and has the same physical properties and contains the same fossil assemblages. Some formations consist of one rock type, like limestone. Others may be interbedded (e.g., alternating layers of sandstone and shale that can be mapped as one unit). By combining faunal succession and stratigraphic sequences, geologists can correlate formations in a local area or around the world. The petroleum industry relies on the application of these principles for exploration and production.


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Geologic Time Scale During the nineteenth and twentieth centuries, geologists built on the knowledge of their predecessors and started to build a world-wide rock column. Although it will never be continuous from the beginning of time, the above principles have allowed geologists to compile a composite world-wide relative time scale.

Fig. 1.1.9—Geologic Time Scale.




Distribution of Oil and Gas Fields Based on Geologic Age It is important to know the geologic age of reservoir rocks because rocks of different ages frequently have different petroleum characteristics and productivity. It is also important to note that the age of the rock does not necessarily coincide with the time of oil accumulation. It is only known that it accumulated sometime after the formation’s deposition.

Table 1.1.1—Distribution of Discovered Oil and Gas Fields Based on Geologic Age. Geologic Age

% of Fields

Neogene

18

Palaeogene

21

Cretaceous

27

Jurassic

21

Permo-Triassic

6

Carboniferous

5

Devonian

1 1

Cambrian-Silurian Total 100


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Basic Classification and Types of Sedimentary Rocks The two main groups of sedimentary rocks are classified on the basis of their origin.

Clastic Sedimentary Rocks These rocks are formed as a result of the weathering or fragmentation of pre-existing rocks and minerals and classified on the basis of their textures, primarily the sizes of the grains. Sedimentary rocks are divided into three grain types: coarse-grained— conglomerates; medium-grained—sandstones; and fine-grained—siltstones, mudstones, and shales. Within each textural category, clastics are further subdivided by mineralogy, which reflects the parent rock (e.g., a quartz-rich sandstone or a feldspar-rich sandstone).

Chemical or Biochemical Sedimentary Rocks These rocks are formed as a result of chemical processes. Primary carbonate deposition results from the precipitation and deposits formed by plants and animals that utilize carbonates in their life processes. The most abundant mineral chemically or biochemically precipitated in the oceans is calcite, which mostly consists of the shelly remains of organisms and the main constituent of limestone. Many limestones also contain dolomite, a calcium-magnesium carbonate precipitated during lithification. Gypsum and halite are formed by chemical precipitation during the evaporation of seawater. There are five types of sedimentary rocks that are important in the production of hydrocarbons:

Sandstones Sandstones are clastic sedimentary rocks composed of mainly sand-size particles or grains set in a matrix of silt or clay and are more or less firmly united by a cementing material (commonly silica, iron oxide, or calcium carbonate). The sand particles usually consist of quartz, and the term “sandstone”, when used without qualification, indicates a rock containing about 85-90% quartz.

Carbonates (Broken into two categories: limestones and dolomites) Carbonates are sediments formed by a mineral compound characterized by a fundamental anionic structure of CO 3 -2. Calcite and aragonite CaCO 3 are examples of carbonates. Limestones are sedimentary rocks consisting chiefly of the mineral calcite (calcium carbonate, CaCO3), with or without magnesium carbonate. Limestones are the most important and widely distributed of the carbonate rocks. Dolomite is a common rock-forming mineral with the formula CaMg(CO 3 ) 2 . A sedimentary rock will be named a



Halliburton Energy Services dolomite if that rock is composed of more than 90% mineral dolomite and less than 10% mineral calcite.

Shales Shale is a type of detrital sedimentary rock formed by the consolidation of fine-grained material including clay, mud, and silt. Shales have a layered or stratified structure parallel to bedding. They are typically porous and contain hydrocarbons but generally exhibit no permeability. Therefore, shales typically do not form reservoirs, but they do make excellent cap rocks. If a shale is fractured, however, it would have the potential to become a reservoir.

Evaporites Evaporites do not form reservoirs like limestone and sandstone but are very important to petroleum exploration because they make excellent cap rocks and generate traps. The term “evaporite” is used for all deposits, such as salt deposits, that are composed of minerals that precipitated from saline solutions concentrated by evaporation. Upon evaporation, the general sequence of precipitation is: calcite, gypsum or anhydrite, halite, and finally bittern salts. Evaporites make excellent cap rocks because they are impermeable and, unlike lithified shales, they deform plastically, not by fracturing. The formation of salt structures can produce several different types of traps. One type is created by the folding and faulting associated with the lateral and upward movement of salt through overlying sediments. Salt overhangs create another type of trapping mechanism.

Source Rock and Hydrocarbon Generation Source rock refers to the formation from which oil and gas originate. Hydrocarbons are generated when large volumes of microscopic plant and animal material are deposited in marine, deltaic, or lacustrine (lake) environments. The organic material may either originate within these environments and/or may be carried into the environment by rivers, streams, or the sea. The microscopic plant and animal material is generally deposited with fine clastic (silt and/or clay) sediments. During burial, the sediments protect the organic material by creating an anoxic (oxygen-depleted) environment. This allows the organic material to accumulate rather than be destroyed by aerobic organisms, such as bacteria. Over time, the organic remains are altered and transformed into gas and oil by the high temperatures and increased pressure of deep burial. This process can take tens of thousands of years to occur. The amount of petroleum generated is a function of the thickness of the accumulated sediments and organic material, the burial of these materials, and time. Note:

Organically-rich, black-colored shales deposited in a quiet marine, oxygendepleted environment are considered to be the best source rocks.


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Migration of Hydrocarbons Primary migration is the process by which petroleum moves from source beds to reservoir rocks. Secondary migration is the concentration and accumulation of oil and gas in reservoir rock. Evidence that petroleum does migrate is suggested by the very common occurrence of active seeps where oil and gas come to the surface either directly from the source rock or from reservoir rocks. In either case, the petroleum had to migrate through rocks with sufficient permeability and porosity to allow the fluids to flow to the surface. Therefore, migration involves rock properties and fluid properties, including the petroleum, moving through the rocks. Some of the rock and fluid properties include porosity, permeability, capillary pressure, temperature and pressure gradients, and viscosity. These and other properties will be discussed in detail in the sections to follow.

Basic Hydrocarbon Chemistry Petroleum is a general term for all naturally-occurring hydrocarbons, whether gaseous, liquid, or solid. It is both simple and complex and is composed almost entirely of carbon and hydrogen. Impurities like, nitrogen, sulfur, and oxygen play a somewhat important role in the formation of hydrocarbon molecules. The numerous varieties of petroleum are due to the way carbon and hydrogen can combine to form different sized molecules, thus creating different molecular weights. Thick, black asphalt and yellow, light crude are examples of two varieties of petroleum with different molecular weights. A hydrocarbon molecule is a chain of one or more carbon atoms with hydrogen atoms chemically bonded to them. At room temperature and pressure, molecules with up to four carbon atoms occur as gases; molecules having five to fifteen carbon atoms are liquids; and the heavier molecules, with more than fifteen carbon atoms, occur as solids. Some petroleum contains hydrocarbon molecules with up to sixty or seventy carbon atoms. The molecular structure of hydrocarbons can vary from simple, straight chains to more complex, branched chains or closed-ring structures. Temperature affects the chemical structure of hydrocarbons and can break heavier longchain molecules into smaller and lighter molecules. For a more detailed explanation of the chemical properties of hydrocarbons, refer to Appendix A.




Five Major Types of Hydrocarbons of Interest to Petroleum Exploration Kerogen/Bitumens Shale rock volume is composed of 99% clay minerals and 1% organic material. We have seen that petroleum is derived mainly from lipid-rich, organic material buried in sediments. Most of this organic matter is in a form known as kerogen. Kerogen is the part of the organic matter in a rock that is insoluble when introduced to common organic solvents. It owes its insolubility to its large molecular size and requires heat to break it down. Maturation of kerogen is a function of increased burial and temperature and is accompanied by chemical changes. As kerogen thermally matures and increases in carbon content, it changes form from an immature light greenish-yellow color to an overmature black, which is representative of a progressively higher coal rank. Different types of kerogen can be identified, each with different concentrations of the five primary elements (carbon, hydrogen, oxygen, nitrogen, and sulfur) and each with a different potential for generating petroleum. The organic content of a rock that is extractable with organic solvents is known as bitumen. It normally forms a small proportion of the total organic carbon in a rock. Bitumen forms largely as a result of the breaking of chemical bonds in kerogen as temperature rises. Petroleum is the organic substance recovered from wells and found in natural seeps. Bitumen becomes petroleum at some point during migration. Important chemical differences often exist between source-rock extracts (bitumen) and crude oils (petroleum). Kerogen is of no commercial significance except where it is so abundant (greater than 10%) as to occur in oil shales. It is, however, of great geological importance because it is the substance that generates hydrocarbon oil and gas. A source rock must contain significant amounts of kerogen.

Fig. 1.1.10—Shale Rock Composition.


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Crude Oil Crude oil is a mixture of many hydrocarbons that are liquid at surface temperatures and pressures and are soluble in normal petroleum solvents. Crude oil can vary in consistency and color due its chemical makeup and the type and amount of impurities it may contain (e.g., sulfur, nitrogen, etc.). Crude oil may be classified chemically (e.g., paraffinic, naphthenic) or by its density. This is expressed as specific gravity or as API (American Petroleum Institute) gravity, according to the formula:

API  

141.5 - 131.5 s. g. @ 60 o F

(Eq. 1.1.1)

Specific gravity (s.g.) is the ratio of the density of a substance to the density of water. API gravity is a standard adopted by the American Petroleum Institute for expressing the specific weight of oils. The lower the specific gravity, the higher the API gravity. For example, a fluid with a specific gravity of 1.0 g cm–3 has an API value of 10°. Heavy oils are those with API gravities of less than 20° (s.g. > 0.93). These oils have frequently suffered chemical alteration as a result of microbial attack (biodegradation) and other effects. Not only are heavy oils less valuable commercially, but they are considerably more difficult to extract. API gravities of 20 to 40° (s.g. 0.83 to 0.93) indicate normal oils. Oils of API gravity greater than 40° (s.g. < 0.83) are light.

Asphalt Asphalt is a dark colored solid to semi-solid form of petroleum (at surface temperatures and pressures) that consists of heavy hydrocarbons and bitumens. It can occur naturally or as a residue in the refining of some petroleums. It generally contains appreciable amounts of sulphur, oxygen, and nitrogen and, unlike kerogen, asphalt is soluble in normal petroleum solvents. It is produced by the partial maturation of kerogen or by the degradation of mature crude oil. Asphalt is particularly suitable for making high-quality gasoline as well as roofing and paving materials.

Natural Gas There are two basic types of natural gas: biogenic gas and thermogenic gas. The difference between the two is contingent upon conditions of origin. Biogenic gas is a natural gas formed solely as a result of bacterial activity in the early stages of diagenesis, meaning it forms at low temperatures, at overburden depths of less than 3,000 ft, and under anaerobic conditions often associated with high rates of marinesediment accumulation. Because of these factors, biogenic gas occurs in a variety of environments, including contemporary deltas of the Nile, Mississippi, and Amazon rivers. Currently, it is estimated that approximately 20% of the world’s known natural gas is biogenic. Thermogenic gas is a natural gas resulting from the thermal alteration of kerogen due to an increase in overburden pressure and temperature. 34 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services The major hydocarbon gases are: methane (CH 4 ), ethane (C 2 H 6 ), propane (C 3 H 8 ), and butane (C 4 H 10 ). The sweet and sour gases are used in the field to designate gases that are low or high, respectively, in hydrogen sulfide. Natural gas, as it comes from the well, is also classified as dry gas or wet gas, according to the amount of natural-gas liquid vapors it contains. A dry gas contains less than 0.1 gal of natural-gas liquid vapors per 1,000 ft3, and a wet gas contains 0.3 gal or more of liquid vapors per 1,000 ft3.

Fig. 1.1.11—Thermal Maturity Indicators.

Condensates Condensates are hydrocarbons in transition between gas and crude oil (gaseous in the subsurface but condensing to liquid at surface temperatures and pressures). Chemically, condensates consist largely of paraffins, such as pentane, octane, and hexane.

Temperature Gradient Temperature is generally a function of depth because of the earth’s natural geothermal gradient. Normal heat flow within the earth’s crust produces a gradient of approximately 1.5°F for each 100 ft of depth below the surface. The temperatures required to produce crude oil occur between 5,000 and 20,000 ft of depth. Temperatures below 20,000 ft are generally too high and only generate gas. Temperatures above 5,000 ft are not usually sufficient to transform the material into crude oil. There are, of course, exceptions to the rules. Geologic conditions, such as volcanism and tectonics (folding and faulting), can change or effect the temperature gradient.


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Graph 1.1.1—Temperature vs. Depth.




Pressure Gradient Most pressures that effect rocks are due to the weight of overlying rocks and are called overburden pressures. Overburden pressure is a function of depth and increases one pound per square inch (psi) for each ft of depth. At 3,000 ft, for example, the overburden pressure would be 3,000 psi. Hydrocarbons evolve from an immature stage to oil generation, oil cracking (wet gas stage), and finally to dry gas generation because of overburden pressure and the associated increase in temperature.

Fig. 1.1.12—Hydrocarbon Formation as a Function of the Burial of the Source Rock.


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Reservoir Geology A reservoir is a subsurface volume of porous and permeable rock that has both storage capacity and the ability to allow fluids to flow through it. Hydrocarbons migrate upward through porous and permeable rock formations until they either reach the surface as seepage or become trapped below the surface by a non-permeable cap rock, which allows them to accumulate in place in the reservoir. Porosity and permeability are influenced by the depositional pore geometries of the reservoir sediments and the postdepositional diagenetic changes that take place. Sandstone reservoirs are generally created by the accumulation of large amounts of clastic sediments, which is characteristic of depositional environments, such as river channels, deltas, beaches, lakes, and submarine fans. Sandstone reservoirs have a depositional porosity and permeability controlled by grain size, sorting, and packing of the particular sediments. Diagenetic changes may include precipitation of clay minerals in the pore space, occlusion of pores by mineral cements, or even creation of additional pores by dissolution of some sediments. Carbonate reservoirs are created in marine, sedimentary environments with little or no clastic material input and generally in a location between 30° north and south of the equator. Porosity types found in carbonate reservoirs can be characterized as vuggy (pores larger than grains), intergranular (between grains), intragranular/cellular (within grains), or chalky. Diagenetic changes, such as dolomitization, fracturing, dissolution, and recrystalization (rare) are extremely important because they have the ability to create very effective secondary porosity. Cementation, another type of diagenesis, generally reduces porosity and permeability.

Fig. 1.1.13—Cross-Section of Sandstone.


Fig. 1.1.14—Cross-Section of Carbonate.

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Abundance and Production of Sedimentary Formations The approximate abundance and production for the three types of sedimentary formations significant to petroleum production are as follows: Abundance Of Sedimentary Formations

Sandstone Carbonate Shale

Graph 1.1.2—Abundance of Sedimentary Formations.

Production from Sedimentary Reservoirs

60% 50%

Sandstone

40%

Carbonate

30%

Other

20% 10% 0%

Graph 1.1.3—Production from Sedimentary Reservoirs.

Note:

Carbonate reservoirs produce almost twice the amount of hydrocarbons than sandstone reservoirs. This occurs because of substantial production from carbonate reservoirs in the Middle East and Mexico.




Physical Characteristics of a Reservoir Physical characteristics of a reservoir include: the original deposition and subsequent changes, the type of reservoir (sandstone or carbonate), depth, area, thickness, porosity, permeability, and capillary pressure.

Depth The physical characteristics of a reservoir are greatly affected by the depth at which they occur. Shallow reservoir—Created by the folding of relatively thick, moderately compacted reservoir rock with accumulation under an anticline or some trap. The hydrocarbons would generally be better separated as a result of lower internal reservoir pressures, less gas in solution, and oil of increased viscosity, resulting from lower temperatures. Deep reservoir—Typically created by severe faulting. The hydrocarbons would be less separated with more gas in solution and oil of reduced viscosity because of higher temperatures. There is often a reduction in porosity and permeability due to the increased compaction.

Area and Thickness The total area of a reservoir and its thickness are of considerable importance in determining if a reservoir is commercial or not. The greater the area and thickness of the reservoir, the greater the potential for large accumulations of oil and gas. However, there are reservoirs that produce substantial amounts of hydrocarbons that are not of considerable size.


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Fig. 1.1.15—Area and Thickness of a Reservoir.




Porosity Porosity is the ratio of void space in a rock to the total volume of rock and reflects the fluid storage capacity of the reservoir.

Porosity ( ) 

volume of void space total volume of rock

(Eq. 1.1.2)

Fig. 1.1.16—Porous Sandstone.

Porosity is expressed as a percentage on a log. When used in calculations, however, it is important that porosity be expressed in decimal form. Primary Porosity—Amount of pore space present in the sediment at the time of deposition or formed during sedimentation. It is usually a function of the amount of space between rock-forming grains. Secondary Porosity—Post-depositional porosity. Such groundwater dissolution, recrystallization, and fracturing.

porosity

results

from

Effective Porosity vs. Total Porosity—Effective porosity is the interconnected pore volume available to free fluids. Total porosity is all void space in a rock and matrix whether effective or non-effective.


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Fig. 1.1.17—Effective vs. Non-Effective Porosity.

Fracture Porosity—Results from the presence of openings produced by the breaking or shattering of a rock. All rock types are affected by fracturing, and a rock’s composition will determine how brittle the rock is and how much fracturing will occur. The two basic types of fractures include natural, tectonically-related fractures and hydraulically-induced fractures. Hydraulic fracturing is a method of stimulating production by inducing fractures and fissures in the formation through the injection of fluids into the reservoir rock at pressures that exceed the strength of the rock. Hydraulic fracturing can tremendously increase the effective porosity and permeability of a formation.

Fig. 1.1.18—Fractures in Rock Material.



Halliburton Energy Services Vuggy porosity—A form of secondary porosity resulting from the dissolution of the more soluble portions of rock or the solution enlargement of pores or fractures.

Fig. 1.1.19—Vuggy Porosity in Carbonates.

Maximum Porosity vs. Realistic Porosity—Porosity can approach, in a very wellsorted, uncompacted sand, a theoretical maximum of 47.6%. In sandstone, this value is typically much lower due to cementation and compaction. In a carbonate, it is possible to greatly exceed the theoretical maximum porosity. This may be achieved if the carbonate is highly fractured along with vuggy porosity.


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Controls on Porosity In sandstone, porosity is largely controlled by sorting. Sorting is a process by which the agents of transportation, especially running water, naturally separate sedimentary particles that have some particular characteristic (such as size, shape, or specific gravity) from associated, but dissimilar, particles. Other important controlling factors include grain packing, compaction, and cementation. Well-Sorted Rock—Grains are generally of the same size and shape. If the grains are well rounded and of similar size, then they will not fit well together, thereby leaving a large amount of pore space between the grains. Porosity in a well-sorted rock is generally high.

Fig. 1.1.20—Example of Very Well-Sorted Grains.

Poorly-Sorted Rock—Rock that is composed of a wide variety of grain sizes and shapes. Porosity can be reduced considerably because smaller or irregularly shaped grains can be inserted in between the larger grains, thereby reducing the amount of pore space.

Fig. 1.1.21—Example of Poorly-Sorted Grains.



Halliburton Energy Services Grain Packing—Refers to the spacing or density patterns of grains in a sedimentary rock and is mainly a function of grain size, grain shape, and the degree of compaction of the sediment.

Fig. 1.1.22—Grain Packing and its Effect on Porosity.

Packing strongly affects the bulk density of the rocks as well as their porosity and permeability. The effects of packing on porosity can be illustrated by considering the change in porosity that takes place when even-size spheres are rearranged from open packing (cubic packing) to tightest or closed packing (rhombohedral packing). Cubic packing can yield a porosity of 47.6%. Rhombohedral packing yields approximately 26.0%. Compaction—Over a long period of time, sediments can accumulate and create formations that are thousands of feet thick. The weight of the overlying sediments squeezes the particles together into the tightest arrangement possible. The load pressure also squeezes out the water that occupies the pore spaces between the particles, thus reducing the bulk volume of the formation. Compaction is dependent not only on overburden pressure but also on the different types of clastic materials present in the formation. Compaction affects porosity and permeability by reducing the amount of interconnected pore space.


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Fig. 1.1.23—Sedimentation Process: Layer A is Compacted by Layer B.

Cementation—The crystallization or precipitation of soluble minerals in the pore spaces between clastic particles. The process of lithification (the conversion of unconsolidated deposits into solid rock) is completed by cementation. Common cementing agents include calcite (CaCO 3 ), silica (SiO 2 ), and iron oxide (Fe 2 O 3 ). Minerals in solution crystallize out of solution to coat grains and may eventually fill the pore spaces completely. Porosity and permeability can be reduced significantly through cementation.

Fig. 1.1.24—Effect of Cementation on Porosity.




Permeability Recovery of hydrocarbons from the reservoir is an important process in petroleum engineering, and estimating permeability can aid in determining the amount of hydrocarbons that can be produced from a reservoir. Permeability is a measure of the ease with which a formation permits a fluid to flow through it. To be permeable, a formation must have interconnected porosity (intergranular or intercrystalline porosity, interconnected vugs, or fractures). To determine the permeability of a formation, several factors must be known: the size and shape of the formation, its fluid properties, the pressure exerted on the fluids, and the amount of fluid flow. The more pressure exerted on a fluid, the higher the flow rate. The more viscous the fluid, the more difficult it is to push through the rock. Viscosity refers to a fluid’s internal resistance to flow, or its internal friction. For example, it is much more difficult to push honey through a rock than it is to push air through it. Permeability is measured in darcies. Few rocks have a permeability of 1 darcy; therefore, permeability is usually expressed in millidarcies (md), or 1/1,000 of a darcy. Permeability is usually measured parallel to the bedding planes of the reservoir rock and is commonly referred to as horizontal permeability, which, generally, is the main path of the flowing fluids into the borehole. Vertical permeability is measured across the bedding planes and is usually less than horizontal permeability. The reason that horizontal permeability is typically higher than vertical permeability lies largely in the arrangement and packing of the rock grains during deposition and subsequent compaction. For example, flat grains may align and overlap parallel to the depositional surface, thereby increasing the horizontal permeability (see Fig. 1.1.25). High vertical permeabilities are generally the result of fractures and of solution along the fractures that cut across the bedding planes. They are commonly found in carbonate rocks or other rock types with a brittle fabric as well as in clastic rocks with a high content of soluble material. As seen in Fig. 1.1.25, high vertical permeability may also be characteristic of uncemented or loosely-packed sandstones.


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Examples of Variations in Permeability and Porosity 





Some fine-grained sandstones can have large amounts of interconnected porosity; however, the individual pores may be relatively small. As a result, the pore throats connecting individual pores may be fairly restricted and tortuous; therefore, the permeabilities of such fine-grained formations may be quite low. Shales and clays—which contain very fine-grained particles—often exhibit very high porosities. However, because the pores and pore throats within these formations are so small, most shales and clays exhibit virtually no permeability. Some limestones may contain very little porosity, or isolated vuggy porosity that is not interconnected. These types of formations will exhibit very little permeability. However, if the formation is naturally fractured (or even hydraulically fractured), permeability will be higher because the isolated pores are interconnected by the fractures.

Fig. 1.1.25—Permeability and Grain Size and Shape.  

Porosity is NOT dependent on grain size. Permeability IS dependent on grain size.




Fluid Distribution within a Reservoir Petroleum reservoirs generally contain a combination of three fluids: 1. Natural Gas 2. Oil 3. Water As hydrocarbons and water accumulate in a reservoir, vertical separation occurs as a result of the difference in the specific gravity of the various fluids. Typically, the lighter fluids, like gas, rise to the top of the reservoir. Below the lighter fluids is a gas-to-oil transition zone. This transition zone is a relatively thin zone above the oil accumulation. The oil Fig. 1.1.1—Reservoir Fluid Distribution. accumulation may be of primary importance because it contains crude oil and possibly saturated gas. Below the oil accumulation in most reservoirs is an oil-water transition zone of varying thickness, which is partly filled with water and oil. Finally, beneath the oil-water transition zone lies the part of the formation that is completely saturated with water. It is important to note that all reservoirs may not contain natural gas, oil, and water. Some formations may only contain water. However, any formation that contains hydrocarbons will also contain some amount of water. It is because of this water that we are able to measure the resistivity of a formation in logging.

The “Fluids First” Revolution Since the 1960’s, most developments in the logging industry have centered around the improvement of existing tools and new evaluation techniques. With the advent of Magnetic Resonance Imaging Logging (MRIL), the industry has been presented with an exciting method for evaluating hydrocarbon reservoirs. MRI logging had its beginnings in the late 1950’s and soon after was offered as a commercial service. With continued improvements in technology and analysis methods, MRIL is quickly becoming a highdemand service. In 1997, Halliburton Energy Services acquired Numar Corporation, positioning itself as the industry leader in MRI logging. With time-honored logging tools, such as the induction, resistivity, and neutron-density, there have always been limitations due to the effects of the formation upon log response. These measurements depend upon petro-physical characteristics of the formation, 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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whereas the main purpose of the logging industry is to investigate the fluids that these formations contain. MRIL circumvents some of these problems by investigating “fluids first.” The measurement made by MRIL is not lithology-dependent; therefore, it is a true measure of the fluids contained in a reservoir. Furthermore, the MRIL provides new measurements of effective porosity and clay-bound porosity as well as links to reservoir permeability, fluid viscosity, and fluid type, which have been difficult to establish with conventional logging tools. An added benefit is that these measurements are made without nuclear sources. The “fluids first” revolution is refocusing the industry on the fluids of interest and not necessarily the rocks that contain these fluids. Over the next few years, MRIL will no doubt become a highly significant component of any open-hole logging job.




Reservoir Fluid Mechanics Reservoirs are composed of rock matrix, pores, and capillaries (channels between matrix grains that connect pores, sometimes called pore throats) of varying sizes. In sedimentary rocks, all of these pores are fluid-saturated. The fluid is sometimes oil and/or gas, but water will always be present. Most water found within the porosity of a reservoir is moderately saline. The degree of salinity is dependent upon the chemical history of that water. Formation water is typically salty because most sediments are deposited in marine environments. During deposition of these sediments, the salty formation water will become entrapped within the porosity. The salinity of this original formation water, however, may change with geologic time. Fresh water from the surface may infiltrate the sediments, mixing with the original salty formation water to form brackish water. In some instances, whether by osmosis or by fresh water being driven off from nearby formations, it is possible for salty formation water to be flushed from a formation altogether. The result may be a deep, fresh waterbearing formation. In some areas, fresh water is encountered at depths as great as 5,000 ft, but in others, salt water occurs at a depth of several hundred feet. The fluids in a sedimentary rock (whether water, oil, or gas) are constantly subjected to a variety of forces, which include cohesion, surface tension, adhesion, interfacial tension, and capillary pressure. The interplay of these forces and their effect on the fluids and their movement is the subject of fluid mechanics. Basic to the understanding of fluid mechanics as it applies to hydrocarbon reservoirs is the concept of surface tension. All molecules in a fluid will attract each other mutually because of their force of cohesion. This can be demonstrated in Fig. 1.1.27, which illustrates several molecules of water in a droplet of water. Molecule A will feel equally balanced forces of cohesion on all sides because of the surrounding water molecules. Molecule B, however, will feel no comparable attractive force from above. Consequently, there will be an unbalanced cohesive force at the air-water interface, which attempts to pull the molecules down and hold them together. This contractile force is called surface tension. The top layer of molecules acts much like a membrane of rubber, squeezing against the water below and keeping the air-water interface straight. In a droplet of water, this same surface membrane keeps the droplet round, as if a balloon filled with liquid. Where one liquid is in with another liquid or is in with a solid, there exists an attractive force on both sides of their interface called adhesion. This attractive force is not balanced across the interface because the molecules on one side of the interface are completely different from those on the other side. The tension resulting from such unbalanced attractive forces between two liquids or between a liquid and a solid is called interfacial tension. Interfacial tension s for whether a fluid will be adhered to the surface of a solid or repelled from that surface. Water, for example, will spread out and adhere to glass because its interfacial tension is low in comparison to that of glass. Mercury, on the other hand, has an interfacial tension that is high compared to that of


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glass and, therefore, will not adhere to the glass, but rather contract into a droplet. This principle is extremely important in reservoir fluid mechanics

Fig. 1.1.27—The Principle of Surface Tension.

because these same forces operate between rock material (matrix) and the fluids filling the porosity. The force of adhesion between water and most matrix material is greater than that of most oils. Therefore, if a rock contains both water and oil, typically the water will occur as a film adhering to the rock grains with the oil occupying the space between (see Fig. 1.1.28). Such a reservoir is said to be water-wet because water is the fluid phase that is “wetting” the grains of the rock. In some instances, although not as common, the chemistry of the oil may be such that it is the fluid that is in with the grains of the rock. This type of reservoir is said to be oil-wet.

Fig. 1.1.28—Distribution of Non-Wetting Oil (Black) in a Single Water-Wet Pore (Water Blank/White).




Capillary Pressure

Fig. 1.1.29—Capillary Pressure Effects in Reservoirs.

Reservoir rocks are composed of varying sizes of grains, pores, and capillaries (channels between grains which connect pores together, sometimes called pore throats). As the size of the pores and channels decrease, the surface tension of fluids in the rock increases. When there are several fluids in the rock, each fluid has a different surface tension and adhesion that causes a pressure variation between those fluids. This pressure is called capillary pressure and is often sufficient to prevent the flow of one fluid in the presence of another. For example, Fig. 1.1.29 shows that the same adhesive forces that were mentioned previously will cause water, when in with air, to rise slightly against the walls of its container, against the pull of gravity, and form a concave meniscus. If several tubes of varying diameter are placed in a water-filled container, a meniscus forms on the inside walls of the tubes. In the very narrow tubes, the entire airwater interface will be concave upward. However, surface tension at the air-water interface will attempt to flatten this interface, thereby causing a slight rise in the level of water across the entire diameter of the tube. As this occurs, the adhesion of the water to glass will continue to pull water molecules upward near the edge of the tubes. By this mechanism, the water level in the tube will continue to rise until the upward force is balanced by the weight of the water column. Again, referring to Fig. 1.1.29 above, the strength of the capillary pressure may be thought of in of the concavity of the air-water interfaces seen in the different tubes. The greater the capillary pressure, the more the air-water interface will be distorted into concavity by the adhesion of water to glass on the side of the tube. As seen in the illustration, the air-water interfaces in the narrow tubes exhibit more concavity than do the air-water interfaces in the wide tubes. Consequently, the height of the water columns in the B tubes (which are narrow) rise even higher than that of the A tubes (which are wider). Essentially, capillary pressures are higher for tubes with smaller openings. With respect to a reservoir, this may be thought of in of pore throat diameters.


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Large pore throat diameters:  

Generally yield a lower capillary pressure because of the decrease in the amount of surface tension. Large pores that are often associated with large pore throat diameters will also contain lesser amounts of adsorbed (adhered) water because the surface-tovolume ratio of the pore is low.

Small pore throat diameters:  

Generally yield higher capillary pressures because of the greater amount of surface tension. Small pores that are often associated with small pore throat diameters will have a high surface-to-volume ratio and, therefore, may contain greater amounts of adsorbed (adhered) water.

Fig. 1.1.30—Grain-Size Effects on Capillary Pressure and Pore-Throat Diameters.

Irreducible Water Saturation As previously stated, all sedimentary rocks have porosity that is fluid saturated. The fluid is sometimes oil and/or gas, but water is always present. Water saturation is defined as the fraction of that porosity that is occupied by water. If the pore space is not occupied by water, then it must be occupied by hydrocarbons. Therefore, by determining a value of water saturation from porosity and resistivity measurements, it is possible to determine the fraction of pore space that is occupied by hydrocarbons (hydrocarbon saturation).



Halliburton Energy Services Water saturation simply refers to the amount of water that is present in the reservoir and says nothing about its ability to be produced. In a reservoir containing a small amount of water, it might be possible to produce this water if capillary pressures are low and the water is not adsorbed (adhered) onto the surfaces of rock grains. However, if this water is adhered to the surfaces of rock grains and there is a high capillary pressure, then it is possible to produce water-free hydrocarbons from a reservoir that does contain some water. For any reservoir, there is a certain value of water saturation at which all of the contained water will be trapped by capillary pressure and/or by adsorption of water on the surface of rock grains (surface tension). This is referred to as irreducible water saturation (S wirr ). At irreducible water saturation, all of the water within the reservoir will be immovable, and hydrocarbon production will be water-free.

Basic Geological Conditions that Create Petroleum Traps Hydrocarbon Traps Hydrocarbon traps are any combination of physical factors that promote the accumulation and retention of petroleum in one location. Traps can be structural, stratigraphic, or a combination of the two. Geologic processes, such as faulting, folding, piercement, and deposition and erosion create irregularities in the subsurface strata that may cause oil and gas to be retained in a porous formation, thereby creating a petroleum reservoir. The rocks that form the barrier, or trap, are referred to as caprocks.

Structural Traps Structural traps are created by the deformation of rock strata within the earth’s crust. This deformation can be caused by horizontal compression or tension, vertical movement, and differential compaction, which results in the folding, tilting, and faulting within sedimentary rock formations.


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Anticlinal and Dome Traps The rock layers in an anticlinal trap were originally laid down horizontally then folded upward into an arch or dome. Later, hydrocarbons migrate into the porous and permeable reservoir rock. A cap or seal (impermeable layer of rock) is required to permit the accumulation of the hydrocarbons.

Fig. 1.1.31—Anticlinal Trap.




Salt Dome or Salt Plug Traps A salt dome or salt plug trap is created by piercement or intrusion of stratified rock layers from below by ductile non-porous salt. The intrusion causes the lower formations nearest the intrusion to be uplifted and truncated along the sides of the intrusion, while layers above are uplifted, creating a dome or anticlinal folding. Hydrocarbons migrate into the porous and permeable beds on the sides of the column of salt. Hydrocarbons accumulate in the traps around the outside of the salt plug if a seal or cap rock is present.

Fig. 1.1.32—Salt Dome Trap.


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Fault Trap The faulting of stratified rock occurs as a result of vertical and horizontal stresses. At some point, the rock layers break, resulting in the rock faces along the fracture moving or slipping past each other into an offset position. A fault trap is formed when the faulted formations are tilted toward the vertical. When a non-porous rock face is moved into a position above and opposite a porous rock face, it seals off the natural flow of the hydrocarbons, allowing them to accumulate.

Fig. 1.1.33—Fault Trap.




Fig. 1.1.34—Faulting.

Fig. 1.1.35—Folding.


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Stratigraphic Traps Stratigraphic traps are formed as a result of differences or variations between or within stratified rock layers, creating a change or loss of permeability from one area to another. These traps do not occur as a result of movement of the strata.

Fig. 1.1.36—Stratigraphic Trap.

Lenticular Traps A lenticular trap is a porous area surrounded by non-porous strata that may be formed from ancient buried river-sand bars, beaches, etc.

Fig. 1.1.37—Lenticular Trap.




Pinch-out or Lateral Graded Traps A pinch-out trap is created by lateral differential deposition when the environmental deposition changes up-dip.

Fig. 1.1.38—Pinch-Out Trap.

Angular Unconformtiy Traps An angular unconformity trap is one in which older strata dips at an angle different from that of younger strata. An angular unconformity trap occurs when inclined, older petroleum-bearing rocks are subjected to the forces of younger non-porous formations. This condition may occur whenever an anticline, dome, or monocline are eroded and then overlain with younger, less-permeable strata.

Fig. 1.1.39—Eroded Anticline.


Fig. 1.1.40—Eroded Monocline.

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Fig. 1.1.41—Angular Unconformity.

Exploration and Mapping Techniques Exploration for oil and gas has long been considered an art as well as a science. It encomes a number of older methods in addition to new techniques. The explorer must combine scientific analysis with an imagination to successfully solve the problem of finding and recovering hydrocarbons.

Subsurface Mapping Geologic maps are a representation of the distribution of rocks and other geologic materials of different lithologies and ages over the earth’s surface or below it. The geologist measures and describes the rock sections and plots the different formations on a map, which shows their distribution. Just as a surface relief map shows the presence of mountains and valleys, subsurface mapping is a valuable tool for locating underground features that may form traps or outline the boundaries of a possible reservoir. Once a reservoir has been discovered, it is also the job of the geologist to present enough evidence to the development and production of that reservoir. Subsurface mapping is used to work out the geology of petroleum deposits. Threedimensional subsurface mapping is made possible by the use of well data and helps to decipher the underground geology of a large area where there are no outcrops at the surface.



Halliburton Energy Services Some of the commonly prepared subsurface geological maps used for exploration and production include: (1) geophysical surveys, (2) structural maps and sections, (3) isopach maps, and (4) lithofacies maps.

Geophysical Surveys Geophysics is the study of the earth by quantitative physical methods. Geophysical techniques, such as seismic surveys, gravity surveys, and magnetic surveys provide a way of measuring the physical properties of a subsurface formation. These measurements are translated into geologic data, such as structure, stratigraphy, depth, and position. The practical value in geophysical surveys is in their ability to measure the physical properties of rocks that are related to potential traps in reservoir rocks as well as documenting regional structural trends and overall basin geometry.

Seismic Surveys The geophysical method that provides the most detailed picture of subsurface geology is the seismic survey. This involves the natural or artificial generation and propagation of seismic (elastic) waves down into Earth until they encounter a discontinuity (any interruption in sedimentation) and are reflected back to the surface. On-land, seismic “shooting” produces acoustic waves at or near the surface by energy sources, such as dynamite, a “Thumper” (a weight dropped on ground surface), a “Dinoseis” (a gas gun), or a “Vibroseis” (which literally vibrates the earth’s surface). Electronic detectors called geophones then pick up the reflected acoustic waves. The signal from the detector is then amplified, filtered to remove excess “noise”, digitized, and then transmitted to a near-by truck to be recorded on magnetic tape or disk. In the early days of off-shore exploration, explosive charges suspended from floats were used to generate the necessary sound waves. This method is now banned in many parts of the world because of environmental considerations. One of the most common ways to generate acoustic waves today is an air gun. Air guns contain chambers of compressed gas. When the gas is released under water, it makes a loud “pop,” and the seismic waves travel through the rock layers until they are reflected back to the surface where they are picked up by hydrophones, the marine version of geophones, which trail behind the boat. The data recorded on magnetic tape or disk can be displayed in a number of forms for interpretation and research purposes, including visual display forms (photographic and dry-paper), a display of the amplitude of arriving seismic waves versus their arrival time, and a common type of display called variable-density. The variable-density display is generated by a technique in which light intensity is varied to enhance the different wave amplitudes. For example, low amplitude waves are unshaded, and higher amplitude waves are shaded black, thus strong reflections will show up as a black line on the display. Seismic waves travel at known but varying velocities depending upon the kinds of rocks through which they and their depth below Earth’s surface. The speed of sound waves through the earth’s crust varies directly with density and inversely with porosity. 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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Through soil, the pulses travel as slowly as 1,000 ft/sec, which is comparable to the speed of sound through air at sea level. On the other hand, some metamorphic rocks transmit seismic waves at 20,000 ft (approximately 6 km) /sec, or slightly less than 4 mi/sec. Some typical average velocities are: shale = 3.6 km/s, sandstone = 4.2 km/s, and limestone = 5.0 km/s. If the subsurface lithology is relatively well known from drilling information, it is possible to calculate the amount of time it takes a wave to travel down through the earth to a discontinuity and back to the surface. This information is used to compute the depth of the discontinuity or unconformity. However, the only way to accurately determine depth is by correlating seismic sections to wireline logs. Reflections are generated at unconformities because unconformities separate rocks having different structural attitudes or physical properties, particularly different lithologies. These principles form the basis for application of seismic methods to geologic study.

