Composite Bit Deisgn

Oilfield Review Summer 2011

Bit Design Downhole Conveyance Source Rock Geochemistry Environmental Advances

11-OR-0003

From Bit to Rig Floor: An Integrated Systems Approach to the BHA The first patent for the rotary rock bit, issued in 1909, marked the birth of the modern drillbit industry. At that time, bits were designed with two cones of interlocking milled teeth, and drilling a few feet was considered a good run. It wasn’t until the 1950s that engineers designed threecone bits that more closely resemble those currently in use. Today, demands on drill bits are more exacting. While fixed cutter and roller cone bits were originally designed to be run to destruction, they are now expected to not only exceed drilling performance expectations but also to end the run in pristine condition. The modern drill bit must be able to drill fast, provide good steerability for directional control and last an extended period of time downhole in even the most extreme environments. Though bit costs typically represent less than 1% of total well construction cost, the right bit can improve drilling performance immensely and in so doing deliver millions of dollars in operator savings. Indeed, the advent of polycrystalline diamond compact (PDC) bits in the early 1970s, along with ongoing improvements to roller cone components, has played a major role in reducing overall well costs for our customers. These refinements also afford today’s engineers the ability to plan the complex well trajectories that are critical to oil company profitability in increasingly complex reservoirs. At first glance, it can be difficult to see the differences between a premium engineered drill bit and one that would drill at half the rate of penetration or lack the steerability. Indeed, without considerable understanding of the design complexities and materials engineering involved, it is difficult to appreciate the amount of technology incorporated into modern drill bits or the scientific approach applied to current bit design and selection methods. Today, vast improvements in materials engineering, design software and manufacturing processes deliver drill bits that are custom designed for every application. These designs are quickly validated in the virtual world of computer modeling and sent to production in a matter of days. This is in stark contrast to the trial-and-error approach used by early bit manufacturers. This new methodology allows the right solution to be delivered with the first design iteration, making it possible for our customers to capture savings immediately instead of after costly and time-consuming field trials. As someone who has been involved in the drillbit industry for 15 years, I am delighted that this edition of Oilfield Review features an article explaining just a few of the drillbit technologies currently used by the industry (see “Bit Design—Top to Bottom,” page 4).

But what’s next? Drillbit design and improvements to diamond materials will no doubt continue to evolve. Materials engineering is what drives drillbit advancement, and we are rapidly escalating investment in that discipline. Future PDC bits will be able to drill harder rock than has been possible in the past, and the one-bit-per-interval goal will be achieved more frequently. The long-term goal, however, is considerably more ambitious than drillbit evolution. Our aim is to engineer the entire bottomhole assembly as a single system rather than as discrete components. While the speed of rock destruction will always be of significant importance to drillers, overall system reliability and optimal well placement are equally important facets of truly efficient drilling operations. Therefore, we believe the next step change in drilling performance will come via an integrated systems approach to the engineering and design of the complete BHA, including the drill bit, drilling tools and drilling fluid, as well as the directional drilling, measurement-while-drilling and logging-while-drilling tools—everything from the bit to the rig floor. The broader range of products and services now within our portfolio will enable the product development that is necessary to achieve this performance and reliability improvement. Greater understanding of the technical issues and mitigating risks in advance of a drilling program will help our customers realize major cost savings and performance improvement. To be able to deliver these cost savings, we are significantly increasing our investment in both short- and long-term R&D projects. And we are employing unique approaches to problem solving that will attract the next generation of engineers and materials scientists to the E&P industry. The industry will always strive for continuous improvement. As a service provider to oil and gas operators around the world, Schlumberger undertakes this challenge with responsibility and passion. Guy Arrington President Bits and Advanced Technologies Schlumberger Guy Arrington, who since 2010 has been President, Bits and Advanced Technologies, a Schlumberger company, has been in the drilling industry for 24 years. He spent 14 years in the drillbit business, working in manufacturing, field engineering and business development in the US and internationally, and later in product and field engineering management. He joined the Schlumberger Drilling and Measurements segment in 2001, first as business development manager and later as vice president for Europe, Central Asia and Africa. Guy was vice president of deepwater operations before managing the Smith Bits and Advanced Technologies integration team during the Schlumberger-Smith merger. He has BS degrees in industrial engineering and mechanical engineering from Texas A&M University.

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Schlumberger

Oilfield Review www.slb.com/oilfieldreview

Executive Editor Lisa Stewart Senior Editors Matt Varhaug Rick von Flatern

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From Bit to Rig Floor: An Integrated Systems Approach to the BHA

Editorial contributed by Guy Arrington, President, Bits and Advanced Technologies, Schlumberger

Editors Vladislav Glyanchenko Tony Smithson Contributing Editors Ginger Oppenheimer Rana Rottenberg Mark Andersen Design/Production Herring Design Mike Messinger Illustration Chris Lockwood Tom McNeff Mike Messinger George Stewart

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Bit Design—Top to Bottom

The right bit plays a key role in optimizing ROP, minimizing rig costs and shortening the time between project commissioning and first production. At one time, engineers designed bits based on little more than rough estimates of the characteristics of the rock to be drilled. Today, however, the emergence of high-speed computers has made it possible for bit designers to consider the bit and the entire drilling system in far more detail and in a far more holistic manner than ever before.