Magnetic Surveys Magnetic surveys are methods that provide the quickest and least expensive way to study gross subsurface geology over a broad area. A magnetometer is used to measure local variations in the strength of the earth’s magnetic field and, indirectly, the thickness of sedimentary rock layers where oil and gas might be found. Igneous and metamorphic rocks usually contain some amount of magnetically susceptible iron-bearing minerals and are frequently found as basement rock that lies beneath sedimentary rock layers. Basement rock seldom contains hydrocarbons, but it sometimes intrudes into the overlying sedimentary rock, creating structures, such as folds, arches, or anticlines that could serve as hydrocarbon traps. Geophysicists can get a fairly good picture of the configuration of the geological formations by studying the anomalies, or irregularities, in the structures. The earth’s magnetic field, although more complex, can be thought of as a bar magnet, around which the lines of magnetic force form smooth, evenly spaced curves. If a small piece of iron or titanium is placed within the bar magnet’s field, it becomes weakly magnetized, creating an anomaly or distortion of the field. The degree to which igneous rocks concentrate this field is not only dependent upon the amount of iron or titanium present, but also upon the depth of the rock. An igneous rock formation 1,000 ft below the surface will affect a magnetometer more strongly than a similar mass 10,000 ft down. Thus, a relatively low magnetic-field strength would indicate an area with the thickest sequence of non-magnetic sedimentary rock. Once the magnetic readings have been plotted on a map, points of equal field strength are connected by contour lines, thus creating a map that is the rough equivalent to a topographic map of the basement rock. This can be useful in locating basic geologic structures, although it will not reveal details of the structures or stratigraphy.

Gravity Surveys The gravity survey method makes use of the earth’s gravitational field to determine the presence of gravity anomalies (abnormally high- or low-gravity values), which can be related to the presence of dense igneous or metamorphic rock or light sedimentary rock in the subsurface. Dense igneous or metamorphic basement rocks close to the surface will read much higher on a gravimeter because the gravitational force they exert is more powerful than the lighter sedimentary rocks. The difference in mass for equal volumes of rock is due to variations in specific gravity. 66 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services Although mechanically simple, a gravimeter can measure gravity anomalies as small as one billionth of the earth’s surface gravity. Data collected from gravity surveys can be used to construct contour maps showing large-scale structures and, like magneticsurvey contour maps, smaller details will not be revealed. Geophysicists applied this knowledge, particularly in the early days of prospecting off the Gulf of Mexico. Often, they could locate salt domes using data from a gravity survey because ordinary domal and anticlinal structures are associated with maximum gravity, whereas salt domes are usually associated with minimum gravity.

Structural Contour Maps Contour maps show a series of lines drawn at regular intervals. The points on each line represent equal values, such as depth or thickness. One type of contour map is the structural map, which depicts the depth of a specific formation from the surface. The principle is the same as that used in a topographic map, but it, instead, shows the highs and lows of the buried layers. Contour maps for exploration may depict geologic structure as well as thickness of formations. They can show the angle of a fault and where it intersects with formations and other faults, as well as where formations taper off or stop abruptly. The subsurfacestructural contour map is almost or fully dependent on well data for basic control.

Fig. 1.1.42—Structural Map and Longitudinal Profile Section Showing Top of Salt, which is Datum for Structure Contours. 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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Cross-Sections Structural, stratigraphic, and topographic information can be portrayed on cross-sections that reproduce horizontally-represented map information in vertical section. Maps represent information in the plan view and provide a graphic view of distribution. Crosssections present the same information in the vertical view and illustrate vertical relationships, such as depth, thickness, superpostion, and lateral and vertical changes of geologic features. Raw data for cross-sections come from stratigraphic sections, structural data, well sample logs, cores, wireline logs, and structural, stratigraphic, and topographic maps.

Fig. 1.1.43—Completed Geologic Map and Cross-Section.




Isopach Maps Isopach maps are similar in appearance to contour maps but show variations in the thickness of the bed. These maps may be either surface or subsurface depending on data used during construction. Isopach maps are frequently color coded to assist with visualization and are very useful in following pinchouts or the courses of ancient stream beds. Porosity or permeability variations may also be followed by such means. Geologists use isopach maps to aid in exploration work, to calculate how much petroleum remains in a formation, and to plan ways to recover it.

Fig. 1.1.44—Isopach Map of Channel Sandstone.


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Lithofacies Maps Lithofacies maps show, by one means or another, changes in lithologic character and how it varies horizontally within the formation. This type of map has contours that represent the variations in the proportion of sandstone, shale, and other kinds of rocks in the formation.

Fig. 1.1.45—Isopach and Lithofacies Maps.

Identification of source and reservoir rocks, their distribution, and their thickness’ are essential in an exploration program; therefore, exploration, particularly over large areas, requires the correlation of geologic sections. Correlations produce cross-sections that give visual information about structure, stratigraphy, porosity, lithology, and thickness of important formations. This is one of the fundamental uses of well logs for geologists. 70 Cased-Hole Associate Field Professional Vol. I



Fig. 1.1.46—Cross-Section Constructed from Correlated Well Logs.


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Wells that have information collected by driller’s logs, sample logs, and wireline logs enable the geologists to predict more precisely where similar rock formations will occur in other subsurface locations. Subsurface correlation is based primarily on stratigraphic continuity, or the premise that formations maintain the same thickness from one well to another. A major change in thickness, rock type, or faunal content can be a geologic indicator that conditions forming the strata changed, or it may be a signal of an event that could have caused hydrocarbons to accumulate.

Fig. 1.1.47—Stratigraphic Cross-Section Constructed from Correlated Well Logs Showing the Effect of Pinchout of Sand 3.




Surface Geology There are several areas to look for oil. The first area is obvious, on the surface of the ground. Oil and gas seeps are where the petroleum has migrated from its source through either porous beds, faults, or springs and appears at the surface. Locating seeps at the surface was the primary method of exploration in the late 1800’s and before.

Fig. 1.1.48—Seeps are Located Either Updip (A) or Along Fractures (B).

Seeps are abundant and well documented worldwide. Oil or gas on the surface, however, does not give an indication of what lies in the subsurface. It is the combination of data that gives the indication of what lies below the surface. Geologic mapping, geophysics, geochemistry, and aerial photography are all crucial aspects in the exploration for oil and gas.


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Subsurface Geology and Formation Evaluation Subsurface geology and formation evaluation covers a large range of measurement and analytic techniques. To complete the task of defining a reservoir’s limits, storage capacity, hydrocarbon content, ability to produce, and economic value, all measurements must be taken into and analyzed. A potential reservoir must first be discovered before it can be evaluated. The initial discovery of a reservoir lies squarely in the hands of the explorer using seismic records, gravity, and magnetics. There are a number of parameters that are needed by the exploration and evaluation team to determine the economic value and production possibilities of a formation. These parameters are provided from a number of different sources, including seismic records, coring, mud logging, and wireline logging. Log measurements, when properly calibrated, can give the majority of the parameters required. Specifically, logs can provide a direct measurement or give a good indication of:        

Porosity, both primary and secondary Permeability Water saturation and hydrocarbon movability Hydrocarbon type (oil, gas, or condensate) Lithology Formation dip and structure Sedimentary environment Travel times of elastic waves in a formation



Halliburton Energy Services These parameters can provide good estimates of the reservoir size and the hydrocarbons in place. Logging techniques in cased holes can provide much of the data needed to monitor primary production and also to gauge the applicability of waterflooding and monitor its progress when installed. In producing wells, logging can provide measurements for:    

Flow rates Fluid type Pressure Residual oil saturations

Logging can answer many questions on topics ranging from basic geology to economics; however, logging by itself cannot answer all the formation evaluation problems. Coring, core analysis, and formation testing are all integral parts of any formation evaluation effort.

Well Cuttings Well samples are produced from drilling operations by the drill bit penetrating the formation encountered in the subsurface. Samples are taken at regular intervals. They are used to establish a lithologic record of the well and are plotted on a strip sample log.


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Cores Cores are cut where specific lithologic and rock parameter data are required. They are cut by a hollow core barrel, which goes down around the rock core as drilling proceeds. When the core barrel is full and the length of the core occupies the entire interior of the core barrel, it is brought to the surface, and the core is removed and laid out in stratigraphic sequence. It is important to note that the sample may undergo physical changes on its journey from the bottom of the well, where it is cut, to the surface, where it is analyzed. Cores are preferable to well cuttings because they produce coherent rock. They are, however, significantly more expensive to obtain. Sidewall cores are small samples of rock obtained by shooting small metal cylinders from a gun into the walls of a drill hole. Sidewall cores can be taken from several levels and at different locations by using the versatile sidewall coring gun tool. Sidewall cores may also be taken using a wireline tool called the RSCT (Rotary Sidewall Coring Tool).

Fig. 1.1.49—Conventional Sidewall Core Gun.

Fig. 1.1.50—Wellbore View of Coring Gun.




Logging While Drilling Formation properties can be measured at the time the formation is drilled by the use of special drill collars that house measuring devices. These logging-while-drilling (LWD) tools are particularly valuable in deviated, offshore, or horizontally drilled wells. Although not as complete as open-hole logs, the measurements obtained by MWD are rapidly becoming just as accurate and usable in log analysis procedures.

Formation Testing Formation testing, commonly referred to as drillstem testing (DST), is a technique for delivering, to the surface, samples of fluids and recorded gas, oil, and water pressures from subsurface formations; such data allows satisfactory completion of a well. This type of testing provides more direct evidence of formation fluids and gases, the capacity of the reservoir and its ability to produce in the long term, than any other method except established production from a completed well. Wireline-formation testers complement drillstem tests by their ability to sample many different horizons in the well and produce not only fluid samples, but also detailed formation pressure data that are almost impossible to obtain from a DST alone.

Wireline Well-Logging Techniques Wireline logging involves the measurement of various properties of a formation including electrical resistivity, bulk density, natural and induced radioactivity, hydrogen content and elastic modulae. These measurements may then be used to evaluate not only the physical and chemical properties of the formation itself, but also the properties of the fluids that the formation contains. There are open-hole logs and cased-hole logs. The open-hole logs are recorded in the uncased portion of the wellbore. Casedhole logs are recorded in the completed or cased well. There are measurements that can be made in both the open and cased holes and some that can only be made in open holes. Resistivity and density porosity are two examples of measurements that can be made in an 12/29/2008 Cased-Hole Associate Field Professional Vol. I

Fig. 1.1.51—Wireline Logging Unit Rigged Up on a Well 77 WPS Training

open hole but not in a cased hole. Perforation is the wireline procedure of introducing holes through the casing (inner wall) and/or the cement sheath into a formation so that the fluids can flow from the formation into the casing. Perforating is generally performed to bring a well into production, although it could also be performed to establish circulation within the wellbore to free a tool string that may be stuck.

Fig. 1.1.52—Perforation.




Borehole Environment Reservoir properties are measured by lowering a tool attached to a wireline or cable into a borehole. The borehole may be filled with water-based drilling mud, oil-based mud, or air. During the drilling process, the drilling mud invades the rock surrounding the borehole, which affects logging measurements and the movement of fluids into and out of the formation. All of these factors must be taken into while logging and during log analysis. It is important to understand the wellbore environment and the following characteristics: hole diameter, drilling mud, mudcake, mud filtrate, flushed zone, invaded zone, and the uninvaded zone.

Fig. 1.1.53—Borehole Environment.  

Hole diameter (d h )—The size of the borehole determined by the diameter of the drill bit. Drilling Mud Resistivity (R m )—Resistivity of the fluid used to drill a borehole and which lubricates the bit, removes cuttings, maintains the walls of the borehole, and maintains borehole over formation pressure. Drilling mud consists


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of a variety of clay and other materials in a fresh or saline aqueous solution and has a measurable resistivity.



Halliburton Energy Services 



Mudcake Resistivity (R mc )—Resistivity of the mineral residue formed by accumulation of solid drilling-mud components on the wellbore walls as the mud fluids invade the formations penetrated by the borehole. Mud Filtrate (R mf )—Resistivity of the liquid drilling mud components that infiltrate the formation, leaving the mudcake on the walls of the borehole.

Note: Resistivity values for the drilling mud, mudcake, and mud filtrate are determined during a full mud press and are recorded on a log’s header. 



Invaded Zone—The zone that is invaded by mud filtrate. It consists of a flushed zone (R xo ) and a transition or annulus zone (R i ). The flushed zone (R xo ) occurs close to the borehole where the mud filtrate has almost completely flushed out the formation’s hydrocarbons and/or water. The transition or annulus zone (R i ), where a formation’s fluids and mud filtrate are mixed, occurs between the flushed zone (R xo ) and the uninvaded zone (R t ). Uninvaded Zone (R t )—Pores in the uninvaded zone are uncontaminated by mud filtrate; instead, they are saturated with formation fluids (water, oil, and/or gas).

The Basis of Log Analysis Log analysis, at the well-site, is performed with the goal in mind of whether or not to run production casing. This decision is usually based on interpretation and calculation of the productive capacity of the formation in question. Such an analysis requires an understanding of what a log measures, the conditions that influence these measurements, and how the log data can be used to attain the goal. Well-site analysis generally concerns the evaluation of two types of logs: electrical or resistivity logs, and porosity logs. Note:

Resistivity and porosity are the single-most important measurements made by conventional logging tools, and form the foundation on which the entire industry is built.

With the data presented on these logs and others, analysts can determine not only the lithology and productive capabilities of the formation of interest, but also the relative proportion of water (water saturation), and, therefore, hydrocarbons that the formation contains.


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Log Data The primary information we are trying to determine from log data is: 1. Porosity (Φ)—The percentage of void space in a reservoir, of which is filled with fluid (either water or hydrocarbons). 2. Resistivity (R)—The resistance of a material to the flow of electrical current calculated by Ohm’s Law. Porosity and resistivity are used to calculate water saturation. 3. Water Saturation (S w )—The percentage of the porosity of a reservoir that is filled by water. But, we don’t actually measure these parameters directly!

Porosity To calculate porosity (Φ), we measure bulk density (ρ b ), hydrogen index (HI), and/or interval transit time (Δt). A sonic tool measures internal transit time (Δt) and is used to determine the effective porosity of a reservoir. The neutron-density combination is used to calculate porosity two different ways and provides us with a value of total porosity. :

Effective porosity is the interconnected pore volume available to free fluids. Total porosity is all void space in a rock and matrix, whether effective or non-effective.

Resistivity Resistivity is, perhaps, the most fundamental of all measurements in logging. All geological materials possess some amount of resistance, or the inherent ability to resist the flow of an electrical current. Resistivity (R) is the physical measurement of resistance and is defined as the reciprocal of electrical conductivity (C).

R

1000 C

(Eq. 1.1.3)

Oil and gas are electrical insulators. They will not conduct the flow of an electrical current; therefore, their resistivities are said to be infinite. Water, however, will conduct electricity depending upon its salinity. Salt water, with high concentrations of dissolved solids (e.g., NaCl, etc.), will conduct electricity much more readily than will fresh water. Therefore, salt water has a much lower resistivity than does fresh water. In most instances, the water present in a formation will be saline, and will have a resistivity much lower than, or similar to, the resistivity of the fluid used to drill a well penetrating that formation. A current and a voltage are measured using an induction or resistivity tool. From these measurements, resistivity (R) can be calculated by Ohm’s Law.




R

V I

(Eq. 1.1.4)

The amount of current flow that can be ed by a formation depends on the resistance of the formation matrix (i.e., rock) and the conductive properties of the fluids that formation contains. Salt water, for instance, requires very little voltage to produce a current flow. The resulting ratio of voltage to current (expressed as resistivity) is, therefore, low. Oil, on the other hand, requires that extremely high voltages be applied in order to generate an electrical current. It is because of this condition that the resistivity of hydrocarbons is said to be infinite (hydrocarbons are insulators). Example of changes in resistivity with changes in reservoir characteristics:     

Start with a dense quartz sandstone with no porosity. Rock is an electrical insulatorR = ∞. Add porosity, but no fluid occupies the pores. Rock and air are electrical insulatorsR = ∞. Add moderately saline water to formation’s porosity, which is typical of reservoir rocks. Current conducted through pore waterR decreases. Add even more saline water. Even more current conductedfurther decrease in R. Add hydrocarbon to water already occupying porosity; hydrocarbon displaces water—occupies a volume formerly filled by water. Path of current flow becomes more tortuousR increases.

Therefore, R depends on the type and amount of fluid present (which is determined by porosity). Once R has been measured, then you can solve for what proportion of that fluid is conductive formation water and what proportion is non-conductive pore water. Note:

Formation water, at depth, is almost always saline.

Water Saturation Water saturation (S w ) is calculated from porosity (Φ) and resistivity (R) and some basic assumptions. Assumptions:  

If porosity (Φ) is measured 2–3 in. from the borehole wall, then you must assume that to be representative of the entire formation. If deep resistivity is measured 5–7 ft from the borehole wall, then you must assume that to be representative of the univaded zone.

These assumptions are used in calculating the water saturation (S w ) of the uninvaded zone.


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Important Terminology and Symbols Rw Ro Fr Φ a m Rt Sw

Formation water resistivity Resistivity of the formation if its porosity is filled 100% with water (wet resistivity) Formation resistivity factor Porosity Tortuosity factor Cementation exponent True resistivity of the uninvaded zone Water saturation

Consider a formation with a given amount of porosity, and assume that the porosity is completely filled with saline formation water of a given resistivity. Because saline water is capable of conducting an electric current, the formation water resistivity (R w ) is quite low. The measured resistivity of the formation itself (R o , wet resistivity, where porosity is 100% filled with water) will depend upon the formation water resistivity (R w ) and the formation resistivity factor (F r ). Ro = Fr  Rw

(Eq. 1.1.5)

Rearranging this equation, the formation resistivity factor (F r ) can be quantified as the resistivity ratio of the entire formation to that of the water present in that formation.

Fr 

Ro Rw

(Eq. 1.1.6)

In this example, formation water resistivity (R w ) is defined as a constant; therefore, changes in the formation resistivity factor (F r ) will occur only with changes in the overall formation resistivity (R o ). The one way in which R o can change in a formation of constant R w is by changing the amount of fluid available to conduct an electrical current. This is accomplished through changes in porosity. As porosity decreases, the amount of water available to conduct electrical current is decreased, resulting in an increase in formation resistivity (R o ). Therefore, formation resistivity factor (F r ) is inversely proportional to porosity (Φ).

F

1 

(Eq. 1.1.7)

This relationship between formation resistivity and porosity was first researched by G. E. Archie, of the Humble Oil Company, while working on limestones in . Archie had electric (resistivity) logs from several wells and core porosity from productive zones within these wells. He noticed that there was some relation between resistivity and porosity and, thus, was able to identify zones of interest through the use of electric logs alone. He wanted to know if there was some relationship that made it possible to determine whether a zone would be productive on the basis of measured resistivity and core porosity.



Halliburton Energy Services Changes in the porosity of a formation may have effects other than simply increasing or decreasing the amounts of fluids available to conduct electric current. With a change in porosity, there may be concomitant changes in the complexity of the pore network that affect the conductive nature of the fluids present, and the formation resistivity factor (F r ) can, therefore, vary with the type of reservoir. These changes are expressed by the tortuosity factor (a) and the cementation exponent (m).

Fr 

a m

(Eq. 1.1.8)

For the limestones of Archie’s experiments, the tortuosity factors and cementation exponents were always constant (a = 1.0, m = 2.0). However, this may not be the case for sandstone reservoirs. Although both parameters can be determined experimentally for a specific reservoir, log analysts commonly use set values for the tortuosity factor (a) and cementation exponent (m), depending upon lithology and porosity, which are presented below.

Table 1.1.2—Standard Values for Tortuosity Factor (a) and Cementation Exponent (m). Sandstones Carbonates

Porosity  > 16% (Humble)

Porosity  < 16% (Tixier)

Tortuosity (a)

1.0

0.62

0.81

Cementation (m)

2.0

2.15

2.00

Consider now that the porous formation discussed previously is filled with some combination of conductive formation water of constant resistivity (R w ) and oil. Oil is an insulator and will not conduct an electrical current. Furthermore, because the formation is filled with both water and oil, the resistivity of the formation can no longer be referred to as wet resistivity (R o ). The measure of formation resistivity in this instance—taking into the resistivity of the rock matrix and the fluids contained—is called true resistivity (R t ). True resistivity of a formation will only be equal to wet resistivity (R t = R o ) when that formation is completely filled with conductive water. However, because some of the available porosity may be filled with non-conductive oil, the theoretical wet resistivity (R o ) of that formation is now related to the measured true resistivity (R t ) by some additional factor, referred to as F . R o = F  R t

(Eq. 1.1.9)

The factor, F , can, therefore, be expressed as a ratio of the theoretical wet resistivity of that formation (R o ) to the actual measured resistivity of the formation (R t ).


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F 

Ro Rt

(Eq. 1.1.10)

In the example formation, because both porosity and formation water resistivity are considered to be constant, the resulting theoretical wet resistivity (R o ) will be constant. Therefore, changes in the factor, F , will occur with changes in measured resistivity (R t ). Under the given conditions, the only way in which true measured resistivity (R t ) of the formation can change is through the addition or subtraction of conductive fluid. For example, the addition of oil to the reservoir would result in the increase of that formation’s measured resistivity (R t ) because some amount of conductive formation water would be displaced by the oil. Therefore, the factor, F , is dependent upon the relative proportion of conductive fluids (water) and non-conductive fluids (hydrocarbons) in the formation. The factor, F , in the above equations represents water saturation (usually expressed as S w ), which is the percentage of pore space within a formation that is occupied by conductive formation water. By substitution of equations, water saturation can be related to the physical properties of the formation and the conductive properties of the fluids it contains.

Sw  n

F R w Rt

or

Sw  n

R a  w m Rt 

(Eq. 1.1.11)

Water saturation is related to these properties by the exponent, n (saturation exponent). The saturation exponent may have a range of values dependent upon specific reservoir conditions, but it is generally assumed to be equal to 2.0. With knowledge of the production characteristics of the formation in question, it is possible to determine more accurate values for the saturation exponent. The equation for water saturation, an expanded version of that presented as a footnote in Archie’s 1942 publication and commonly referred to as “Archie’s equation,” has become the foundation of the entire industry of well logging. In its simplest form, Archie’s equation is often expressed as:

Sw  n

R a  w m Rt 

(Eq. 1.1.12)

where: n = saturation exponent (commonly, n = 2.0) a = tortuosity factor Φ = porosity m = cementation exponent



Halliburton Energy Services R w = formation water resistivity R t = true formation Resistivity

A Note on Water Saturation It is important to realize that while water saturation (S w ) represents the percentage of water present in the pores of a formation, it does not represent the ratio of water to hydrocarbons that will be produced from a reservoir. Shaly sandstone reservoirs with clay minerals that trap a large amount of formation water may have high water saturations, yet produce only hydrocarbons. Saturations simply reflect the relative proportions of these fluids contained in the reservoir. Nonetheless, obtaining accurate values for water saturation is the primary goal of open-hole log analysis. With the knowledge of water saturation, it is possible to determine that percentage of porosity that is filled with a fluid other than water (i.e., hydrocarbons) and, therefore, hydrocarbon reserves.

Review of Permeability As previously stated, permeability is the property that permits the age of a fluid through the interconnected pores of a rock. Permeability is measured in darcies. A rock that has a permeability of 1 darcy permits 1 cc of fluid with a viscosity of 1 (viscosity of water at 68°F) to flow through 1 cm2 of its surface for a distance of 1 cm in 1 s with a pressure drop of 14.7 psi. Few rocks have a permeability of 1 darcy; therefore, permeability is usually expressed in millidarcies (md) or 1/1000 of a darcy. The permeabilities of average reservoir rocks generally range between 5 and 1,000 md. A reservoir rock whose permeability is 5 md or less is called a tight sand or a dense limestone, according to composition. A rough field appraisal of reservoir permeabilities is: Fair Good Very Good


1–10 md 10–100 md 100–1,000 md

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 



Absolute Permeability (K a )—Permeability calculated with only one fluid present in the pores of a formation. Effective Permeability (K e )—The ability of a rock to conduct one fluid in the presence of another, considering that both fluids are immiscible (e.g., oil and water). Effective permeability depends not only on the permeability of the rock itself, but also on the relative amounts of the different types of fluid present. Relative Permeability (K r )—The ratio of a fluid’s effective permeability to the formation’s absolute permeability (100% saturated with that fluid). Relative permeability reflects the amount of a specific fluid that will flow at a given saturation—in the presence of other fluid—to the amount that would flow at a saturation of 100%, with all other factors remaining the same.

Graph 1.1.4 illustrates the relative permeabilities of oil and water in an example formation. In a reservoir that is 100% saturated with oil, the relative permeability of oil (K ro ) to water is equal to 1. As water saturation increases, the relative permeability of oil to water will begin to decrease. The value of water saturation where no water will flow is referred to as irreducible water saturation (S wirr ). At some value of water saturation, water will begin to flow within the formation because it can no longer be contained by capillary pressure. With increasing water saturation, the relative permeability of oil (K ro ) to water will continue to decrease. Meanwhile, the relative permeability of water (K rw ) to oil will increase. Eventually, a value of water saturation will be reached at which the relative permeability of oil (K ro ) to water is 0. At this point, oil will no longer flow within the reservoir, and that value of water saturation is referred to as residual oil saturation (ROS). At water saturations above the residual oil saturation, only water will flow within the reservoir. In a reservoir that is 100% saturated with water, the relative permeability of water (K rw ) to oil is equal to 1. Notice in Graph 1.1.4 that there is a point at which the relative permeability of oil (K ro ) is equal to the relative permeability of water (K rw ). At this value of water saturation (approximately 55% in this example), both oil and water will flow with equal ease. This does not mean that the same amounts of oil and water will be produced from the reservoir. The amount of fluid flowing is not a direct effect of the relative permeability of a fluid because different fluids have different viscosities. For example, if water and gas were existing in a reservoir and had equal relative permeabilities (K rw = K rg ), the more gas would flow within the formation because the viscosity of gas is much lower than that of water.




Effective Permeability to Flowing Fluid

Relative Permeabil

1

Krw

0.8

Kro

0.6 0.4 0.2

Swirr

0 0

10

20

ROS

30

40

50

60

70

80

90 100

Water Saturation %

Graph 1.1.4—Effective Permeability to Flowing Fluid.

Reserve Estimation Accurately estimating the reserves of hydrocarbons in the reservoir is extremely important. This calculation not only relies on computations from log data but also on the size and shape of a reservoir and correlations of logs from many wells in the field. Dipmeter data and seismic data also assist the analyst in making accurate calculations. In summary, a log analyst can say with some reasonable degree of certainty that, for example, 10% of the volume of the reservoir is full of oil. It is up to others to determine the size of the reservoir and, therefore, deduce the actual volume of oil available.

How Much Hydrocarbon can be Recovered from the Reservoir? First, calculations need to be made to determine the volume of hydrocarbon found in a trap, or the OIP (oil-in-place). This is accomplished when some reservoir thickness (h) is delineated to exist over an area (A) to produce a volume (V). If (h) is measured in ft and (A) in acres, the reservoir volume (V) is expressed in acre-ft. In actual reservoirs, both porosity and saturation vary laterally and vertically. A useful quantity for OIP measurements is, therefore, the hydrocarbon pore volume, or HV, which is defined as: HV = Φ(1-S w ) 12/29/2008 Cased-Hole Associate Field Professional Vol. I

(Eq. 1.1.13) 89 WPS Training

Thus, at any depth in a well, if both porosity and saturation are deduced from logs, the concentration of hydrocarbon in the reservoir at that depth can be estimated. For example, if porosity is 30% and water saturation is 40%, then HV = 0.3(1-0.4) = 0.18, or 18% of the bulk-reservoir volume contains oil. At a neighboring point in the same well, the value of HV may be different. Thus, in order to sum the total oil-in-place (OIP), an integration of HV with respect to depth and area is called for: OIP = ΣΦ(1-S w )h*A

(Eq. 1.1.14)

Fig. 1.1.54—Oil-in-Place.

Second, we must convert the oil-in-place to reserves, which requires two additional pieces of data: the recovery factor (r) and the formation volume factor (B). Neither of these can be estimated from logs. The recovery factor is a function of the type of reservoir and the drive mechanism, and the formation volume factor is a function of the hydrocarbon properties. The reserves (N), in of stock tank volumes, are thus expressed as:

N

C    (1 - Sw)h  A  r B

(Eq. 1.1.15)

where: C = a constant, 7,758 bbl/acre A= acres Φ = porosity of reservoir, in percent h = thickness of reservoir, in ft S h = hydrocarbon saturation, in percent = 1-Sw (water saturation) r = recovery factor



Halliburton Energy Services B = formation volume factor or shrinkage factor = 1.33 ± 0.16 =

volume at downhole conditions volume at STP

Fig. 1.1.55—Graphical Depiction of the Constant, 7758 bbl/acre


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Glossary Accretion—The process by which an object grows larger due to the addition of fresh material to the outside. Catagenesis—Middle level (between diagenesis and metagenesis) sediment consolidation and alteration when most oil and gas are generated. Cementation—Precipitation of mineral material into intergranular or intercrystalline pore space. Chalk—Fine-textured marine limestone formed by shallow water accumulation of calcareous remains of floating micro-organisms and algae. Clast—A rock fragment. Clastic (rock)—A rock composed of clasts. Compaction—Sediment volume decrease by increase in overburden pressure. Crystallization—Physical and/or chemical conversion of gaseous or liquid material to solid crystal. Diagenesis—The process of converting sediment to rock. Differentiation—The process by which planets and satellites develop concentric layers of different compositions. Dissolution—When solid material in sediment dissolve in interstitial solutions. Dolomite—Calcium magnesium carbonate: CaMg(CO 3 ) 2 . Dolomitization—A volume-reducing recrystallization process, which adds the magnesium ion to calcium carbonate to form dolomite: can occur contemporaneously with deposition or diagenetically. Induration—The hardening of a rock or rock material by heat, pressure, or the introduction of cementing material. Intergranular—Between the grains of a rock. Intragranular—Within the grain of a rock. Lithification—Solidification of sediment to rock: induration, diagenesis. Metagenesis—Late-stage diagenesis to early metamorphism corresponding to dry gas generation and thermally over-mature petroleum source sediments.



Halliburton Energy Services Oxidation—The chemical combination of oxygen with other substances resulting in compositional change and elimination of organic material. Oxidizing environment—A depositional environment in which oxidation occurs. Chemical elimination of organic material occurs in an oxidizing environment. Precipitation—The process by which dissolved materials come out of solution. Recrystallization—The generation of new, usually larger, crystals in a rock. Reducing environment—A depositional or ecological condition in which oxygen is diminished or eliminated. Replacement—A subsurface water process involving solution exchange of one mineral for another in a rock medium. Specific gravity—The ratio of the density of a substance to the density of water. Terrigenous—Derived from the land: terrigenous sediment. Viscosity—The property of a substance to offer internal resistance to flow; its internal friction.


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References Allen, P.A. and J.R. Allen, 1990, Basin Analysis – Principles and Applications: Blackwell Science Ltd., Osney Mead, Oxford. 451. Asquith, G.B., 1982, Basic Well Log Analysis for Geologists: The American Association of Petroleum Geologists, Tulsa, OK. 216. Boggs, S. Jr., 1995, Principles of Sedimentology and Stratigraphy, Second Edition: Prentice Hall, Upper Saddle River, NJ. 774. Hatcher, R.D. Jr., 1995, Structural Geology – Principles, Concepts, and Problems, Second Edition: Prentice Hall, Englewood Cliffs, NJ. 525. Klein, C. and C.S. Hurlbut, Jr., 1977, Manual of Mineralogy: John Wiley & Sons, Inc. New York, NY. 681. Levorsen, A.I., 1954, Geology of Petroleum: W.H. Freeman and Company, San Francisco, CA. 724. Link, P.K., 1982, Basic Petroleum Geology, Second Edition: OGCI Publications, Tulsa, OK. 425. Morris, J., R. House, and A. McCann-Baker, 1985, University of Texas at Austin – Division of Continuing Education, Austin, TX. 234. Press, F. and R. Siever, 1994, Understanding Earth: W.H. Freeman and Company, New York, NY. 593. Tarbuck, E.J. and F.K. Lutgens, 1991, Earth Sciences, Sixth Edition: Macmillan Publishing

Company, New York, NY. 659.




Section 2 Open-Hole terpretation for Cased-Hole Field Professionals Logging and the Reservoir Logging provides data that become the foundation for making the most important decision in the life of a well: plug or complete? It is for this reason alone that we are obligated to provide our clients with the most accurate data possible. In our haste to deliver quality data, many times we lose sight of the “plug versus complete” decision and how logs play a role in it. Our job is to acquire the data. Someone else will interpret them and evaluate the formation…until they ask us to. The overall objective of formation evaluation is to assess a reservoir’s ability to produce hydrocarbon and then use this knowledge to exploit that hydrocarbon by drilling as few wells as possible. This type of analysis requires as much information as can be obtained and is multi-faceted with respect to the source of that information. Formation evaluation incorporates data from seismic surveys, geological studies, mud logs, core data, production information, economic analyses and logs. In many cases, the decision to plug or complete a well is made at the wellsite with nothing more than resistivity and porosity logs. Wireline logs are a critical source of data and might possibly be the only source of subsurface information. They provide us with our “first look” at physical properties of the reservoir. After going to the trouble of planning and drilling a well, logs provide clues about lithology, the amount of fluids present, what types of fluids they are, and whether or not they are producible. Effective and accurate interpretation of logs at the wellsite depends not only upon our knowledge of formation evaluation principles, but also upon our understanding of their limitations. No single physical property recorded on a log is a direct indicator of whether or not a formation contains hydrocarbon. This indirectness is where the science of measuring a formation’s physical properties meets the art of their interpretation. To become proficient in the art of interpretation, we must become familiar with the science of the measurements. Yet, to effectively apply the science of the measurements, we must first be comfortable with the art of their interpretation. Above all, terpretation requires experience, and every expert was once a beginner. 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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Fundamental Formation Properties Log responses can be thought of as being functions of two components of the formation (Fig. 1.2.1), including physical properties of the matrix (solid rock) and physical properties of any pore fluids. Using logs to investigate one usually requires assumptions about the other. Because our main interest is the fluid contained in the pore space, we commonly must assume something about matrix properties. Fortunately, because logs also respond to matrix properties, we have a means of double-checking our assumptions and adding validity to the interpretation.

Fig. 1.2.1—Log Responses are Functions of Matrix Properties and Pore Fluid Properties.

Regardless of what we might like to know about a formation, the measurements presented on conventional open-hole logs (i.e., gamma ray, resistivity, and porosity) have traditionally been used to estimate four fundamental properties of a formation. These include: 1. 2. 3. 4.

Lithology Porosity Fluid saturations Permeability

Logs do not provide direct measurements of these properties. No tool measures lithology, or even porosity. Instead, logs measure other physical properties of the formation that can be related to lithology and porosity. The same is true of fluid saturations and permeability. Together, knowledge of these four properties can be used to determine whether or not a formation contains hydrocarbon and has the ability to produce it. By themselves, these properties are little more than very small pieces of a very large puzzle.




Lithology In simple , lithology refers to rock type. Are we evaluating sandstone, limestone, dolomite, or something else? More correctly, lithology is a property related to the physical character (framework) and chemical composition (mineralogy) of the rock. Knowledge of lithology is vital, if only because it gives us an idea of what to expect. What type of void space might be encountered in a sandstone, and will fluids be able to flow through these voids? What about in limestone? How will a logging measurement react to the formation’s mineralogy? These are questions that must be answered in the early stages of evaluation. No log provides a measure of lithology. Some measurements (gamma ray, neutron porosity, density porosity) investigate interactions between the formation and logging tool at a molecular level and, therefore, depend upon mineralogy. Other measurements (acoustic porosity) are more sensitive to the framework of the formation. All of these measurements give us only indicators to use in determining lithology. Even after the decision to complete a well is made, lithology continues to play an important role. It provides geologists with the information necessary to reconstruct depositional environments so they can streamline future exploratory drilling efforts. It provides reservoir engineers with information about how the rocks will react mechanically and chemically during production optimization treatments, such as hydraulic fracturing and acidizing.

Porosity Porosity (Φ) is a ratio of the volume of void space in a rock to the total volume of rock, commonly expressed as a percentage.



volume of voids total volume of rock

(Eq. 1.2.1)

Hydrocarbon-producing reservoirs can have a wide range of porosities, depending upon lithology and the depositional and diagenetic histories of the rock. Some produce large volumes of fluid from as little as 2% porosity, while others might have as much as 70% porosity (although exceptionally rare). The only means of directly measuring porosity is to have an actual “piece of the rock,” or core sample. On the other hand, various physical properties recorded on logs can be related to porosity and provide estimates rather than measures of this important physical property. Simply knowing the amount of pore space present is not enough. We must be able to determine if the porosity is interconnected and is capable of producing fluids (Fig. 1.2.2). Formations with isolated porosity might very well contain hydrocarbon, but not produce it. Performing multiple types of porosity measurements (e.g., neutron, density, and acoustic) helps answer the question of interconnected pore space.


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Fig. 1.2.2—Porosity can either be interconnected or isolated. Interconnected pores contribute to a reservoir’s ability to transmit fluids, whereas isolated pores do not.

An accurate estimate of porosity using neutron, density, and acoustic logs is vital in terpretation. Combined with a measure of formation resistivity, porosity is used to determine the relative quantities of water and hydrocarbon present. Additionally, porosity estimates make possible the calculation of volumetric hydrocarbon reserves.

Fluid Saturations With an estimate of porosity, the relative proportions of different fluids (water and hydrocarbon) occupying that pore space can be determined by incorporating a measurement capable of distinguishing between them. Water conducts electrical current, and hydrocarbon does not. Therefore, a measure of a formation’s resistivity helps in estimating the relative proportions, or saturations, of fluids (Fig. 1.2.3). Water saturation (S w ) is the fraction of pore space occupied by water. All subsurface formations contain at least some amount of water, while the remainder of the pore space is assumed to be occupied by hydrocarbon. With knowledge of water saturation, a formation’s hydrocarbon saturation (S h ) can be known.

Fig. 1.2.3—Saturation is the Percentage of Pore Space Occupied by a Particular Fluid.



Halliburton Energy Services Fluid saturations, though important, are not necessarily good indicators of a formation’s ability to produce hydrocarbon. Simply because a formation has a water saturation of 30% does not mean it will produce 7 barrels of oil for every 3 barrels of water. At least some small volume of water present in a formation is irreducible, or incapable of being produced. In addition, the formation must have interconnected porosity, and the hydrocarbon present must be moveable in order to be producible. All of these concerns must be addressed. Regardless of their limited use in indicating what a formation will produce, saturations do provide indications of the relative quantities of fluids present. Fluid saturations are essentially the “starting point” for evaluating a formation’s productive potential: Is hydrocarbon present and, if so, how much? Beyond this, the objective is to determine if that hydrocarbon is producible.

Permeability For a rock to produce fluid, it must be permeable. One requirement is that it must contain interconnected pores (Fig. 1.2.4). Absolute permeability (k a ) is a rock property reflecting its ability to transmit a single fluid through its pore space and can only be measured directly from core samples. A rock’s absolute permeability is largely controlled by the diameters of connecting ages between pores (or pore throats). The smaller the pore throat diameter, the more difficult it is for fluid to through and the lower the absolute permeability.

Fig. 1.2.4—Thin-section photograph of limestone containing a large amount of porosity (shaded dark gray), but pores are not interconnected. This rock has no permeability.

Some logging measurements are influenced by the invasion of drilling fluid into permeable formations and can be used as qualitative indicators of permeability. Both the spontaneous potential (SP) measurement and resistivity measurements at multiple distances form the borehole are useful for this purpose. None of these measurements, though, can provide a value of permeability. Short of taking core, perhaps the best method for estimating permeability is from pressure measurements taken with a formation tester like the SFTT or RDT. Permeability indicators on logs are often misleading because absolute permeability might not be the sole factor that determines whether or not a formation can produce the fluids it contains. Formations of interest to us contain two fluids: water and hydrocarbon. 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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These fluids are immiscible, so the possibility arises that one of these fluids might be transmitted through the pore space more easily than the other. Effective permeability (k e ) refers to a rock’s ability to transmit one immiscible fluid when in the presence of another. Unfortunately, effective permeability is almost impossible to assess with conventional wireline logs. Qualitative permeability indicators on conventional open-hole logs should be taken for what they are worth—indicators. Still, by combining several such indicators, it becomes possible to identify those formations likely to produce the fluids they contain.

The Logging Environment It is convenient to think of log responses in of only two contributing factors: matrix properties and pore fluid properties. However, log data are acquired by sensors located in the borehole and which are exposed to the influence of such things as borehole diameter, the resistivity and density of the borehole fluid, and the presence of certain fluid additives. These borehole properties and their influences on log responses must also be considered. While the effects of some borehole characteristics can be minimized through tool design, many can never be completely eliminated. Most residual influence can be reduced through post-processing environmental corrections, but we must first recognize these effects before applying these corrections. The depth to which a formation is invaded by mud filtrate can also have important implications on the accuracy of logging measurements. Fresh water-based mud typically has a high concentration of solids, which leads to the development of mudcake adjacent to permeable formations. As mudcake forms, invasion slows. Saltwater-based mud, on the other hand, contains very little in the way of solids. Because very little mudcake develops with saltwater-based mud, permeable formations might experience very deep invasion. Oil-based mud, although expensive, is typically used in an effort to minimize filtrate invasion, and air will not invade a permeable rock. Logging measurements with shallow depths of investigation may be dramatically influenced by the presence of invaded mud filtrate. Depending upon what type of fluid invaded the formation and whether or not mudcake develops, those measurements with deeper depths of investigation are influenced to different degrees. Invasion of a permeable formation creates a distribution of different fluid types surrounding the borehole (Fig. 1.2.5). An invaded formation can be described in of the types of fluid (invaded or original) that exist within its pore space at different distances from the borehole. The flushed zone is that part of the formation immediately surrounding the borehole in which pores are filled mostly with invaded mud filtrate. During invasion, mud filtrate causes the partial displacement of original formation fluids. Although “flushed” implies that all original fluids were displaced during invasion, some irreducible formation water and hydrocarbon remains. Beyond the flushed zone is the transition zone in which pores are filled with a mixture of invaded mud filtrate and original formation fluids. With increasing distance from the borehole, pore fluids “transition” from mostly invaded mud filtrate to mostly original formation fluids.




Fig. 1.2.5—The Open-Hole Logging Environment (Halliburton, 1994).

Beyond the depth to which mud filtrate invades a permeable formation is found the uninvaded zone. Pores of the uninvaded zone are filled only with original formation fluids (water and hydrocarbon). Measured properties of the uninvaded zone are our greatest interest because they represent the undisturbed formation, but measured properties of the flushed zone and transition zone add to our understanding of the rock’s permeability and the fluids it contains.

Depth of Investigation Limitations The ability of any logging tool to accurately measure formation properties that are representative of the different regions of a formation depend upon elements of tool design and the physics of the measurement. Some logging tools offer shallow measurements that are sensitive to the borehole properties and properties of the flushed zone. Other tools provide deeper measurements that are relatively free of borehole effects and more sensitive to properties of the transition zone or uninvaded zone. Invasion effects differ on measurements acquired at different depths of investigation (Fig. 1.2.6).


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Fig. 1.2.6—Depths of Investigation for Selected Halliburton Logging Measurements.

It may seem desirable that all logging measurements have extremely deep depths of investigation so that only the properties of the uninvaded zone are investigated, but shallow resistivities are also useful. Some formation-evaluation applications take advantage of the fact that different measurements are acquired at different depths of investigation and that some tools offer multiple depths of investigation. In a temporal sense, measurements of the uninvaded zone reflect formation properties prior to invasion, while those in the flushed zone reflect formation properties after invasion. Comparisons between deep and shallow measurements can provide indications about what types of formation fluids (water or hydrocarbon) were displaced from the flushed zone during invasion. The extent of invasion, evidenced by differences in deep and shallow resistivity measurements, provides a qualitative indicator of permeability.

Vertical Resolution Limitations In addition to borehole properties and characteristics of invasion, other factors not directly related to our formation of interest can influence its log responses. The physical design of a logging tool has a strong impact on its ability to resolve very thin formations. Some measurements offer a very fine vertical resolution, meaning they are capable of measuring formation properties without being greatly influenced by overlying and underlying formations. Still, others offer very coarse vertical resolutions and can be dramatically influenced by adjacent formation properties. Formation thickness, therefore, plays a role in determining the accuracy of our interpretation. 102 Cased-Hole Associate Field Professional Vol. I



Environmental Corrections: To Do, or Not? When interpreting logs at the wellsite, you should always keep in mind that most logging measurements are only estimates of the properties they are intended to represent. Even though a measurement might have a deep depth of investigation, it is still influenced by borehole properties to some extent. In some situations this influence may be extreme. Similarly, measurements in permeable formations can be influenced by the invasion of mud filtrate, and measurements in thin formations can be influenced by adjacent formations. Prior to interpreting the logs, environmental corrections might be necessary to either minimize or eliminate the adverse effects of borehole, invasion, and bed thickness characteristics. Failure to perform these corrections when necessary can lead to further error in our analyses. Fortunately, if a logging tool is used to acquire data in the environment for which it was designed, then the magnitude of these corrections is often minimal. However, in those cases where conditions are not optimal, the magnitude of the corrections may make the difference between success and failure.

The Role of Inference and Assumption Regardless of a logging tool’s inability to directly measure a required formation property; regardless of the influence of borehole and invaded mud filtrate; regardless of the tool’s depth of investigation and vertical resolution; and, regardless of whether or not environmental corrections are necessary—open-hole logs often provide the only data to use in evaluating a formation’s productive potential. Considering the hostile borehole conditions in which logging tools are expected to acquire data, they are extremely accurate in their measurements. It is the responsibility of the service company to provide their customers with calibrated and valid data. However, in using these measurements, the log analyst makes a number of inferences and assumptions that can dramatically influence the results of the interpretation. Making assumptions in a process that will ultimately decide whether to plug or complete a well can be intimidating. Such assumptions are often necessary, especially when no core samples are available. (Up to this point in the text, some form of the word “assume” has already been used nine times!) Provided there is some logical basis for our assumptions, we can take some comfort in the knowledge that our interpretation is as accurate as it can be without the benefit of additional information. Keep in mind, however, that additional information means additional cost. Logging companies offer many specialty services that provide their clients with whatever additional information is required. Formation testers, borehole imagers, magnetic resonance logs, and acoustic waveform logs give clients valuable information, but the acquisition and processing of these data is an additional investment that the client may not be willing to undertake. For many clients, the decision to plug or complete a well is based on nothing more than the interpretation of resistivity and porosity logs—oftentimes at the wellsite. Even though assumptions are required as substitutes for missing information, these interpretations 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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are remarkably accurate if the log analyst is familiar with the basic principles and their limitations. Successful decisions can be made even with the most basic logs. If not, then logging companies would never have survived long enough to develop specialty tools! This is the challenge of wellsite terpretation.

Understanding Resistivity Logs Resistivity measurements provided by logs are often poorly understood because we tend to oversimplify them as being a function only of the type of pore fluid present. It is very easy to visualize why a formation containing hydrocarbon has higher resistivity, if only because hydrocarbon is non-conductive. For this reason, novices often equate high values of resistivity with hydrocarbon and low values of resistivity with water. However, the measured value of resistivity is also dependent upon matrix properties. This means that high resistivity does not necessarily indicate hydrocarbon, and low resistivity does not necessarily indicate water. The best way to visualize what controls measured resistivity is to think in of the length of current flow through the formation. Current flow follows the path of least resistance, which, in a clean formation, is through water-filled pore space. The longer the path of current flow, the higher the resistivity. The amount and distribution of any nonconductive fluids (i.e., hydrocarbon) in this pore space influences the path of current flow through the water that is also present. To explain how resistivity measurements respond to changing formation characteristics, each control must first be considered individually before being considered together.

Formation Water Resistivity Before jumping to the complex relationship between resistivity and porosity, we should first consider the simple influence of water salinity. It can be safely assumed that all subsurface formations contain at least some small volume of original water that was either trapped within sediments at the time of their deposition or infiltrated the porous rock sometime later. Depending upon its source, this water can be salty or fresh. Salinity generally increases with depth; however, formation water salinity can be quite variable, depending upon geologic setting. Formation water resistivity (R w ) is a measure of the original formation water’s ability to resist the flow of electrical current, expressed in Ω-m. It is a function of water salinity, and is completely independent of the presence of any non-conductive hydrocarbon or matrix. Measured resistivity of a formation is directly proportional to the resistivity of the water contained in its pore space. The higher the salinity, the lower the R w and, therefore, the lower the value of measured resistivity. Most subsurface formation water is moderately saline, but as mentioned above, there are exceptions to this generality. The relationship between formation water resistivity (R w ) and the measured resistivity of a formation can be expressed as follows:



Halliburton Energy Services (Eq. 1.2.2)

Porosity Although often thought the case, the absolute amount of porosity does not necessarily influence resistivity. This can be proven by considering a porous rock that resembles Swiss cheese (Fig. 1.2.7). In such a rock, there is no way for current to travel through the formation because it cannot through the non-conductive matrix from one waterfilled pore to another. Measured resistivity is infinite. It makes no difference if the amount of porosity is increased or decreased; measured resistivity of such a rock with isolated pores is always infinite. Fortunately, these “Swiss cheese” rocks are the exception rather than the rule.

Fig. 1.2.7—“Swiss cheese” rocks in which all pore space is isolated. A change in porosity does not result in a change in measured resistivity because there is no interconnected path for current to travel through the formation. Resistivity is infinite in both cases.


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However, if we consider the two extremes of porosity (Fig. 1.2.8), it can be demonstrated that resistivity is inversely proportional to porosity. For an open volume of water (where Φ = 100%), measured resistivity equals formation water resistivity (R w ). On the other hand, measured resistivity of a volume of solid matrix (where Φ = 0%) is infinite because, once again, current cannot through non-conductive matrix. Although resistivity is inversely proportional to the amount of porosity, the primary requirement for current to through a formation is the presence of effective pore space. This means that the path of current flow through the formation is controlled by the complexity of the interconnected pore network.

Fig. 1.2.8—For an open volume of water (Φ = 100%), measured resistivity equals formation water resistivity (R w ). For a volume of solid matrix (Φ = 100%), measured resistivity is infinite.

The relationship between measured resistivity and porosity can be expressed as follows:

(Eq. 1.2.3)

Pore Tortuosity Up to this point, the measured resistivity of a formation has been considered only in of formation water resistivity (R w ) and the amount of porosity (Φ). There is a complication in these basic relationships that can be demonstrated by considering two rocks of equal porosity and containing waters of equal salinity (Fig. 1.2.9). The measured resistivity of a formation is strongly influenced by matrix properties, including grain size variations (sorting), grain size and shape, and the presence of cementing minerals. Because of these influences, rocks of the same porosity and containing identical waters can very easily have vastly different resistivities.




Fig. 1.2.9—Two rocks of equal porosity (all effective) and containing waters of equal salinity do not necessarily exhibit equal values of resistivity.

The complexity of the pore network can be represented by its tortuosity. Tortuosity (τ) is a ratio of the total length of current flow through water-filled pore space to the linear length of rock (Fig. 1.2.10). The greater the distance traveled by current over a given length of rock, the greater its tortuosity. If we think about the open volume of water illustrated in Fig. 1.2.8, current flow follows a straight-line path, and the resulting value of resistivity is low (i.e., equals R w ). If this same volume contained spherical beads of nonconductive glass, then tortuosity is increased, and measured resistivity is higher. Current flow must follow a longer path as it wanders around the non-conductive glass beads. This implies that, for a decrease in the amount of effective porosity, there is a corresponding increase in pore tortuosity. Once again, the measured resistivity is inversely proportional to porosity—but we must somehow quantify the effect of pore tortuosity.

Fig. 1.2.10—Pore tortuosity reflects the length of current flow through a water-filled formation. The greater the tortuosity, the higher the measured resistivity.


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Unfortunately, pore tortuosity is a rock property that cannot be measured, even with core. Because it exerts such an important control on resistivity, an appropriate quantifiable parameter that can be substituted for this property is necessary if we are to better define the relationship between measured resistivity and porosity. Such a 1 parameter can be determined by plotting the log of porosity in a water-saturated formation against the log of measured resistivity in that same formation. Data points cluster along a line (Fig. 1.2.11), and the slope of this line (m) can be taken as the coefficient relating pore tortuosity to the measured resistivity of a formation at a given porosity.

Fig. 1.2.11—For a water-saturated formation, a log-log plot of porosity versus measured resistivity yields cementation exponent (m), which relates pore tortuosity to resistivity. R o is the measured resistivity of a water-saturated formation.

The parameter, m, is known as cementation exponent. Its name is derived from the fact that one control on the tortuosity of the pore network is the presence of cementing minerals between matrix grains. As the abundance of cements increases, pore tortuosity increases. Cementation exponent is variable even in the unlikely event that cements are absent. Referring once again to the open volume of water illustrated in Fig. 1.2.8, the cementation exponent for a straight-line current flow is defined as 1.0. As pore tortuosity increases with a decrease in the amount of effective porosity, cementation exponent increases. Cementation exponent (m), unlike tortuosity, is a “measurable” quantity but is not a rock property. It can be derived experimentally from core, and how this is accomplished will be discussed later. For now, it is only important to consider how cementation exponent (m) factors into the relationship between measured resistivity and porosity, expressed as follows:

1

Water saturation is the percentage of pore space that is occupied by water. “Water-saturated” refers to a rock that is at 100% water saturation, meaning that all pore fluid is water.




(Eq. 1.2.4)

The application of this relationship to real-world data was not without its problems. In fact, it was observed early on that the relationship expressed in Eq. 1.2.4 did not work. Rather than completely abandoning the theoretically-sound principle of pore tortuosity and its influence on measured resistivity, an additional parameter was introduced to essentially force-fit the relationship to empirical data. This new parameter was called— confusingly enough—the tortuosity factor (a). Tortuosity factor (a) is not a rock property. It is merely a factor that attempts to compensate for the non-linearity of the empirical relationships observed between measured resistivity and porosity. Taking into consideration both cementation exponent (m) and tortuosity factor (a), the relationship between measured resistivity and porosity can be expressed as follows:

(Eq. 1.2.5)

Further experimental work demonstrated that both tortuosity factor (a) and cementation exponent (m) are variable in different formations. There are no universal values for these parameters that can adequately describe the relationship between measured resistivity and porosity in all rocks. For this reason, core is necessary to experimentally determine tortuosity factor (a) and cementation exponent (m). Where core is not available, assumptions for these parameters can be made based on average values for formations of the same lithology. These assumptions and their limitations will be addressed later.

Fluid Saturations The most often confused aspect of resistivity measurements provided by logs is the influence of non-conductive hydrocarbon. While it is true that an increasing abundance of such non-conductive fluid will increase the measured resistivity of a formation, the true reason for this increase is not often well understood. Measured resistivity of a rock is inversely proportional to the fraction of its pore space that is filled by water. The higher the water saturation, the lower the resistivity. This relationship is expressed as follows:

(Eq. 1.2.6)

Eq. 1.2.6 cannot adequately explain why some formations containing large amounts of effective pore space can produce large quantities of oil and gas and still exhibit exceptionally low values of resistivity, nor can it explain why some high-porosity formations with very high values of resistivity produce only water. The key to 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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understanding the effect of hydrocarbon on measured resistivity once again lies in a consideration of the length of current flow through the formation. The distribution of a non-conductive fluid within the interconnected (effective) pore space of a rock affects the length of current travel and, accordingly, exerts a strong control on resistivity. Fig. 1.2.12 illustrates the same rock at two different water saturations. As the abundance of non-conductive hydrocarbon increases (i.e., water saturation decreases), the conductive path available to current flow becomes longer. Current flow must now wander around the non-conductive matrix and non-conductive fluid. Tortuosity of current flow is increased, so resistivity must increase.

Fig. 1.2.12—The addition of non-conductive hydrocarbon (i.e., a decrease in S w ) increases a formation’s resistivity because of an increase in current flow tortuosity.

As discussed previously, tortuosity is a non-measurable rock property. It makes no difference whether this tortuosity is caused by the complexity of the water-filled effective pore network or the distribution of non-conductive fluids within that pore space; tortuosity remains an unknown. An appropriate parameter that can be substituted for this “fluid tortuosity” is necessary if we are to define the relationship between measured resistivity and the distribution of non-conductive fluids. This can be achieved by plotting the log of water saturation in a formation that contains hydrocarbon against the log of measured resistivity in that same formation. Data points cluster along a line (Fig. 1.2.13), and the slope of this line (n) is a parameter describing the relationship between measured resistivity and the distribution of non-conductive fluids in the pore network at a given water saturation.




Fig. 1.2.13—For a formation that contains hydrocarbon, a log-log plot of water saturation versus measured resistivity yields the saturation exponent (n), which relates fluid distribution to resistivity. R t is the measured resistivity of such a formation, generally approximated by the deepest-reading measurement.

The parameter, n, is known as saturation exponent. A value for saturation exponent (n) can be determined experimentally from core. If core is not available, then an assumption is required. The effect of water saturation (S w ) as a function of the distribution of nonconductive fluids on the measured value of resistivity can be expressed as follows:

(Eq. 1.2.7)

The basis for assuming a value of saturation exponent (n) depends upon formation wettability. Wettability is the preference for one fluid (in the presence of another) to adhere to the grain surfaces of the rock (Fig. 1.2.14). In formations containing both oil and water, water-wet refers to the condition in which water adheres to grain surfaces and oil exists as a discontinuous phase. On the other hand, oil-wet is the condition in which oil adheres to grain surfaces and water is the discontinuous phase. Applying the principle of resistivity as a function of the length of current flow through a rock, it can be demonstrated that water-wet formations typically have lower resistivities than their oilwet equivalents. This is because—all other factors considered equal—the length of current flow through the conductive fluid (i.e., water) depends upon whether it is the continuous or discontinuous fluid in the effective pore space. Most formations are waterwet, and the average saturation exponent (n) determined experimentally in these formations is approximately 2.0.


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Fig. 1.2.14—Wettability refers to the type of fluid that adheres to the grain surfaces of a rock (water or oil). The length of current flow through the conductive fluid (i.e., water) depends upon whether that water is the continuous or discontinuous fluid.

Putting It All Together Up to this point, it has been shown that the measured resistivity of a formation is a function of five separate factors, which can be expressed by the three following relationships: 1. 2. 3. Combining each of these three relationships results in the following expression:

(Eq. 1.2.8)

What should be obvious from Eq. 1.2.8 is that the measured resistivity of a formation is not only a function of the amount of hydrocarbon present. In simplest , measured resistivity depends upon the resistivity of formation water and its distribution within an interconnected (effective) pore network. The distribution of water within effective pore space is influenced by the amount and distribution of non-conductive hydrocarbon; therefore, the resistivity measurement remains a good indicator of the presence of hydrocarbon. What must be ed, however, is that other factors are at work.




R T Versus R XO Resistivity measurements made at different distances from the borehole in a porous and permeable formation respond to different fluids. For any formation, it can be assumed that the rock is homogeneous and that porosity near the borehole is the same as porosity far from the borehole. While this is not always a safe assumption (particularly in carbonates), it provides a starting point from which an investigation into the different types of fluids occupying that pore space can begin. The uninvaded zone is that portion of a formation existing farthest from the borehole and which is not contaminated by the invasion of mud filtrate. Fluid types present in the uninvaded zone included original formation water and, hopefully, hydrocarbon. Ignoring any influence of the borehole on our ability to measure resistivity, we can assume that a resistivity measurement at a sufficiently deep depth of investigation approximates uninvaded zone resistivity (R T ). Therefore, R T depends upon the resistivity of formation water (R w ) and the tortuosity of current flow through this water as determined by the amount and distribution of non-conductive hydrocarbon. This relationship is expressed as follows:

(Eq. 1.2.9)

The flushed zone is that portion of an invaded formation existing closest to the borehole and which extends only a few inches into the formation. Filtrate invasion within this zone causes the partial displacement of original formation water and hydrocarbon. Flushed zone resistivity (R XO ) will depend upon the resistivity of the “water” in that pore space— 2 here, mud filtrate (R mf )—and the tortuosity of current flow as determined by the amount and distribution of non-conductive hydrocarbon remaining in the flushed zone after invasion. By assuming a homogeneous formation and substituting for the resistivity of Eq. 1.2.9, resistivity of the flushed zone (R XO ) can be expressed as follows:

(Eq. 1.2.10)

where: R mf = mud filtrate resistivity S xo = flushed zone water saturation 2

For the purposes of this discussion, we are assuming that mud filtrate is water-based. Water-based mud filtrate is conductive and can, therefore, be distinguished from hydrocarbons on the basis of its resistivity. Oil-based mud filtrate, on the other hand, cannot be distinguished from formation hydrocarbons using a resistivity measurement, and evaluation of logs where it is used is slightly different from those where water-based mud filtrate is present.


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Again ignoring any influence of the borehole on our ability to measure resistivity, we can assume that a resistivity measurement at a sufficiently shallow depth of investigation approximates R XO . As water-based mud filtrate invades a formation, that mud filtrate mixes with original formation water; therefore, R mf may not adequately describe the resistivity of a mixture of both mud filtrate and original formation water. Nevertheless, shallow resistivity measurements are often assumed to be an approximation of R XO . Because shallow and deep measurements of resistivity logs provide estimates of both R T and R XO , Eq. 1.2.9 and Eq. 1.2.10 can be solved for the variables of most interest to our customers—water saturations (S w and S xo ). It is only with the benefit of additional information, such as porosity, water salinity, and the complexity of the pore network that this is possible.

Archie Water Saturation Water saturation of the uninvaded zone (S w ) provides an indication of the relative proportions of water and hydrocarbon existing in the pore space. With a measure of deep resistivity, and assuming that it represents R T , then Eq. 1.2.9 can be rearranged to solve for water saturation of the uninvaded zone in what is referred to as the “Archie equation” as follows:

(Eq. 1.2.11)

Not all fluids existing in effective porosity are moveable. Some water and hydrocarbon is trapped in place by surface adhesion, high capillary pressures within small pore throats, high viscosities, or other factors. Because of this, water saturation of the uninvaded zone (S w ) does not provide a good indication of the relative proportions of fluids that will be produced from the formation. A water saturation of 20% does not mean the formation will produce 2 barrels of water for every 8 barrels of oil. It is simply an estimate of what the formation contains in the subsurface. As such, calculating a value of S w is essentially the starting point for evaluating the producibility of the formation. Water saturation of the flushed zone (S xo ) helps us answer the question of fluid moveability through its comparison with S w . If S xo = S w , then it is an indication that hydrocarbon was not displaced by water-based mud filtrate in the flushed zone during invasion and, therefore, an indication that any hydrocarbon present is not moveable. On the other hand, if S xo > S w , then it is an indication that hydrocarbon was displaced by water-based mud filtrate during invasion and that the hydrocarbon is producible (granted, the formation must be permeable and have sufficient pressure). With a measure of shallow resistivity, and assuming that it represents R XO , then Eq. 1.2.10 can be rearranged to solve for water saturation of the flushed zone as follows:

(Eq. 1.2.12) 114 Cased-Hole Associate Field Professional Vol. I



Limitations of the Archie Approach Novices risk falling into the trap of placing too much trust in their water saturation values calculated with the Archie equation. Much of this misconception results from a poor understanding of the assumptions implied. True values for tortuosity factor (a), cementation exponent (m), and saturation exponent (n) might need to be assumed for lack of core data. However, other limiting assumptions of the Archie equation must be kept in mind when using it to evaluate a formation’s water saturation.

Clean Formation The Archie equation assumes a clean formation, which means one that contains less than 10–15% shale or clay fraction. Physical properties of clay minerals existing in a formation cause porosity estimates to be too high. In addition, because clay minerals in shale are actually conductive, their presence causes our resistivity measurements to be lower than they would otherwise be. To the Archie equation, higher porosity and lower resistivity equates to more water. Therefore, using the Archie equation in shaly formations produces S w results that are too high.

Single Water Phase The Archie equation assumes a single phase of formation water and does not distinguish between water that is producible (or “free”) and water that is irreducible (or “bound”). All formations contain at least some volume of water, part of which is free to produce and the remainder of which is trapped by surface adhesion or capillary pressure in small pore throats. Very fine-grained reservoirs often result in calculated S w values that are high but may produce very little water. This is because a large percentage of that water is made irreducible by surface adhesion and capillary pressure within the small pores. The Archie equation “sees water as water,” and thus provides an estimate of the total water saturation of a formation.

Effective Pore Space The controls on measured resistivity that have been discussed up to this point have all assumed that any pore space present is interconnected, so it should come as no surprise that the Archie equation relies on this same assumption. The presence of any isolated pore space in a rock results in resistivity values being higher than normal because current follows in a much more tortuous path through the formation. In formations that contain such isolated pores, S w results from the Archie equation are often too low.

Water-Wet Formation Finally, the Archie equation assumes that the reservoir is water-wet. When we assume saturation exponent (n) equals 2.0, we are assuming that this parameter reflects the effect of fluid tortuosity on resistivity in an average water-wet formation. In oil-wet formations, S w results from the Archie equation are often too low.


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Determining Tortuosity Factor and Cementation Exponent Obviously, one important concern for calculating water saturations is the reliability of tortuosity factor (a) and cementation exponent (m) values. The importance of core samples in the process of evaluating producibility of a formation can best be exemplified by considering how these parameters are determined when they are available. The relationship between measured resistivity and the porosity of a formation is adequately described by Eq. 1.2.5. Resistivity is a function of the amount of water-filled pore space and its tortuosity. Suppose that a core sample is available and that all fluids existing in its pore space can be evacuated. Porosity of the core sample can then be measured by one of several methods. The evacuated pore space of this core sample can then be saturated with a brine of known salinity (i.e., known R w ). The resistivity of this water-saturated core sample (R o ) can then be expressed as follows:

(Eq. 1.2.13)

If porosity and formation water resistivity (R w ) are known, then cementation exponent (m) can be solved by holding tortuosity factor (a) constant. The constant value chosen for tortuosity factor is usually 1.0, which is based upon the assumption of an inverse 3 linear relationship between resistivity and porosity (see Eq. 1.2.3). It is by this method that the tortuosity factor and cementation exponent are determined experimentally from core samples. Rotary sidewall coring often provides a core sample of sufficient size for performing such tests. But what if a core sample is not available? Whole coring is a costly investment, and wireline coring poses certain risks and associated costs. Values for tortuosity factor and cementation exponent must still be obtained so that the water saturation of the formation can be evaluated. Assumptions are required in the absence of core-derived data. The most commonly assumed values for tortuosity factor and cementation exponent are illustrated in Fig. 1.2.15. The basis for these assumptions is experimental studies of core data, so there is at least some validity in their use. However, assumed values might not be appropriate for the formation being evaluated, and the potential uncertainty resulting from these assumptions must be kept in mind.

3

Notice that, even when core is available, assumptions are still involved with its analysis.




Fig. 1.2.15—Typical Assumed Values for Tortuosity Factor and Cementation Exponent.

An understanding of the meaning of cementation exponent values as they apply to pore tortuosity becomes important later in the qualitative interpretation of resistivity logs. Fig. 1.2.16 pictorially illustrates how cementation exponent (m) varies as a function of pore tortuosity. Cementation exponent, itself, does not depend upon the additional tortuosity of current flow through a formation caused by the introduction of non-conductive hydrocarbon. That “fluid tortuosity” is quantified by the saturation exponent, as discussed earlier.


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Fig. 1.2.16—Cementation exponent (m) varies as a function of pore tortuosity. In the illustrated rocks, pore space is water-saturated; therefore, current flow tortuosity is only a function of pore tortuosity.

The most important things to keep in mind when assuming values for tortuosity factor (a) and cementation exponent (m) are that the values listed in Fig. 1.2.15 represent clean formations that contain effective porosity. Where these conditions are not met, the assumptions are inappropriate, and there is not a reliable method for predicting their values in those instances. Make the most reasonable assumptions based on the information available to you, but also realize potential uncertainty in your calculations.

Determining Formation Water Resistivity (R W ) Oddly enough, the reservoir fluid that is most important to the accurate evaluation of a formation is not hydrocarbon, but water. Water—whether salty or what we consider to be “fresh”—s the flow of current through formations with interconnected pore space, thereby allowing their finite resistivities to be measured. Any current flow through a clean, shale-free formation occurs in water, and not in rock matrix or hydrocarbon. Water’s ability to conduct current is proportional to its salinity, and saltwater, with its high concentration of dissolved solids, is a better conductor than fresh water. Both saltwater and fresh water are better conductors than matrix or hydrocarbon, which are electrical insulators. Formation water resistivity (R w ) is one of the critical variables for determining water saturation. While small errors in values of R w might not cause critical uncertainty in S w calculations, larger errors in R w can make the difference between deciding to complete 118 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services or abandon a potential reservoir. A value of R w that is too high causes us to overestimate the amount of water present (i.e., higher S w ), and one possible result might be to overlook a hydrocarbon-productive formation because we believe it contains too much water. On the other hand, a value of R w that is too low can cause us to become interested in a formation that contains a large volume of water but not enough hydrocarbon to be economical. There are many potential sources for a value of formation water resistivity (R w ), the most accurate of which tend to be actual water samples from the formation of interest. These samples can be taken from formation testers, such as SFTT and RDT, drill-stem tests (DST), or even produced water. Each source has its distinct advantages and disadvantages. Water catalogs are another potential source in many geographic regions where records of R w have been maintained for many years. These cataloged R w values are derived from actual water samples, so their use is subject to the limitations of whatever method was used to collect them. In many cases, for lack of a water sample or water catalog, it may be acceptable to assume some commonly used R w value for the particular geographic region. Resistivity and porosity measurements provided by logs can also be used to derive formation water resistivity (R w ) when no other source is available, or when it is desirable to cross-check values from those of another source. While there are several methods for obtaining R w from logs, the most straightforward method involves observing resistivity and porosity responses to locate a formation that obviously contains water and assuming that it is water-saturated (S w = 100%). For a formation that is completely water-saturated, Eq. 1.2.11 can be solved for R w as follows:

(Eq. 1.2.14)

The Danger in Calculating Water Saturation Armed with little more than an idea of lithology and measurements of resistivity and porosity, it is possible to calculate water saturation (S w ) of a clean formation with the Archie equation (Eq. 1.2.11). It becomes the simple task of reading values from a log, assuming some parameters, plugging them into the equation, and calculating a result. However, this is where our evaluation of a formation’s producibility can become anything but simple. A common oversight is to calculate S w and automatically accept it as valid. Very little thought is given to matrix and fluid properties influencing the log measurements (particularly resistivity). Oftentimes, the validity of assumptions is rarely questioned, and rarely is the possibility of uncertainty considered. Our failure to recognize how matrix and fluid-related properties affect logging measurements, how the resulting error is compounded by uncertainty in our assumptions, and how inaccurate our S w results can quickly lead to mistakes. Once a formation is completed and its production confirms what was predicted by S w calculations, the venture is deemed a success and our confidence in terpretation 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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grows. When a formation’s production contradicts its calculated S w , however, the accuracy of the log measurements—rather than the accuracy of our interpretation of them—is often called into question. By the time oversights, mistakes, and uncertainties are recognized, it may be too late to take remedial action. Production casing might have already been set, or the well might have already been plugged. The effective interpretation of a formation’s producibility requires a thorough understanding of the measurements, variables, assumptions, and calculations involved.

Understanding Porosity Logs Even using the best technology available, porosity cannot be measured with any wireline tool. This usually comes as a surprise considering the fact that neutron, density, and acoustic porosity curves are presented on clients’ logs. The porosity values we present on logs are only estimates derived from measurements of other formation properties that can be related to porosity. Density porosity and neutron porosity can be used to demonstrate this principle. The bulk density (ρ b ) of a formation measured by the SDLT is dependent upon three factors, including: 1. The density of the solid rock (matrix) within the measured volume 2. The volume of void space (porosity) within the measured volume 3. The density of the fluid(s) filling any void space present Of these three factors, the one of greatest interest to our clients is porosity. From a measurement of ρ b , it is only possible to derive a value for porosity if the matrix density and fluid density are known or assumed. Very rarely does the client know the precise rock or fluid properties before we log the well. (After all, that is why we are logging the well—to learn more about formation properties!) Density porosity is calculated from a linear relationship with ρ b and using assumed values for matrix density and fluid density. The density porosity curve that appears on a log is only as accurate as our two assumptions that were used to calculate it. The same principle applies to the porosity estimates from a neutron tool. The DSNT measures the distribution of thermal neutrons in a formation. This distribution is related to the abundance of hydrogen and, assuming all hydrogen exists in pore fluids, can be used to estimate porosity. Just like ρ b , the distribution of thermal neutrons is also related to matrix properties as well as fluid properties. To estimate porosity with a neutron tool, we must also make assumptions and, once again, our estimate is only as accurate as the two assumptions. In this chapter, we will examine the assumptions involved in calculating porosity with the SDLT and the DSNT, and how inaccuracies in our assumptions can affect their validity. We will also examine how SDLT and DSNT response can be used to determine lithology. Lithology and porosity are closely related rock properties, and, to better understand our estimates of these properties from logs, they must be considered 120 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services together. An early understanding of these basics (presented here in a non-technical approach) helps to simplify more detailed quality control and interpretation issues.

Two Porosities are Better than One By now you have probably noticed that density porosity and neutron porosity are frequently presented together. There is a simple reason for this: by itself, one estimate of porosity is not very useful because it depends upon too many unknowns. A change on the density porosity curve or the neutron porosity curve might truly represent a change in the porosity of the formation, or that same change might also result from a change in the type of matrix or the type of fluid. The fact of the matter is that we do not know what is causing the change if we have only one porosity curve. As an example, consider a density porosity curve that reads 20% in a particular formation. Is 20% porosity correct for that rock? You can look at the log header and determine what assumptions were used to calculate porosity. But by simply knowing those assumptions, is the value of 20% porosity correct? You still cannot conclude because you are working only with assumptions at this point. Because any porosity estimate involves two unknowns (matrix and fluid), there must be some other independent method of solving for both of these unknowns if we are to place any confidence in our porosity estimate. A second porosity curve fits this requirement. Density porosity and neutron porosity curves are calculated assuming the same matrix and the same fluid can be used together to gain more confidence in our assumptions and, therefore, the accuracy of the porosity estimate. If both density porosity and neutron porosity curves read 20% for the same rock, then we can be more confident—though still not absolutely sure—that our assumptions are correct. Still, more information is needed (e.g., another lithology indicator and resistivity, if available). Two porosity curves that read the same value and that are calculated with like assumptions indicate a greater probability that the matrix and fluid assumptions are correct. Notice the important phrase here: a greater probability. Equal curve values do not prove that the assumptions are met; they only mean that there is a better chance. But, what if the two porosity curves are not the same?

Two Porosities? A rock has one, and only one, value of porosity, but it is quite common to see neutron porosity and density porosity values on a log that are not equal. This condition indicates one thing: your matrix and fluid assumptions are not met. Two porosity values that are not equal but that were calculated with like assumptions can be used to conclusively indicate your assumptions are incorrect. By process of elimination, you have ruled out one possible solution for lithology. An important characteristic of density porosity and neutron porosity is that their responses tend to be opposing. We will not yet worry about why this is the case, other 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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than to say that where one is overestimated, the other is underestimated, and vice versa. Any difference between density porosity and neutron porosity estimates on a log can assist in determining formation lithology and—interestingly enough—a more accurate value for porosity. Why? Because the curves are different, you already know what the rock is not. Now you must discover what the rock is.

Photoelectric Factor (P e ) The photoelectric factor (or P e ) curve provides one of the fastest, though not necessarily most accurate, methods of determining lithology from logs. All minerals have characteristic P e values that depend upon their chemical compositions (Fig. 1.2.17). However, all rocks contain more than just one mineral, so the P e response of a formation is best used as an indicator of its predominant lithology.

Fig. 1.2.17—Characteristic P e Values of Minerals Common to Sedimentary Rocks.

Lithology determination is not always as easy as reading a P e value. As an example, consider the mineral calcite, which is the primary component of limestone. Not all limestones have a P e of 5.08 because other minerals besides calcite are present. Minor amounts of quartz or clay minerals cause limestone P e values to be lower than 5.08. Similarly, most dolomites contain at least some small percentage of anhydrite, resulting in a P e greater than 3.14. For rocks having approximately the same P e (e.g., limestone and anhydrite), it is impossible to distinguish between them on the basis of P e alone. Further complicating this is the fact that rarely do we deal with pure lithologies. For that reason, additional lithology indicators like gamma ray, neutron porosity, density porosity, and even resistivity are essential.

Starting Out Simple The first things to consider when working with porosity logs are the matrix and fluid assumptions and the porosity scales. Matrix and fluid assumptions are defined by client request, and are found in the Parameters Report or Header of the log. Clients often request certain matrix assumptions based on what types of rocks they expect to encounter; however, in geographic areas where complex lithologies are the rule, porosities are often calculated assuming limestone. By first considering the matrix and fluid assumptions, you have a known reference for determining lithology. Porosity scales, also defined by client request, are usually based on how much porosity is 122 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services typically expected in the rocks to be logged. By considering porosity scales, you can establish references for estimating more accurate porosity values as well as identifying lithology. Fig. 1.2.18 illustrates a neutron-density log where porosity curves are calculated assuming a limestone matrix and water-filled pore space. Knowing this, and as a first approximation, we can say there is a good probability that water-filled limestone exists where neutron porosity and density porosity curves equal. Such a lithology estimate can be confirmed by considering the P e response. If both porosity curves equal and P e reads approximately 5, the most probable solution for lithology is limestone. The importance of using combined neutron-density responses to confirm or reject lithology estimates based on P e response can also be demonstrated with Fig. 1.2.18. Notice that P e responses in both the limestone and anhydrite intervals are the same (approximately 5). Without some other indicator besides P e , it is impossible to distinguish between these two lithologies. Gamma ray responses in these intervals are also very similar. However, neutron porosity and density porosity curves do not overlay in the anhydrite interval. This means that the matrix and fluid assumptions are not correct for that interval, and that its lithology cannot be limestone. Anhydrite is proven by the fact that density porosity reads a strongly negative value (a characteristic to be discussed later in this chapter). Notice also in Fig. 1.2.18 that porosity curves do not overlay in the sandstone interval where density porosity is greater than neutron porosity. This is because a limestone matrix was assumed for calculating porosities, and the lithology of this interval is not limestone (as confirmed by the P e response). Anytime porosity curves do not overlay because of an incorrect matrix assumption, the response is referred to as matrix effect. Matrix effect can result in the cross-over of porosity curves (see the sandstone and halite intervals where Φ D > Φ N ) as well as separation of porosity curves (see the shale, dolomite, and anhydrite intervals where Φ N > Φ D ).


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Fig. 1.2.18—Neutron-density log showing porosity curves calculated assuming a limestone matrix and water-filled pore space. Only in limestone are both porosity curves equal and P e approximately 5.

Imagine what would happen to the porosity curve responses above (Fig. 1.2.18) if shale was added to the sandstone interval. A “true” shale is characterized by a neutron porosity that is much greater than density porosity. Adding shale to the sandstone causes its neutron porosity to increase and its density porosity to decrease, thereby reducing the magnitude of the matrix effect cross-over. At some volume of shale, the neutron and density porosity curves will actually overlay, giving the impression that the interval is limestone. A quick glance at the P e curve should confirm that the interval is not limestone because it will not read ~5.0.



Halliburton Energy Services Determining lithology from neutron-density responses is not always as easy as these few examples make it appear and is almost an art that requires practice in order to master. For this reason, we will take a closer look at how neutron-density logs and other logs can help answer the lithology question before we deal with the porosity question.

Lithology Indicators In most cases, determining a formation’s predominant lithology can be accomplished by a quick glance at the P e curve. This is particularly true in regions where there is little variation in the types of rocks logged. In other regions where many different rock types exist in a single well or where formations have complex mineralogies, lithology determination often relies upon indicators provided by several curves. A brief look at the applications of some other lithology-dependent measurements helps.