Printing RR Donnelley-Wetmore Plant Curtis Weeks

18 Conveyance—Down and Out in the Oil Field Evaluating, perforating and performing mechanical services on horizontal and high-angle wells present challenges for operators and service companies. This article reviews some of the methods used to convey equipment and logging tools downhole for cased hole and openhole operations; the article also describes conveyance options for logging in high-angle and horizontal wells.

On the cover: A laboratory technician at Smith Bits, a Schlumberger company, performs a test to quantify bit cutter forces and cuttings as a function of rock failure mechanisms and rock removal rates. These data are used for bit design analysis. Virtual scenarios are run to determine parameters such as the optimal bit profile, blade and cutter count, gauge length, bottomhole bit pattern and force balance on tricone (inset, left ) and PDC (inset, right ) bits.

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About Oilfield Review Oilfield Review, a Schlumberger journal, communicates technical advances in finding and producing hydrocarbons to employees, clients and other oilfield professionals. Contributors to articles include industry professionals and experts from around the world; those listed with only geographic location are employees of Schlumberger or its affiliates.

Oilfield Review is published quarterly and printed in the USA. Visit www.slb.com/oilfieldreview for electronic copies of articles in multiple languages.

© 2011 Schlumberger. All rights reserved. Reproductions without permission are strictly prohibited. For a comprehensive dictionary of oilfield terms, see the Schlumberger Oilfield Glossary at www.glossary.oilfield.slb.com.

Summer 2011 Volume 23 Number 2 ISSN 0923-1730

Advisory Panel Dilip M. Kale ONGC Energy Centre Delhi, India

32 Basic Petroleum Geochemistry for Source Rock Evaluation The pursuit of prospects in increasingly complex plays is giving E&P companies a renewed appreciation for one of the fundamental principles of exploration: The viability of any prospective reservoir depends on an effective source rock. Petroleum geochemistry is proving its value in helping operators evaluate source rocks and quantify the elements and processes that control the generation of oil and gas. Geochemistry is also an important tool for reducing uncertainty inherent in exploration and production of frontier basins. This article explores basic geochemical techniques used to evaluate new prospects.

Roland Hamp Woodside Energy Ltd. Perth, Australia George King Apache Corporation Houston, Texas, USA Richard Woodhouse Independent consultant Surrey, England Alexander Zazovsky Chevron Houston, Texas

44 Technology for Environmental Advances In recent years, the E&P industry has improved many technologies and practices to remove or mitigate detrimental effects on the environment. These improvements have been introduced throughout the life cycle of fields. Many of those new technologies also demonstrate improved performance over technologies they replaced.

53 Contributors 56 New Books and Coming in Oilfield Review 59 Defining Exploration: The Search for Oil and Gas The second in a series of articles introducing basic concepts of the E&P industry

Editorial correspondence Oilfield Review 5599 San Felipe Houston, Texas 77056 USA (1) 713-513-1194 Fax: (1) 713-513-2057 E-mail: [email protected]

Subscriptions Client subscriptions can be obtained through any Schlumberger sales office. Clients can obtain additional subscription information and update subscription addresses at www.slb.com/oilfieldreview. Paid subscriptions are available from Oilfield Review Services Pear Tree Cottage, Kelsall Road Ashton Hayes, Chester CH3 8BH UK Fax: (44) 1829 759163 E-mail: [email protected] Current subscription rates are available at www.oilfieldreview.com.

Distribution inquiries Tony Smithson Oilfield Review 12149 Lakeview Manor Dr. Northport, Alabama 35475 USA (1) 832-886-5217 Fax: (1) 281-285-0065 E-mail: [email protected]

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Bit Design—Top to Bottom Individual bits are one of the least expensive pieces of hardware used in drilling operations, yet the return on millions of investment dollars often depends as much on bit performance as on any other single component of today’s complex drilling systems. Spurred by that reality, engineers today are bringing powerful, high-speed computers and the latest in modeling and simulation software to the science of bit design.

Prabhakaran Centala Vennela Challa Bala Durairajan Richard Meehan Luis Paez Uyen Partin Steven Segal Sean Wu Houston, Texas, USA Ian Garrett Brian Teggart Tullow Oil plc London, England Nick Tetley London, England Oilfield Review Summer 2011: 23, no. 2. Copyright © 2011 Schlumberger. For help in preparation of this article, thanks to Guy Arrington, Ashley Crenshaw, Diane Jordan and Chuck Muren, Houston; and Emma Jane Bloor, Sugar Land, Texas. DBOS, IDEAS, i-DRILL, ONYX and Spear are marks of Schlumberger.

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Bit choice has long been viewed as a key to successful drilling operations. The right bit plays a leading role in optimizing rate of penetration (ROP), which helps minimize rig costs and shortens the time between project commissioning and first production. In field development programs, predictable ROP is critical to efficient allocation of rigs, personnel and materiel. Operators are drilling increasingly complex, extended-reach wells in which a bit poorly matched to the formation, drilling parameters, BHA or downhole tools may introduce unwanted dynamics or create forces that cause the well path to stray from the planned trajectory. On the other hand, a correctly designed bit delivers a more in-gauge hole and a less tortuous

well path. These wellbore characteristics allow engineers to more easily log the hole and then to install the tubulars, tools and instrumentation required for the planned completion. At one time, engineers designed and selected bits based on little more than rough estimates of formation hardness, interval depth and hydraulics. However, as with many aspects of drilling and production, in recent years, the science of bit design has evolved at an accelerated pace. Options within the general categories of fixed cutter and roller cone bits have grown from a select few to a wide variety differentiated by manufacturing material, processes and function.1