Gamma Ray Indicators Gamma ray is considered by some to be the primary lithology indicator, but its use as such is actually very limited. The gamma-ray curve responds to a formation’s natural radioactivity—principally from potassium, uranium, and thorium—and shale often contains higher concentrations of these elements than other rocks. High gamma-ray responses often indicate shale, but it should be kept in mind that gamma ray in shale can range from as low as 70 to several hundred GAPI units. Using gamma ray to identify the lithology of a rock that is not shale is much more problematic. Sandstone, limestone, and dolomite generally contain lower concentrations of radioactive elements than shale, so their gamma ray responses are low in comparison. However, this is not always the case. Some dolomites can exhibit high gamma-ray responses because of trace amounts of uranium. Although uranium is not a typical chemical component of dolomite, its size is such that it fits well within dolomite’s crystal structure. As a result, these “hot dolomites” can be easily confused with shale. In addition, “sandstone” is not always quartz sandstone. The “granite wash sands” of the Texas Panhandle consist of grains of orthoclase rather than quartz. Orthoclase contains large amounts of potassium and can result in a gamma ray response that is easily confused with shale. In summary: Never trust in a gamma ray curve as the sole indicator of lithology!

Resistivity Indicators Resistivity is most commonly used to identify the type of fluid present, but it also has limited use as a shale indicator. Shale, unless fractured, is impermeable and not invaded by mud filtrate. Resistivity measurements at multiple depths of investigation in shale are equal, and, because of the conductive nature of clay minerals, measured resistivities are often low (commonly 1–10 Ω-m). Resistivity can also be used to indicate tight (low-porosity) formations because of its inverse relationship to porosity. Evaporite rocks (e.g., anhydrite and halite) lack porosity 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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and exhibit exceptionally high values of resistivity. Low-porosity limestones and dolomites can exhibit equally high values. The primary use of resistivity as a lithology indicator is to distinguish something that is shale from something that is not shale. More than any other lithologies, novices tend to confuse shale and dolomite because of their similar nuclear responses. Gamma ray, P e , and neutron-density responses of these two rocks can be virtually identical. In many cases, the simplest means of distinguishing one from the other is a resistivity curve.

Neutron-Density Indicators By themselves, neutron porosity and density porosity curves cannot be used to determine lithology to any degree of accuracy. Neutron porosity is calculated from a measure of the distribution of thermal neutrons in a formation, which varies as a function of fluid type, amount, and rock type. Density porosity is calculated from a measure of a formation’s bulk density, which also varies as a function of fluid type, amount, and rock type. Variations in the type and amount of pore fluids can easily be mistaken as a change in lithology if only one porosity curve is considered. For now, it is important to understand that the calculation of neutron and density porosity values appearing on a log requires assumptions of lithology and fluid type. Most porosity curves are calculated assuming a limestone matrix, although sandstone and (much less frequently) dolomite are other possibilities. Most porosity curves are also calculated assuming that any pore space is filled with water. If neutron and density porosity curves appearing on a log are calculated with like assumptions, then together they can be used to determine lithology. It may seem like a circular argument, but it works! Two rules of thumb can help you in using neutron-density logs to determine lithology. They include: 1. Always consider the matrix assumption and fluid assumption used to calculate neutron porosity and density porosity. 2. Never exclude the P e curve or gamma-ray curve from lithology estimates based on neutron-density responses.

Other dicators Almost every logging measurement (with the possible exception of MRIL) has at least some small dependency on lithology and can be used, to some degree, for estimating the rock type. Spontaneous potential (SP) usually displays a static response in shale while showing deflections in permeable formations. The caliper can even be used to distinguish shale from harder formations, such as sandstone and carbonates that are much more resistant to erosion caused by the drill bit. Whatever the method used, your lithology determination should always include information from as many curves as possible. The limitations of each measurement should also be considered. When will this curve be useless as a lithology indicator? How is this response influenced by shale? Never trust in one lithology indicator while ignoring all the others.




After Lithology, What Next? Once lithology is determined, that information becomes critical in many different applications. Geologists can predict what type of pores might be present and whether or not they are interconnected and capable of producing fluids. Based on lithology information from several wells within an area, they might be able to reconstruct depositional environments in an effort to determine the best locations for drilling future wells. Reservoir engineers gain vital clues about how effective stimulation treatments, such as hydraulic fracturing and acidizing, might be. At the wellsite, lithology estimates are necessary for assuming variables required to calculate water saturation. In some cases, quick-look methods of determining the predominant lithology might not provide the amount of detail necessary. True, the formation may be mostly quartz sandstone, but is the smaller fraction calcite, dolomite, or some other mineral? In situations where relative proportions of different mineralogy components are required, a number of software applications and graphical methods are available.

Porosity Estimates from Logs Porosity (Φ) is defined as the ratio of the volume of void space in a rock to the total volume of rock, often expressed as a percentage.



volume of void space total volume of rock

(Eq. 1.2.15)

Porosity is a rock property that can only be measured if a core sample is available. Because of the costs and risks involved, core is rarely taken, and no logging tool provides a measure of porosity. Various physical properties of a formation can be, however, related to its porosity. Bulk density, the velocity of acoustic energy, and the distribution of thermal neutrons are all measurable properties than can be used to estimate porosity. The bulk density (ρ b ) of a formation is a function of the rock’s matrix density, the amount of porosity, and the density of fluids filling that pore space. If lithology and fluid type is known or assumed, then porosity can be calculated from a measure of bulk density. Similarly, the velocity of a compressional acoustic wave through a formation is a function of its velocity through the rock matrix, its velocity through the pore fluids, and the amount of pore fluids present. If lithology and fluid type is known or assumed, then porosity can be calculated from a measure of compressional wave velocity. Finally, all pore fluids (gas, oil, and water) contain hydrogen. Assuming that hydrogen is present only in pore fluids and not the rock matrix, a measure of a rock’s hydrogen abundance (with the neutron tool) can be used to estimate porosity. Each of these methods requires assumptions, and the porosity values obtained from density, acoustic, and neutron tools should only be considered estimates. While it is true that a formation’s measured bulk density, compressional wave velocity, and hydrogen 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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abundance are related to pore fluids, they are also related to the rock matrix. Only when we are sure of lithology can we be confident in the accuracy of porosity estimates these tools provide.

Total Porosity versus Effective Porosity When interpreting porosity logs, it is important to consider how porosity contributes to producibility. A rock might contain a large amount of void space, but fluids occupying those voids will not be producible if there is no interconnectivity between the voids. Enter the concept of total porosity versus effective porosity. A formation’s porosity depends upon both depositional processes and the sequence of chemical and physical changes that affect the rock after deposition (diagenetic processes). When sand-sized sediments are deposited, well-interconnected pores exist between them. The amount of original porosity depends upon characteristics of the sediments themselves, such as their sorting, packing, roundness, and sphericity. Geologists refer to pore space created during deposition as primary porosity (Fig. 1.2.19).

Fig. 1.2.19—Examples of Primary Porosity in Sedimentary Rocks.

Diagenetic processes that alter a rock after its deposition can dramatically reduce or increase its original porosity. In some cases, primary porosity existing at the time of deposition is reduced by compaction and cementation of sediments. In other cases, pore space can actually be created after deposition by dissolution or fracturing of rock matrix. This is particularly true in carbonates. Pore space created after deposition is known as secondary porosity, examples of which are illustrated in Fig. 1.2.20.



Halliburton Energy Services Fig. 1.2.20—Examples of Secondary Porosity in Sedimentary Rocks.

As defined here, “primary” and “secondary” refers only to the timing of porosity development. To the log analyst, the degree of interconnectivity of these pores is of far greater importance than the time at which they were created. Both primary and secondary pores can either be interconnected or isolated, but isolated pores do not conduct fluids and do not contribute to a formation’s permeability. terpretation requires a different definition of pore types, one that can be related to producibility. Effective porosity (Φ E ) refers to pore space that is interconnected, while isolated porosity refers to pore space that is not. Together, these fractions of interconnected and isolated pores contribute to the formation’s total porosity (Φ T ).

Density Porosity (Φ D ) Estimates

The bulk density (ρ b ) of a formation is a function of three variables: the rock’s matrix density (or grain density), the amount of pore space present, and the fluid density of whatever fluid occupies the pore space. If lithology and fluid type are known, then a measure of bulk density can be used to calculate porosity by the following linear expression:

(Eq. 1.2.16)

Lithology and fluid type are rarely known to any degree of accuracy before logging, and both matrix density (ρ ma ) and fluid density (ρ fl ) in Eq. 1.2.16 are input assumptions based on client requirements. This means that density porosity (Φ D ) is only correct when those assumptions are met, and that we must know the lithology of a formation to gain confidence in the accuracy of Φ D . Furthermore, Φ D provides us with an estimate of the formation’s total porosity. The assumption for matrix density (ρ ma ) is often based upon the lithology of formations expected to be encountered while logging. If formations of interest are mostly limestone, then the client might require a limestone matrix density assumption. If formations of interest are mostly sandstone, then the client might require a sandstone matrix density assumption. Regardless, we must that Φ D is most accurate when that assumption is correct. Commonly assumed values for matrix density include the following:   

Sandstone (quartz)—2.65 g/cc Limestone (calcite)—2.71 g/cc Dolomite—2.87 g/cc

At this point, it is easy to see why anhydrite displays a strongly negative density porosity (see Fig. 1.2.18). If the measured bulk density of a rock (ρ b = 2.98 g/cc for anhydrite) is greater than the matrix density assumption, then Φ D will be negative according to Eq.


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1.2.16. When assuming a limestone matrix (ρ ma = 2.71 g/cc), Φ D in anhydrite is approximately -15%. In many cases, clients request that Φ D be calculated assuming a limestone matrix even when they know their formations of interest are mostly sandstone. In doing this, the client is aware that Φ D is incorrect in sandstones, but limestone is an “industry standard rock” and many clients expect to see responses that are based on a limestone assumption. With another porosity measurement, such as that from the neutron tool, the inaccuracy of the matrix assumption can be recognized and dealt with. The assumption for fluid density (ρ fl ) is based upon the density of the borehole fluid. The depth of investigation of the bulk density measurement is very shallow (about 7 in.), and, in a permeable formation, it is reasonable to assume that pores within this zone of investigation are mostly filled with invaded borehole fluid. Fluid density assumptions, therefore, depend upon the type of drilling fluid used. Commonly assumed values for fluid density include the following:    

Fresh water-based mud—1.0 g/cc Saltwater-based mud—1.1 g/cc (or 1.15 g/cc) Oil-based mud—0.85 g/cc (variable, depending upon mud) 4 Air-drilled borehole—1.0 g/cc (see footnote )

Density porosity (Φ D ) calculated using these matrix and fluid assumptions is not very useful by itself. Because of the combined matrix and fluid dependencies, it is possible to mistake a change in fluid type as a change in porosity. More likely is the possibility of mistaking a change in lithology as a change in porosity. For best results in estimating a formation’s total porosity, the Φ D measurement must be used in combination with another porosity measurement, usually neutron porosity. For now, it is important to understand that Φ D is only correct when our assumptions are met.

Neutron Porosity (Φ N ) Estimates

All pore fluids (whether gas, oil, or water) contain hydrogen, so a measure of the formation’s hydrogen abundance can provide an estimate of its fluid-filled volume. This is, of course, assuming that the rock matrix itself contains no hydrogen. Neutron porosity (Φ N ) is based upon this concept, and is used to estimate a formation’s total porosity. Unfortunately, the neutron tool’s measurement of hydrogen abundance is not solely dependent upon the amount of fluid present (i.e., porosity). There is also a lithology effect; some lithologies are better disposed to slowing and absorbing neutrons than others and mislead us as to the actual hydrogen abundance. To determine an accurate value of porosity with the neutron measurement, we must assume that the formation logged is a certain lithology. This principle is identical to that of calculating density porosity. 4

In an air-drilled borehole, it is always assumed that the fluid that fills pores of the flushed zone (i.e., close to the borehole) is water, regardless of mud type.



Halliburton Energy Services When logging a neutron tool, a neutron lithology is assumed, and Φ N will be the most accurate when this assumption is met. If we assume limestone and log through a sandstone, then Φ N will be in error. However, if we assume sandstone and actually log through a sandstone, then Φ N will be more accurate, and any remaining inaccuracy is a function of the hydrogen abundance of any pore fluid. The neutron lithology assumption must match the matrix density (ρ ma ) assumption for density porosity if we are to use the neutron and density porosity curves together for any purpose. Commonly assumed neutron lithologies include the following:     

Sandstone Limestone Dolomite Limey sandstone Limey dolomite

Apart from the lithology effect on hydrogen abundance, there is also a fluid effect. Some pore fluids contain a larger amount of hydrogen per unit volume than others. For example, gas contains much less hydrogen per unit volume than water and oil. This means it is possible to mistake a change in fluid type as a change in porosity when only considering Φ N . For this reason, and much like density porosity, Φ N has very little use as the sole indicator of porosity. Neutron porosity (Φ N ) is always calculated assuming that pore space is filled with fresh water. While the reason for this may seem confusing at first, it is simply because oil and water contain very similar amounts of hydrogen per unit volume. If our neutron lithology assumption is correct for the formation of interest, then oil-filled pore space and waterfilled pore space will show little, if any, difference in Φ N . Gas-filled pore space, on the other hand, causes a noticeable difference in Φ N when compared to water-filled or oilfilled pore space. In the next section of this chapter, we will consider how a change in fluid type affects the neutron tool’s response, and how we can determine an accurate value of porosity when our assumptions do not agree with the true rock and fluid properties.

Combined Neutron-Density Porosity Estimates Individually, neutron porosity (Φ N ) and density porosity (Φ D ) represent a formation’s total porosity. Both values are dependent upon matrix and fluid assumptions, and only when the actual lithology and fluid type matches our assumptions do these two porosity values have the greatest probability of being correct. It is for this reason that both Φ N and Φ D , when presented together, must assume like lithologies. Fig. 1.2.21 again illustrates a neutron-density log where both porosities are calculated assuming a limestone matrix and fresh water-filled pore space. This implies that both porosities are only correct in limestones that contain fresh water. A quick glance at the interval labeled “Limestone” confirms this: Φ N and Φ D overlay in this interval where P e ≈ 5. It is, indeed, a limestone.


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Estimating total porosity in this limestone interval is easy. Both porosity curves display the same value (~ 15%); therefore, 15% must be the total porosity of that limestone. However, the sandstone interval (where P e ~ 1.8), immediately below the limestone, exhibits cross-over resulting from an incorrect matrix assumption. How can total porosity be estimated in this sandstone interval where the two porosity curves are different? Recall that neutron porosity and density porosity often exhibit opposing responses. Where Φ N is underestimated because of an incorrect matrix assumption, Φ D is overestimated, and vice versa. It is logical to expect that a fairly accurate value for total porosity of the sandstone might be determined by taking the average of the two porosity values. Because the matrix effect on one porosity curve is not equally opposite the matrix effect on the other porosity curve, a weighted average can be used. Cross-plot porosity (Φ XP ) is one means of estimating total porosity based on a formation’s neutron and density responses, regardless of the accuracy of matrix assumptions. Cross-plot porosity is calculated by the following equation:

(Eq. 1.2.17)




Fig. 1.2.21—Neutron-density log showing porosity curves calculated assuming a limestone matrix and water-filled pore space. Only in limestone are both porosity curves equal and P e approximately 5.

Using Eq. 1.2.17, it is possible to estimate the total porosity of the sandstone interval even though Φ N and Φ D are calculated assuming limestone. Similarly, the same equation can be used to estimate total porosity of the dolomite interval, even though porosity curves there exhibit separation instead of cross-over. Cross-plot porosity (Φ XP ) is an acceptable method of estimating total porosity when lithology does not match the matrix assumption. However, it should be used with caution. Eq. 1.2.17 should not be applied in evaporite formations, such as halite and anhydrite. Halite (see Fig. 1.2.21) contains no pore space and Φ D calculated assuming 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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any matrix results in a dramatic overestimate of porosity (because halite has such a low ρ b ). Applying Eq. 1.2.17 in evaporite formations results in values of total porosity that are too high. Fig. 1.2.22 changes things slightly and illustrates a neutron-density log where both porosities are calculated assuming a sandstone matrix and water-filled porosity. This implies that both porosities have the greatest probability of being correct in water-filled sandstone.

Fig. 1.2.22—Neutron-Density Log Showing Porosity Curves Calculated Assuming a Sandstone Matrix.



Halliburton Energy Services Notice in Fig. 1.2.22 that Φ N and Φ D overlay across the interval labeled “intermediate oil or water.” When both porosity curves provide the same value, it is a fairly accurate (though not conclusive) indication that our assumptions are met. This interval is sandstone (which can be confirmed from the P e value of ~ 1.8). However, notice that cross-over develops between Φ N and Φ D curves at shallower depths within the same low gamma-ray sandstone interval. In this example, lithology remains constant, but fluid type changes. Neutron porosity (Φ N ) and density porosity (Φ D ) are almost always calculated assuming all pore fluid is water. The two curves should overlay in formations containing water that are of the same lithology as the matrix assumption (sandstone, as indicated in Fig. 1.2.22). As the pore fluid changes from water to intermediate oil to light oil to gas, the amount of cross-over between Φ N and Φ D increases. Gas contains much less hydrogen per unit volume than water; therefore, a formation that contains gas will have a lower Φ N than one that contains water in an equal volume of pore space. Similarly, gas has a much lower fluid density (ρ fl ) than is assumed in Eq. 1.2.16 for calculating density porosity (ρ fl = 1.0 g/cc for water). As a result, Φ D of a formation containing gas is higher than that of a formation containing water in an equal volume of pore space. Comparing Fig. 1.2.21 with Fig. 1.2.22 reveals that incorrect lithology assumptions and the presence of gas can result in similar neutron-density crossover. Notice that in the case of gas, Φ N and Φ D curves display mirror-image responses, whereas an incorrect lithology assumption generally results in two curves that follow the same trend (one increasing with the other, and vice versa). Recognition of these curve shapes provides a basis for distinguishing formations that contain gas from those logged with incorrect matrix assumptions. Again, the P e curve is also useful for helping confirm lithology.

Acoustic Porosity (Φ S ) Estimates

The velocity of a compressional-acoustic wave through a formation is a function of three variables: its velocity through the rock’s matrix, the amount of pore space present, and its velocity through the fluid occupying the pore space. If lithology and fluid type are known, then a measure of compressional-acoustic velocity can be used to calculate porosity. As was the case with density porosity, lithology and fluid type are rarely known beforehand and require assumptions. Rather than presenting velocity information, acoustic logs present delta-t (∆t). Delta-t, or interval transit time, is simply a reciprocal of velocity, and its absolute value is much smaller and easier to deal with than values of velocity. Acoustic porosity (Φ S , or “sonic” porosity) that appears on a log is calculated using the following linear equation:

(Eq. 1.2.18)


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As was the case with the density porosity equation (Eq. 1.2.16), Eq. 1.2.18 requires input assumptions for matrix delta-t (∆t ma ) and fluid delta-t (∆t fl ) that depend upon client requirements. Therefore, acoustic porosity (Φ S ) will only be accurate when those assumptions are met. We must know lithology of a formation to place any confidence in our Φ S estimate. The assumption for matrix delta-t (∆t ma ) is based upon the lithology of formations we expect to encounter. Much like density porosity, this matrix assumption can be for any lithology, but we must that Φ S is the most accurate when that assumption is met. Commonly assumed values for matrix delta-t include the following:   

Sandstone (quartz)—55.5 µsec/ft Limestone (calcite)—47.6 µsec/ft Dolomite—43.5 µsec/ft

Just like density porosity, many clients request that Φ S be calculated assuming a limestone matrix even when their formations of interest are sandstone. Once again, this is because limestone is the “industry standard” lithology. The clients are aware of the inaccuracies involved in their assumptions. The assumption for fluid delta-t (∆t fl ) uses the same logic as was used for calculating density porosity. In a permeable formation, it is reasonable to assume that pores within the acoustic tool’s depth of investigation are mostly filled with invaded borehole fluid. Therefore, fluid delta-t depends upon the type of drilling fluid used. Commonly assumed values for fluid delta-t include the following:    

Fresh water-based mud—189 msec/ft Saltwater-based mud—185 msec/ft Oil-based mud—205 msec/ft 5 Air-drilled borehole—(see footnote )

Because the measured value of a formation’s delta-t is dependent upon both matrix properties and fluid properties, it is impossible to use acoustic porosity (Φ S ) by itself as an indicator of porosity or lithology. A change in lithology can easily be mistaken as a change in porosity, and vice versa. Fig. 1.2.23 illustrates an acoustic log where porosity is calculated assuming a limestone matrix. Without the benefit of a neutron-density log, it is impossible to accurately identify lithology over this logged interval.

5

In an air-drilled borehole, it is always assumed that the fluid that fills pores of the flushed zone (i.e., close to the borehole) is water, regardless of mud type.




Fig. 1.2.23—Acoustic log showing porosity calculated assuming a limestone matrix. Without a neutron-density log, it is impossible to accurately identify lithology (sand and dolomite are both present) using only the porosity and delta-t curves.

When used together with neutron-density logs, acoustic porosity (Φ S ) can provide an indicator of a formation’s permeability. Neutron and density porosities provide estimates of a formation’s total porosity. Acoustic porosity, because it is sensitive to the framework of the formation rather than its chemical composition, provides an estimate of effective porosity. When a formation’s acoustic porosity equals its cross-plot porosity, it is reasonable to assume that all pore space is effective and permeable.

Summarizing Porosity Logs By now you may very well be entirely confused, or at least suspicious, of log values of porosity, how they are calculated, and how we can determine such things as lithology and estimate total or effective porosity. If so, then don’t lose hope! It is very difficult to explain in text how these logs are used to obtain the answers we require of them. Practice makes perfect—the more logs you are exposed to, the more proficient you will become in their interpretation. For now, several points should be ed when dealing with porosity logs and will serve as a basis for using them effectively. These points include: 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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1. Lithology must be assumed for calculating a log value of porosity. If this matrix assumption is incorrect for the formation of interest, then the value of porosity will be incorrect. 2. When calculating a log value of porosity, the fluid type occupying pores is assumed to be water (generally). If this fluid assumption is incorrect for the formation of interest, then the value of porosity will be incorrect. 3. If porosity curves overlay within a formation, then it is highly probable that the formation matches the matrix and fluid assumptions. The P e curve is extremely helpful in answering this question. 4. Look at some logs—practice makes perfect!




Appendix A Chemical Properties of Hydrocarbons As previously stated, hydrocarbons are formed from the alteration of sediment and organic materials. They are the simplest organic compounds, consisting of only carbon and hydrogen. Hydrocarbons are classified according to the ratio of carbon and hydrogen, their molecular structure, and their molecular weight. Hydrocarbons have been divided into various series, differing in chemical properties and relationships. The four series that comprise most of the naturally occurring petroleums are the normal paraffin (or alkane), the isoparaffin (or branched-chain paraffin), the naphthene (or cycloparaffin), and the aromatic (or benzene) series. A fifth group is the NSO compounds, which are hydrocarbon compounds that sometimes contain substantial amounts of nitrogen, sulphur, oxygen, and other minor elements.

The Paraffin Series The paraffin series consists of compounds in which each carbon atom is completely saturated with respect to hydrogen. Structures include simple straight chains (alkanes) of carbon atoms and branched chains (isoparaffin or isoalkanes). The paraffin hydrocarbons, sometimes called the methane series, are chemically inactive. Methane is the simplest of all the hydrocarbons and is also the most stable. of the paraffin series are generally the most abundant hydrocarbons present in both gaseous and liquid petroleums.

Fig. A.A.1—Straight-Chain Paraffin Molecular Structure.

Fig. A.A.2—Branched-Chain Paraffin Molecular Structure.


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The Naphthene (Cycloparaffin) Series These saturated compounds have a cyclic arrangement (closed-ring) of the carbon atoms with only single valences connecting the carbon atoms.

The Aromatic (Benzene) Series These hydrocarbons, so named because many of Fig. A.A.3—Cycloparaffin Molecular Structure. its have a strong or aromatic odor, are a group of unsaturated hydrocarbons with a cyclic structure. Benzene, a colorless, volatile liquid, is the parent and most common member of the series found in petroleums. They include several important biomarker compounds that allow oils and source rocks to be correlated. Biomarkers are compounds found in crude oils and source rock extracts that can be unmistakably traced back to living organisms.

Fig. A.A.4—Aromatic Molecular Structure.

NSO Compounds These compounds are known as heterocompounds and are subdivided into the resins and asphaltenes. They form by combining the organic carbon and hydrogen with other elements, predominantly nitrogen (N), sulfur (S), and oxygen (O) in complex molecules. Nearly all crude oils contain small quantities of nitrogen. Nothing is known of the nature of the nitrogen compounds in undistilled crude oil, but the nitrogen compounds in the distillates are frequently of the general type known as pyridines (C 5 H 5 N) and quinolines (C 9 H 7 N). Because nitrogen is a common, inert constituent of natural gas, it may be that the nitrogen content of the crude oil is contained in the dissolved gases. Nitrogen is an unwanted component of both crude oil and natural gas. Sulfur occurs, to some extent, in practically all crude oils and in each of the fractions that make up the oil. It may be present in one of the following forms: free sulfur, hydrogen sulfide (H 2 S), or organic sulfur compounds. The presence of sulfur and sulfur compounds in gasoline causes corrosion, bad odor, and poor explosion. Before the development of modern cracking processes by refineries, the presence of sulfur made petroleum less desirable and, consequently, worth less per barrel. Since sulfur can now



Halliburton Energy Services be removed from oil, this price differential has been largely eliminated, and sulfurbearing crude oils are nearly equal to non-sulfur crudes. Oxygen is found in crude oil and occurs in the following various forms: free oxygen, phenols (C 6 H 5 OH), fatty acids and their derivatives, and naphthenic acids.


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Cased-Hole Associate Field Professional Course Manual Volume I Chapter 2 Cased-Hole Basics Revision (A) (August 2008) Reference No. WPS-TD-20002


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Preface This WPS Training manual provides information on cased-hole services, cased-hole cables, cased-hole depth and tension, and cased-hole weak points for the Cased-Hole Associate Field Professional. Study the manual to develop a through understanding of the tool before operating or servicing it for the first time. Observe all notes, cautions, and warnings to minimize the risk of personal injury or damage to the equipment. Section 1 Introduction to Cased-Hole Services – Overview of company history and WPS cased-hole services. Section 2 Cased-Hole Cables – Introduction to properties and characteristics of electric wireline. Section 3 Cased-Hole Depth and Tension – Overview of cased-hole depth and tension systems and processes. Section 4 Cased-Hole Weak Points – Cased-hole weak-point selection, construction and determination of safe-pull values.


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Section 1 Introduction to Cased-Hole Services The Legend of Halliburton Erle P. Halliburton was born on a farm near Henning, Tennessee on September 22, 1892. At age 12, his father ed away, and at age 14, Erle left home to find work to his family. When he left, he vowed not return until he had a million dollars. From age 14 to 18, he held no less than 12 different jobs. Erle began working in a railroad commissary and even spent six months as merchant seaman. In 1910, at age 18, Erle ed the United States Navy where he trained in engineering and hydraulics and operated the Navy’s first motor barge. Erle Halliburton honorably discharged from the Navy in 1915 and began working in Los Angeles, California as the Superintendent for Water Distribution for the Dominguez Irrigation Company, which at the time, was the largest pressure irrigation project in the world. In that year, he also married his wife and eventual business partner, Vida Taber. In 1918, Erle Halliburton was introduced to the oilfield when he went to work for Perkins Oil Well Cementing Company as a truck driver. Perkins had invented and patented a method of cementing oil wells that would grow increasingly important as the oil business developed. Erle Halliburton’s dedication and hard work quickly got him promoted to cementer. While working at Perkins, Erle Halliburton was constantly seeking new ways to improve the cementing process and equipment. His drive to improve the process often came in conflict with the owner of Perkins, and he was eventually fired. But, that did not stop Mr. Halliburton. Erle Halliburton moved to Wichita Falls, Texas in 1919 where, with a borrowed wagon, team of horses, and a pump, he formed the New Method Oil Well Cementing Company and went into business for himself. At that time, a major boom was occurring. The oil was so close to surface and so easy to recover that the oil companies were making money with little to no effort, so little concern was given to conserving oil or controlling the wells. The process of cementing was, in most cases, considered useless and often times considered to be damaging to the well. Work was very slow for the New Method Oil Well Cementing Company. Shortly after his arrival in Wichita Falls, he packed up and moved to the fields in Wilson, Oklahoma to find business.


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It was in Wilson, OK in January of 1920 that Erle Halliburton got his first big break. Bill Skelley, owner of Skelley Oil Company had a gushing oil well in the Hewitt Field near Wilson, OK, and all other methods for getting it under control had failed. Erle P. Halliburton, hovering on the edge of bankruptcy promised Mr. Skelley that hat he could get the well under control, and if he could not do so, he would not charge him for his services. Mr. Skelley, with nothing tolose, agreed to allow Mr. Halliburton to attempt to gain control of the gushing well. Taking advantage of his new cementing process, Erle successfully gained control of the well and heads began turning in his direction. Erle P.Halliburton (far left in dark suit) working to get Bill Skelley’s (center foreground) well under control. Courtesy John Jennings

From that point forward, the business grew dramatically. By the end of 1920, Erle Halliburton and the New Method Oil Well Cementing Company had worked on over 500 wells in the fields surrounding Wilson, OK. As work began to slow down in the Wilson area, Erle looked to the horizon and saw that work was growing around Duncan, OK only 50 miles away. Consequently, in March of 1921, he packed up his family and the company and moved to Duncan. While in Duncan, OK, Erle bought five Army surplus trucks and began working the fields surrounding Duncan, Oklahoma as well as fields in Texas and Arkansas. By 1923, the New Method Oil Well Cementing Company had acquired a fleet of 20 cementing trucks. As the business grew, Erle constantly searched for new ways to improve the oil well cementing process. In early 1922, he invented what he called the Jet Mixer, which later became known as the Halliburton Cement Mixer. This mixer revolutionized the cementing process in that it had the capability of mixing up to 1,000 sacks of cement in just a few minutes. The mixer was a drastic improvement over the hand mixing method. Other inventions also included the Halliburton Measuring Line, which was implemented to determine how far the cement traveled down into the well. Innovation and improvement were early trademarks of Halliburton’s business, and they remain so to this day. In a landmark move in 1924, Erle P. Halliburton solidified his company’s status by convincing seven large oil companies to with him in forming a corporation. On July 148 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services 1, 1924, Halliburton Oil Well Cementing Company (HOWCO) was formed in partnership with Magnolia (Later Mobil), Texas Company (Later Texaco), Gulf (Later Chevron), Humble (Later Exxon), Sun, Pure (Later Unocal) and Atlantic (Later ARCO) oil companies. On that day, Erle P. Halliburton began with a simple mission statement: “We intend to build up and maintain a complete organization. We will cover all phases of the oil-well cementing service. We will maintain an aggressive and sustained program of research. We shall give uniform quality and service. We’ll get there somehow, regardless of location.” Those words formed the backbone of a company that forged a path to industry leadership through good times and bad and still stand today to guide this company. From that day forward, HOWCO played a pivotal role in developing many oilfield technologies and not just in cementing. In 1926, Erle Halliburton secured the patent rights to the original Drill Stem Tester from John Simmons, and with the help of his chief engineer, A.D. Stoddard, modified it to work in oil wells. In 1930, HOWCO established a chemical laboratory that would later become the premier chemical research and development laboratory for the industry. In 1933, chief chemist, Hayden Roberts, began research on a process to acid treat limestone and carbonate formations to enlarge the pore spaces to enable greater flow. The service, known as acidization, first became available by HOWCO in 1934. 1934 was also the year when Halliburton first began offering Electrical Well Logging Services. This service included the location of hydrocarbons by lowering a tool suspended on electric line in the well and in order to measure the resistance of the formation. Throughout the 1930’s and 40’s, Halliburton continued to grow and expand its services. During World War II, HOWCO provided key machining and engineering processes to the war effort and received no monetary compensation or government funding for it. Erle Halliburton even gave his personal yacht, the Vida, to the US Navy to use as a floating weather monitoring station. Erle Halliburton’s philosophy was that he took no federal assistance building his company up from the mud, so why should he take federal money now?


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In 1949, Halliburton completed its first commercial fracturing job using surplus napalm, gasoline, crude oil and just 150 lb of sand. This was the first in a long series of successful ventures into what would become a major cornerstone of the HOWCO business portfolio. In 1957, HOWCO purchased Welex Company. Welex was the company that first pioneered the use of shaped-charge explosives for oilwell perforating. Technology adapted from US Military bazooka designs was successfully used to penetrate the casing and cement in an oil well and create a communication path between the formation and the wellbore. This Frac job in 1952. Courtesy John Jennings. technology replaced the use of bullet guns. Tragically, 1957 was also the year that Erle P. Halliburton ed away. At the time of his death, HOWCO was valued at 190 million dollars and had over 10,000 employees in 203 locations and 15 countries. With his ing, he left a legacy of success and proved that hard work and determination is an integral part to achievement. HOWCO changed its name to Halliburton Company in 1960 to reflect more accurately the nature of a company that started as a one-wagon cementing crew and grew to encom almost every phase of oil-well development and production. In 1962, in a move that stunned the world, two giants became one with Halliburton’s purchase of the engineering and construction conglomerate Brown & Root. The two companies shared many similarities in the fact that they both were started by energetic and hard working men who were dedicated to providing the best product possible to their clients. History recounts that the aging Brown brothers were looking to sell Brown & Root to a corporation that reflected their business practices, philosophy, and history—an enterprise grown by work-roughened hands that knew how to make money. George Herman later reflected that: “We began to look around to see a service company that we thought had the same concepts of operation and treatment of employees and of free enterprise that we had, and I approached the officers of Halliburton.” In 1989, Halliburton purchased Gearhardt Industries and merged it with Welex to create Halliburton Logging Services. This acquisition brought two innovative and successful companies together under one umbrella to create the backbone of what is now the Wireline and Perforating Services PSL.




Wireline Perforating Job—1956 Courtesy John Jennings

From 1960 to present day, Halliburton has prospered and endured through periods of growth and expansion as well as times of hardship, all the while maintaining a reputation and position as an oilfield service industry leader. From the acquisition of the construction and engineering giant, Brown & Root, in 1962, to the sands of Kuwait where Halliburton put over three hundred burning oil wells back under control in 1991 following the first Gulf War, to the creation of an eastern hemisphere headquarters in Dubai, United Arab Emirates in 2006, Halliburton has continued to grow its business portfolio. Today, Halliburton is comprised of two divisions with twelve product service lines that provide over 160 oilfield services. Halliburton has over 24,000 employees in 400 locations operating in over 70 countries around the world. The spirit of Erle P. Halliburton is continued today with Halliburton’s continued commitment to research and development, employee care, and above all, customer satisfaction.


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Cased Hole Services Presently, the Wireline and Perforating Services are comprised of three divisions: Wireline, Slickline, and Tubing Conveyed Perforating. The Wireline group is further broken down into two divisions: Open Hole and Cased Hole. The Cased-Hole services group performs six different main categories of services: 5. Cement Evaluation/Pipe Inspection 6. Cased-Hole Formation Evaluation 7. Perforating 8. Mechanical Services 9. Pipe Recovery 10. Production Logging This section will briefly discuss each category and the tools used to perform them.

Cement Evaluation/Pipe Inspection Cement Evaluation Cement evaluation is one of the basic services provided by the Cased-Hole Services Division, and it also comprises more than 15% of our business market. The purpose of the cement evaluation is to determine the quality of the cement behind the casing. The cement bond log provides two basic answers to the client. The first being the quality of the cement bond to the casing, and the second being the quality of cement bond to the formation. By knowing the answers, we can determine how much of the annular space between the casing and formation is filled with cement. In order to effectively produce hydrocarbons from a given reservoir while at the same time preserving the integrity of the formations above and below it, casing is lowered into the open hole, and cement is pumped down the casing through the bottom and up along the outside of the casing to fill the annulus between the casing and the formation.

Fig. 2.1.1—Example of Hydraulic Isolation.

The cement serves as a hydraulic barrier between the geological zones and makes it possible to target only the zones that have oil or gas. The cement evaluation is extremely important in most cases because the client needs to know that no other path of flow exists for the oil or gas produced from a given zone. This can prove especially harmful if the zone of interest is not hydraulically isolated from a water bearing zone that may be the source of a local aquifer. 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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The cement bond log is performed with acoustic-bond tools. The tools produce a sonic pulse, which impinges upon the casing and radiates outward into the surrounding cement and formation. As the sonic wave returns, it is recorded at various receivers located on the tool and then analyzed by surface software. The cement bond log began with a basic dual receiver tool, which contained one transmitter and two receivers located at 3 and 5 ft, respectively, from the transmitter. As advances in technology continued, the sectored-bond tool was created, which led to the radial bond tool. The radial bond tool has a segmented receiver that is divided into equal sections. This segmented receiver allows for a better picture of the cement to casing bond to be obtained. Fig. 2.1.2—Dual Receiver CBL Tool.

Currently, Halliburton employs both dual receiver and radial bond tools manufactured by Sondex, Inc., Computer Sonics Services, Probe Technologies, and Tekco.

Pipe Inspection In older wells, or wells with suspected casing problems, a pipe inspection may be performed to determine the condition of the casing or whether or not the integrity of the casing has been breached. This service may be performed with several types of tools: 1. Ultrasonic Acoustic Tool 2. Multiple-Arm Caliper 3. Magnetic Thickness Gauge Tool

Fig. 2.1.3—Computer generated 3-D Model of Pipe Inspection Results.



Halliburton Energy Services Currently, Halliburton uses the CAST-V or CAST-F (Circumferential Acoustic Scanning Tool) to perform the majority of our casing inspection jobs. This tool uses a rotating ultrasonic transducer that produces high-frequency sound pulses at a high rate. The tool then records the resulting waveform and forms an image of the internal surface of the casing. It also provides casing thickness. This tool may also be used to determine the casing-to-cement bond; however, due to the short wavelength and high frequency of the sound pulses, information about the formation-to-cement bond is not reliable. Another tool that is used to perform casing inspection is the multi-arm caliper tool. This tool uses a set of 12 to 60 highly-sensitive arms (fingers) that extrude from the tool. As the tool is pulled up hole, the caliper arms respond to irregularities in the casing surface. Also used is a magnetic thickness-gauge tool that contains powerful magnets to create a strong magnetic field around the tool. As the tool is pulled up hole, the magnetic field responds to any minute changes in the steel thickness, which correspond to areas of reduced thickness caused by damage or corrosion. Regardless of the tool used, the data is usually processed by a form of threedimensional modeling software to give the client a picture of the internal surface of the casing. In the case of the CAST tool, limited cement evaluation may also be performed, and a log of the cement-to-casing bond can also be provided in addition to casing thickness and surface conditions.

Cased-Hole Formation Evaluation Many forms of formation evaluation behind casing are available today. The information provided by cased-hole formation evaluation ranges from simple, natural gamma ray and hydrogen-index measurements to complex data collection that can be used in modeling processes, which will provide the same data as a standard open hole log series. Casedhole formation-evaluation tools are used for correlation purposes. Sometimes, clients will perform cased-hole formation evaluation if the hole conditions do not warrant risking an open-hole tool suite or if the client already has all of the detailed information for that region and does not want to incur the expense of an open-hole log series. The market for cased-hole formation evaluation is expanding rapidly. Currently, cased-hole formation evaluation comprises 17% of the cased-hole business market in Halliburton. Two types of cased-hole radioactive formation evaluation tools are in use today: chemical-neutron sourced tools and pulsed-neutron tools.

Chemical Source Tools Several models and types of chemical source tools exist in the Halliburton inventory. All of the tools use a 2-micro Currie Americium-Beryllium chemical-neutron source and a Helium-3 neutron detector. The two most common tool models used by Halliburton are:


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1. Hostile Gamma Neutron Tool (HGNT) 2. Compensated Neutron Tool Both of these tools function in the same manner as the open-hole neutron tool by emitting neutrons from the source and then recording the amount of neutrons that return to the detector after traveling through the casing, cement, and formation. In doing so, the tool is capable of taking rudimentary hydrogen-index measurements for the purpose of differentiating between water and hydrocarbons. This tool can also be used for perforating correlation purposes in the event the gamma ray curve response is ineffective.

Pulsed-Neutron Tools All pulsed-neutron tools contain a powerful neutron emitter called a pulsed-neutron generator. The pulsed-neutron generator uses high voltages to bombard a tritium target with deuterium ions to produce large quantities of high energy neutrons. The PNG is a powerful radioactive source when activated, and caution should always be used when operating this tool. The high-energy neutrons are radiated out into the formation and collide with the atoms of the elements inside the formation, causing the atoms to emit gamma rays. The gamma rays are then recorded and measured at one of two gamma ray detectors also located on the tool. Pulsed-neutron logging is an advanced logging service and is used primarily for locating byed oil reserves in an existing well. Although, in recent years, pulsed-neutron logging has begun to replace open-hole logging in many areas due to the large amount of data already possessed by the client who only has a need to locate the hydrocarbon reservoirs in the given well for the purposes of perforating and completion.

Fig. 2.1.4—Example of Pulsed-Neutron Log.

The pulsed-neutron tool may also be used in conjunction with a production logging suite in order to measure quantities of oil, gas, and water in a wellbore as well as to define flow rates. Two main types of pulsed-neutron tools are currently used by Halliburton: 1. Thermal Multigate Decay Lithology (TMDL) tool 2. Reservoir Monitoring Tool (RMT) The TMDL is the older of the two tools and has recently been replaced by the RMT. Although, both tools function in the same manner, the RMT has updated electronics and 156 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services a more robust pulsed-neutron generator. The newest model, the RMT-E (Elite), is also equipped with the latest ultra-link telemetry modules, which allow it to be run in combination with other ultra-link tools. Ultra-link telemetry is proprietary to Sondex, Inc.

Natural Gamma-Ray Tools The basic cased-hole natural gamma-ray tool is used to measure naturally occurring gamma rays emitted from the formation rock. These gamma rays are also recorded by a standard open-hole suite. Using the natural gamma rays, we have a common curve between open- and cased-hole logs that can be used to correlate the two together. This is required mostly because perforation intervals are typically chosen from the open-hole log; however, correlation for perforating commonly uses casing collars. When the open-log is performed, casing does not exist in the well; hence, a collar log is not created. Therefore, when the cased-hole log is run for perforation correlation purposes, a means must be obtained to ensure that the cased-hole log is on depth with the open-hole log so that the perforations can be made on depth. All natural gamma ray tools use a scintillation gamma ray detector. The simplest form of this detector counts the amount of gamma rays that strike the detector. More advanced forms of the scintillation detector will also record the energy level of the gamma ray for lithology identification.

Mechanical Services Cased-hole mechanical services consist of all mechanical services with the exception of perforating. Mechanical services include dump bailing, setting plugs and packers, junk baskets, and gauge ring services. The bulk of our mechanical services involve the setting of a plug or packer in a well using an explosive two-stage mechanical setting tool or an electrically-powered downhole power unit (DPU). When the customer needs to seal off a portion of the wellbore, either permanently or temporarily, they may opt to set a bridge plug or packer. There are several types of, and manufacturers of, plugs and packers, and they differ in design, composition, and function. Generally speaking, the composition, either cast iron or composite, is tied to the length of time it is required to stay in place. Another driving factor for the design of the plug or packer is what purpose it will serve.

Plugs A plug is a mechanical device that is designed to be forcibly set inside the casing and seal off the wellbore to prevent flow completely above and below it or, in some cases, allow flow in one direction. Plugs are built out of either cast iron or a compositefiberglass material and, in most cases, are designed to be drilled out after a certain amount of time or once the process that required it to be set is complete.


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Plugs are divided into two basic categories: 1. Bridge Plug 2. Flow-Through (Frac) Plug The Bridge plug is designed to seal off the wellbore and prevent flow in both directions, up and down. The bridge may be a permanent fixture in the case of a “plug and abandon,” where the well itself is never intended to produce hydrocarbons again and will be permanently closed. In the case of a “plug and abandon,” it is likely that a significant amount of cement will be dumped on top of the bridge plug to help seal it in place. Additionally, this type of permanent plug is generally made from cast iron. If the plug is meant to be removed or only stay in place for a limited period of time, the client will typically select a plug that is made from a composite-fiberglass material. Fig. 2.1.5—Composite Bridge Plug.

The flow-through, or frac, plug is designed to seal off the wellbore and prevent downward flow of fluids past the plug. This type of plug is generally used during production enhancement (frac) jobs when multiple zones will be treated. Thus, this type of plug is often called a “frac” plug. The frac is usually fitted with a one-way internal check valve or uses a hardened ceramic ball that fits in a recess at the top of the plug, which prevents the downward flow of fluid. When the pressure from above is lifted, the valve opens, or the ball moves aside and will allow the operator to flow the well from bottom to top. A “frac” plug is generally not meant to stay in the well for long periods of time and is most often drilled out when the completion phase of the well is finished.

Packers There are many types of packers in use today, each having a specific purpose. They are generally segregated into two types:

Fig. 2.1.6—Composite Flow Through (Frac) Plug.

1. Permanent 2. Retrievable In most cases, a packer is used to centralize and hold production tubing of various sizes for the purpose of producing hydrocarbons. A permanent packer may be used when the client does not predict that the production tubing will have to be removed. However, a retrievable packer may be used if the client believes that they will change out tubing or perform additional work to the casing portion of the well at a later date.

Setting Tools There are three models of setting tools in use by Halliburton today.



Halliburton Energy Services 1. GO Shorty Setting Tool 2. Baker E-4 Wireline Pressure Setting Tool (WPST) 3. Downhole Powered Unit (DPU) The GO Shorty and Baker E-4 setting tools are both explosively-initiated and gasoperated, two-stage setting tools. They rely on gas pressure provided by a slow burning power charge to produce the mechanical force that drives the pistons and applies pressure to the plug or packer to actuate its mechanisms. The down-hole powered unit (DPU) is completely powered by electricity and requires no explosives of any kind. The DPU uses an electric motor to provide the mechanical force that is applied to the plug or packer.

Perforating Perforating occupies approximately 42% of the cased-hole business market. This is due, in large part, to the surge in oilfield new-well exploration and completion activity around the globe. The simple purpose of perforating is to create an effective communication path between the wellbore and the virgin formation after the casing has been cemented in place. This service is provided with many different types of perforating systems, both on wireline and via tubing. Perforating systems are generally classified into two groups: 1. Hollow-Steel Carrier Guns 2. Capsule Guns (JRC Deepstar®) Hollow Steel Carrier guns come in three forms: 1. Port-Plug Gun 2. Scalloped Gun 3. Slick-Wall Gun

Fig. 2.1.7—Hollow Steel Carrier Gun.

All HSC guns share the common characteristic of having an external steel carrier, which carries the charges and elements of the explosive train assembly. Capsule guns, which are also called “strip” or “exposed-gun” systems, are a simpler form of conveyance that mounts the charges and the elements of the explosive-train assembly to a small, expendable metal strip. In this fashion, the explosive elements are exposed directly to the wellbore. Each gun system has distinct advantages and disadvantages and is selected based on completion, environmental, or wellbore conditions.


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Stim Gun/Sleeve In addition to standard perforating guns, a stim gun, or sleeve, may be run with the perforating guns or run separately. The stim gun, or sleeve, is composed of a quantity of Ammonium Perchlorate (solid rocket fuel). When detonated, it creates a momentary over-balanced condition in the wellbore with additional high pressure added to the perforating tunnel. This over-pressure aids in the creation of the tunnel and also serves to create near-wellbore fracturing of the existing pores. A stim gun, or sleeve, is run when the client wants to help the formation naturally produce hydrocarbons as a precursor to hydraulic fracturing.

Pipe Recovery Pipe recovery is the process of freeing drillpipe that has become stuck in the well. When drillpipe becomes lodged in the well for any reason, drilling cannot continue, and, generally, circulation of drilling fluids is lost. Therefore, it is necessary to run a freepoint tool into the well to determine where the drillpipe is stuck. Once the free point is located, then a “backoff” or “string shot” is lowered into the well, and while torque is being held on the drill pipe, the string shot is detonated to help jar the collar free and unscrew the free section of drillpipe. A “string shot” is a length of metal rod that is wrapped in detonating cord and provides a mechanical concussion when detonated. If the drill pipe does not come free with the string shot, then a severing job may be performed. The drill pipe may be severed using three types of casing cutters: 1. Explosive-Jet Cutter 2. Chemical Cutter 3. Radial-Cutting Torch All three tools are designed to cut the drillpipe in a radial, uniform line so that it can be freed and brought to surface.The disadvantage of using the jet cutter is that it leaves a jagged edge that must be milled down before any attempt is made to fish the down-hole portion of the drillpipe. The chemical cutter, although it makes a “clean” cut, is hazardous because it uses Bromium Tri-Fluoride, which is extremely dangerous to humans. The newest technology is the radial-cutting torch and is manufactured by MCR Oil Tools, Inc. The radial cutting torch does not use explosives or toxic chemicals of any kind and makes a clean cut that is ready for fishing. The radial cutting torch uses Thermite, which burns at a temperature in excess of 4,000°F. Fig. 2.1.8—Explosive Jet Cutter.




Production Logging Once drilling and completion operations are finished, the well enters into the production phase. As the well progresses, operators need to be able to evaluate the performance of the well and each zone from which it is producing. Halliburton offers a wide range of production logging services that can help the client: 1. 2. 3. 4.

Maximize reservoir performance Three-phase flow identification (Gas-Oil-Water) Monitor production and injection rates Identify problem areas inside the well

There are a wide range of tools in the production logging array. These tools range from simple flow meters to complex gas-oil tools that can differentiate between gas and oil inside the wellbore. In addition, production logging tools may be run in conjunction with pulsed-neutron tools for a complete analysis of hydrocarbon production inside and outside the casing. The accurate monitoring of production/injection rates has substantial economic benefits and can help the customer maximize their return on investment.

Fig. 2.1.9—Example Production Log.


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Section 2 Cased-Hole Cables In electric line logging, one of the most vital pieces of equipment used on any job is the Wireline. It provides the back bone for all of our operations. This electro-mechanical cable allows us to lower tools into the well, provides a path for electrical power and communication between the tools and surface system, and provides a way to accurately measure the depth at any given point in the well. Even though this cable is so vital to our operations, it can be one of the least-cared-for pieces of equipment in Halliburton Wireline. This under-appreciation for the cable is most likely due to a lack of understanding and/or recognition of the problems that can occur from inadequate maintenance and misuse. This chapter will help reduce some of the problems faced in the field by explaining the various electro-mechanical properties, safety considerations, preventive maintenance procedures, and strength calculations associated with cased-hole cables.

Cable Properties Wireline cable must possess certain key electro-mechanical properties that make it suitable for use in Wireline logging applications. These key features separate it from conventional braided cables and, therefore, require more attention. The features that make Wireline cable desirable for use in logging applications are: 1. 2. 3. 4. 5.

Mechanical Strength Electrical Continuity Temperature Rating Ability to resist corrosion No ts


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Mechanical Strength The first property, mechanical strength, is vital to our operations, as the Wireline cable must be flexible, yet capable, of ing heavy tool strings without breaking. Conventional braided cable is constructed of a single-helix coil. A single-helix coil is capable of ing heavy loads depending on the size and type of the material it is constructed from. As the weight is applied to the coil, the cable will lengthen, and radial forces will compress the core. In addition, the cable and the device attached to it will rotate to relieve the stress burden on the cable. All of these properties would be suitable for our use if we did not rely on the core of the cable containing one or more insulated conductors used as a medium for transmitting electrical signals. If a single-helix coil were to be used for Wireline logging applications, then as the weight is applied and radial force is exerted on the core, the Wireline conductor would get crushed and, subsequently, hinder the transmission of electrical signals.

Fig. 2.2.1—Single-Helix Coil.

To overcome the problem of excess force being placed on the core, a cable was constructed that took advantage of two helix coils wrapped counter to each other with a single or multiple conductor surrounded in an insulating material core. The double helix design provided torque relief for the radial forces as weight was applied to the cable, which alleviated the crushing force placed on the core. It should be noted that this design does not remove all of the crushing force, and all cables, if stretched past the limits, will damage the conductor core. On Wireline cables, both the inner and outer wires are referred to as armors. The inner and outer armors are constructed with high-tensile steel or an improved alloy for special lines. Based on the cable construction parameters, breaking strengths may be the same or different and may, or may not, equal in number. The cable armors are placed one inside the other and are wrapped in opposite directions to provide counter-torque capability. This means that as weight is applied to the line and the outer armors begin to compress, the inner armors will begin to decompress or vice-versa depending on the direction of travel.




Fig. 2.2.2—Double-Helix Coil.

Electrical Continuity The second property, electrical continuity, is also vital to our operations. In Wireline applications, it is necessary to have a medium through which power and tool signals can be transmitted efficiently with as little loss of signal as possible. Wireline cable is typically separated into two categories: 1) monocable—having only one conductor at the cable core, and 2) heptacable—having seven conductors at the cable core. Both cables require the core to be constructed of a metal that has a relatively low resistance to electricity and also maintains integrity at high temperatures. Generally, Wireline cable conductors are constructed from copper. Copper has a low electrical impedance property and is also semi-reliable at hotter temperatures. For the transmission of any signal, a transmission path and a return path must be provided to complete the electrical circuit necessary for electron flow. Detailed information regarding tool power and telemetry will be covered later in Chapter 3. For the purposes of this chapter, the basics of how that circuit is formed will be discussed. In heptacable (7-conductor) lines, the cable lines are usually separated into three pairs of conductors and one ground. In this method, signals and tool power can be transmitted and returned along the pairs with the one conductor serving as a ground. For monocable lines with only one conductor, the return path for signals is the cable armor.


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In both lines, it is necessary to evaluate electrical continuity and insulation periodically to ensure electrical integrity. Normally, these tests are performed at each cable reheading and should be performed prior to each job. Based on conductor size, each cable will have a constant resistance expressed in ohms per thousand feet (Ω/kft). The logging engineer can obtain these values from the cable manufacturer’s documentation regarding physical properties. This value can be as low as 2 Ω/kft and as high as 5 Ω/kft. Continuity should be checked with a suitable or approved volt-ohm meter by measuring the resistance from end to end of the cable. The total resistance measured should be the sum of the amount of cable in kft multiplied by the resistance of the cable per kft. In addition to continuity, the insulation material must be checked to that it is properly isolating the conductor from the cable armors. Insulation checks should be performed using a suitable mega-ohm meter measured from one end of the cable. (The cable slips should be disconnected prior to performing this check to protect the electronic components inside the logging unit instrument cab.) The minimum electrical isolation should be 500 MΩ at 1,000 V applied.

Temperature Rating Temperature affects our work and tools in various ways. Because the nature of our work is subsurface and our tools are required to operate in temperatures ranging from 100– 400°F, the cable that s our tools must also be able to withstand those temperatures. Temperature affects the Wireline cable in two ways: 1) mechanically and 2) electrically. Whereas the armors are composed of metal, exposing the armors to heat can cause the metal to lose its rigidity. Therefore, the metal that is used to construct the cable armors must be able to withstand high temperatures without losing its strength. Heat will also degrade the performance of the cable conductor. Although copper is an excellent metal for conducting electricity, it does have one negative attribute. As the core temperature of the copper conductor increases, its resistance to electrical conductance increases. Therefore, consideration must be given to the insulating material surrounding the copper conductor to ensure its resistance to heat and its ability to electrically isolate the conductor. Various materials are used to construct the insulating material ranging from Polypropylene to TefZel. The insulation material will change with the temperature rating of the cable. Additional elements may also be added to the cable, such as a jacket that surrounds the core material, which will add in temperature resistance, electrical isolation, and also increase resistance to exposure to wellbore fluids.




Anti-Corrosion Properties In addition to having to have mechanical strength, electrical continuity, and resistance to heat, the cable must also have an ability to resist corrosion. Our cable is routinely exposed to a wide variety of fluids and gases inside the wellbore. The fluids include hydrocarbons, water, mud, and other elements, which by themselves or through their byproducts, will cause corrosion of metal. Some of the wells may contain specifically corrosive acidic elements, such as Carbon Dioxide (CO 2 ) and Hydrogen Sulfide (H 2 S). To combat this hostile environment, the cable armors are constructed of metal alloys or special metals, such as nickel, to help prevent corrosion. The prevention of corrosion will increase the life of the cable and help it to maintain its mechanical strength in hostile environments.

No ts (Seamless) Part of the strength of the cable is derived from its continuous strands of armor that form a single length. In this way, weight is equally distributed throughout the cable as the load on it increases. Although, some of our applications require that the cable contain no ts, other applications will tolerate ts or splices made in the line, provided that there is not an excess. Cased-hole applications generally require no ts or splices in the cable. Due to the use of pressure control equipment, a splice would make it impossible or improbable that the line would be able to through the hydraulic grease tool (grease head), which has limited tolerances built into it for the line to through. Open-hole logging operations will tolerate some splices being in the line provided that the line maintains its original mechanical strength. The end result of these requirements is a cable constructed of five major components: 1. 2. 3. 4. 5.

Outer Armor Inner Armor Conductor Insulation Jacket


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Fig. 2.2.3—Main Components of a Cable.

Heptacables (7-conductor) will also contain one additional component of a filler material. The filler material serves to fill the void spaced created when the seven conductors are spun together.

Fig. 2.2.4—Cross-Sectional View of the Major Components of Heptacable.




Cable Care and Operational Considerations This section of the chapter will discuss basic cable care, recommended practices, operational considerations and special situations. The section will be generic in of specific cable types due to the variance in cable manufacturers and cables that are currently being used in Halliburton WPS. The following guidelines apply to all electromechanical cables.

Installation It is essential that a logging cable be set on a winch using the proper spooling profile. The proper spooling profile is the profile that will match the tensions expected during logging as closely as possible. In instances where cables have been installed at significantly lower tensions than those experienced in the borehole, the cable in the lower layers under low tension have been "crushed". By "crushed," we mean that at certain spots in the cable, the two dimensions of the cable measured at 90° with respect to each other are significantly different (i.e., the cable is no longer round, but egg shaped). The most likely spot to experience cable crushing is where the cable "crosses over" the winding in the layer below. In the winding below, the crossover direction is opposite the direction in the layer being installed. At the "break or crossover", the cable s the cable underneath at only one point. That single point of is directly beneath the cable. The pressure at this single point is twice as high as the pressure on the cable around the rest of the circumference of the winding, since at all other locations, the cable is ed in 2 adjacent windings as it sits in the valley between those two windings. A logging engineer should be alerted to the following two situations in order to prevent the logging cable from being crushed.

Tension During Installation During cable installation, it is very important to build up cable tension as quickly as possible so that the cable in the lower layers will have the highest tension possible. The higher the cable tension, the more resistant the cable is to being crushed. This is because the armor wires act as a barrier or fence between the core and the outside world. If a fence is pulled tight, it deflects less under any outside force. Less deflection of the fence means less deflection of the armor wires into the core. During installation of heptacable (7-conducter cable), the line is kept at a constant tension of 1,000 lb. This serves two purposes. First, heptacable is magnetically marked every 100 ft to help correct for line stretch. In order to place the marks correctly on the cable, a constant tension of 1,000 lb must be maintained. Second, the mathematical


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equation used by Halliburton to perform cable stretch calculation is structured to assume a constant spooling tension of 1,000 lb. Cased-hole cables, however, are not magnetically marked. Therefore, the tension of the line, while being spooled onto the drum, should conform to the manufacturer’s recommendations for that particular line size and type.

Logging Operations Concerns Slack Cable In situations where a tool reaches TD or encounters an obstruction or a bridge in the hole and additional cable is paid out, the tension at the surface will fall off. When the cable is put back on the drum, the slack cable goes on first at a lower tension. When the slack is picked up, the tension will become greater at the moment that the slack cable is totally removed and the tool weight is added to the load that the cable must . This slack section of cable that has gone on the winch at low tension is "soft". Low tension in the armor wires allow the cable to be compressed under the weight of the higher tension layers, which will be installed over this low-tension section. This is where cable crush is very likely to occur. If the cable tension falls below installation tension during a job, the cable should be returned to the shop immediately following the job to re-establish the proper tension profile. Many times, problems associated with crushed cable will not show up immediately; however, they can be prevented by re-establishing the proper tension spooling profile.

Shock Loading When a cable is pulled at high tensions momentarily, but repeatedly, to work a tool free, the cable experiences tension "jolts" or "impacts". Such tension impacts are more likely to cause problems than a slowly-increasing tension or a steady pull. Cable impacts are somewhat similar to taking a hammer and beating on the cable at the point it goes onto the winch. These impacts are felt by all the layers below the point where the cable is entering the winch. The likelihood of cable damage due to crushing exists in sections spooled at lower-than-normal spooling tension under the force of these impacts.

Basic Cable Care To ensure a lengthy service life and to prevent operational failures, the following steps should be taken to care for the cable. 1. Proper Installation: Set up for the proper Fleet Angle, watch the spooling crew, do not get in too big of a hurry, keep checking the tension, and inspect the cable. 2. Proper Reheading: Rehead often using the correct parts. Calculate the correct number of strands to use or the proper tension link/cable. Inspect the cable head before and after each job (should be every run in hostile environments). 3. Spot the truck properly: Again, the Fleet Angle. The truck should be further away from the rig than the derrick is high for safety. Spot so the cable will not 170 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services be rubbing or binding on any part of the rig, safety rails, catwalk ladder, or other equipment between the unit and the bottom sheave. The farther the unit is away from the bottom sheave, the easier it will be to spool and prevent excess strain on other components, such as the measuring head and the spooling arm.

Fig. 2.2.5—Fleet Angle for Spooling.

4. Rigging up and down: Use care and common sense when rigging up and down. Be especially watchful where the cable lays. Watch for anything that may kink or mash it. Have preplanned and defined hand signals or other modes of communication when picking up and laying down tools. Park a vehicle between the catwalk and the truck to prevent from driving into the cable. When picking up tools, pull all of the "slack" cable through the bottom sheave toward the truck. 5. Proper Break-In Period: The break-in period for new line is the first 25 to 30 runs in the well. It takes this many runs to "season" the cable. Be aware! Nearly every truck or skid has in the field probably has some new line on it! It may be only the bottom 3 or 4 wraps on some units, but it has not been seasoned. Also, that when you cut off a large amount of cable (1,000 ft or more) or go on an unusually deep well, you may be running unseasoned cable. During the break-in period run the cable slowly, and always maintain at least 50% of your weight going in the well. When coming out of the well, keep line speed under 300 ft/min to avoid causing excessive reverse torque forces on the cable. These forces can result in loose armor. Watch for any cable deformities or spooling problems during the break-in period and report them immediately. 6. Use correct diameter sheaves: This means rig-up sheaves. Too small of a sheave causes extreme bending stress on the cable. This can cause loose or "ropey" armor. Large-diameter sheaves are even more critical in deeper (below 15,000 ft) wells. The minimum sheave diameter is recommended by the cable manufacturer. It will be different for each cable diameter. As the cable diameter increases, the sheave diameter also increases. The sheave wheel diameter will be approximately 60 times greater than the cable diameter. Always check the sheave wheel and frame for physical damage. Grease and check bearings regularly. 7. Correct sheave groove: The sheave groove is even more important than the sheave diameter. The correct groove should cradle at least 120° of the cable diameter. Sheave grooves that are too small will pinch the cable, which results in 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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excessive wear and may cause jerky cable movement. If the sheave groove is too large, it results in flattening of the cable, possibly causing the armor to deform, and may damage the insulator and/or conductor. Improper sheave grooves may also cause loose or "ropey" armor. Inspect all sheave grooves after every job to be sure they are clean and do not have any kinks, cuts, or burrs. 8. Regular sheave maintenance: Inspect all sheaves at least monthly for wear, damage, and cleanliness. Stand sheave on end and spin to check the bearings. Be sure that the sheave groove is clean and is not cut, burred, or worn. Check all screws and bolts to be sure they are tight. Check the sheave wheel and frame for physical damage. Grease and check the bearings at least monthly and repaint the wheels as necessary. Check all tie-down cables of chains and fastening hardware. 9. Measuring Head/Horsehead: Check and grease all bearings. Make sure idler and tension wheels are in good condition and are clean. Check the height adjustment after starting in the well and correct, if necessary, to reduce the strain on the cable. 10. Keep tension on cable: The cable is designed and constructed to operate under tension at all times and should never be run in the well so fast that it is put into compression. As speed increases going into the well, a point will be reached where the tool will begin "floating". Further speed increase results in the cable trying to push the tool down the well, thus causing the cable to be compressed. When this happens, the armor wires go slack, and large gaps may appear between the wires. The insulator and conductor are very susceptible to damage, and this is also when "mud lumps" may form in the armor. 11. Proper spooling: If the cable is installed properly, it should practically spool itself when the truck is spotted properly. If the cable is allowed to miss "corners," make gaps, stack up and cross over, it can lead to armor and/or conductor damage. Ensuring the corners and obtaining a perfect spool job is important. 12. Do not over-run the cable: This may sound like step #10. However, this is a much worse condition. By "over-running" the cable, we are referring to slack cable in the well. It may lay beside the tool head or down alongside the tool, loop around itself, tie itself in knots, etc. Cable speed must be controlled to avert these problems. We have total control of cable speed, so it is really a matter of exercising good judgment and responsibility. Be aware of what excessive cable speeds can do to your cable. 13. Conscientious spudding: We often have to spud our tools to try to get down the well, but common sense is necessary. We always worry about the logging tool taking a beating, and rightly so, but do you think about the beating that is being given to the cable and the cable head? Each time you spud a tool, you are putting extra strain and shock forces on the cable and cable head. Electric leakage in the cable and/or the cable head is often caused by excessive spudding. 14. Watching for cable problems: While running the reel, one of your responsibilities is to inspect the cable as it is spooled out and in. Watch for loose armor, high strands, broken strands, ropey cable, and discoloration of the cable (by H 2 S or acid). You should always find out what kind of environment the cable will be run in. The well may contain KCl (salt water). KCl is corrosive to our cable, but the corrosion will be slow, and we can reduce its action and effects by wiping and lubricating the cable as it comes out of the well.



Halliburton Energy Services 15. Hostile environment: Some wells contain Hydrogen Sulfide (H 2 S). Care must be exercised in handling the cable and tools that are retrieved from the well. H 2 S is a very potent acid and reacts very quickly on metal. Check the cable and cable head on every run. Other corrosive materials, including Carbolic Acid, may also be in the well. Carbolic Acid is formed when water mixes with Carbon Dioxide (CO 2 ). CO 2 is introduced into the well in different ways, the most prominent being during hydraulic fracturing. Ensure that you know the well conditions before arriving on location, and be sure to select the correct Wireline for performing operations. Caution: H 2 S and CO 2 : Both of these gases, Hydrogen Sulfide (H 2 S) and Carbon Dioxide (CO 2 ), are dangerous and require special equipment and training prior to working on a well where either of them are present. Again, it is important to know what environment your cable will be run in; be sure to take the necessary action to protect it. Special cables are available, and inhibitors can be injected on the cable to aid in slowing the corrosive action.

16. Proper use of Hydraulic Pack-Off Heads: This consists mainly of communication. If the pack-off head needs to be packed down, be sure that good communication is set up (visual and auditory) between the reel operator and the hydraulic pump operator. Too much pressure on the packing rubbers will strip down the cable armor and may break one or more wire strands, causing a "birdcage." It is possible to exert so much pressure on the cable that it will be pulled apart. Always be sure to have the correct size rubbers and top and bottom brass. 17. Proper use of grease heads: The same care should be taken with regard to headpressure control as with correct size rubbers and brass, as was just discussed in Hydraulic Pack-Off Head use. Additionally, there should always be a minimal amount of grease pressure applied to lubricate the tubes and reduce line wear. Caution: For both standard and grease head pack-off equipment, slow down by reducing line speed.

18. Regularly Check for leakage: In this case, “regularly” means after every job and any time electrical problems are suspected in the cable. This check tells us if there may be a breech in the conductor insulation. Before hooking up a meter to check for leakage, make sure both the cable head end and the reel end of the cable are open. If the cable shows leakage, double check both ends of the cable. Make sure that any moisture, dirt, or grease on your hands is not adding to the reading. Strip the cable head "rope socket" down and recheck before cutting off the cable head. 19. Regularly check and record resistance: Each month, during the Truck PM II, the cable total resistance should be measured and recorded in the cable record book. This measurement is a check of the conductor total resistance from the cable-head end to the reel end. 20. Proper Cable Lubrication: The cable must be lubricated. By lubricating the cable, we reduce wear, inhibit corrosion, protect the outer armor, and increase the life of the cable (total number of service runs). The single most important maintenance step in preserving cable life is proper cable lubrication. There are four specific times that the cable needs to be lubricated: 21. If it will not to be used for at least a week or longer (stacked trucks and 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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skids). 22. At least every five runs or more, and more often under harsh conditions. 23. Any time the cable looks dry. 24. The last run out of the well. After every job, be sure to check the cable oiler and refill the supply tank.

Seasoning New Cable It is essential that a new cable be operated properly during the first runs in the well. During seasoning, a cable is much more susceptible to damage due to improper operation than later in its life. Proper seasoning is the first step to ensure the longest possible cable life. When the cable is first put into use at the wellsite, it undergoes changes in length, diameter, and torque condition. The goal is for the cable to become properly "normalized" for the typical well conditions in which it operates. The changes in length, diameter, and torque are interrelated and are primarily a function of the cable's operating tension. The cable is in a low-tension condition (several hundred pounds only) during the manufacturing process. The cable experiences high tension when it is first installed on the logging unit drum. The installation-tension profile is chosen to be appropriate for the maximum tensions at which the cable will operate. As a cable is subjected to high tensions, it becomes smaller in diameter due to compression of the core from the radial forces exerted by the armor package. Any void space present in the core will be eliminated as the cable "pulls down" or becomes smaller in diameter. The cable also gets longer during the seasoning process, gaining its permanent stretch. The amount of permanent stretch and the degree of length stability is primarily related to cable tension and borehole temperature. The permanent stretch of a cable will be larger as operating tension and downhole temperature increases. The permanent stretch is primarily related to the rotation or "unwinding" of the cable and the compression of the core as opposed to the stretching of the individual armor wires. In addition to the changes in length and OD, and most important to proper seasoning, are the changes the cable undergoes in its torque condition. Because cables are installed with the ends fixed (not free to rotate), they will undergo much of the permanent rotation in the first few runs in the well when the down-hole end is free. For example, consider a new 15/32-in. OD, seven-conductor cable that is 25,000 ft long. If the full length is placed in a perfectly vertical, 25,000-ft deep air-filled well for the first trip where it is allowed to hang under its own weight and be completely free to rotate, the free end will rotate 600 to 700 times. After this permanent rotation is established, it will rotate only when the tension changes. A cable that is not allowed to rotate freely can develop serious problems, including loose outer armor and tight inner armor, loss of tensile strength, development of high wires and birdcages, and damage to the plastic insulation. Also, a cable with loose outer armor and tight inner armor does not stretch predictably. An important aspect of the rotation factor is the dynamic condition of the two armor layers. During seasoning, the layers are not "seated" against each other—both layers of 174 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services armor and each individual wire can and will move independently. As the cable becomes normalized with respect to tension and torque, the armor wires stretch only a small amount, the helical layers unwind and lengthen, and the OD decreases. As the cable is operated and accumulates runs in the well, solid particles from the wellbore fluids and corrosion accumulate between the wires and armor layers, and the individual wires become seated against each other. In old cables, the armor layers can become securely fixed to the point of acting like a single solid "tube" of steel instead of individual wires. A new cable's condition and limitations are important to recognize when working with wellhead pressure and pressure control equipment. Pressure-control equipment seals only around the outside diameter of a cable. It is possible to lose the seal when the pressurized wellbore fluids up between the armor layers. As a new cable accumulates runs in the well, the voids between the armor layers become filled with the solid particles present in the borehole and grease from the injection head. Therefore, an older cable does not usually experience problems associated with pressure by. Note:

Camesa applies Superseal between the armor layers of all monocables during manufacturing. This compound reduces or eliminates the movement of fluids between the armor layers in new cables.

The improper use of pressure control equipment can easily damage a new cable during the seasoning process. The grease injection head, hydraulic packoff, pressure-type wireline-fluid applicator, and any similar device can cause forced rotation and "milking" of the outer armor strands. The closer the fit of the grease-head flow tubes to the cable, the greater the wellhead pressure, and the greater the compression from the rubber element in the hydraulic packoff, the greater the tendency for forced rotation and milking of armor wires. The effect will be to "straighten out” the lay angle of the outer strands. It is important to never use new pack-off rubbers with a new cable. Because the rubber elements always fit snugly when new, even without applying pressure from the pack-off pump, they can "milk" and concentrate looseness up and down the cable length. The hydraulic packoff is designed to seal around a cable that is not moving. The hydraulic packoff should never be used while moving downhole since loose armor can be "milked" and concentrated at the high-tension portion of the cable. Much of the cable's tensile strength can be lost because tension is no longer equally distributed between inner and outer armor wires. It is preferable to not use the packoff while moving uphole, and if is used, it should only wipe the line lightly. Tension increase when the packoff is applied while moving uphole should not be more than 50 or 100 Ib. The packoff should then be monitored on the way out of the well and reduced as much as possible.


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Recommended Practices During Cable Seasoning  

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Plan for the appropriate jobs for the seasoning runs of a cable. If possible, season the cable in a test well. The ideal test well exceeds typical working depths, is vertical, has no well-head pressure, and contains fluid, preferably water. The seasoning process should be used anytime an unused portion of the length is run in the well. The most important run is the first. Use the seasoning process until the permanent stretch and permanent rotation are complete and until the armor layers become fixed or "locked" together. Maintain cable tension according to the 80/120 rule. Operate at such a speed that, at all depths, down-hole tensions are at least 80% of static tension, and uphole tensions are no more than 120% of static tension. , think tension, and speed controls tension. Do not exceed a tension of 50% of the cable's fixed-ends break strength. Use of a larger weight at the cablehead is advantageous. Running tools that weigh up to 10% of the break strength of the cable is acceptable. If possible, avoid jobs requiring use of the grease head or hydraulic packoff. If they must be used, use the largest flow-tube ID possible while still maintaining a pressure seal. Use worn rubber elements in the packoff. Do not use the packoff while going downhole, and use absolute minimum force while coming out of the well. It is preferable to not use over-the-line fluid applicators for applying corrosion inhibitors, such as the tube type with rubber seals at each end. Operate such that the cable rotates freely. Give the cable time to rotate. Reversing direction for a short distance aids rotation. "Yo-yo" the cable to bottom in the first trips by running down 1,000 ft, then back up 100 ft, down 1,000 ft, back up 100 ft, etc., all the way to bottom. Avoid deviated wells if possible. Avoid the use of caliper-type instruments that prevent rotation if possible. Use of swivel ts between the cable and logging tool is recommended. Do not attempt to perform azimuth direction type surveys on the first few runs because of the large amount of rotation the end of the cable will experience. The dipmeter log is one example. If the new cable or tool becomes stuck while working with pressure control equipment, do not "work" the cable or make repeated pulls at high tension to unseat the cable or tool. Doing so can concentrate loose outer armor above the packoff, which causes the cable to lose strength. Outer armor looseness can accumulate at the end of the short section of cable, which stretches as the cable cycles through the grease head and across the sheave(s). In a cased-hole environment, the CCL can sometimes be used to monitor rotation. Stop the hoist and monitor the CCL signal while increasing its sensitivity. A changing signal can indicate tool rotation. Remain stopped for a minute or two until the CCL signal stabilizes. This will help assure that the cable has "spun out” and come to torque equilibrium while going in and out of the well. If severe logging conditions are encountered or a possible cable problem is observed during seasoning, have the cable inspected at a qualified service center immediately after the job.




Identifying Cable Damage Compression Gap When an electromechanical cable is designed, the size of the armor wires, their lay length, and the lay angle are all calculated to provide maximum strength and wear characteristics coupled with minimum torque. The armor coverage is also a product of the above calculations and is designed to be as high as possible and generally, depending on the type of cable, to be of the order of 97—99%. If the coverage were up to 100%, the cable would be so stiff that it would not bend (around a sheave wheel for example) without damage to itself, so the armor must have some gap in order for the cable to be flexible. In a perfect cable, the compression gap will be equally spaced all around the periphery of the cable so that between each armor wire and its neighbor, there is an equal gap. However, during manufacturing, it is difficult, if not impossible, to ensure that the gaps are all equally spaced around the circumference of the cable, and it often happens that most of the gap lies between two particular armor wires. Practically, this is of no consequence, and in usage, the gap will often even itself up between all the armor wires as the cable beds in. On a brand new cable, the compression gap is often more obvious than on an older cable due to the fact that the anticorrosive grease put into the cable as they were being manufactured shows up as a distinct, dark line between the bright galvanized armor wires. From this explanation, it should be understood that an apparent gap between cable armors is not necessarily detrimental. When the gap is detected, the logging engineer should stop and examine the area to ensure that the gap is not caused by any apparent damage. If in doubt, the logging engineer should report the suspect area to the immediate supervisor.

Cable Kinks Any time the tension on a cable is suddenly released, it is possible that kinks could form in the cable conductor. This class of kinks is often referred to as z-kinks. The soft copper strands, which make up all conductors, are elastic over a narrow range. If the cable is pulled so that it stretches over 0.1%, the copper can be stretched permanently so that it is longer than the original length. The permanent elongation of the copper presents a problem when the tension on the cable is suddenly removed. Under such a condition, the elastic steel armor relaxes and may even overshoot going into compression. The weaker, more pliable copper and plastic core is forced to follow the steel. When the tension on the cable is removed gradually, the cable has time to rotate out allowing some of the elongation to be 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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absorbed. However, if there is no rotation, the extra length of copper has nowhere to go. Under certain conditions, the copper can double back on itself. This "doubling back" is often in the shape of the letter "z," thus the name "z-kink." Alternately, the lengthened copper strands, instead of folding back on the conductor, may form a spike extending perpendicular to the conductor. A z-kink is detrimental only to the extent that the distance between the conductor, and the armor can be significantly less than normal. This increases the likelihood of an electrical short developing at the z-kink. Such shorts are more apt to show up when the line is put under higher tensions, causing the-core to decrease in diameter slightly, and/or when the cables run over a sheave.

Corrosion and Wear Indicators This is one of the most often asked questions from electric wireline operations. To accurately determine the answer, the mechanical evaluation should include factors, such as the wires brittleness, wear, corrosion and physical damage. If any of these factors show a problem existing in the tested sample, then the cable length should be cut back until the sample shows an acceptable result from testing.

Armor Wire Brittleness 

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As a rule of thumb, the should be able to perform a "wrap" test by bending a wire around a rod twice its own diameter 5 times without the wire cracking or breaking. More specifically, wire brittleness is more critical at the point where the cable is terminated at the cable head. Cased-hole termination of the wires normally involves bending them around a small radius before trimming. The wires should be able to bend around this radius without cracking or breaking. Another common location that can be affected by wire brittleness is the top of the cablehead where the wireline enters the head. A "gooseneck," or other device designed to provide of the wireline around the recommended bend radius at the cable head, should always be utilized when lifting the tool string. A visual inspection of this area of the wireline after every run is recommended, particularly if the wireline has been tested and considered to be brittle.

Abrasive wear: 

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Physical wear on the outer wires due to abrasion of the cable against the wellbore, formations, or casing. Uniform wear around the outside of the cable is less suspect than wear on one side of the cable in a particular section. Individual wires with less than 90% of the original diameter will exhibit only 80% of the original break strength. In the case of localized wear, a careful observation of the entire length of wireline would be necessary. Polished sections in a used wireline would indicate localized wear on high wires or larger diameters; this interval should be inspected more carefully.