Oilfield Review

Bit bounce

Stick-slip

Bending

Whirl

Backward Fast Slow Forward

Axial motion

Torsional oscillations

Lateral shock

Eccentered drillstring

> Vibration sources. Axial motion, or bit bounce, has a characteristic frequency whose value is a function primarily of the type of bit, mass of the BHA, drillstring stiffness and formation hardness. Torsional oscillations, or stick-slip, result from an excessive amount of torque in the drillstring. This type of motion also has a frequency dependent on the mass of the BHA, torsional stiffness of the drillstring and dogleg contact points. Stick-slip often results in transients of extreme lateral vibrations. Lateral shock refers to sideways bending of the BHA, and is often chaotically coupled to axial and torsional motions. BHA whirl is the bending and precession of the drillstring center around the borehole. This eccentered movement can be either forward—that is, in the same rotational direction as the pipe—or backward. Forward whirl is very common and is induced by centrifugal forces caused by any slight imbalance in the drill collars. Backward whirl results when the frictional forces between the drill collar and the borehole are sufficient to cause the drillstring to move backward along the borehole wall.

While bits have never been designed in total isolation, today’s high-speed computers have made it possible to consider the entire drilling system in far more detail and in a far more holistic manner than ever before. Designers are also able to better match the bit to the formation and thus avoid low ROP or excessive nonproductive time (NPT) caused by trips to replace worn bits. The most damaging result of poor bit design is the creation of excessive downhole shocks and vibrations. Vibrations can cause anything from slow ROP—induced by premature bit wear—to damage and ultimate failure of complex and costly downhole electronics. Vibrations are caused primarily by often-linked drilling phenomena known as bit bounce, stick-slip, bending and whirl (above). Bit bounce most frequently occurs when drilling vertically through hard formations, usually with a roller cone bit, but it may also occur with a fixed cutter bit. The cutting action of tricone roller bits tends to create lobes on the bottom of the hole, which causes the bit to be axially displaced three, six or even nine times per bit revolution, changing the effective weight on bit (WOB) and repeatedly lifting the bit off and then

Summer 2011

slamming it back to bottom. The resulting axial vibrations damage bit seals, cutting structures, bearings and BHA components and also reduce ROP and destroy downhole sensors. One operator has said stick-slip accounts for about 50% of on-bottom drilling time.2 Stick-slip, a function of the rotary speed of the BHA, occurs when the bit stops turning due to friction between the bit and the formation. Once torque within the drillstring becomes greater than these friction forces, the bit releases from the wellbore wall and is spun by the unwinding of the long drillstring at very high angular velocities, causing destructive lateral movement. Bending is caused by placing too much downward force on the drillstring. This can create lateral shocks when the drillstring is deformed enough to make contact with the wellbore. Another operator has estimated that 40% of footage drilled worldwide is adversely affected by bit whirl.3 Whirl creates severe lateral movement at the bit and the BHA. A drilling imbalance brought on by a poorly selected bit or negative bit-BHA interaction pushes one side of the bit against the wellbore wall, creating a frictional force. When drilling a gauge hole, the bit rotates

about its center. But during whirl, the instantaneous center of rotation becomes a cutter on the face or gauge of the bit, the same way a turning axle moves the instantaneous center of rotation of a car’s tire to the road. As a consequence, the bit tries to rotate about this contact point. Because the bit’s center of rotation moves as the bit rotates, one result of whirl is an overgauge hole. Motion within this hole may force the cutters to move backward (relative to the surface rotation), or laterally, causing the bit to travel longer distances per revolution than in a gauge hole. These actions create high-impact loads on the bit and BHA. Whirl also creates a centrifugal force that pushes the bit toward the wall, increasing the frictional force, which in turn reinforces whirl.4 1. For more on bit types and manufacturing: Besson A, Burr B, Dillard S, Drake E, Ivie B, Ivie C, Smith R and Watson G: “On the Cutting Edge,” Oilfield Review 12, no. 3 (Autumn 2000): 36–57. 2. Xianping S, Paez L, Partin U and Agnihorti M: “Decoupling Stick-Slip and Whirl to Achieve Breakthrough in Drilling Performance,” paper IADC/SPE 128767, presented at the IADC/SPE Drilling Conference and Exhibition, New Orleans, February 2–4, 2010. 3. Xianping et al, reference 2. 4. Brett JF, Warren TM and Behr SM: “Bit Whirl—A New Theory of PDC Bit Failure,” SPE Drilling Engineering 5, no. 4 (December 1990): 275–281.

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Drill bits

Fixed cutter

Roller cone

Polycrystalline diamond compact (PDC)

Diamond

Natural diamond

Impregnated diamond

Milled tooth

Insert

Fixed cutter

PDC

Roller cone

Natural diamond

Impregnated diamond

Milled tooth

Insert

> Drillbit designs. Selection begins with a choice between a bit whose cutting mechanism is fixed to the bit body or on roller cones. A selection of fixed cutters (left) may be further refined, based on formation hardness, by opting for PDC or natural diamonds, which are on cutter blades or impregnated into the bit body. Roller cones (right) consist of milled-tooth cutting structures or inserts.