Corrosive Wear  

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Corrosives or chemical attack can cause localized pitting in the wires. The "wrap" test can again be utilized as a ductility indicator for the individual wires. General corrosion can occur in a cable that is exposed to a corrosive fluid during the last run in the well and then not run for a period of time. The critical time frame is dependent upon several factors (i.e., type of corrosives, amount of lubrication in the wireline, etc.). This type of exposure can also cause severe localized corrosion on the outer wraps of wireline at the lowest point on the drum. Corrosion is usually most pronounced on the inner armor wires. When inspecting for this type of corrosion, the inner and outer wires would need to be tested for brittleness every 6 in. for an interval equal to the circumference of the drum on the outer surface of the wireline. If brittleness is detected in any of these individual tests, then this procedure should continue until all unacceptable brittleness is removed.

Miscellaneous Damage 

Physical operational damage, such as kinks, nicks, or flat spots, should be removed from the operating cable if a service repair center cannot restore the wireline to its original condition.

An evaluation should be performed on the usefulness of the wireline, which considers all of the above factors. Evaluation of a wireline’s previous operating or handling history, brittleness, corrosion, or uneven/excessive wear is critical to performing a successful job.

Location of an Electrical Leak There are a number of techniques that can be used to locate a short or leak in an EN cable. Depending upon the test equipment available and options available to remedy the problem, the individual who is performing the task can decide which technique would best suite their needs. The following technique can be used on either single or multi-conductor EM cables to locate and eliminate electrical leakage from an electrical conductor to armor. Finding the exact location of the electrical leakage is a two-step process. First, the location of the problem is approximately located using a battery and a digital voltmeter. If the goal of fault location is only to remove the fault, then the cable may be spooled to the approximate location, the line cut, and step one can be repeated to eliminate the fault. If the fault itself must be examined, then a second step is necessary. In this second step, the cable is spooled to the approximate fault location as determined in step one. Then, a centering voltmeter and a battery are used to find the exact location of the electrical leakage. The following technique can be used to locate the electrical leakage point to within +100 ft or closer depending on how accurately the length of the line is known. The equipment 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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needed is a digital voltmeter, preferably with at least 4-digit accuracy and a battery. The length of the line, L, must be known. Connect the positive terminal of the battery to one end of the conductor, which has electrical leakage to armor. Connect the negative terminal of the battery to the other end of the conductor, which has leakage to armor. Measure the voltage from the positive terminal of the battery to the negative terminal of the battery with the cable connected; call this voltage "V 3 ." Measure the voltage from the positive terminal of the battery to the armor; call this voltage "V 1 ." The distance, F, from the end of the file cable, which is connected to the positive terminal of the battery to the point of electrical leakage is: F = (L X V 1 ) / V 3

(Eq. 2.2.1)

A digital voltmeter is needed for this type test because the input impedance of this type of voltmeter is on the order of 10 MΩ. If an electrical leakage is causing problems, its resistance is usually less than 10 MΩ. In some situations, it is only necessary to remove the electrical leak. If this is the case, the line can be cut at the location, which is determined by the above technique. Each of the two sections of the line can be tested to see which one still has electrical leakage problems. The line can be tested again by using the above technique to locate the leakage. The point of leakage will be very close to the end of the section having the leakage. Short sections can be removed from that section until the point of leakage is removed.

Reversing the Line Often, an operator will want to reverse a line end for end so that the unused portion on the drum can be used as the outer end of the cable. This practice is not recommended for the following reasons: 1. A "reversed" cable can be very difficult to spool. The reason for the spooling difficulty lies in inserting the smaller diameter section of the cable on the drum first. This creates a bed layer with too many grooves for the unused larger diameter cable. The unused larger diameter section just does not fit into the grooves that are too close together to accommodate it. The used section of the cable is typically 0.001–0.003 in. smaller in diameter than the unused section of cable. The actual diameter difference depends on the cable type, the severity of the usage, and the number of previous cable trips into the hole. 2. The cable weak point is no longer guaranteed to be at the cable head. The used section of the cable may have wires that are weakened by abrasive wear and/or by corrosion of borehole fluids. Reversing the cable is likely to put this weakened section of cable near or at the highest field-operational tension point of the cable. This cable experiences its highest tension at the top sheave in the derrick above the 180 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services borehole. It is not a good idea to place weakened line at this location during logging operations. 3. Corrosion rate of the used portion is accelerated when the unused portion is not flexed during normal logging operation. The winch bed layer should never come off the drum during normal operating conditions. If the section of cable that has been in a borehole is wound on the bed layer of the winch, then that section will have accumulated borehole fluids between the inner and outer armor layers. The corrosion rate of these fluids on the armor plow steel is dramatically increased if there is no movement between the inner and outer armor layers. Experience indicates that used cables, which are stored on shipping reels corrode at much faster rates than cables that are used to log day after day. It is believed that since there is no movement between the inner and outer armor wires during storage that corrosion occurs continuously. Sometimes after several months, such stored cables will exhibit periodic (of drum circumference period) cable bulges. Inspection of these bulges shows extreme rust buildup. 4. Overlap of previous tension-rotation profile with new tension-rotation profile. If a cable is reversed, the virgin section, being used for the first time, will acquire a tension-rotation profile. If the logging depth is such that the previously-acquired profiles and the new profiles overlap, there is a high likelihood that the profiles will be different. At the intersection of the differing tension-rotation profiles, expect to experience bird caging, loose armor, and/or high wires. Any or all of the above effects can be expected when a logging line is "reversed."


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Section 3 Cased-Hole Depth and Tension Depth is the single most important measurement taken by a Wireline logging unit. While being the easiest to acquire, it is often times the most prone to human error. Its importance stems from the fact that depth is associated with every down-hole logging operation performed. For this reason, it must be accurate and consistently repeatable. The depth measurement systems are vital pieces of equipment and must be maintained on a regular basis. The Field Professional is responsible for ensuring the logging unit’s depth and tension measurement system are functioning properly and accurately prior to each job. In addition, the Field Professional is required to follow all the depth control processes outlined in the Halliburton Management System.

Depth Systems Currently, Halliburton WPS employs two depth measurement systems. Both systems use different types of display s and measuring heads. 5. Stand-alone Depth Display (SDDP) w/Kerr Measuring Head 6. Benchmark (Kerr Measurement Systems) a. Cased Hole (AM3K) b. Open Hole (AM5K) Currently, WPS is in the process of phasing out the SDDP’s and replacing them with Benchmark s and measuring heads. However, because both systems are still in use today, they will be discussed in this chapter.


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Fig. 2.3.1—Overview of Logging Unit Depth/Tension System.

Stand-Alone Depth Display (SDDP-A/B) The SDDP system is a 386-based processor depth interface that was deployed in older model open-hole logging systems. The SDDP processes depth signals from a Kerr measuring head, which has two tangentially-mounted measuring wheels. Tension signals are processed from an externally mountable load cell, which is designed to be placed on the upper sheave wheel but may be placed on the lower sheave wheel if necessary. When installed, the SDDP communicates with the CHIP/Warrior logging system via a GPIB to USB interface, which is directly connected to the USB hub on the back of the CHIP . This mode allows for bi-directional communication between the CHIP and the SDDP. Therefore, depth and tension information can be updated or changed from either the SDDP or the Warrior Software.

Fig. 2.3.2—SDDP-A/B Depth .


Fig. 2.3.3—Wayne Kerr Measuring Head (Old Style).



Benchmark (Wayne-Kerr) Measurement System The Benchmark (Wayne-Kerr) depth and tension measuring systems are currently deployed in two models of display s and two models of measuring head. Although, they are typically segregated by Cased Hole and Open Hole, they are not exclusively used for those type services. The smaller measuring head cannot be used for larger seven-conductor line.

AM5K Measuring System The AM5K measuring head has two tangentially-mounted measuring wheels, which drive two individual 1,200-pulse optical encoders. The unit also includes an independent magnetic encoder for back-up depth indication. The measuring head can accommodate line sizes from .190 in. to .484 in. in diameter. Maximum depth resolution for the AM5K without magnetic marks is +/- 10 ft in 10,000 ft.

Fig. 2.3.4—Wayne-Kerr (Benchmark) AM5K Measuring Head.

The AM5K also includes a magnetic-mark detecting unit, which comes optional upon request. The AM5K also has a built-in tension load cell, which removes the need for an external load cell. The load cell has a maximum test rating of 16,000 lb. Note:

Per OEB 2007-097, the tension wheel and guide wheels must be replaced after .010 in. of wear has occurred. Failing to replace these wheels can lead to errors in tension measurement as large as 1,500 lb per 5,000 lb of tension.


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Fig. 2.3.5—Diagram Illustrating Points Outlined in OEB.

The AM5K can be driven by the cased-hole or open-hole display s or directly by the logging system.

AM3K Measuring System The AM3K measuring head is a lightweight compact measuring head with only one measuring wheel that drives a 1,200-pulse optical encoder. A pressure wheel mounted on top maintains correct pressure on the Wireline for accurate depth measurement. The AM3K can accommodate line sizes from .1 in. to .375 in. in diameter without wheel replacement. The AM3K also has an independent magnetic encoder for back-up depth display. The AM3K measuring head is not equipped to except a magnetic-mark detecting unit and is, therefore, usually deployed on units that are designated for cased-hole use only. As with the AM5K, the AM3K also has an electronic strain axle mounted through the middle for tension measurement. The maximum tested tension rating is 10,000 lb. Fig. 2.3.6—Wayne-Kerr (Benchmark) AM3K Measuring Head.




AMS4A044 Hoistman’s Touch-Screen The AMS4A044 touch-screen is currently being deployed in all WPS Open-Hole Logging units to replace the SDDP-A/B depth systems. This allows the operator to set parameters and make adjustments to the depth and tension data as necessary. The AMS4A044 uses an Intelbased, high-speed processor and runs the Windows XP platform. Fig. 2.3.7—Wayne Kerr (Benchmark) AMS4A044 The depth interface can be Hoistman’s Touch-Screen Depth . operated via the color touch screen or the supplied USB mouse and keyboard. This is designed to be used in conjunction with the AM5K measuring. For casedhole applications, this does not communicate with the CHIP via a USB bus. In the current configuration, the AMS4A044 slaves any data received from the depth/tension units directly to the CHIP , and the CHIP performs a separate counting. The operator needs to take special care when using this system, as any changes made in either the Warrior Software or at the AMS4A044 will not update both systems. Any depth or tension changes that need to be made must be made in both systems and verified; this includes tension calibrations.

AMS4A040/AMS4A041 Winch Operators The AMS4A040/AMS4A041 is a more simplistic version of the touch screen designed for use in units designated for cased-hole applications only. This allows for only minimal input from the , defining basic parameters for the acquisition of depth and tension information. Currently, this is being deployed in cased-hole designated units to replace older line-load modules and comprobe depth tension s. Similar to the touch-screen , this will also not allow bidirectional communication between it and the CHIP. Therefore, any changes in either system must be followed by a change and verification in the opposite to ensure uniformity Fig. 2.3.8—Wayne-Kerr (Benchmark) AMS4A040/041 Winch in measurement. Operators .


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Signal Processing Depth and tension signals can be processed through two means in the current configurations available in WPS. The pulses and data may be driven by a depth-tension front-end , such as the SDDP or Wayne Kerr s, and the front-end s will then relay “slave” information to the CHIP for processing and measurement by the Warrior Software. The CHIP is also capable of directly driving the optical encoders and tension-load cell without assistance. The standard configuration of a cased-hole unit includes optical encoders and tension load cell, which are driven by a depth display front end (SDDP/KMS), and optical pulses or tension voltages, which are sent on a slave feed to the CHIP. Two methods of slave feeding exist today and are differentiated between the two systems currently in service. When the SDDP is being used, the SDDP outputs the depth and tension information it receives from the load cell and depth encoders via an IEE 432 connection bus on the side of the . This cable is, in turn, connected to a GPIB to USB converter, which changes the IEE 432 connection to a USB output that is connected directly to the CHIP USB Hub. When connected in this fashion, bi-directional communication is maintained, and changes in either system will be reflected in both. The chart below outlines the signal path for depth and tension signals when configured with an SDDP. There are currently three models of GPIB-to-USB converters in service today: A, B, and HS (High Speed). It is important to note that in order for the SDDP to communicate with the CHIP and the Warrior software, the proper National Instruments software for the model being used must be installed. Two software versions are in use: one version for the A and B model converters and one version for the HS model. Both versions of software are available from the Halliburton Technical Software orders website.




Fig. 2.3.9—Depth/Tension Signal Processing with SDDP-A/B.

When either of the Benchmark (Wayne-Kerr) depth-display s is being used, the pulses and voltages from the optical encoders and the load cell are relayed to the CHIP along a slave feed in their raw format. The CHIP processes the raw signals and es them to the Warrior Software for measurement. The illustration below depicts a system configured for use with a Benchmark (Wayne-Kerr) display . When using the Benchmark (Wayne-Kerr) depth s configured in this manner, it is important for the to understand that bi-directional communication does not exist between the depth and the CHIP. Therefore, any changes that need to me made for depth or tension should be made on the depth and then verified in the logging software. If changes are then made, they will be reflected in the logging software. However, if a change is made in the logging software, it will not be communicated to the depth , and no change will occur.


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Fig. 2.3.10—Depth/Tension Signal Processing with Benchmark Depth s.

Depth Control Basics Depth control is perhaps the easiest measurement to acquire. Yet, it is the single most important measurement provided, as it is associated with the every down-hole logging operation (measurement) performed. For this reason, it must be accurate and consistently repeatable.




Measurement Principle The most obvious method for depth control is the measurement of spooled-out cable. This is achieved by either single- or dual-measuring wheel systems. The measuring wheels are mounted tangentially and are held in constant with the cable. The axle of the measuring wheel is connected to an optical encoder and mechanical odometer. The mechanical odometer serves as a backup. As the cable is spooled in and out, the measuring wheel revolves, and the optical encoder outputs a fixed number of pulses per one revolution of the measuring wheel. If the circumference of each wheel is known, then the depth can be updated by the surface system simply by counting the number of pulses. For example, if the 2-ft circumference wheel gives out 600 pulses per revolution, then with each pulse, the depth increment would be: 2 X 12 in. = 24 in. for 600 pulses, so one pulse would be 24/600 = 0.04 in. Obviously, this system is not sufficient for accurate depth control without some form of external reference to the depth reading. It is at this point that the separation between cased-hole and open-hole depth control can be made. In the case of cased hole, apart from the accurate depths, we need to tie in our depths with the reference logs, which could include logs with open-hole gamma ray or simple cased-hole cement-bond logs or, in some cases, down-hole references, such as a short collar, a 7-in. liner top, or packers and tubing shoes in the case where jobs are run through tubing. Open-hole depth control cannot rely on the down-hole reference, as that will most often be the first run in the hole. Even though a casing shoe can be used as a down-hole reference, it is usually thousands of feet apart from the T.D. Therefore, in the case of open hole, a separate external reference, provided by the magnetic marks, is required. The wireline cable is marked at a constant tension and at a fixed interval. In an openhole situation, the magnetic marks become the primary reference, and the encoder pulses are used to interpolate in between the two magnetic marks. However, as the distances between the marks on the cable vary depending upon the tension, it can be seen that an accurate tension measurement is also desirable. By utilizing magnetic marks and cable tension, the stretch in the wireline cable can be calculated, and the correct tool depth can be determined. To understand the cased-hole depth system correctly, we first need to have an understanding of the different parts of the depth-measurement system and their principles of operation, which include:     

Cable and Cable Properties Line Tension Encoders Measuring Wheels Depth s


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

Measuring Heads Systems

Cable Properties Cable stretch is the predominant cable property that affects depth measurement. From the previous chapter, we learned that Wireline undergoes two types of stretch: elastic and permanent. Although permanent stretch cannot be ed for, elastic stretch must be corrected for in order to attain correct depth measurements. Elastic stretch may be ed for mathematically provided that we have an accurate tension reading and we know the effective tool weight in mud. The stretch value that is obtained from the calculation or from the graph needs to be added to the depth-counter raw value, as the stretch correction is always added. The formula below is used to calculate the stretch correction necessary for each log performed under the given conditions. If any of the variables change (i.e., effective tool weight, mud weight, etc.), then the calculation must be performed again. True Depth Mode:

Stretch  1 K 1LT  ETW  2# 2

(Eq. 2.3.1)

Where: Stretch

in ft

K1

the cable stretch coefficient, ft/kft/klb

L

the length of cable in the well in kft

T

the cable tension measured at surface in klb

E TW

the effective tool string weight (in fluid) in klb

K2

the drillpipe stretch coefficient, (this value is 4.63 x 10-8 ft/ft2 Firmware)

Tension information is obtained from a load cell. The load cell may be incorporated into the depth measurement system or may be externally mounted to one of the Wireline sheave wheels. A load cell is a weight-measurement device, which outputs the combined weight of the tool and the logging cable. Ideally, it makes sense to put it in between the top sheave wheel and whatever device is used to mechanically suspend it. It may also be mounted in between the bottom sheave wheel and its stand or the tie-down chain when necessary. If the load cell is mounted in a place other than above the top sheave, then a new calibration-tension value must be derived in order for correct tension measurements to be taken. A load cell is comprised of a sturdy external housing with two holes in each end for affixing mechanical hardware for mounting. Inside the load cell are four strain gauges 192 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services that are electrically connected to form a Wheatstone-bridge circuit. For a given input (excitation) voltage, the output is proportional to the load placed on the strain gauges. The depth , or CHIP , provides the power to the circuit and then receives the proportional response from the load cell as tension is applied to the Wheatstone bridge. The logging software, via calibration, then interprets the change in voltage and converts the voltage to engineering units (lb/kg). The correct tension value is important for the following two reasons: 7. To know exactly how much tension is applied on the cable head or on the cable, depending on the situation. 8. To be able to compensate for the elastic stretch, which is only possible if the correct tension value is known. Caution:

The load cell must be calibrated at the beginning of each job to ensure accurate measurements.

As previously discussed, there are two types of tension measurement devices currently deployed with WPS logging units: external load cell and Benchmark (Wayne-Kerr) measuring head with integrated load cell.

Measuring Head with Built-in Load Cell The external cable-tension measuring system consists of a load cell built in the measuring head and a that provides power to the load cell and drives its information. The sends digital signals to the logging system. Some cased-hole systems have the ability to drive the external load cell by themselves. This type of a tension measurement is done using an electronic device that employs a measuring wheel to create an angle in the wireline cable. The wheel is connected to an elongation-type sensor in order to sense the line tension. The tension- calibration value changes with the wireline cable size because of the angle that the line forms with the measuring wheel.

Fig. 2.3.11—Cable Routing through a Measuring Head with a Built-in Load Cell.


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Table 2.3.1—Calibration Values per Line Size

Note:

Cable Size

Calibration Value

7/16–0.484 in.

3,250

3/8 in.

4,171

5/16 in.

4,656

9/32 in.

4,808

7/32 in.

6,187

If you are using the measuring head with the built-in load cell, then it is only necessary to enter the calibration value according to the size of the cable and calibrate the tension for “Zero” and that particular value, as shown in the above table. We do not have to do the following exercise.

External Cable-Tension Measuring System The external cable-tension measuring system consists of a load cell and a that provides power to the load cell also drives its information. The may have a digital or analog output to transmit the information to the logging system. Some cased-hole systems have the ability to drive the external load cell by themselves.

Load Cell Calibration During the calibration of the load cell, a reference voltage is generated, which simulates a physical load of 6,500 lb on the load cell. This is illustrated in Fig. 2.3.12. Because the line itself would only encounter 3,250 lb when the load cell had 6,500 lb of tension on it, we regulate our calibration to reflect half of the total tension, as seen by the load cell.




Fig. 2.3.12—Load-Cell Principle of Operation.

The surface system can have more than one type of s, but the basis behind the calibration process remains the same for all of them. To ensure the accuracy of the tension measurement, the calibration procedure must be performed. Deploy the load cell as shown in Fig. 2.3.12. The load cell calibration is a simple two-step calibration: 1) zero and 2) full scale.


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Fig. 2.3.13—Illustration of Fleeting Angle.

that the connectors are clean and dry. Rig up the top sheave wheel with the load cell connected to it, as shown in Fig. 2.3.13. The position of the load cell will affect the value that we need to use for the tension calibration. The value will change with the fleeting angle, θ. When the load cell is connected to the top sheave wheel, the fleeting angle is zero. For some special jobs or due to special circumstances, if we connect the load cell to the bottom sheave wheel for instance, jobs like Free Point / Back Off, where the driller will need the blocks to pull on the pipe to give stretch or in any other case when the up and down cables are not parallel to each other (the fleeting angle between them is no longer zero), then a correction needs to be applied to the calibration value for the tension reading to be accurate.




Fig. 2.3.14—Load Cell Mounted on Lower Sheave Wheel.

The full-scale calibration value that is typically used if the load cell is on the top sheave wheel is 3,250. If the load cell is connected with the bottom sheave wheel as shown in Fig. 2.3.14, then the calibration value will be calculated by Eq. 2.3.2 as follows:

(Eq. 2.3.2)

For the load cell at the bottom sheave wheel, the fleeting angle will be 90°, and, hence, the calibration value will be 4,596 lb rather than 3,250 lb. Therefore, if we connect the load cell on a bottom sheave wheel, then the calibration values will be 0 and 4,596 lb.


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Table 2.3.2 shows the values for the full-scale tension calibration with the respective fleeting angle.

Table 2.3.2—Calibration Value per Major Fleeting Angle Change Angle

Full-Scale Calibration Value

0°

3,250 lb

90°

4,596 lb

115°

6,049 lb

120°

6,500 lb

Transportation, Handling, and Storage Handle the load cell with care, as the electrical connections can be deformed or broken. Avoid any external mechanical shocks, as the strain gauge may be damaged. Positioning the load cell on the bottom sheave wheel will increase the chance of mechanical shock. Do not crush or pinch the load-cell cables, and set up barricades or warning signs to prevent the damage from the traffic. Keep all connections dry and capped when not in use. Note:

After the job is finished, try to spool back the line-tension cable as soon as possible avoid damage to it during rig down.

Check all connectors and connections and make sure there is no water/moisture in them. Make sure that the line-tension cable spool and the cable are not cut anywhere and the line itself is having no leakage. Secure the load cell properly when not in use in the logging unit or in the truck. Make sure that the storage area for the load cell is dry and there is no moisture or water dripping on it or on the connections. After the job is over, the line-tension cable should be spooled neatly on to the supply reels, and ensure that all the connections are capped so that no moisture or water can enter the connections, strain gauge, or amplifier.




Depth-Measurement Encoders Optical Encoder Currently, the depth-measuring systems in WPS may have either a 300-pulse/ft or 600pulse/ft optical encoder. The Benchmark (Wayne-Kerr) systems all come standard with a 1,200-pulse/rev, 600-pulse/ft optical encoder. As the phase out of the older systems occur and are replaced with Benchmark systems, there will only be 1,200-pulse encoders on WPS logging units. However, for the time being, each engineer must inspect the system and the type of encoder prior to the job. This is important as the system parameters, both in Warrior software and the depth , must have the correct pulses selected. The output of each optical encoder is fed into the surface system for processing. The direction is obtained from the difference in phases between the quadrature pulses present on channels A and B; the line direction (Up/Down) is obtained after processing is completed.

Fig. 2.3.15—Optical Encoder Channels for Direction Determination.


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Back-up Encoders There are three different types of back-up depth measurement systems currently in use in WPS that use mechanical, electrical, or magnetic encoders. Most of the old straightline measuring heads have a mechanical odometer, which is used as a back-up measurement. This odometer is equipped with a gear set that matches the wheel diameter, so the odometer will display a depth change equivalent to the wheel circumference in one revolution. Most of these have been replaced in the new systems by 12-V electrical back-up encoders. The Benchmark (Wayne-Kerr) measuring head uses a magnetic back-up encoder to provide secondary-depth measurements to a separate depth display.

Measuring Wheels Measuring wheels are the wheels made up of special quality steel. The surface of the wheels is hardened by an induction-hardening process in order to have minimum wear and tear. The measuring wheels used by all Halliburton measuring systems are 2-ft circumference wheels. The formula for the circumference of the wheel is Circumference = π x d

(Eq. 2.3.3)

Where: d = diameter of the wheel

Fig. 2.3.16—Illustration of Cable Wheel Movement to Determine Distance (Circumference of Wheel = Rotation Equals Straight-Line Distance).



Halliburton Energy Services For a 2-ft circumference measuring wheel, the diameter of the wheel should be: 2 X 12 in. = 24 in. = π x D D= 24 in./3.1412 D= 7.639 in. Refer to the CALCULATION section for more examples on the depth control and corrections.

Straight-Line Depth Measurement System All measuring heads currently in service are known as straight-line measuring heads. This means that the Wireline is spooled off of the drum through the measuring head in a straight line. Aside from the minimal pressure applied to the line to keep it in with the measuring wheels, no other pressure is applied. This is referred to as tangential . Refer to Fig. 2.3.17. Whether the measuring head is configured with two measuring wheels or one measuring wheel with a pressure wheel, the Wireline is ed through the measuring head in a straight line with no deforming curvature to the line. Older-style measuring heads, known as radius-style heads, would the line through the measuring head over the top of a large center wheel, deforming the line at the point of . This makes the depth measurement extremely sensitive to cable diameter. As a result, the radius-measurement system was replaced by the straight-line system. This system of measurement is fairly straight forward because it is assumed that the amount of line spooled from the drum is equivalent to the amount of movement in ft that the tool’s string traversed in the well. Given a known circumference of the measuring wheel of 2 ft, we can equate the revolutions of the wheel to the distance traveled via the optical encoders. Therefore, a full rotation of 2 ft will equal 1,200 pulses; thus, every time the system receives 1,200 pulses, it will advance the depth counter 2 ft. This is the easiest way to view the measurement system. In reality, as was discussed previously, because each optical encoder outputs 1,200 pulses/rev and 600 pulses/ft, we can easily divide the circumference by the number of pulses and derive a resolution of .02 ft/pulse. Thus, every wheel movement of .02 ft will generate an optical pulse that is received by the system in which the system, in turn, advances the depth by .02 ft.


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Fig. 2.3.17—Wheel Movement Along Cable to Measure Length of Line Spooled Out.

There are other factors affecting depth measurement that will cause error in measurement and require correction. So far, we have discussed the effects of cable stretch, and now we will examine the effects of wheel diameter. Wheel diameter is extremely important. As the depth-measuring system is set for a parameter of 2 ft of travel, which is equivalent to 1200 pulses output from the optical encoder, any change in the diameter of the measuring wheel will cause the ratio of pulses to feet to change. Most measuring wheels will wear over time and with continuous use. This wear is usually seen in the form of a groove through the center of the wheel. This groove is a byproduct of the constant frictional with the wheel, which is necessary for the correct operation of the system. This has the effect of reducing the wheel circumference. Therefore, the wheel will traverse a shorter distance in a single rotation while the optical encoder still outputs 1,200 pulses, indicating a full 2-ft rotation. As a result, the tool will be shallower than the depth displayed. For example; the depth display may show a depth of 10,000 ft, but due to an incremental reduction in circumference, the tool will actually be at a depth of 9,990 ft. The reverse is true if the measuring wheel circumference is increased. Given the adverse nature of the environment that we operate in, it is possible that buildup of snow, ice, and mud may occur on the wheels. This buildup will cause an increase in the wheel diameter. Therefore, in a single rotation, the Wireline will traverse a greater distance than is indicated by the system because the optical encoders still output 1,200 pulses per revolution. As a result, the tool will be deeper than the depth displayed. For example; the depth display may indicate a depth of 10,000 ft, but the tool will actually be at a depth of 10,010 ft. The relationship of pulses-to-ft traveled may be derived mathematically using the following series of equations:



Halliburton Energy Services Revolutions = Odometer Reading/2 Circumference = Actual (Tool) Depth/Revolutions Diameter = Circumference/π

Example Assume that a 2-ft measuring system indicates a tool depth of 990 ft, but the actual tool depth is 1,000 ft. Revolutions = 990/2 = 495 Circumference = 1,000 ft/495 = 2.02 ft Diameter = 2.02 ft/π = .64 ft In converting to inches (in.), multiply by a factor of 12, which will give a wheel diameter of 7.68 in. In the example above, the wheel diameter/circumference was increased; therefore, the depth display indicated a tool depth shallower than the actual position.

Cased-Hole Depth Control Procedures Unlike open-hole logging, cased-hole logging may or may not be in a position to be the first logging run in a particular well. Therefore, procedures have been designed to for the first or second run in the hole. These procedures must be followed to ensure accurate depth measurements in a customer’s well. Aside from the type of run being performed in a customer’s well, we must also take into any equipment that may be used to perform the job, such as pressure-control equipment. The use of pressure-control equipment may alter or prevent compliance with these procedures. If such a situation occurs, it is the responsibility of the field engineer to discuss the issues with his or her manager and the client prior to commencement of the job.


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First Run Procedures If the cased-hole log being run is the first logging to run in the customer’s well and the log will be used as the primary depth reference for the well, then the following procedures should be performed to ensure depth accuracy. 9. Perform rig-up operations as necessary and prepare to enter the well. 10. Zero the logging tools. 11. Perform RULS (Rig-Up Length Surface) measurement. 12. Perform RULB (Rig-Up Length Bottom) measurement. 13. Log out. 14. Compare Zero and RULS vs. RULB measurements to ensure no change in surface equipment has occurred and the depth measurement system is recording accurately.

Zeroing the Logging Tool String Typically, the tool-zero reference for a logging string is the bottom of the tool. This may vary with type of service or tool string; however, unless otherwise specified, tool zero should be declared in the Warrior software as the bottom of the string. In most cases, the depth reference for the well is usually the rig floor, or the Kelly Bushing. The rig floor, or Kelly Bushing, usually exists some distance above the actual ground level or sea floor. However, in order for our measurements to match the client’s measurements, both sets of measurements must begin at the same point. The conditions for taking this measurement may vary with the presence or absence of the drilling rig-in, cased-hole operations, but the point of measurement does not change. Zeroing the logging tool requires placing the tool at the customer’s reference point and zeroing our depth system, or placing our tool zero at a known distance and calculating the difference between the location of our tool versus the location that the client began his measurements. The depth-reference point can be obtained from the drilling report, casing report, or any other logs that may have been run on the well if the cased-hole logging run being performed is not the first run.

Example If a drilling rig is present, the logging engineer lowers the tool down until the bottom of the tool is resting lightly on the Kelly Bushing or drill floor. The engineer will then engage the drum brake and set his depth systems to read zero. From that point, the logging engineer may enter the well and begin logging. If a drilling rig is not present, the logging engineer obtains the distance, or height, of the drill floor or Kelly Bushing from one of the aforementioned sources and then lowers the tool until it rests gently on the ground. The difference between ground level and the 204 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services drilling-reference point can then be calculated, and this calculated value is set as the depth. This is due to the fact that when the tool zero is touching the ground, it is already below the surface, according to the driller’s measurements. For example, if the height of the ground level is 700 ft and the height of the Kelly Bushing is 718 ft, then the difference in distance is 18 ft. Therefore, if the logging tool zero is touching the ground level, and the Kelly Bushing is the drilling-depth reference point, then the engineer would enter a depth of 18 ft into the depth systems.

Rig-Up Length at Surface (RULS) The presence of Wireline-pressure control equipment will prevent this measurement from being taken as is. It requires the line to be flagged, and any material placed on the Wireline may not easily through the flow tubes in a hydraulic grease tool. However, if the log is being performed without pressure equipment, then this step should be performed to help ensure that no mechanical movement of equipment (e.g., travelling blocks, logging unit, etc.) has occurred during the log. To perform this step, the tool must be introduced into the well at a sufficient depth where the combined tool and line weight have removed any slack in the line from the spooling head to the lower sheave. When the tool has been introduced to that depth, the logging engineer stops the winch and engages the brake. The line is then marked/flagged at the measuring, head and the engineer records the depth indicated on the depth display. With an operator assisting him at the well head or drill floor, the logging engineer continues to log down, watching for the line flag. When the flag reaches the drill floor, the operator will signal the logging engineer to stop the winch and engage the brake. At this time, the flag is removed from the line, and the logging engineer records the depth indicated on the depth display. The logging engineer then subtracts the first depth from the second depth and obtains the value of the total rig-up line spooled out from the drum to the drill floor or wellhead.

Example A flag is placed on the line at 700 ft. The flag is removed from the line at the well head, which is at 1,000 ft. Therefore, 1,000 ft – 700 ft = 300 ft of total rig-up line.

Rig-Up Line at Bottom of Well (RULB) When the tool is nearing the bottom (TD) of the well, the engineer stops the winch and engages the brake. The engineer should perform this step at a depth above the TD of the well of at least a distance greater than the sum of the first rig-up line measurement. The line is again flagged at the measuring head, and the logging engineer records the depth indicated on the depth display.


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The engineer then resumes logging down and stops the winch when the line flag once again reaches the drill floor. The logging engineer then performs the same calculation as RULS. The RULS should be equal to RULB within +/- 1 ft. If the distance is greater than 1 ft, then the logging engineer must investigate the cause, as this may indicate possible movement of the travelling blocks, logging unit, etc. If the difference is less than 1 ft, it is most likely due to slack in the line being taken up by the increased line weight at TD. This tolerance is acceptable.

Example TD = 11,000 ft The engineer stops the winch at 10,000 ft and flags the line at the measuring head. He then resumes logging down and stops the winch when the flag reaches the drill floor at 10,300.5 ft. Therefore, 10,300.5 ft – 10,000 = 300.5 ft total rig-up line. RULB:

300.5 ft

RULS:

300.0 ft

Difference: .5 ft (Difference within 1-ft tolerance)

Logging-Up Procedures Once at TD, the logging engineer corrects the depth for line stretch and begins logging up. No further depth corrections should be made.

Final Check Once the logging service has been performed, the logging engineer then returns the tool to surface and rechecks the zero by placing the tool zero at the same reference point as the initial zero. The depth indicated on the depth-display should be equal to the stretch correction plus the initial zero. If the tool zero does not repeat within +/- 1 ft of the initial zero, then the logging engineer should inspect the depth-measurement system and investigate the cause of the difference. This difference could possibly indicate a problem with the depth-measuring system and may require further investigation.

Subsequent Runs/Trips If the logging engineer is making a second run into the client’s well on the same day after performing a first run (Primary Depth Reference) log or the logging engineer is making a run into a client’s well in a subsequent trip to the well, then the following procedures should be adhered to. 206 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services 15. The logging engineer meets with the customer to determine the appropriate correlation log to be used for the specific job. If perforating, the logging engineer should that the specified log is the log that the perforation intervals were chosen from. 16. Once the correlation log has been determined, the logging engineer rigs up the equipment and tools in accordance with Halliburton and NWA processes. 17. Zero the tool appropriately and introduce the tool into the well. If performing an evaluation log, then the logging engineer should review the correlation log and identify a minimum of a 200-ft section of the log close to the TD of the well that contains a distinct pattern (Gamma Ray/Neutron/CCL) to correlate to. 18. When at the chosen depth, the logging engineer should log a minimum of 200 ft across a distinct pattern of sensor curve response to ensure positive correlation. It is important to that the distinct pattern should not repeat anywhere else in the vertical axis of the well. If it does, then it will be necessary for the logging engineer to include both distinct patterns in their order to prove depth accuracy. 19. Once the minimum 200-ft correlation strip has been logged, the engineer must stop the winch, engage the brake, and print out the log section. 20. The correlation-log section should be compared with the customer’s correlation log using a light table to determine an appropriate depth correction. 21. When the depth correction has been determined, the logging engineer will make the necessary changes in the depth systems to reflect the depth change. 22. The correlation interval must be logged again in real time to ensure that the depth adjustment made was correct. If any further corrections need to be made, then the must be logged again until no further adjustments are necessary. 23. Once a proper correlation has been made, then the logging engineer is safe to proceed down and tag the TD of the well and begin logging up. Once the log is commenced, no further depth corrections should be made. Run the log to the full length of the interval requested and DO NOT make any adjustments. a. If the log is being run for the purposes of performing an explosive service, then the logging engineer must log at least one casing collar below the interval before initiating the explosive device. b. After initiating the explosive device, the logging engineer must record a minimum of 200 ft of valid sensor data from all sensors above the top-most interval. 24. At the end of the logging service or explosive run, the engineer returns to the surface. 25. Once on surface, the engineer rechecks the tool zero, which should equal the depth correction plus the initial tool zero value.


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Total Depth Logger/Bottom terval Given the vertical displacement of the logging sensors in the tool string and the distance from the tool zero, several key factors must be defined on the log for our customer to fully understand the measurements we are providing. The proper annotation of these points is critical to log performance and must first be understood by the logging engineer.

Total Depth (TD) The first piece of information that a client has concerning the depth of the well is the total depth, as reported by the driller. Driller’s depth is measured by the total number of ts of drillpipe placed in the well. This measurement may or may not include pipe stretch and is a close approximation to the actual total depth of the well. This depth should not be confused with the casing depth. The production casing string often times includes additional elements that may subtract from the TD, and the cased-hole engineer needs to be aware of the differences between the two.

Plug-Back Total Depth (PBTD) PBTD is often confused with total depth of the well. As explained above, the TD of the well is gathered from the total ts of drillpipe used to drill the well. However, when the cased-hole engineer is operating in the well, he is usually in production casing, which is not the same. There are two factors that will cause a difference between TD and PBTD. First, the casing in the well may not have been run all the way to the bottom of the physical hole; therefore, the bottom of the casing will be shallower than the actual reported TD by the driller. The second factor is the cement plug. After the well is cased, it is then cemented. The cementing process requires the use of two plugs, which at the end of the process, will remain at the bottom of the well. These plugs will also subtract from the TD reported by the driller. For this fact alone, the cased-hole engineer must be especially careful when approaching the TD of the well to ensure that they do not prematurely tag these elements and possibly damage them or the tool string. When the engineer does tag the bottom of the cased well, he should report this as the Plug-Back Total Depth (PBTD), not TD. This may also occur if remedial work was required on the well and a portion of the well had to be blocked off with a bridge plug. In this case, the TD reported by the driller and the Plug PBTD may be significantly different.

Total-Depth Logger In some cases, PBTD and total depth logger (TDL) may be the same. TDL is simply the deepest point in the well that the logging tools reached for a particular trip in the well. The most common mistake that logging engineers make in calculating TDL is not including any tool length that may exist below the tool zero. This measurement is typically obtained from the log by observing the point where the tension curve increases and then levels off to a constant value (see Fig. 2.3.18). However, because the Warrior



Halliburton Energy Services Software indicates tension pick up at tool zero, the tension pickup will not accurately reflect TDL if there are any portions of the tool that extend below the tool zero.

Bottom-terval Given the vertical separation of the tool sensors throughout the tool string, it is also necessary to indicate to the client the point at which the collecting of valid sensor data begun. This is due to the distance from the first sensor to the bottom of the tool, or tool zero. When the log has begun, there will be curves represented on the log that do not reflect valid data from the sensor. Therefore, we must indicate to the client the absolute depth where taking valid measurements begins. Often times, this is the portion of the log where the bottom-most sensor begins transmitting valid data. To mark the log correctly, the logging engineer must take the TDL value and subtract the distance from the bottom of the tool to the bottom-most sensor in the logging tool string. This point will be the bottom-terval, which represents the beginning of usable data for the client.

Fig. 2.3.18—Relative Position of the Tool (Measured Depth) vs Physical Position of the Logging Sensor.


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Calculation Examples Example #1 A 2-ft/rev system is found to be measuring 1 ft/kft error due to wheel and cable wear. To calculate the amount of correction needed for this example: A. How many feet per revolution is the wheel actually showing?

This shows that the wheel is moving the odometer 2.002 ft for every 2 ft of cable that is actually spooled in or out. B. To determine the total error in diameter, we use the equation: D = C/π D = 1.998 ft/ 3.1416 = 0.6363 ft Next, convert the calculated diameter in feet (0.6363) to inches. 0.6363 ft X 12 in. = 7.635 in. Now, subtract the calculated diameter from the system "absolute" diameter. 7.639 in. – 7.635 in. = .004-in. error in total diameter These calculations have proven mathematically that .004-in. error in total diameter will equal a 1-ft/kft odometer reading (and log recording) error when using a 2-ft/rev system.

Example #2 A 2-ft/rev system measures 4 ft/kft deep. In this case, the tool zero is at 996 ft, but the odometer after 500 revolutions reads 1,000 ft. Calculate the system’s "absolute" diameter. 26. 996 ft/500 rev = 1.992 ft/rev 27. 1.992 ft/3.1416 = 0.63407 ft in diameter 28. 0.63407 ft X 12 in. = 7.609 in. 29. 7.639 in. (absolute diameter) – 7.609 in. = .0.03 in. The diameter is 7.609 in. instead of 7.639 in.




Example #3 In a free-pipe/back-off job, what should be the full-scale tension calibration value and why? In a free-point/back-off job, or any job where there is a need for non-conventional rigup, the top-sheave wheel will be put on the derrick (not with the elevators). 30. It is difficult to determine fleet angle. 31. It may not be practical because the driller is required to move the elevator up and down with a free-point/back-off job so that the stretch readings can be taken. Due to both of the reasons mentioned above, it is more logical for the load cell to go on the bottom-sheave wheel where the fleeting angle will be almost 90°. Hence, the fullscale calibration value will be: Calibration value (full-scale) = 3,250/[cos (90°/2)] = 4,596 lb

Example #4 Due to conditions beyond our control, the load cell must be placed on the lower-sheave wheel during rigup. Our best approximation of the lower-sheave fleet angle is 130°, with the logging unit spotted 25 m from the well head. Given these conditions, what is the correct tension-calibration value for the full-scale tension calibration? Calibration value (full-scale) = 3,250/[cos (130°/2)] = 7,690 lb

Example #5 What will be the effect on the depth reading if you there is a groove in the measuring wheel? Assume that there is no slippage. The depth read by the depth counter will be more than the actual tool depth.

Example #6 On a 600-pulse/rev system with 2-ft circumference measuring wheels, what will happen if the engineer inputs 1,200 pulse/rev while configuring the depth system at a well depth of 10,000 ft? On a system with 600 pulse/rev, if you enter 1,200 pulse/rev as an input while configuring the depth , then the tool will be at 10,000 ft; however, the depth counter will display 5,000 ft. 12/29/2008 Cased-Hole Associate Field Professional Vol. I

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Example #7 Calculate the stretch factor in True Depth Mode with the following conditions:     

The line in use = 7/16 in. The stretch coefficient = 0.8 ft/kft/klb Effective Tool Weight = 1,000 lb Depth = 10,000 ft Surface tension = 4,000 lb

The True Depth Mode Stretch in ft = 0.5 X 0.8 X 10 (4 + 1 -2) = 12 ft

Wheel Diameter Error For a 2-ft/kft system: (7.639 in. absolute diameter) Diameter Change Measurement Error    

.0039 in., .5 ft/kft .0078 in., 1.0 ft/kft .0117 in., 1.5 ft/kft .0156 in., 2.0 ft/kft




Section 4 Cased-Hole Weak Points The nature of Wireline work requires the use of a weak link constructed between the cable and the tool string that is being deployed in a well. This is designed to allow for the capability of separating from the tool string in the event it becomes stuck in the well. The dynamics of how the weak leak is constructed and how the strengths of each weak link are calculated are very important for a Wireline field professional to understand. There are two types of weak links used in Halliburton WPS today. The first is a solid weak link, which is used in the open-hole DITS cable head. The second is the casedhole weak link, which is constructed from the individual armors of the cable. This chapter will discuss the construction and calculation of the strength of a cased-hole weak link. The fact that a cased-hole weak link is constructed from the cable armors makes the construction and calculation of the weak point very dynamic. Factors, such as age, condition of the cable, method of construction, and design characteristics play a large role in the strength and performance of the weak link. Some of these factors can be ed for while others cannot. To address these issues, Halliburton has recently begun a deployment program to obtain a cased-hole cable head pull testing unit in each WPS location. This unit will give cased-hole AFPs the ability to test the weak points they construct with their cable to determine the actual strength of the weak link.

Construction To understand how strength is calculated, construction must first be discussed. The cased-hole weak link is constructed as part of the cable head. The cable head serves as a housing to protect the weak link and also serves as the electrical and mechanical connection point between the cable and tool string.

Step 1: Preparing the Cable The first step is to slide the stinger over the end of the cable and out of the way. Caution:

The fishing neck must be on the cable before proceeding with the rehead procedures.


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Fig. 2.4.1—Sliding the Stinger on the Cable.

Step 2: Securing the Cable Wrap the cable with tape about 2 ft from the end of the cable. This prevents the cable from slipping when it is put in the cable clamp and secured in a vise.

Fig. 2.4.2—Use Tape to Protect the Wireline When being Secured in the Vise.

Next, place the cable between the two halves of the cable clamp, and secure the clamp lightly in a vise. 214 Cased-Hole Associate Field Professional Vol. I



Fig. 2.4.3—Cable Secured in Vise.

Step 3: Wrapping the Cable Using nylon seizing cord, wrap the cable 18 in. from the end. Tie the cord securely, and trim off the excess. The cord is used to prevent the brass core from slipping during the rehead process.


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Fig. 2.4.4—Wrapping the Cable with Nylon Seizing Cord.




Step 4: Installing the Brass Core Slip the brass core over the end of the cable, and seat it firmly against the nylon cord. Make sure the brass cord is installed with the flat side down.

Fig. 2.4.5—Installing the Brass Core.


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Step 5: Building the Weak Point Assembly The single-conductor cable head uses the strands of armor from the cable to make the weak point assembly. The table in Fig. 2.4.6 is used to determine the number of outer and inner strands of armor required for the weak-point assembly. Note:

Always refer to the most up-to-date charts from the cable manufacturer to obtain the correct values to be used in weak point calculations.

Fig. 2.4.6—Camesa Cable Specifications.



Halliburton Energy Services Note:

For this manual, we are reheading a 5/16-in. cable with weak point tension strength of 3,250 lb. We are using 7 strands of outer armor and 2 strands of inner armor to build the rope socket.

Use a pair of pliers to unravel the first strand of outer armor.

Fig. 2.4.7—Unraveling the Outer Armor.

Bend the strand around the rounded part of the brass cone while holding the cone with the other hand.


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Fig. 2.4.8—Bending the Armor around the Cone.

Next, the strand of armor through the nearest hole in the bottom of the brass cone.




Fig. 2.4.9—ing the Strand through the Cone.


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Pull the strand tight with a pair of pliers (Fig. 2.4.10). Then, bend the strand out from the brass cone at a right angle to keep the strand tight around the cone (Fig. 2.4.11).

Fig. 2.4.10—Pulling the Strand Tight.

Fig. 2.4.11—Bending the Strand.

Use a set of wire cutters and cut off the strand of armor even with the edge of the brass cone.

Fig. 2.4.12—Cutting the Strand of Armor.



Halliburton Energy Services Repeat the process with the six remaining strands of outer armor, leaving space between each strand around the cone (Figs. 2.4.13 and 2.4.14).

Fig. 2.4.13—Tightening Last Strand of Outer Armor.

Fig. 2.4.14—Outer Armor Strands around Cone.


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Clip the remaining strands of outer armor off directly above the cone (Fig. 2.4.15). Do NOT bend them over the curve of the cone.

Fig. 2.4.15—Removing the Remaining Strands of Outer Armor.

Next, take two strands of the inner armor and bend them over the top of the cone. Then, feed them through the corresponding empty hole in the base of the cone (Fig. 2.4.16). Pull the strands tight and bend them at a right angle from the bottom of the cone. Cut them off flush with the base of the cone.




Fig. 2.4.16—Inner Armor.

Step 6: Removing the Inner Armor Take a length of nylon seizing cord and wrap it around the remaining strands of inner armor about ½ in. above the cone (Fig. 2.4.17).

Fig. 2.4.17—Wrapping the Inner Armor.


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Bend each of the remaining strands of inner armor down sharply over the nylon cord, and cut the armor, leaving ¼ in. pointing down (Fig. 2.4.18). Do NOT leave any sharp edges pointing upward (Fig. 2.4.19).

Fig. 2.4.18—Cutting the Inner Armor.

Fig. 2.4.19—Inner Armor Removed.

Step 7: Sliding the Stinger over the Cone Take the cable out of the vise and slide the stinger up over the cone (Fig. 2.4.20).

Fig. 2.4.20—Sliding the Cone into the Stinger.




Step 8: Installing the Cone Retainer Slide the brass cone retainer over the insulated conductor wire with the beveled side down until it rests on the cone (Fig. 2.4.21).

Fig. 2.4.21—Installing the Cone Retainer.


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Step 9: Installing the Cable Head Sleeve Hold the stinger in one hand and thread the cable-head sleeve over the insulated conductor wire. Screw it into the stinger until it is hand tight (Fig. 2.4.22). Note:

The fishing neck and cable head sleeve are left hand threads.

Fig. 2.4.22—Installing the Cable Head Sleeve.




Step 10: Cutting the Insulated Conductor Wire Secure the cable head back in the vise. Measure and cut the insulated conductor wire, leaving 4 in. of conductor wire sticking out of the end of the cable-head sleeve (Fig. 2.4.23).

Fig. 2.4.23—Cutting the Conductor Wire.

Trim 1 in. of insulation from the end of the conductor wire, exposing the wire (Fig. 2.4.24).

Fig. 2.4.24—Insulation Removed.


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Step 11: Threading the Boot Thread the boot over the end of the conductor wire, small end first, and slide it down to the cable-head sleeve (Fig. 2.4.25).

Fig. 2.4.25—Boot Installed.




Step 12: Connecting the Conductor Wire Thread the exposed portion of the conductor wire through the hole in the brass terminal nut of the subassembly (Fig. 2.4.26).

Fig. 2.4.26—Threading the Conductor Wire.

Twist the wire around the terminal to secure it to the subassembly (Fig. 2.4.27).

Fig. 2.4.27—Securing the Conductor Wire.


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Slide the boot over the end of the terminal nut of the subassembly, and seal the large end of the boot with nylon seizing cord (Fig. 2.4.28).

Fig. 2.4.28—Boot Installed.

Step 13: Final Assembly of the Cable Head Unscrew the cable-head sleeve from the stinger until one thread holds them together. Then, screw the subassembly into the cable head sleeve one full turn. Clamp the subassembly in the vise. While holding the stinger in one hand, screw the cablehead sleeve into the subassembly. This tightens the cable-head sleeve to the stinger and subassembly (Fig. 2.4.29).

Fig. 2.4.29—Assembling the Cable Head.



Halliburton Energy Services Using an 18-in. pipe wrench, tighten the cable head sleeve onto the subassembly (Fig. 2.4.30). Do NOT over-tighten the sleeve, or damage could occur to the thread’s subassembly.

Fig. 2.4.30—Tightening the Sleeve to the Subassembly.

Remove the subassembly from the vise and secure the stinger in the vise. Use the pipe wrench to tighten the cable-head sleeve into the stinger (Fig. 2.4.31). , this is a left-handed thread.

Fig. 2.4.31—Tightening the Cable Head Sleeve to the Stinger.


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Step 14: Greasing the Cable Head To grease the cable head, first remove the set screw from the cable-head sleeve using an Allen wrench (Fig. 2.4.32).

Fig. 2.4.32—Removing the Cable-Head Sleeve Set Screw.

Install a grease fitting into the cable-head sleeve, and use a grease gun to fill the cable head with silicon grease (Figs. 2.4.33 and 2.4.34).

Fig. 2.4.33—Grease Fitting Installed.




Fig. 2.4.34—Filling the Cable Head with Grease.

Remove the grease fitting and re-install the set screw.

Summary This section covered the procedure to rehead the 1-7/16 single-conductor cable head. Follow all of the steps as presented to ensure the cable head is ready for use upon completion of the rehead.


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Weak Point Calculations Conventional thinking would lead us to believe that the cased-hole weak point, being constructed of the individual armor strands, would have the strength of the sum total of individual armor strengths used in constructing the weak point. For the most part, this statement is true with some exceptions, which will be discussed later in this chapter. When deg a job, cable-head and weak-point construction are part of the preparations that are performed prior to the job. Each job and well must be considered individually, and the weak-point strength should be evaluated to determine if the strength is sufficient to perform the job. Although the practice of establishing a one-size-fits-all standard weak point for an NWA is used, it is not recommended.

Determining Maximum Weak-Point Value For the purposes of this document, the following information will be used for all calculations: Camesa 1N22PZ 7/32-in. Monocable 18 Outer / 12 Inner Strength per Armor: 204 lb Armor Diameter: 0.031 in. Breaking Strength: 5,200 lb Weight in Air: 96 lb/kft Weight in Water: 82 lb/kft Well Depth: 10,000 ft Well-Bore Fluid (Fresh Water): 9.0 ppg Tool Weight: 300 lb The maximum weak-point value is the value that the weak point cannot exceed in the well for which it will be used. This value is determined to prevent the wireline from being exposed to tensions in excess of 50% of its rated breaking strength. Exposing the cable to tension greater than 50% of its breaking strength could result in permanent damage. The following equation is used: Weak Point ≤ 50% Cable Breaking Strength—Cable Weight in Mud at Maximum Depth In order to perform this calculation, we must first determine the cable weight in mud per 1,000 ft. This is accomplished by using the following formula: W CM = W CA – [(W CA – W CW ) x W M /8.33]


(Eq. 2.4.1)


Halliburton Energy Services Where: W CM = Weight of Cable in Mud W CA = Weight of Cable in Air W CW = Weight of Cable in Water W M = Weight of Mud (Bore-Hole Fluid) Using the information above: W CM = 96 lb/kft – [(96 lb/kft – 82 /kft) X 9.0 ppg/8.33 ppg] W CM = 96 lb/kft – [ 14 lb/kft X 9.0 ppg/8.33 ppg] W CM = 96 lb/kft – [126/8.33] W CM = 96 lb/kft – 15.12 W CM = 80.88 lb/kft The next step is to calculate the maximum weak-point value. Using the formula and the example information, the maximum weak point value can be determined. Weak Point ≤ 2,600 lb – (10 kft X 80.88 lb/kft) Where:   

2,600 lb is 50% of the cable breaking strength 10 is the depth in kft 80.88 lb/kft is the weight of the cable in mud per kft.

In the example: Weak point ≤ 2,600 lb – 808.8 lb Maximum Weak-Point Value ≤ 1791.2 lb By using the process above, the weak point that is constructed must not have a strength greater than 1791.2 lb.


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Weak-Point Construction Calculations At this point, the number of armors to be used for the construction of the weak point must be determined. There are considerations when determining the number and type of armors to be used for constructing a monocable weak point. The values that are published by the cable manufacturer are based on new cable values. However, this will not always be the case, and the cable will be used to construct many weak points throughout its service life. Therefore, a couple of key factors must be considered when determining the designed strength of the weak point. These factors are: 32. Age and condition of wireline 33. Consistency in construction of the weak point 34. Angle of the armor strands as they are bent over the brass cone For this purpose, a 15% downgrade is applied to the published cable-armor strengths to determine a value to be used for the calculation of weak point strengths. To determine the number of armors to be used in the construction of the weak point, use the following formula:

(Eq. 2.4.2)

Using the example information: Number of Armors = 1791.2 lb/173.4 lb = 10.3 For safety purposes, round the number down to the lowest whole number. The next step requires that the number of inner and outer armors to be used in the construction of the weak point be determined. Depending on the cable, construction there are design factors that must be taken into consideration. The primary driving factor for this decision is the inner and outer armor diameter. Some cables are constructed with equal amounts of inner and outer armors. This construction style requires that the inner armors have a smaller diameter and, thus, a lower strength. Therefore, all of the armors used in the weak point will not contribute equally to the overall strength. For this purpose, the following guideline has been established. If: 35. The inner and outer armors are the same diameter, then the inner armors may be used to calculate the weak-point strength. 36. The inner and outer armors are not the same diameter, then do not include the inner armor strength in the weak-point strength calculation.



Halliburton Energy Services Note:

Regardless of inner and outer armor diameter, a minimum of two inner armors should be used in the weak-point construction to maintain the counter torque properties of the cable. Not including at least two armors prevents the cable from releasing torque and may cause damage to the cable.

Using the data from the example, a total of 10 armors will be used. In the example, the inner and outer armors are the same diameter, so the weak point could consist of 8 outer armors and 2 inner armors. Other configurations may also be used, such as 6/4 or 7/3; however, for purposes of symmetry and ease of construction, the number of outer and inner armors are usually kept at an equal ratio.

Determining Weak-Point Strength Once the weak point is constructed, determine the value of the weak point for operational use.

(Eq. 2.4.3)

Using the example information: Weak-Point Strength = 10 X (204 lb X .85) Weak-Point Strength = 10 X (173.4) Weak-Point Strength = 1,734 lb From this point forward, all calculations while in the well will use this value. Be aware that although we have applied a 15% reduction in strength, the weak point may still have a value that is the sum total strength using new cable values. When considering the amount of tension to apply to the weak point, this fact must be taken into .

Maximum Safe Pull and Maximum Pull During the run in the well, a value for the maximum amount of tension that may be applied to the weak point if the tool becomes stuck must be determined. This value is known as the Maximum Safe Pull. To determine Maximum Safe Pull, the following formula is used:


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(Eq. 2.4.4)

Assuming that our tool is stuck at a depth of 5,000 ft, and using the example information, the formula would be applied as: MSP = (5 kft X 80.88 lb/kft) + 1734 lb X .66 MSP = 404.4 lb + 1134.4 lb MSP = 1548.8 lb In the event that the tool cannot be freed and the decision has been made to separate the weak point, the value at which the weak point will break must be determined. Note:

Prior to pulling out of any weak point, a manager must be notified, and all safety precautions on the well site must be taken to prevent injury to personnel.

To determine the pull-out value, simply remove the 66% reduction from the equation above.

(Eq. 2.4.5) Note:

The value that was used to determine our MSP included a 15% downgrade in weakpoint strength. Keep in mind that when attempting to break the weak point, the actual point where the weak point breaks could go as high as the full weak-point value using the raw-armor strength.

To for either scenario, the pull-out calculation should be performed using the 15% downgraded weak-point value and the full weak-point value. In doing this, we will determine the minimum and maximum breaking point. Using the example information we would apply the formula as:

(Eq. 2.4.6)

(Eq. 2.4.7) 240 Cased-Hole Associate Field Professional Vol. I


Halliburton Energy Services Example: Minimum Pull Out MinPO = (5 kft X 80.88 lb/kft) + 1,734 lb MinPO = 404.4 lb + 1,734 lb MinPO = 2,138.4 lb Maximum Pull Out MaxPO = (5 kft X 80.88 lb/kft) + 2,040 lb MaxPO = 404.4 lb + 2,040 lb MaxPO = 2,444.4 lb


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Cased-Hole Associate Field Professional Course Manual Volume I Chapter 3 Telemetry, LOGIQ, Filters, and Delays Revision (A) (August 2008) Reference No. WPS-TD-20002


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Preface This WPS Training manual provides information on telemetry, filters, LOGIQ-CH, and delays for the Cased-Hole Associate Field Professional. Study the manual to develop a through understanding of the tool before operating or servicing it for the first time. Observe all notes, cautions, and warnings to minimize the risk of personal injury or damage to the equipment. Section 1 Telemetry –Overview of Wireline telemetry forms and processing within the LOGIQ-CH system. Section 2 Filters – Overview of electronic and software filters. Section 3 LOGIQ-CH – Overview of the LOGIQ-CH system, processes, and hardware configuration. Section 4 Delays – Explanation of software delays and the process of declaration in the Warrior logging software.




Section 1 Telemetry Basic Telemetry Well logging is the measurement of the characteristics of different earth formations traversed by a borehole, usually an oil or gas well, using one or more measurement tools or instruments. The logging tools are typically stacked and attached to a logging cable. The logging cable s the tool string, supplies power to the tool or tools, and provides a communication medium for the transmission of data between the tools and the data acquisition equipment on the surface. Telemetry is a technology that allows the remote measurement and reporting of information of interest to the system designer or operator. To understand telemetry and how we use it, it is necessary to understand the greater system to which it belongs. This system as a whole is called a Data Logging System (DLS). A DLS is comprised of four main components: 1. 2. 3. 4.

Measuring Output (Logging Tool) Recording Output (Logging Unit) Analysis of recorded data (DAS Hardware/Software) ing/accessing recorded data (Telemetry)

Measuring Output The first component of a Data Logging System is a series of sensors used to record data measurements in a given environment. In the Wireline business, this is our logging tool. Each tool is designed and built with a series of sensors designed to measure a specific response or characteristic. The measurements are usually taken via direct with the elements inside the well. Depending on the tool, measurement of the data is either taken by the surface systems or inside the tool.

Recording Output The second component of a Data Logging System is the recording output unit. This unit is comprised of a hardware interface and serves to record the data output of the logging 12/29/2008 WPS Training


Halliburton Energy Services sensors. For cased-hole logging applications, this function is performed by the RackMounted Portable Computer (RMPC) for digital storage and the Printrex Thermal Printer to generate paper logs. The RMPC is a principle component in the larger total system called LOGIQ. The RMPC is the platform for the Warrior Logging Software and is the interface between the Warrior Software and the CHIP.

Analysis of Recorded Data (DAS Software) The third component of a Data Logging System is the data acquisition system. The data acquisition system is normally electronics based and is made of hardware and software. The hardware is made of sensors, cables, and electronic components, including memory where information is stored. The software consists of the data acquisition logic and analysis software. Early surface acquisition systems required a separate surface module for each logging sensor (see Fig. 3.1.1). As advances in technology were made, the size of the components was reduced to the point that a single electronics unit containing printed circuit boards was capable of performing the same data processing as the modules.

Fig. 3.1.1—Early Surface Acquisition vs. Current LOGIQ.

In the LOGIQ system, the CHIP performs the function of hardware interface. The software component of the LOGIQ-CH system is the Warrior Logging Software, which is located on the Rack-Mounted Portable Computer (RMPC). The Warrior Logging Software performs measurement, analysis, and records the data in a format for longterm storage.



Halliburton Energy Services ing/Accessing Recorded Data The fourth component of the Data Logging System, and the subject of this chapter, is telemetry. The word telemetry is derived from the Greek roots tele, meaning remote, and metron, meaning measure. Simply put, it is a format for transmitting data across a medium. Telemetry is comprised of two elements: 1. Telemetry 2. Telecommand Telemetry is the communication of data from the sensor to the data acquisition system. Systems that need instructions and data sent to them in order to operate require the counterpart of telemetry, which is known as the telecommand. In order for information to be sent effectively from one point to another, it must be compiled into a pre-arranged format (which may follow a standard structure), modulated onto a carrier wave that is then transmitted with adequate power to the remote system. The remote systems will then demodulate the signal from the carrier, decode the information, perform necessary measurement or analysis, and record the data or execute the command contained within. The complexity and nature of the format will differ with the amount of sensors combined in a tool string. As the amount of sensors increases, the telemetry will change to a format that is capable of handling larger amounts of data. Earliest forms of telemetry used an analog carrier (sine) wave to transmit simple measurements, such as temperature, to a remote monitor. Advances in processing technology slowly made it possible to move the measurement functions from the surface into the tool. This migration of processing reduced the size of the surface measurement systems, but it also required more complex forms of telemetry.




Wireline Telemetry Forms Analog Telemetry An analog or analogue signal is any time-continuous signal, where some time-varying change in signal is a representation of some time-varying quantity. It differs from digital signals in that small fluctuations are meaningful. Analog is often thought of in an electrical context. Analog signals are typically expressed as a sinusoidal waveform. Alteration of frequency, voltage, charge, or current will correspond to a change in the value detected by any sensor. In all forms of analog telemetry, it is important to note that the measurement of the wave form is performed by the surface acquisition system. The sensor outputs a simple response encoded into an analog carrier wave that is sent up the wireline and measured by the surface systems. The purest form of analog telemetry that we use is the signal from an analog CasingCollar Locator. The CCL coil, surrounded by a magnetic field, generates a constant voltage output. When the CCL es through a collar, magnetic fields are disrupted or placed out of balance by the change in metal thickness (density), and the output voltage of the CCL coil changes. The change in voltage is recorded by the surface system as a collar strike.

Fig. 3.1.2—Sinusoidal Waveform.

Another example of this type of telemetry is the basic tension load-cell signal. Although the tension load cell signal is not transmitted through logging the Wireline, the signal and process are the same. The load cell outputs a constant voltage to the measurement system. As tension is applied to the load cell, the output voltage will change. The system measures this change and converts the change in voltage to display the change in pounds.



Halliburton Energy Services The primary disadvantage of analog signaling is that any system has noise (i.e., random variations). When the signal is transmitted over long distances, such as required in well logging, these variations (noise) may become dominant and prevent the intended signal variations from being detected. This ratio between line signal and line noise is called the signal-to-noise ratio. The signal-to-noise ratio is the ratio of signal strength to noise strength in the waveform. The optimum condition is that the signal amplitude stays higher than the noise amplitude, making it possible for the surface acquisition system to identify the intended signal variations, which are the logging sensors data. If the signalto-noise ratio becomes too low, then the surface acquisition system will have difficulty distinguishing the tool telemetry from the line noise and can result in distortion or the loss of data. The data loss is often not recoverable because any amplification of the signal will also amplify the noise. The sources of the noise can be diminished electrically by good shielding and cabling, but the noise can never be fully eliminated. The largest contributor to line noise is the increase in line resistance/impedance as cable is spooled off the drum. In order to transmit any signal; telemetry, power, etc. through a physical medium, there must be two lines to complete the circuit. In an open-hole, seven-conductor line, there are multiple pairs of conductors available. However, with a cased-hole, mono-cable line, the return path to ground is the cable armor. When the cable is spooled on the drum, the resistance of the armor is very low because all of the armors are making metal-to-metal . However, as line is spooled off of the drum, the length of the line, in of the path electrical signals must follow, increases. As line resistance increases, signal strength decreases, thus, compounding the effect of any noise already on the line. In other words, as line length increases, the signal-tonoise ratio decreases, causing distortion of the data. Another contributing factor to increasing line resistance/impedance is heat. Most logging cables use conductors constructed from copper. The resistance of copper increases as its core temperature increases, which causes distortion of the power and telemetry signal. The two principle causes of the heating are well-bore temperature and electromigration. As the Wireline descends into the well, the natural increase in temperature as depth increases will cause heating of the cable. In addition, another process called electromigration will also cause an increase in the core temperature of the conductor. Electromigration is the process of heating caused by the continual flow of electrons through a medium. The longer the flow is maintained, the more heat will be generated. In most cases, the distortion of the telemetry signal is compensated for inside the surface-acquisition-system gain and filter controls. (*Refer to Warrior Logging Software documentation for adjusting signal gain and filter.*)

Bi-Polar Pulses Bi-Polar Pulse Telemetry is another form of analog telemetry. This form of telemetry is most common in counting tools, such as the natural gamma-ray tool or compensatedneutron tool, where the only data that needs to be transmitted is a simple pulse to signal a single count of a gamma ray or neutron by the detector. This telemetry still uses a continuous-time waveform transmitted at a specific voltage and frequency; however, when the detector counts a gamma ray or neutron, the tool generates a positive or 12/29/2008 WPS Training


Halliburton Energy Services negative pulse, which is imposed on the waveform. The pulse generated is at a higher voltage than the waveform continuous voltage and, therefore, can be identified by the system as a gamma or neutron count. The pulse is then counted by the system as one gamma ray or neutron. For this reason, tools of this type are often called pulse tools or pulse counters. In most tools, gamma-ray counts are sent uphole as negative pulses, and neutron counts are sent as positive pulses.

Fig. 3.1.3—Bi-Polar Pulses. (Warrior Logging Software will display a graphical representation of the Bi-Polar pulse signal in the Pulse Monitor (PMON) window.)

Fig. 3.1.3 shows a typical Bi-Polar pulse from a gamma-ray/neutron tool. Notice the imposed pulses on a carrier wave. This is typical and should be seen for normal telemetry signals. However, it is important to adjust the signal strength to maximize the size of the positive and negative pulses while, and at the same time, minimizing the signature of the underlying carrier wave. This process is called adjusting the signal to noise ratio. In addition, setting proper detection-threshold levels will also help the system distinguish the pulse from the noise (see Fig. 3.1.4).




Fig. 3.1.4—PMON with Detection Threshold.

Fig. 3.1.4 shows the positive and negative detection threshold set to indicate to the surface acquisition system when a positive or negative pulse should be counted. Threshold values are set according to signal height versus noise height (signal-to-noise ratio). Standard practice is to set the thresholds at 20% and 80% of the total windowheight span and adjust according to signal strength.

Multiple Sensors/Acoustic Tools The limiting factor of Bi-Polar pulses is that a maximum of two-pulse, counting-type tools (sensors) could be used in any one tool string. As logging tools became more advanced, it was possible to stack multiple tools in one string or multiple sensors in one tool. However, because the telemetry form was still analog, the amount of data that could be transmitted was limited mostly by time. Recall that an analog signal is the continuous measurement of variations in amplitude, polarity frequency, or current over time. This means that for any given frequency, there is a maximum amount of data that can be encoded onto a carrier waver in a specific time period. When a tool string with multiple sensors has reached full power, all of the sensors will begin collecting and transmitting data at once. However, all of the data from the sensors cannot be encoded onto a carrier wave at the same time. Therefore, the tool has a master clock that controls the opening and closing of windows for each sensor data to be encoded onto the carrier wave at different times in a predetermined order. This allows even distribution of the data in a sequential manner so that it can be sent to the data acquisition system in an orderly fashion and prevents sensor data from overlapping and distorting each other. Once a complete set of tool sensor data (all sensors) has been encoded onto the carrier wave, the process repeats at a predetermined interval; this is known as a data cycle. In order for the surface acquisition system to properly receive, decode, and process the sensor data, it must be synchronized with the tool. Inside the analog tool, tied to the master clock, is a pulse generator. This pulse generator will generate what is called the synchronization pulse (sync pulse). The purpose of the 12/29/2008 WPS Training


Halliburton Energy Services synchronization pulse is to signal to the surface system when a new data cycle begins. In simpler , the synchronization pulse is a zero count or reset signal. Once the surface acquisition system has been adjusted to recognize the sync pulse, it can then begin counting in time with the tool. The analysis software is configured to receive the data in the same order as the tool is sending and, therefore, associates it with the correct sensor. For cased-hole applications, the best example would be the cement bond tool. An analog CBL tool, in most cases, combines a negative-pulse gamma-ray tool, a standard analog CCL a 3-ft acoustic receiver, and a 5-ft acoustic receiver. Fig. 3.1.5 depicts a typical analog signal as viewed on an oscilloscope.

Fig. 3.1.5—Data Cycle.

The type of pulse (positive/negative) that is sent at the beginning or end of a sequence will depend on tool design. In addition, the placement of the synchronization pulse may also change with tool design. For example, some cement bond tools will place synchronization pulses at the beginning of the acoustic data from each receiver (i.e., 3 ft or 5 ft) and then rely on timing to identify the remaining sections of data.




Fig. 3.1.6—Warrior Pulse Monitor.

Digital Telemetry As previously discussed, electrical pulses transmitted via wire are typically attenuated by the resistance of the wire and changed by its capacitance or inductance. In addition, temperature variations may also increase these effects. Because analog telemetry is a time-continuous signal in which variations in frequency, amplitude, current, or polarity represent changes in value, any distortion of the signal will degrade the overall quality of the measurement. The advent of the microprocessor made it possible to move the measurement processes from the surface to the tool. All logging sensor data is ana nature, and in order for it to be processed by a computer-based system, it must be converted to digital. In a pure analog logging tool, this conversion was performed at surface by the data acquisition system, thus, the inherent problem with analog signal distortion. In a digital-logging tool, the sensor sends its data to an Analog-to-Digital Converter (ADC) circuit where the analog data is converted to digital data. The ADC then sends the digital data to a Remote Terminal Unit (RTU) usually located in the telemetry section or portion of the logging tool. The RTU then combines all of the digitized sensor data into a digitaltelemetry format for transmission to the surface acquisition system. The exact architecture of this format will change with tool design and is not relevant to basic understanding of the forms of telemetry. It is important to note that the digitizing of data served two purposes. The first purpose is that it greatly enhanced data quality, as the sensor data was not subject to the distortion caused by the attenuation of the logging cable. The second purpose is that the amount of data capable of being sent along the Wireline was increased and, therefore, allowed for more measurements to be taken or more tool sensors to be combined in a single tool string.




Basic Digital Telemetry A waveform that switches between two voltage levels representing the two states of a Boolean value (0 and 1) is referred to as a digital signal, even though it is an analog voltage waveform, since it is interpreted in of only two levels. Therefore, a digital signal is a discrete-time sampled version of an analog waveform; the value of the datum is noted at fixed intervals (for example, every microsecond) rather than continuously. The two states of a wire are usually represented by some measurement of an electrical property. Voltage is most common, but current is used in some systems. A threshold is designed for each logic family. When below that threshold, the wire is "low;" when it is above the threshold, the wire is "high." Digital circuits establish a "no man's area" or "exclusion zone" that is wider than the tolerances of the components. The circuits avoid that area in order to avoid indeterminate results. It is standard to allow some tolerance in the voltage levels used. For example, 0 to 2 V might represent logic 0, and 3 to 5 V may represent logic 1. A voltage of 2 to 3 V would be invalid and would occur only in a fault condition or during a logic level transition, as most circuits are not purely resistive and, therefore, cannot instantly change voltage levels.

Fig. 3.1.7—Digital Signal Properties.

All digital data is combined of 1s and 0s, which is known as the binary numeral system format.

How Binary Works The decimal number system that people use everyday contains ten digits, 0 through 9. Start counting in decimal: 0, 1, 2, 3, 4, 5, 6, 7, 8, 9, Oops! There are no more digits left. How do we continue counting with only ten digits? We add a second column of digits, worth ten times the value of the first column. Start counting again: 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20 (Note that the right column goes back to zero here.), 21, 22, 23,…, 94, 95, 96, 97, 98, 99, Oops! Once again, there are no more digits left. The only way to continue counting is to add yet another column worth ten times as much as the one before. Continue counting: 100, 101, 102,…, 997, 998, 999, 1000, 1001, 1002, you should get the picture at this point.



Halliburton Energy Services Another way to make this clear is to write decimal numbers in expanded notation. 365, for example, is equal to 3×100 + 6×10 + 5×1. 1032 is equal to 1×1000 + 0×100 + 3×10 + 2×1. By writing numbers in this form, the value of each column becomes clear. The binary number system works in the exact same way as the decimal system, except that it contains only two digits, 0 and 1. Start counting in binary: 0, 1, Oops! There are no more binary digits. In order to keep counting, we need to add a second column worth twice the value of the column before. We continue counting again: 10, 11, Oops! It is time to add another column again. Counting further: 100, 101, 110, 111, 1000, 1001, 1010, 1011, 1100, 1101, 1110, 1111.... Watch the pattern of 1s and 0s. You will see that binary works the same way decimal does, but with fewer digits. Binary uses two digits, so each column is worth twice the one before. This fact, coupled with expanded notation, can be used convert between from binary to decimal. In the binary system, the columns are worth 1, 2, 4, 8, 16, 32, 64, 128, 256, etc. To convert a number from binary to decimal, simply write it in expanded notation. For example, the binary number 101101 can be rewritten in expanded notation as 1×32 + 0×16 + 1×8 + 1×4 + 0×2 + 1×1. By simplifying this expression, you can see that the binary number 101101 is equal to the decimal number 45. Now that we understand the basis of binary counting, we can continue further by defining the structure of digital telemetry. Each digit in the binary system is called a bit. The term bit is used to define to different characteristics. A digital circuit is defined by the number of bits it can process or, in simple , how high it can count. For example, an 8-bit system can count to 256 (0–255). When defining the amount of data that a format can transmit across a medium, it is referred to as bits per second (bps). Most systems in use today are measured in kilo (thousands of) bits or mega (millions of) bits per second (kbps or Mbps). The basic unit of a digital system is a bit. A group of bits together form words. A group of words may be assigned to a data block, which is dedicated to a tool sensor. A group of data blocks will be put together to form a telemetry frame. An easy way to understand this model is to apply it to conventional english grammar structure. Consider the bits as letters of the alphabet. When grouped together, the letters will make a word that represent a value or object. A group of words together would be a sentence, which can be thought of as a data block. A sentence is used to communicate an idea or thought. A group of sentences can be put together is a paragraph, which is likened to a frame. A paragraph is used to communicate multiple ideas or thoughts in a single format. Digital telemetry functions in the same manner. Sensor data is acquired by the sensor and converted into a digital format (bits) by the ADC. The ADC outputs a word that is equivalent to the analog value of the sensor measurement. Although not always necessary, multiple words may be required for each sensor data. The words are placed together in data blocks, and the data blocks are arranged in a format for transmission called a frame. Each frame consists of a complete set of data from each logging tool or sensor and is preceded by a Sync Word. Digital tools are not unlike analog tools in that they also require a signal to align the surface-system timing with the tool-transmission timing.




Fig. 3.1.8—Basic Digital Telemetry Frame as it Might Apply to a Logging Tool.

The Warrior Logging Software generates a graphical representation of the digital packet and displays it in the Telemetry Monitor window (Fig. 3.1.9). However, this is not the same as the Pulse Monitor (PMON) window for analog tools. For a pure digital tool, the threshold controls in the telemetry monitor window serve no purpose. The primary purpose for the telemetry threshold window is to aid the in adjusting the signal strength.

Fig. 3.1.9—Warrior Telemetry Threshold Monitor.



Halliburton Energy Services When running a tool that uses digital telemetry, the warrior software also allows the to monitor the amount of frames received and decode properly and also the mount of bad frames the software received. This is shown as the frame count and the error count and can be viewed from the DSP Monitor function in the warrior acquisition interface (Fig. 3.1.10).

Fig. 3.1.10—Warrior DSP Monitor.

When using the TMDL or RMT, a separate monitoring and control window is loaded for monitoring frame and error counts (Fig. 3.1.11). This window has an additional feature of indicator lights that help the engineer monitor the frame-count-to-error-count ratio.

Fig. 3.1.11—Warrior TTTC Telemetry Monitor. 12/29/2008 WPS Training


Halliburton Energy Services For any digital tool, the logging engineer should record the error-count total at the beginning of the logging run once synchronization has been achieved. This will help the engineer monitor the amount of good frames received versus error frames.

Hybrid Telemetry Over time, it was discovered that some sensor data, such as acoustic signals and CCL signals, would degrade if encoded digitally. In addition, some manufacturers did not want to invest the money into putting microprocessors in a tool for data that did not necessarily need to be digitally encoded. This is the case for most of the newer cement bond-logging tools. With the limited number of sensors in a CBL string (GR, CCL, acoustic receivers), there was not a need to digitize all of the data from the tool in the tool. This gave rise to what is called hybrid telemetry. Hybrid telemetry is a mix between digital and analog telemetry. Using a newer CBL tool as an example, the gamma ray and tool-status information would be digitally encoded inside the tool while the CCL and acoustic waveforms will be sent to the surfaceacquisition system in an analog format. This combination of telemetry allowed for higher data-transmission capacity while, at the same time, preserving the integrity of the signal as much as possible. In addition, the lack of need for microprocessors in the tool to do analog-to-digital conversion helped to hold tool cost and size down.

Fig. 3.1.12—Example of What the Structure of a Hybrid Signal Would Look Like.



Halliburton Energy Services A hybrid telemetry frame will still begin with a Sync Word, and a period of time following the Sync Word is reserved for the transmission of the analog acoustic data. This period is followed by a short delay, and the rest of the tool data, digitally encoded, will follow that. At the end of the frame, another Sync Word will be transmitted to identify the end of transmission to the system. After the surface system receives the end of transmission word, any tool commands will be sent.







Section 2 Filters Previously, this chapter discussed the Cased-Hole Interface and the various forms of telemetry. This section will explain the basics of filters. Regardless of the sensor or the telemetry type, the signal/data received must be filtered to determine an end value. Filters can be divided into two main categories: electronic and software. They both perform separate functions, but the mathematical processes behind their functions do not change.