Traditionally, the driller must change WOB or pipe rotation speed to counter drilling dysfunctions such as bit bounce, stick-slip, whirl and bending. Increasing WOB may induce stick-slip and raising the rotation speed may invite whirl. Restraining both may reduce all four types of vibrations but result in unacceptably low ROP. The third choice is to find an optimized combination of the two variables, which may be done only when the bit, BHA, drillstring and hydraulics program are integrated as part of a drilling system rather than as isolated components. Engineers have long known how to model the complete system. However, the volume of calculations to do so has historically required an investment of time that made the task economically untenable. Additionally, the parameters calculated were valid for only a single instance in a specific formation in a well. These limitations have been overcome in recent years by the proliferation of fast, powerful computers that have allowed designers to model the performance of drilling systems for specific

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applications. The result has been an increased ability to minimize axial and lateral vibrations by determining the optimum range of WOB and rpm. Even more important, engineers are able to design systems before they are manufactured. This article looks at the tools available for modern bit design including simulation, modeling and finite element analysis programs. Case studies from offshore West Africa, Peru and the US will demonstrate the impact increased computer power is having on drilling operations. Drillstring Design as an Iterative Process The aim of drillbit design is creation of a bit, which, when matched to the correct BHA, downhole tool, formation to be drilled and drilling parameters, will perform optimally as defined by the following: • ROP • durability • stability • steerability • versatility.

Each of these metrics is weighted by the operator according to the specifics of the section to be drilled. For example, if fast ROP is the primary driver in a given interval, it may require sacrificing bit durability for faster drilling, resulting in faster bit wear. Similarly, if steerability is of primary concern, the operator may be forced to use a less aggressive bit and slow the ROP. Guided by operator objectives and the characteristics of the formations to be drilled, bit designers consider many options for each facet of the bit. The bit designer must first choose between a roller cone or fixed cutter bit (above). On roller cone bits, the cones turn independently as the BHA rotates on bottom. Each cone has cutting structures of hard-faced steel or tungsten-carbide inserts. By design, they wedge and crush like chisels, or gouge and tear like shovels, depending on formation hardness.

Oilfield Review

By contrast, fixed cutter bits, or drag bits, have integral blades that turn together. Their steel cutting structures may include natural diamonds suspended in the blade matrix. The body of the fixed cutter bit is a cast of tungsten-carbide matrix or machined steel. Composed of manmade polycrystalline diamond compact (PDC), fixed cutters shear the bottom of the hole.5 Historically, bits and BHAs were chosen through a process of elimination. For a given drilling program, engineers first chose a bit based on offset well data. The amount and value of the data vary according to location, but of special interest to drillers are bit records that include bit type and design used, ROP, footage drilled per bit and an accurate International Association of Drilling Contractors (IADC) bit grading. Based on this information, a specific bit type is chosen and run. When the driller decides the bit is no longer effective—for example when the ROP slows below a predetermined rate—the drillstring is pulled and the bit inspected. This empirical bit selection process continues in many drilling programs today. The bit is then analyzed for cutting structure wear and breakage. Historically, drillers learned through experience how to examine a used bit, called a dull, to determine what type of bit to run next or what changes to make to the bit type. In the 1950s, the industry established general guidelines for relating typical bit wear patterns to possible causes.6 In 1961, responding to a need for a common vocabulary and standard reporting method, the American Association of Oilwell Drilling Contractors (AAODC) established the first dull-bit grading system. It graded teeth and bearing wear on a 1 to 4 scale in which a 4 was a missing or totally flat tooth or a missing or locked bearing. Soon after, the system was expanded to a 0 to 8 scale with added detail.7 In March 1985, the IADC, successor to the AAODC, recognized that the system was again in need of updating. Bits had evolved since the last system update, most significantly with the inclusion of journal bearings and tungsten-carbide inserts.8 The new system was adopted in March 1986. In addition, a fixed cutter dull grading system, created in 1987, was revised in 1991 and was presented to the industry in 1992 (above right).9 With this standardization of wear analysis and reporting, it became possible to create bit records that could be used to select bits and drillstring components for similar wells. Smith Bits, a Schlumberger company, initiated a Drilling Record System (DRS) in 1985. Today this database of nearly three million drillbit runs includes records from every oil and gas field in the world.

Summer 2011

In past efforts to improve drilling performance, engineers have used the dull grading chart to make changes to the bit design, the BHA and drilling parameters after each run. As each new configuration was run, engineers analyzed bit performance, graded the bit and made changes

However, as exhaustive as these records are, they contain an element of subjectivity, which can impact bit life and performance from one well to the next. Additionally, bit performance may be impacted by significant lithology variation within a field.