Electronic Filters Electronic filters are electronic circuits that are designed to either remove unwanted signal components or enhance wanted components. Electronic filters have several properties by which they can be classified: 1. ive or Active 2. Analog or Digital 3. Linear or Non-Linear In the previous section on telemetry, we discussed the problems encountered when transmitting an analog signal across a medium due to signal distortion. These problems led to the use of digital signal processing, which, in a sense, is a method of filtering to remove unwanted variations in an analog signal while providing a more consistent data output. There are several types and combinations of electronic filters that will be discussed next. Filters are not segregated by type alone and may be a combination of several functional characteristics. Electronic filters can be segregated into two categories according to the components that are in them: ive filters and active filters. ive electronic filters are circuits composed of the four principle electronic components: resistors, inductors, capacitors, and transformers. More complex ive circuits exist; however, for the purposes of this document, complex ive-filter circuits will not be discussed. A ive filter is so named because it does not produce any energy. It is simply a means of limiting any input signal to a desired output in voltage, amperage, frequency, or polarity. 12/29/2008 WPS Training


Halliburton Energy Services Active electronic filters are distinguished by the use of one or more active components, such as voltage amplifiers and buffer amplifiers. Active electronic filters also generally require power to be supplied to the active components for them to work. Electronic filters may also be separated by the type of filter that it is designed to apply: Linear and Non-Linear. Linear filters are the most common of electronic filters. Regardless of whether the filter is electronic, electrical, or mechanical, the mathematical theory for linear filters is universal. A linear filter is simply a means of limiting any input signal to a desired output in voltage, amperage, or frequency. Some of the most common linear filters are low-band , high-band , or band-stop filter. A low-band filter allows low-frequency signals to through and blocks high-frequency signals. The inverse can be said for highband filters. The band-stop filter es all frequency except for a specific range. ive or active-linear filters are used throughout the Cased-Hole Interface to provide functions, such as decoupling the line-power signal from the telemetry as seen in the ANASW card. An example of an active linear filter is the operational-amplifier board for the CCL circuit in the CSP 1/7. In this case, the filter is designed to boost the relatively low-strength CCL signal to a discernable level. Non-linear filters are signal-processing devices in which the output is not a linear function of the input. Non-linear filters are used to locate and remove data that is recognized as noise. They are so named because they look at each data point and decide whether it is noise or a valid signal. An example of this type of circuit would be the CBL02 card, and its function is to detect the sync pulse. Having previously discussed the differences between analog and digital, the differences between analog and digital filters are quite simply the components and the means of filtering. An example of an analog filter would be the active linear filters on the CBL1D card that filters the signal coming from a natural gamma-ray tool to remove the noise from the bi-polar pulse signal. In electronics, a digital filter is any electronic filter that works by performing digital mathematical operations on an intermediate form of a signal. This is in contrast to older analog filters, which work entirely in the analog realm and must rely on physical networks of electronic components (such as resistors, capacitors, transistors, etc.) to achieve the desired filtering effect. Digital filtering is performed by the Analog-to-Digital Converter attached to the DSP Aux card, which processes the analog telemetry and encodes it into a digital format so that the Warrior software can analyze it.




Software Filters In addition to filtering the signal from any tool, the data from the tool must also be filtered to remove statistical variation. Statistical variation is the result of detector design and is inherent to the nature of the tools we use due to the physical and geological elements that are being measured. For example, a natural gamma-ray tool is designed to count the amount of gamma rays that strike the crystal. Given that the amount of gamma rays produced by any atomic element are not uniform in nature, the tool counts are, therefore, not uniform over any given period of time. The example below is a comparison between a non-filtered curve and a filtered curve. The curve on the left is a standard gamma-ray curve plotted with no filter applied to the data. The curve on the right is the same signal with a filter applied. Without filtering, raw data plot erratic and hard-to-follow curves, making correlation and interpretation difficult.

Fig. 3.2.1—Non-filtered vs. Filtered Signal Curves.

For almost all logging tools, filters of different types and lengths are applied to the recorded data to help remove variations and provide a more clean and consistent response. Depending on the sensor and client request, the filter type and length will change. There are several types of filters that may be applied to a sensor. The Warrior Logging Software for cased-hole applications allows for the choice between three types of filters: 1. Triangle 2. Gaussian 3. Square



Halliburton Energy Services The type of filter refers to the mathematical algorithm used to calculate the values that are given. A triangle filter is a fractional-weighted average where each sample in the specified range is given a total value of only a fraction of its actual value. These fractional values are then added together to give the total value for the specified range. For example: take the data acquired over a 1-ft interval and take five individual samples inside the 1 ft. A triangle filter applied over a 1-ft interval that took five samples would take 1/9 the value of the first sample, 2/9 the value of the second sample, 3/9 the value of the third sample, 2/9 the value of the fourth sample, and 1/9 of the fifth sample, and then add them together to achieve a total value for the 1-ft interval.

Fig. 3.2.2—Example of a Triangle Filter.

A Gaussian filter is also known as a weighted filter. In the Gaussian-filter process, values closer to the center are given more weight in the final sum than values obtained further from the center of the sample range. The filter works in the same manner as the triangle filter in that it takes fractional values of the raw samples and combines them together to form a single value. However, the only difference is that it first applies an additional value, weights, to one or more aspects of the data set.




Fig. 3.2.3—Gaussian Filter Curve.

A Square filter is a straight-forward average of all the curve values measured over a given interval divided by the total number samples taken in that interval. For example: Depth Curve Value 100.00 52 100.25 48 100.50 56 100.75 53 101.00 49 258 Total 258/5 = 51.6 Output at 101.00 = 51.6 A square filter is the easiest filter to apply because the data used is either in or out of the samples’ range. In this method, data outside of the range is ignored.




Fig. 3.2.4—Comparison of the Triangle Filter, Gaussian Filter, and Square Filter Curves.

In addition to the type of filter used, a range over which the filter is applied must also be specified. This parameter is known as filter length. When a logging sensor is active, it is sending a continuous stream of measurements. In order for the filter to work properly, a range or window must be established for the software to define which values to use in the filter algorithm. Typically, for the , this value is in ft. Therefore, along with establishing the type of filter to be used, the must also establish a length. Historically, filter length has been defined by the number of points of measurement it takes in the given data range, usually referenced by the number of ¼-ft samples or number of .1-m samples, if using metric units. For example if a filter length of 3 ft is established, then the software will take 12 samples of the data over a 3-ft interval. This would be the equivalent to a sample being taken every 3 in. Fig. 3.2.5 depicts a gamma-ray curve over the same terval with different filter lengths applied. Notice how the curve loses definition as the filter length increases, and when the filter length is decreased, the curve looks as if no filter has been applied. This is very important to note, as filter length can greatly affect the log results.




Fig. 3.2.5—Gamma-Ray Curve Over the Same terval with Different Filter Lengths Applied.

In Halliburton software, filter length is usually established as an odd number (e.g., 3,6,9, etc.). Because our measurements must correspond to a depth in the well, establishing an odd-number filter length allows for an exact midpoint in the data range to be a known value. The filter selection may be accessed through two menus: Edit Logging Tool Details (Fig. 3.2.6) or the AcquisitionEditFilters Menu (Fig. 3.2.7).




Fig. 3.2.6—Edit Logging Tool Details.

Fig. 3.2.7—Edit Filters Menu.




Section 3 LOGIQ-CH In the previous sections, the four principle components of a Data Logging System were discussed: 1. 2. 3. 4.

Measuring Output (Logging Tool) Recording Output (Logging Unit) Analysis Of Recorded Data (DAS Hardware/Software) ing/Accessing Recorded Data (Telemetry)

This section will discuss the second and third components of the system: Recording Output and Analysis of Recorded Data. The LOGIQ-CH system is the principle surface-acquisition system used by Halliburton today. The LOGIQ package is designed to fulfill both the recording output and the data acquisition and analysis functions of a Data Logging System. The LOGIQ system will be comprised of the basic components listed below. However, if the logging unit is configured for open-hole logging as well, the LOGIQ unit will also include a DIMP, two Sorenson DC power supplies, and as many as four Elgar AC power supplies. In this chapter, the cased-hole configuration is discussed in all the examples. 1. 2. 3. 4. 5. 6.

Cased-Hole Interface (CHIP) Rack-Mounted Portable Computer (RMPC) Cable-Shooting (Mono-conductor/Multi-conductor) Depth/Tension Front End (SDDP/Wayne-Kerr) Printrex 840 DL/G Thermal Printer 20-in. LCD Flat- Monitor

In this chapter, we will discuss the design, function, and operation of each component in the LOGIQ-CH system. This system is critical to job completion. Each component must be functioning for any Wireline job to be performed.




Fig. 3.3.1—Overview of LOGIQ-CH.

Cased-Hole Interface (CHIP) The Cased-Hole Interface , manufactured by Scientific Data Systems, Inc., is the heart of the LOGIQ-CH system. This is responsible for the acquisition of all signals and data coming from the tools and the depth/tension systems and outputting them to the Warrior Logging Software for interpretation and recording. The CHIP is capable of interfacing with all of the tools used at Halliburton. The CHIP is a single unit that contains seven individual cards located on a back plane, which are used to process various types of data. It utilizes DSP-(Digital Signal Processing) based technology for data handling. The CHIP contains the necessary components to direct drive depth and tension encoders and is also capable of receiving a slaved input from a depth/tension front-end system. It also contains an integral DC power supply for down-hole tool power, which can be controlled manually or through software. A seven-port USB hub located inside the CHIP is used to connect various instruments and communicate with the Rack-Mounted Portable Computer (RMPC).




Fig. 3.3.2—Face-Plate Assembly.

Front The front of the CHIP consists of: 1. 2. 3. 4. 5. 6. 7. 8.

LCD display Voltmeter and Ammeter for tool power display Two potentiometers for positive and negative polarity tool power control Manual switch for enabling tool power polarity or software controlled tool power Toggle switch for manually enabling tool power RCA Audio jack for connecting to noise tools Front USB connector to connect any to PC Main Power switch Indicator lights for tool power and line enable

It is important to note that the CHIP cannot interface with two computers simultaneously. Therefore, if the front USB is used to connect to a computer, then the computer connected to the back of the CHIP must be powered off or physically disconnected. In the current configuration used by Halliburton, tool power must be controlled manually. Software power controls have been disabled. 12/29/2008 WPS Training



Back The back of the CHIP consists of: 1. Two connections for the Wireline cable a. BNC Connection b. UHF Connector 2. Encoder connections for Depth and Tension 3. ive CCL Connection (BNC) 4. Five USB input connections 5. One USB output connection 6. Auxiliary BNC connection for slave tension feed

Fig. 3.3.3—Rear-Plate Assembly.




Internal Components

Fig. 3.3.4—CHIP Internal Components Diagram.

Tool Power Supply The CHIP contains an integrated 0-400 VDC power supply, which supplies power to all logging tools. This power supply is controlled manually from the front of the via a toggle switch and two potentiometers. It is important to note that although the power supply is controlled manually from the front of the , power will not be sent to the line until it has been enabled in the software controls. The tool power supply consists of a regulator board (TpsDR3), four transistors, two transformers, and the front- controls to set positive and negative voltage levels and switch output polarity. If the front- switch is in the AUTO position, then the polarity and voltage may be set under software control. A small 12-V transformer powers the regulator, allowing it to float on the tool voltage. The main power comes from a 1:2 stepup isolation transformer. The two transformers, together with the rectifier and smoothing capacitor, are mounted on the rear chassis.




USB 44 The USB44 board contains a 16-bit, 10-μs ADC with an analog multiplexer, HI506, allowing 16 channels to be digitized. Three channels are dedicated to line tension, tool voltage, and tool current. The rest are available for customer tool signals. The digitized signals are sent to the PC by the USB controller. There are two three-channel counters. The line speed and a 1-MHz clock are processed by the IC1. Three channels are available for pulse tools. The depth information comes from a quadrature encoder mounted on the measuring head. Its outputs are pulses that come in on J1-10 and 11 and go to IC7, LS7084, quadrature-clock converter. IC7 decodes the direction of cable movement, which goes to IC1 as DIR and sends pulses, PPR, to the counter, U1, to monitor line speed. The tension signal may be a 4-20 mA current loop, R14, 24.9 Ω installed, or a strain gauge, 2 μF installed. The signal is amplified by U5 and digitized by U3 channel 6. The USB controller, IC1, sends the depth, line speed, and direction and tension information to the PC when the software requests it. IC1, the USB controller, is connected to the USBHUB through J1-14 and 15. IC11 is a noise suppressor for the serial line. IC5 contains the identity code for the board so that the Warrior software can identify it and the proper program into the memory on IC1. The controller is constantly keeping track of the counters. The one MHz is used as a time base to scale the counts. The analog channels are constantly monitored and may be viewed on the MONITER DEVICES – DSP . The controller communicates with the serial DACs on the Analog Switch Board over the I2C serial bus.

SDSDSP (Digital Signals Processor) This card contains a Texas Instruments DSP, which does signal processing tasks to free up PC resources. When a service is selected, software for it is ed to the DSP external memory over the USB bus. Signal gain and filtering are controlled from here. In addition, pulse, CBL, and telemetry signals are processed here. The DSP routes control signals to the various cards inside the CHIP. Software commands are sent to the DSP from the PC, and the DSP then routes controls and commands to the various cards inside the CHIP.

DSP Aux This board contains the signal-processing hardware for the DSP. The raw telemetry data received from a logging tool is processed by the DSP Aux and then sent to the DSP for conditioning and formatting. The DSP then es the data to the PC over the USB bus. The DSP Aux also controls the gain and filtering for the ADC (Analog-to-Digital Converter), which is used to process analog signals, such as acoustic data. The DSP Aux also contains the DAC (Digital-to-Analog Converter), which controls gains and filtering on the other boards.




CBL1D The CBL1D card conditions acoustic and analog pulse signals that are subsequently input to the SDSDSP card for data acquisition. The input to the card is connected to the line via the ANASW card. The card outputs three signal channels that are used for soniulse detection, analog-pulse detection, and two channels of sonic signal for amplitude measurement, waveform recording, and travel-time measurement. The board has three filter sections that are controlled by Warrior software with the USB I2C bus to allow the greatest degree of flexibility for signal processing from different down-hole tools.

CBL02 The CBL02 board provides detection of positive and negative sync pulses. The CBL02 card receives several inputs and performs the functions of sync-pulse detection. It receives acoustic-signal inputs from the CBL1D card as well as analog- and digitalcontrol signals from the DSP. The card outputs are positive and negative sync-detection signals.

Analog-Switch Interface Board (ANASW) The analog switch board decouples the tool power voltage from the line signal input and routes it to the various interface boards. The primary outputs of the card are a series of buffered signals that are connected to the other cards of the interface . In addition, the card also includes an audio amplifier circuit that is used to amplify the line signal with output to a loud speaker or headphones. This function is primarily used with audio (noise) surveys, well-head pressure, and aux channel audio amplifier.

Applied Free-Point Card This board drives a sine wave down the logging cable to an applied electronics or SIEstyle free-point tool. The response of the tool attenuates the signal. The amplitude of the attenuated signal has a bias applied to it to set a zero reference. The change in the amount of attenuation is then measured to create an output. Because the drive of the board must be directly connected to line without the effects of line termination or power-supply load, the es the line through a relay on this board to the rest of the circuitry or when engaged, connects the electronics on the board directly to the line connection. Note:

This board is only actively used for a free-point service. When any other service is being run, the tool signals are ed through this board directly to the ANASW board.

Pre-Relays Board (Prelays) This board controls the flow of tool power and tool signal through the interface . The power-relays board connects the line input of the tool-interface to the rest of the circuitry in the . Functions of the card include enabling line, controlling line termination, selecting positive or negative power to be applied to the tool, and enabling the downlink capabilities of the TELA card. 12/29/2008 WPS Training



CCL Board This card provides filtering and amplification of the casing-collar signal when it appears as a low-frequency signal imposed on the line or from an external source, such as a shooting with CCL output. Experience has shown that the CCL signal must be sampled at a rate of at least 20 samples per ft in order to obtain a detailed collar log. The sample-rate default value is set in the services.ini file. The CCL card input is connected to the line input via the ANASW card. In addition, there is an auxiliary input, which is connected to a BNC connector at the rear of the CHIP. This input is used for the input of a CCL signal while the perforating gun is being run and allows a CCL to be run without the main line-enable relay being activated. The output of the card is a filtered and amplified version of the input CCL signal, which is connected to the ADC on the USB44 card in the interface .

TELA R6 Board The TELA board processes telemetry signals. The down-hole communication comes from the DSP, and it is amplified and sent directly to the cable.

Power Supply Auxiliary Board (PSXD) This card receives I2C signals from the USB44 board that control the outputs of the two octal bus drivers. The outputs of these drivers are used as control bits to engage various relays and switches throughout the . The I2C signals also control the output of IC3, which supplies software control for the tool power supply. The card also contains the tool current-sense amplifier and the line-voltage divider. The outputs from these components drive the front- meters and are also routed to the DAC circuitry on the USB44 board. There is additional circuitry to control the polarity and the source of control to the tool power supply.

Audio Board This board consists of a high- filter with 3-dB point around 100 Hz followed by a low- filter with 3-dB point around 20 kHz. The noise board has four outputs. Maximum signal input to the DSP is +2.5 V DC. With a board input of 20 Vp-p, the range1 output is 5 Vp-p with gain of 0.25. Range2 is set with a 2-Vp-p input with gain of 2.5. Range3 is 200 mV with gain of 25, and range4 is 20 mV with gain of 250. The software finds the largest signal that is not saturated and uses a Fourier transform to extract the signals in each frequency range.




USBHUB Board The CHIP is designed to be operated with a laptop PC over a USB port. The has a built-in seven-port hub. The USBHUB board is mounted in the back of the CHIP. It contains one up-link port and seven down-link ports. The up-link port is connected to both the front and the rear of the CHIP. Relay K1 disconnects the back port when the front one is used. The 5 V supplied by the host USB cable energizes the relay. If the PC does not supply this voltage, it will be necessary to use the back port. One port inside the is dedicated to the Warrior Software dongle. Three ports are used to connect internal devices, such as the USB44 board and the DSP board and are not available externally. Three ports are available for external devices, such as the Warrior Depth and Tension , and plotters, which may be operated with a USB to serial cable. The USBHUB is operated as a generic device because it requires no programming. When the PC is plugged into the CHIP, there will be a momentary pause as the Warrior software recognizes the internal devices and s the software necessary to operate them.

Ultra-Link Module Board (ULLM) The Ultra-Link Board, manufactured by Sondex, Inc., is an after-market installation board that is used to communicate with tools that are equipped with Sondex Ultra-Link technology. Ultra Link is a type of telemetry used to link multiple tool sets together in one string.

Telemetry Processing Data is routed and processed through the various cards inside the CHIP before it is sent to PC for interpretation by the Warrior software program. This section will describe how each type of telemetry signal is processed and the path that it follows through the CHIP . The depth and tension data is the most basic of all the telemetry received by the CHIP . It is also the most important measurement that is taken in any logging service. The CHIP has two ways in which it can acquire depth and tension data. The first method is by directly driving the depth and tension devices. This means that the CHIP is directly connected to the device and provides the necessary power to run the encoders or load cell. The second method is most commonly referred to as a “Slave” feed. In this configuration, a depth/tension front-end device, such as the Kerr Measurement systems , or the SDDP drives the encoders and load cell and sends a separate feed of pulses or voltages to the CHIP. Current models of both Wayne-Kerr Depth s, open- and cased-hole, are configured for a slave-pulse output to the CHIP . When using a KMS depth , the drives the encoders directly and sends a separate feed of pulses to the CHIP . The CHIP then counts the pulses as it would if it were driving the encoders directly. In 12/29/2008 WPS Training


Halliburton Energy Services this configuration, bi-directional (two-way) communication does not exist between the CHIP and the depth . Both s are counting the pulses from the encoder separately. Therefore, the must ensure that any depth changes that need to be made are done from the depth and then verified in the Warrior software to ensure that both systems are on depth with each other. When using a unit equipped with the Stand-Alone Depth Display (SDDP), the SDDP drives the encoders and load cells and then sends a data feed via a USB interface to the CHIP. In this configuration, bi-directional communication exists between the SDDP and the CHIP. Therefore, any depth changes made in either system will be reflected in both. In either mode, the depth and tension data is received and processed by the USB44 Board inside the CHIP and then sent to the PC via the USB Hub (see Fig. 3.3.5). Note:

needs to check to ensure that the correct version of the National Instruments USB_GPIB driver software is installed and operating correctly when using an SDDP.

In the current release of the software, the auto position has been disabled. Tool power must be applied via the potentiometers located on the front of the . Each potentiometer controls a single polarity.




Fig. 3.3.5—Tension and Depth Signal Block Diagram.




CCL (Non-SDDP Equipped Systems) The simplest form of telemetry processed by the CHIP is the analog CCL signal. This processing path is used when the CSP1 or CSP7 is placed in the CCL position and a shooting CCL is used. Note:

This signal flow is not for SDDP-processed CCL signals.

The CCL signal enters the CHIP through the ive CCL input connection, which is connected directly to the CCL board. The CCL board applies any software filter and gain to the signal and sends it to the USB44 board where it is sent across the USB bus to the PC (see Fig. 3.3.6). In this configuration, the should be aware that any gain applied in the Warriorsoftware controls will not have any affect on the strength of the signal being received. For this reason, gain should be adjusted at the CSP before attempting to adjust software gain.

Fig. 3.3.6—CCL Signal Block Diagram for Non-SDDP Equipped Systems.



Halliburton Energy Services With an SDDP-equipped system, the signal path for the CCL signal is altered because the CCL signal is routed through the SDDP before being ed on to the CHIP. Note:

The SDDP digitizes the CCL signal before sending it to the CHIP.

The will need to adjust scales appropriately for collars to be displayed properly on a log. The needs to be cautious when applying software gains to the CCL signal when configured in this manner. Gain and filtering is applied at the CSP and also at the SDDP before the signal reaches the CHIP. For this reason, the needs to check the gain settings on the CSP and the SDDP before attempting to apply any software gain in the Warrior software (see Fig. 3.3.7). Additionally, the correct version of the National Instruments software driver for the USBGPIB device must be installed for any information to be received by the CHIP.

Fig. 3.3.7—CCL Signal Block Diagram SDDP Equipped Systems.



Halliburton Energy Services When the CCL signal is received as part of a logging-tool telemetry frame, the signal follows the same path as the entire frame and is separated at the ANASW Board and sent to the CCL Board. When the CSP is in the log position, the active channel is connected on the back of the CSP and all tool telemetry is routed to the active-line connection on the back of the CHIP. The first card the signal comes in with is the Pre-Relays (Prelays) board where line power and telemetry flow is controlled. The Prelays board es the signal through the Applied Free-Point Board and then to the Analog Switch Interface Board (ANASW), where tool power is decoupled from the telemetry signal. At this point, the CCL signal is sent to the CCL board for processing. The CCL board es the CCL signal to the USB44 board, and the signal is then sent across the USB bus to the PC (see Fig. 3.3.8).

Fig. 3.3.8—CCL Signal Block Diagram, CSP in “LOG” Position.




Bi-Polar Telemetry (Gamma-Ray Neutron) The next form of telemetry that is received and processed by the CHIP is Bi-Polar, more commonly referred to as analog telemetry. This type of telemetry is most commonly used by tools, such as the Gamma Perforator and the Hostile-Gamma Neutron Tool. It is known as Bi-Polar telemetry because it sends data in the form of positive and negative pulses in a sinusoidal (analog) wave. The telemetry signal enters the CHIP from the active (Log Mode) channel and first enters the Prelays board. The Prelays board routes the telemetry through the Free-Point board and to the ANASW board where tool power is decoupled from the signal. The ANASW board routes the signal to the CBL1D and CBL02 boards, where sync-pulse detection, gains, and filters are applied. The data is then ed to the AuxDSP board for processing and then ed to the DSP where it is sent to the USB Hub. The USB hub routes the data along the USB bus to the PC (see Fig. 3.3.9).

Fig. 3.3.9—Bi-Polar Telemetry Block Diagram.




Cement Bond Log Telemetry Telemetry from a cement-bond tool is processed in the same manner as all other types of active telemetry. The signal from the tool will enter the CHIP on the active channel via the UHF or BNC connection, which is connected to the Prelays board. The Prelays board will the signal through the Applied Free-Point board to the ANASW board, where tool power is decoupled from the signal. The ANASW will then route the signal to the appropriate board for processing. Primarily, the signal will be sent to the CBL1D card, where it is divided into three parts: Sync, Sonic, and Aux. The CBL1D card will apply gains as directed by the software and then route the Sync signal to the CBL02 card for sync-pulse detection. The remaining portions Sonic and Aux will be processed in by the CBL1D card. Aux channel is for processing gamma-ray and neutron-pulse signals. Aux gain will be applied to the signal, and it will then be routed to the Aux DSP for processing. The CBL1D card identifies the 3-ft and 5-ft, and radial sonic data applies the specified gains and routes the data to the Aux DSP for processing. The Aux DSP will then route the data to the DSP, and the DSP will send the data to the RMPC via the USB hub (see Fig. 3.3.10).

Fig. 3.3.10—Cement Bond Log Telemetry Block Diagram.




MUXB2 (Uplink) The Manchester (MUXB) telemetry format is a form of digital telemetry. (Telemetry will be discussed later in this chapter). This type of telemetry is used in services, such as Pulsed-Neutron Logging. The signal enters the CHIP via the UHF or BNC line connection and is processed through the Prelays board, where it is ed through the Applied Free-Point board to the ANASW board. The ANASW board routes the data to the CBL1D, where gains and filters are applied. The signal is then sent to the AuxDSP for decoding and processing. The AuxDSP sends the data to the DSP, where it is then sent to the PC via the USB bus (see Fig. 3.3.11).

Fig. 3.3.11—MUXB2 Uplink Block Diagram.




MUXB2 (Downlink) Downlink commands are sent to the tool string from the DSP to the Tela board. The Tela Board conditions and formats the commands and relays, then directly to the cable via the Prelays board (see Fig. 3.3.12).

Fig. 3.3.12—MUXB2 Downlink Block Diagram.

.




Ruggedized Rack-Mounted Portable Computer (RMPC) The RMPC is the platform for the Warrior Logging Software system. The RMPC performs all standard computing functions, interfaces with the Printrex Thermal Plotter, and is used for the temporary storage of the logging data. The RMPC is designed to fit a standard 19-in. electronics rack and occupies a 2-unit height. It comes with either an Intel or AMD processor and 1 GB of RAM. Features include: 1. Custom mounting brackets for all internal components. Custom brackets are designed to absorb the vibrations incurred during transport. 2. 2 X 60-GB SATA mirrored hard drives 3. Standard DVD/CD rewritable drive 4. 400-W Power Supply 5. 1 GB of DDR2 533-MHz System Memory (2 X 512-MB Modules) 6. 4-Port USB Hub 7. PS2 Mouse and Keyboard Connections 8. 1 X 10/100/1000 Ethernet Card mounted on motherboard 9. 1 X 10/100/1000 PCI Ethernet Card 10. Intel PCI Express Dual Head Graphics Display Adapter 11. Positive pressure cooling system

Printrex 840 DL/G The printrex thermal plotter is the standard output printing device installed in all logging units. It is a thermal-printing unit designed to use 8.75-ft X 6.25-in. Thermal Fanfold Paper. Thermal roll scratch log paper can also be used with the optional roller- bar. Two calibrations are required for this plotter to function correctly. The first calibration is for the first page-detection sensor. Refer to the OEB for calibration instructions. The second calibration must be performed in the Warrior Logging Software. The plotter can be installed in two configurations. Most cased-hole logging units directly connect to the plotter via a standard LPT printer cable from the RMPC. A print server may also be used to interface with the plotter. In this configuration, the plotter is set up in the Windows software as a network printer connected across the print server. The print server communicates with the RMPC via the private Ethernet controller along a CAT5 (RJ45) cable. The print server enables a unit to have multiple plotters installed.




Flat Monitor All logging units are equipped with a minimum of one 20-in. LCD display for interface and graphic display. Care should be taken so as to not to expose the monitor’s to physical pressure on the front of the screen, as could damage the liquid crystals. The RMPC is capable of ing two monitors in either the clone mode or split-screen display modes.

Cable Shooting (CSP) The Cable Shooting (CSP) is the primary interface between the cable conductor(s) and the surface-acquisition systems. This serves several functions: 1. Provides various levels of communication control 2. Supplies necessary power to fire-explosive devices 3. Provides a safety barrier when using explosive devices In this chapter, we will discuss the construction guidelines, design, function, operation, and basic PM-1 of the Cable Shooting . The Cable Shooting is a critical piece of equipment that must be maintained and fully functional for each job. Wireline operations should not be performed with a faulty CSP.

Design and Features In response to several explosive incidents within the industry, the American Petroleum Institute published Recommended Practice 67: Recommended Practice for Oilfield Explosives Safety. This document outlined basic operational and equipment design tenants that should be followed when using explosives in the oilfield. Section 5 of API RP 67 outlines specific guidelines for the function and design of a Cable Shooting (CSP). Currently, Halliburton uses the CSP 1 (Fig. 3.3.13) and 7 (Fig. 3.3.14) and the Probe Tools, WSP 1 (Fig. 3.3.15) and 7 (Fig. 3.3.16). All four s conform to the guidelines established in RP 67.



Halliburton Energy Services Although each may vary in control position and type, each will be equipped with the following: 1. 2. 3. 4. 5. 6. 7. 8. 9.

Cable Safety Switch (CSS) Variac Power Switch At least one spring-loaded switch (Trigger) Voltmeter Ammeter CCL Gain Control CCL Meter Shooting Polarity Selector

Fig. 3.3.13—CSP 1.

Fig. 3.3.14—CSP 7.




Fig. 3.3.15—Probe WSP 1.

Fig. 3.3.16—Probe WSP 7.




Safe Mode API RP 67 Section 5 states that a Cable Shooting should have several design features to enable the safe use of explosives in the oilfield. RP 67 refers to the CSP as the Cable Safety Circuit. These features are: 1. The CSP should be maintained inside the electric Wireline unit. 2. When in safe mode, the cable circuit shall open all cable connectors from the electric Wireline unit circuits, and all conductors shall be shunted to armor through a nominal resistance of 5,000 Ω. This resistance shall be provided by a minimum of two similar resistors in parallel with the net resistance being 5,000 Ω. See Fig. 3.3.17. 3. The SAFE mode shall be assured with a lockout feature. 4. Electrical continuity shall exist from the cable safety circuit to the cable conductor, and the wiring providing this continuity shall have mechanical protection.

Fig. 3.3.17—CSS in SAFE Position.




Shoot Mode When the Cable Shooting Safety Switch (CSS) is in the shoot mode, the cable conductors are connected directly to the shooting circuit inside the CSP. This circuit is what provides the electrical power for firing an explosive device. While in this position, the line connection to the CCL is shunted to ground, and the connection to the surfaceacquisition systems is open. This protects the CCL Filter/Amplifier circuit and the surface-acquisition systems from the high voltages required to fire an explosive device. See Fig. 3.3.18. API RP 67 Section 5 states that the firing system shall incorporate the following features to protect oil-field personnel from accidental detonation of an explosive device while on surface. See Fig. 3.3.19. These features are: 1. At least three deliberate actions shall be required to fire the explosive device. 2. At least one action shall require the use of two hands. 3. At least one action shall involve a spring-loaded switch.

Fig. 3.3.18—CSS in SHOOT Position.




Fig. 3.3.19—CSP 1.

Using Fig. 3.3.19 for reference, shooting power would be applied by: 1. 2. 3. 4. 5.

Placing the CSS in the SHOOT position Enabling the power switch Selecting the appropriate polarity Lifting spring loaded switch covers Depressing both spring-loaded switches simultaneously and maintaining constant upward pressure. 6. Applying power by adjusting the Variac slowly.

Shooting Circuit The CSP provides power to an explosive device via the shooting circuit located inside the CSP. Via the shooting circuit, the CSP is capable of providing up to 690 V DC of power. The following section will explain how this power is generated. A standard logging unit is equipped with a 123-V AC generator that is used to provide power to the various electronic components in the instrument cab. However, this presents a problem for applying power to an explosive device. The first problem being that we do not use AC voltage to fire any explosive device. The second being that the generator does not provide sufficient power in most cases to fire an explosive initiator attached to Wireline. Therefore, the voltage supplied by the AC generator must be amplified and converted to DC power for use with explosive devices. This process is performed by the CSP Shooting Circuit in the following manner. See Fig. 3.3.20. All logging units today route power from the AC generator to a standard 115-V AC wall socket. Therefore, the maximum amount of AC power that the CSP has to draw from is 115 V AC . This power is made available when the power switch on the CSP is enabled. The variac controls are scaled from 0 to 100%. This means that the variac will allow the to apply to the shooting circuit a range of 1 to 100% of the available power. When the depresses the first trigger (Left), it will open the pathway to the transformer located outside of the CSP. The transformer multiplies the power output by a ratio of 1:4. This means that for every volt sent to the transformer, it will output 4 V.



Halliburton Energy Services The CSP voltmeter measures the AC voltage output of the transformer. A common mistake that most s make is viewing the voltage reading on the CSP voltmeter as being the DC voltage that is received at the end of tool string. This is not the case. The CSP voltmeter exists in line after the transformer and before the rectifier. Therefore, it only responds to the AC voltage output of the transformer. When the depresses the second trigger (Right), the circuit pathway is open to the full-wave rectifier. The rectifier converts the AC-power output from the transformer to DC. The DC voltage from the rectifier is then routed through a filter-capacitor circuit and out of the CSP. To calculate the amount of DC voltage that we can receive at the cable head from the CSP, multiply the AC-voltage value observed on the CSP voltmeter by a factor of 1.41. It is important for the EUIC to understand the power-application functions of the CSP in order to properly check the CSP and also ensure that it can provide the appropriate amount of power needed to initiate any explosive device. The CSP ammeter responds to any load placed on the shooting circuit from the output side of the . Thus, the ammeter responds to the resistance of all elements that are connected to the CSP. This begins with the Wireline and includes any equipment attached to the cable head and an explosive initiator. Therefore, when we calculate expected current values, they will be based on DC-voltage values. This is important for the to understand because any current value observed on the CSP ammeter will be the result of resistance provided by elements outside of the , and the should know the expected values that elements will produce if they are fully functional and operating correctly. This will enable the to detect any voltage leakage or equipment failures during the explosive-check fire procedure.




Fig. 3.3.20—CSP Shooting Circuit Block Diagram.

Log Mode When the CSP is placed in the “LOG” position, then the circuit pathway from the cable to the surface acquisition system is connected. See Fig. 3.3.21.

Fig. 3.3.21—CSP Log Mode Block Diagram.



Halliburton Energy Services This circuit pathway consists of two output connections. The first output is commonly referred to as the active channel because this pathway allows for bi-directional communication between the surface-acquisition system (CHIP/DIMP) and the cable. The second pathway is the CCL output, which is simply a ive connection to the CHIP that allows for the reception of an analog CCL signal. It is important to note that the CCL-signal circuit includes an amplifier and filter. This allows the to directly adjust the amplification (Gain) of the CCL signal received from the cable. Therefore, gain adjustments for a poor CCL signal should be made here before attempting to adjust any software gains.

CCL Mode When the CSP is placed in the “CCL” position, the pathway from the cable to the ive CCL output is connected (see Fig. 3.3.22). It is important to note that the active-channel connection to the surface-acquisition system is not connected when in CCL Mode. This mode is used for the detection of a CCL signal coming from a perforating CCL (ive CCL) only.

Fig. 3.3.22—CSP CCL Mode Block Diagram.




Multi-Conductor Shooting The seven-conductor or multi-conductor shooting has all of the same features and functions of a mono-cable shooting plus added features for specific open-hole explosive devices. The added features include conductor selection for firing and CCL signal, line monitor and select for explosive coring, and variable frequency voltage selection for using the releasable Wireline cable head. Note:

All the safety-feature requirements of API RP 67 exist in the CSP7/WSP7 for each conductor.

When in “SAFE” mode, all conductor connections to the surface-acquisition systems are opened, and all conductors are shunted to ground through individual sets of 10-kΩ resistors in parallel. When in “SHOOT” mode, each conductor can be connected to the shooting circuit via the line-select switch.







Section 4 Delays To effectively evaluate an oil- or gas-bearing reservoir, it is necessary to take multiple measurements from several sensors. It is also beneficial for our client to be able to place as many instruments as possible in a single tool string. The previous section on telemetry forms stated that the primary limiting factor for multiple-sensor tool strings was the telemetry. In addition to that factor, the electronics packages required to run those sensors, design, weight and size of the sensor also make it impractical to place all of the sensors at the same physical location on the logging tool. Therefore, our entire logging tool strings are composed of multiple-logging sensors stacked on top of each other to form a single vertical string. This configuration of sensors presents the problem of placing all of the sensor data on depth with each other to ensure that the data acquired by each sensor corresponds to the same formation or well-bore characteristic in regard to physical position in the well. Given the physical position of the sensor in relation to the physics of the wellbore, a means had to be developed to accomplish depth matching of the sensors. Therefore, processes were created in the logging software to adjust the data being received in relation to time in order to place all of the data on depth. This process is known as sensor “Delay” or “Offset”. When the tools are combined in the software, a tool-string zero point is defined, and then distances are established for each sensor from the tool zero point. The software can then delay the incoming data and align it accordingly in relation to time and distance. The example below depicts the results if the sensor data was not delayed. Notice the offset curves in the log.




Fig. 3.4.1—Incorrect Delays.

With the sensor data properly delayed by the software, all of the data would align correctly and match the well-bore characteristic being measured. Fig. 3.4.2 depicts a log with properly delayed tool sensors.




Fig. 3.4.2—Correct Delays.

It is important for the logging engineer to ensure that the offsets are properly declared in the logging software and to cross check the log results with what is declared in the logging software. Improperly-declared offsets will result in poor log-quality output. In the case of perforating, incorrectly-declared offsets or tool zero will result in off-depth perforating.




Software Offsets (Delays) The warrior software calculates the offsets to be used on a per tool basis. This means that each tool has an offset established for the sensors that it contains. Sensor offsets are always defined in distance to the sensor from the bottom of the tool. As each tool is added into the tool string in the software, Warrior calculates a new total-offset distance from the tool zero declared in the service setup. To ensure proper offset establishment, each tool must be checked in the WarriorUtilitiesTools Editor menu. The first tab labeled “Model” is where the correct overall tool dimensions should be entered. Overall tool length is extremely critical. The tool length should be cross-checked with manufacturer’s specifications and also physical dimensions measured by the logging engineer. In some cases, the manufacturer’s tool diagrams will not include bottom-nose assemblies or other jewelry added to the bottom of the tool.

Fig. 3.4.3—Establish Correct Tool Length in Tools Editor Menu.



Halliburton Energy Services The next tab, “Software,” allows the to define the offset distance from the bottom of the individual tool to the sensor. The offset value should be declared according to the manufacturer’s specifications. Because the logging engineer cannot see the exact center of the sensor through the tool housing, the manufacturer provides these distances in the tool diagram located in the FOM for the tool. This distance should be verified by the logging engineer by physically measuring the distance.

Fig. 3.4.4—Establish Correct Offset in the Tools Editor Menu Software Tab.

Once each tool has been checked in the tools editor, the logging engineer should then combine the tools as necessary in the Warrior Tool String Editor, which loads when the declares a service to be used. As each tool is added, the software calculates a new combined offset. Fig. 3.4.5 shows a Cement Bond Log tool sonic sonde only. Notice the offsets for the acoustic receivers are 3 ft and 4 ft, respectively. Fig. 3.4.6 depicts the same CBL tool with the GR/CCL section added. Notice that the software took into a new tool being added to the bottom of the string and adjusted the sensor offsets accordingly.




Fig. 3.4.5—Cement Bond Log Tool Sonic Sonde Only.




Fig. 3.4.6—CBL Tool with the GR/CCL.

The Warrior software calculates offsets based on the distance that the sensor is spaced away from the declared tool-zero point. Tool zero is established in the Warrior service file. To check the declared tool zero, go to WarriorUtilitiesEdit Logging Services menu. Select the service, and the tool zero will be declared in the upper right-hand portion of the menu window.




Fig. 3.4.7—Declare the Zero Point for the Tools String in the Services Editor Menu.

Proper declaration of offsets is essential to performing a correct log. Sensor offsets should be checked and verified both in the software and on the logging tool prior to each logging service performed.



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