IADC Bit Dull Grading Code Cutting structure

B

Inner rows Outer rows Dull characteristic Location

Bearing seals

G

Remarks

Gauge 1⁄16 in. Other characteristic Reason pulled Roller Cone Bits

Fixed Cutter Bits Inner rows

0

1

2

Outer rows

3

0

1

2

Inner cutting structure (all inner rows) 4

3

4

5

6

7

8

Cone 1

Cone 3 5

Outer cutting structure (gauge row only)

6

Cone 2

7

> Grading dulls. Using a linear scale from 0 to 8, engineers assign a value to cutters in the inner and outer rows of bits to indicate amount of wear. Grading numbers increase with amount of wear, with 0 representing no wear. Eight indicates that no usable cutter remains. PDC cutter wear is also measured in a linear scale from 0 to 8 across the diamond table—the diamond section atop the cutting structure—regardless of the cutter shape, size, type or exposure. Today, the dull grading system adopted by IADC includes codes to dull grade both fixed cutter (left) and roller cone (right) bits. The engineer assessing bit damage uses a chart that includes eight drillbit factors. The first four items on this chart (top) describe the cutting structure. The third and seventh spaces are for noting dull characteristics of the bit, which are the most prominent physical changes relative to its condition when manufactured. The fourth space, location, indicates the location of the primary dull characteristics noted in the third space. For fixed cutter bits, one or more of four profile codes is used to indicate the location of the noted dull characteristic. The fifth item, labeled B, refers to bearing seals and does not apply to fixed cutter bits. This space is always marked with an X when fixed cutter bits are graded. The sixth item, G, refers to gauge measurement. The gauge space is used to record the condition of the bit gauge. If the bit is still in gauge, the letter I is placed here. Otherwise, the amount by which the bit is undergauge is recorded to the nearest one-sixteenth inch. The last two spaces, remarks, are used to indicate other dull characteristics and the reason the bit was pulled.

5. Besson et al, reference 1. 6. Bentson HG and Smith HC: “Rock-Bit Design, Selection and Evaluation,” paper API 56-288, presented at the Spring Meeting of the API Pacific Coast District, Division of Production, Los Angeles, May 1956. 7. Hampton SD, Garris S and Winters WJ: “Application of the 1987 Roller Bit Dull Grading System,” paper SPE/IADC 16146, presented at SPE/IADC Drilling Conference, New Orleans, March 15–18, 1987. 8. Hampton et al, reference 7.

9. Brandon BD, Cerkovnik J, Koskie E, Bayoud BB, Colston F, Clayton RI, Anderson ME, Hollister KT, Senger J and Niemi R: “First Revision to the IADC Fixed Cutter Dull Grading System,” paper IADC/SPE 23939, presented at the IADC/SPE Drilling Conference, New Orleans, February 18–21, 1992. Brandon BD, Cerkovnik J, Koskie E, Bayoud BB, Colston F, Clayton RI, Anderson ME, Hollister KT, Senger J and Niemi R: “Development of a New IADC Fixed Cutter Drill Bit Classification System,” paper IADC/SPE 23940, presented at the IADC/SPE Drilling Conference, New Orleans, February 18–21, 1992.

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> FEA mesh. An FEA mesh represents a modeled body—in this case a drillstring—with mesh elements that connect at the nodes (black lines) to critical components affecting drilling performance. This mesh is used in the IDEAS program to optimize bit cutting structures (black cylinders). In this instance, red and green patches indicate that side forces on the bit during this simulation are being imposed on the gauge of one blade (red), more so than on the other five (green).

to the system accordingly before drilling the next section or next well. The process was repeated in successive attempts to incrementally improve ROP or bit life. In some cases, these changes resulted in little progress from one well to the next, and the driller had to restart the process. More commonly, the iterative method enjoyed at least partial success as ROP was increased or the bit was able to drill more footage before it had to be replaced. Still, well histories abound in which little improvement was seen even after many iterations, or, if the iterative process was successful, it was only after many such trial-and-error cycles. An iterative approach is particularly handicapped when the first well includes little offset data or the drilling program includes only a few wells. The iterative process for developing optimal bit and BHA configurations is also hampered by several factors inherent in the process. Engineers of differing experience draw different conclusions from essentially the same wear patterns; some engineers, for example, may arrive at the cause of a particular wear pattern after making false assumptions. The most common of these assumptions is that drillstring weight is efficiently transferred to the bit. WOB directly

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impacts ROP. An engineer may assume that poor bit selection is hampering ROP when in fact WOB, which is a function of BHA design, is actually less than calculated.10 Conversely, when WOB is too high, the drillstring and BHA may bend, leading to an overgauge hole and destructive lateral vibrations as the angled bit engages and cuts away the borehole wall. In 1987, efforts were made to correct this possible pitfall with the introduction of BHAP, a BHA performance prediction computer program. BHA design decisions include the type, placement, shape and size of all components above the bit. Before the introduction of BHAP, engineers relied on mathematical models that used descriptions of the BHA components to predict WOB. These models were two-dimensional, used a constant wellbore curvature and were static.11 Although designed to be simple to minimize computer run time, BHAP was an improvement over previous practices that tended to view bit performance in isolation. More complex modeling awaited the arrival of computing power that could, at reasonable speed and cost, handle massive volumes of data and calculations.

An Elemental Answer When BHAP was introduced, engineers had at their disposal a powerful tool for creating a more comprehensive and more accurate description of the drillstring. In the 1940s, scientists and mathematicians seeking to analyze vibrations in complex machinery had introduced the world to finite element analysis (FEA). FEA involves 2D or 3D modeling and uses a complex system of nodes to create a grid called an FEA mesh. This FEA mesh is populated with the material and structural properties that define how the system will react to loading conditions. Throughout the material, the density of the nodes depends on the anticipated stress levels of a particular area. To concentrate computer power where it is needed, regions receiving large amounts of stress usually have a higher node density than those experiencing little or no stress. From each node, a mesh element extends to each of the adjacent nodes (above).12 By the 1970s, FEA was commonly used by mechanical engineers, although its application remained limited to a few users who could afford the necessary computing power. As a consequence, most drilling optimization computations

Oilfield Review

relied predominantly on offset well data rather than FEA techniques to plan wells. These programs’ attempts to assess and predict drillstring and bit behavior were restricted to static or steadystate analysis designed to understand a specific part of the system at a particular moment. These assessments were most useful as postmortem descriptions of drilling system failures and identified only a fraction of the problem.13 To optimize bit and drillstring component selection and placement, engineers needed to understand the dynamic interaction of all components as drilling progressed. This finally became feasible when high-powered, fast computers became widely available in the 1990s. Engineers began, relatively quickly and at reasonable cost, to digitally recreate and analyze drilling systems and their behavior over time. Rather than performing expensive, time-consuming field trials, engineers—now armed with dynamic modeling capabilities—began to pinpoint the cause of drilling system failure and then test solutions using a virtual prototype. Dynamic models may be run to analyze the behavior of individual components, such as the bit or BHA, or they may address the entire system. The net forces and moments acting on a bit are obtained from vector sums of the contributions of individual cutters. Fixed cutter bit forces are obtained from laboratory test data; roller cone insert forces are based on simple crushing and shearing models. The equations of motion are integrated using a variable-timestep procedure.14 Six degrees of freedom (DOF) are allowed for the bit body: three translations and three rotations. For roller cone bits, DOF functions may be toggled off to simulate a seized cone.15 10. Williamson JS and Lubinski A: “Predicting Bottomhole Assembly Performance,” paper IADC/SPE 14764, presented at the IADC/SPE Drilling Conference, Dallas, February 10–12, 1986. 11. Williamson and Lubinski, reference 10. 12. “Introduction to Finite Element Analysis,” http://www. sv.vt.edu/classes/MSE2094_NoteBook/97ClassProj/num/ widas/history.html (accessed February 8, 2011). 13. Frenzel MP: “Dynamic Simulations Provide Development Drilling Improvements,” paper OTC 19066, presented at the Offshore Technology Conference, Houston, April 30–May 3, 2007. 14. Algorithms using a variable-timestep procedure continuously monitor the accuracy of the solution during the course of the computation, and adaptively change the timestep size to maintain a consistent level of accuracy. The step size may change many times during the course of the computations; larger time steps are used when the solution is varying slowly, and smaller steps are used when the solution varies rapidly. 15. Dykstra MW, Neubert M, Hanson JM and Meiners MJ: “Improving Drilling Performance by Applying Advanced Dynamics Models,” paper SPE/IADC 67697, presented at the SPE/IADC Drilling Conference, Amsterdam, February 27–March 1, 2001. 16. Dykstra et al, reference 15.

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Depth of cut Low

High

> Cutter design. Bit design engineers begin with an initial cutting structure layout (black cylinders) modeled within the IDEAS program. Each cutter on each blade is analyzed using force vectors (green and red lines) representing components of the cutting force. Vector length represents relative force magnitude. Color represents depth of cut according to the scale. Engineers use this information to position each cutting structure in terms of height above the blade surface, its radius from the bit center, the back rake and side rake angles, the size of the cutter and its profile angle. Back rake is the angle of cutter face in reference to bottomhole, and side rake refers to its angle relative to the radius of the bit face.

Dynamic Modeling Engineers first applied dynamic modeling to drilling operations to improve efficiency and protect expensive downhole components from destructive toolstring vibrations. This method included planning, real-time monitoring and detailed postjob analysis. During planning, engineers identify likely dynamic dysfunctions that cause bit bounce, stick-slip and bit- and BHA-whirl. Mathematical models are then used to design BHAs based on directional control and desired ROP and to counter expected dysfunctions. Downhole and surface sensors monitor dysfunction-related vibrations. Based on measurements from the sensors, model results and prior experience drilling in the field, engineers adjust drilling parameters to optimize ROP and minimize destructive vibrations.16 Usually, bit dynamic stability is ascertained through laboratory tests that determine the ROP or WOB that will force the bit to become unstable

at a given rotary speed. Bit-dynamics modeling allows the manufacturer to eliminate poor designs before bits are built and to determine optimal rotary speed ranges for a given design and downhole environment. Drillstring-dynamics simulations are based on finite element methods. Like bit-dynamics models, each node of the BHA model has six DOF and the equations of motion are integrated using a variable-timestep procedure. When drillstring and bit-dynamics models are coupled, dysfunctions that hinder drilling performance can be predicted and avoided. In the 1990s, Smith scientists introduced a comprehensive FEA program aimed at accurately modeling the total drilling system. The IDEAS integrated dynamic engineering analysis system predicts drillbit performance as part of a total drilling system (above). Based on laboratoryderived drilling mechanics and physical input

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Variation of vertical force with increases in DOC 0.20

12,000

0.18 0.16 0.14

8,000

0.12 0.10

6,000

0.08

4,000

0.06 0.04

2,000 0

DOC, in.

Vertical force, lbf

10,000

0.02 0

60

120 Cutter angle, degree

180

240

0

> Scrape and indentation tests. A roller cone insert (top) scrapes a sample rock—Carthage marble here—with 3,000-psi [20.7-MPa] unconfined compressive strength (UCS) at various depths-of-cut (DOCs). In the graph (bottom) measured vertical force (red) and DOC (green) are recorded for various cutter angles. This information is then loaded into the IDEAS application as a rock file, which is specific to this rock and cutter combination.

data, it uses equipment that accurately characterizes the cutting structure’s interactive mechanics during crushing and shearing across a broad range of rock samples. These input data, captured from a series of indentation and scrape tests, are acquired under laboratory-controlled pressures to replicate the dynamic interaction between a bit cutting structure and a specific rock sample (above). The experiments quantify actual cutter forces and cuttings generated in terms of magnitude and orientation as a function of both rock failure mechanisms and rock removal rates. These data are then used for the design analysis in lithologies comparable to the specific field application. In some cases, these tests are conducted on actual core samples from offset wells near the new well. The simulation model can incorporate either roller cone or fixed cutter bits.

10

Also in the early 1990s, Smith developed the DBOS drillbit optimization system, which allows engineers to characterize each target interval in terms of the unconfined compressive strength (UCS) of the rock, an abrasive index and an index of the rock’s impact on cutters. Based on this assessment, the system then defines the appropriate bit type and features with which to drill each interval of depth change. Over the years, Smith has built a database of DBOS studies, which includes bit types and formations drilled. The DBOS formation characterization database, coupled with the IDEAS simulations, enables engineers to select the appropriate rock test files for a given application. The rock and cutter mechanics data from the IDEAS laboratory are imported into a virtual drilling environment along with information

about the specific drill bit to be evaluated. This assessment includes the following elements: • precise location, material properties and dimensions of cutters • bottomhole component dimensional data and the physical characteristics of each BHA element • geometry of the proposed wellbore • planned operating parameters.17 Bit performance can then be examined in a confined environment during initial design development. The process also predicts bit performance while considering the BHA, well geometry, drilling parameters and lithology variations. All of this is done in a dynamic simulation that considers influences on the bit that are as close as possible to those it will encounter while drilling. The resulting outputs enable designers to match projected bit performance with drilling objectives, such as ROP, footage drilled per bit and specific directional characteristics. Designers use the IDEAS software as an interactive tool to test the effects of iterative changes to bit features on overall performance in specific applications. The modeling programs reveal how subtle changes in a cutter’s position and orientation significantly affect drilling performance and dynamic stability of the bit and BHA. The engineer can quickly optimize design and then use the modeling process to certify the performance capabilities of each bit through a dynamic simulation and modeling methodology.18 Looking for Trouble In 2004, Smith commercialized the i-DRILL engineered drilling system. This engineering service uses the IDEAS program platform to quantitatively identify the forces, vibrations and ROP for a specific complex drilling system over time. The system tests the dynamic effects of bit type, BHA design, drive mechanism and drilling parameters as a function of hole size and formation characteristics. This FEA drilling simulation model uses more than one million lines of code to accurately describe the total drilling system. The simulation is created by combining a bitrock cutting model, based on extensive laboratory testing, with FEA of the bit and drillstring. Design engineers then evaluate the behavior of various combinations of drill bits, drillstring components and configurations, surface parameters and overbalance pressures. The dynamic behavior of the entire drilling system can be analyzed through multiple geological formations of varying compressive strength, dip angle, homogeneity and anisotropy to gain optimal drilling performance through formation transitions.

Oilfield Review

> Modeling milled-tooth bit operation. This view of a milled-tooth bit application generated by i-DRILL software includes displacement and contact forces at the rotary steerable system (RSS) pads (blue rectangles, top left). In this case, a cross-sectional view of the RSS oriented along the drillstring axis shows the tool to be centered in the hole. This indicates that there is no contact force on the pads, which means the wellbore trajectory is not being changed at the instant the data are captured. The pattern made by the bit on the bottom of the hole is shown (bottom left) as are critical BHA–wellbore wall contact points along the BHA (red lines, right).

The i-DRILL process integrates offset well data, surface and downhole measurements and knowledge of available products and applications as part of the design process. It also considers detailed geometric input parameters and rock mechanics data. These inputs enable engineers to simulate a specific drilling operation and thus evaluate and, through dynamic analysis, correct root causes of inefficient and damaging BHA behavior. The i-DRILL system creates dynamic drilling simulations that help engineers visualize the downhole environment prior to drilling; this is in contrast to engineers having only static analyses, which provide just a small slice of data for a fixed point in time. The i-DRILL modeling process begins by using the available offset well data to calibrate the simulation software for each application. The dataset may include the following: • details regarding the physical characteristics of the entire drillstring, the BHA and the drill bit • directional surveys and caliper logs to characterize the hole geometry • surface and downhole operating parameters such as WOB, torque and rpm • mud log and wireline log data to evaluate the formations being drilled.

Summer 2011

Designers use this information to build a computer model of the offset drilling assembly, the formations and the wellbore (above). The program simulates the operation of the drilling assembly as a function of time. Because it allows analysis of the specific target lithology and the behavior of each BHA component, any suspect behavior is identified, quantified and illustrated using the system’s advanced graphics capabilities. Simulation video clips accurately illustrate what would occur downhole. The process identifies damaging and efficiency-reducing dysfunctions such as high rotary steerable system (RSS) contact forces, bit whirl and excessive bending moments.
 Once the underlying causes of undesirable drilling characteristics are identified, the engineer can reconfigure the modeled drilling assembly and use simulation analyses to correct the problems. Corrective actions can include switching to a different drill bit, exchanging stabilizers for reamers, repositioning individual BHA components, changing operating parameters or combinations of changes that will produce significant performance improvements. Last, the software generates a comprehensive report documenting the findings and analysis process, which designers can then present to the

operator. It contains the results of each simulation, identifying all potential changes that could be made to the drilling assembly and the effect that each would have on drilling performance. The operator can then select the best option to meet drilling objectives, minimize problems and improve performance.19 Dynamic modeling systems allow engineers to process a multitude of simulations representing any combination of drillbit options, drilling assembly components, drillstring design, component placement and operating parameters. Because the method is highly accurate, engineers are able to quantitatively evaluate various scenarios and then choose a solution in which a specified performance will be achieved in the drilling operation. The method helps identify operational technical limits, which avoids NPT, and eliminates inefficiencies resulting from operating too far below the technical limits. It also helps the operator avert needless trips to change bits and BHAs that are the result of using 17. Garrett I, Teggart B and Tetley N: “FEA Modeling System Delivers High-Angle Well Bore Through Hard Formations,” E&P 83, no. 9 (September 2010): 68–71. 18. Garrett et al, reference 17. 19. Garrett et al, reference 17.

11

Hyedua-1

Odum-1

50

Porosity % 0

Mahogany-1

UCS 0 psi 30,000

UCS 0 psi 30,000 Depth, m

50

Porosity % 0

3,300

Depth, m 2,100

Porosity 50 % 0

Depth, m

2,550

2,650 3,550

Porosity Depth, m % 0 3,600

3,650

2,700

3,700

3,750

2,750

2,450 2,500

3,500

50

2,600

2,400 3,450

Depth, m

3,500

2,250

2,350

Porosity 50 % 0

UCS 0 psi 30,000

2,500

2,300 3,400

J-02

UCS 0 psi 30,000

2,150 2,200

3,350

Mahogany-2

UCS 0 psi 30,000

2,800 3,600

3,800

2,850 3,850

2,550 2,900 2,600

3,550

3,600

2,650

2,950 3,650

2,700

3,000

2,750

3,050

3,950

2,800 3,650

2,850

3,700

4,050 3,200 3,750

3,150

3,250

4,100

3,300

3,050

4,150 3,350

3,100 3,800

4,000

2,950 3,000

3,750

3,100 3,150

2,900 3,700

3,900

3,800

3,400

4,200

3,200

> Jubilee field well logs. Interpretations of sonic and gamma ray logs of four 121/4-in. sections of Jubilee wells drilled at different depths were used to determine lithology and UCS. The first track, lithology, includes shale (green), sandstone (red) and marl (blue). The second track shows UCS (dark blue line) with porosity (aqua shading).

trial-and-error methods to solve particular drilling challenges. Dynamic modeling was used in 2007, after Tullow Oil plc drilled successful exploration wells—Mahogany-1, Mahogany-2 and Hyedua-1— offshore Ghana, West Africa, which resulted in the discovery of the Jubilee field. Results from three appraisal wells drilled in 2008 confirmed that the field is a continuous stratigraphic trap. The Jubilee field is one of only a few deepwater developments in the world containing hard and abrasive formations through the reservoir sections. Engineers identified these challenging formations while drilling the first four wells in the region. With log data from the first three test wells, a rock mechanics program quantified the formation’s UCS between 6,000 psi and 10,000 psi [41.4 MPa and 68.9 MPa] with turbidite stringers as high as 25,000 psi [172 MPa] (above).

12

Due to the difficulties encountered on the first four wells, the operator commissioned a full i-DRILL study based on all the available data. This study recommended an initial seven-bladed PDC bit to drill to a planned core point. After coring, a more durable nine-bladed PDC bit was recommended. When the operator drilled the first appraisal well—Hyedua-2—the first bit wore quickly once it began to penetrate the reservoir, further confirming the abrasive nature of the reservoir.20 The more durable bit was run below the cored section, but after it drilled only a short distance, it was pulled in response to low ROP. Once retrieved, it too was found to be badly worn. The i-DRILL process successfully predicted which bits would yield a stable system; this allowed engineers to turn their attention more specifically to bit durability.

Using an FEA-based dynamic modeling system, engineers then began a series of virtual tests to identify a PDC bit optimized for the reservoir section. While engineers analyzed the results of the Hyedua-2 well and developed an improved bit and cutter design, the operator drilled three more development wells and tested several bit designs. An optimized bit was manufactured in 2009. At the same time, Smith developed the proprietary, highly abrasion-resistant ONYX PDC cutter, which was incorporated into the optimized bit. On its first application in the J-02 well, it drilled the entire hard and abrasive 121/4-in. section in a single run. Further bit refinement improved performance. Engineers then turned their attention to the BHA design in an effort to reduce high vibration levels that were causing LWD tool failure, which in turn forced the operator to run time-consuming wireline logs.

Oilfield Review

Bit Grade Well name Number

Out, m

Drilled, m

Hours

ROP, m/h

Inclination, degree

BHA

I

O

C

L

#1 #2

#3

G

O

R

Hyedua

02

Oct. 25, 2008

Spud date

Bit type PDC 6

3,393

996

56.0

17.8

14

BHA 8

2

8

RO

S

X

X

X

1

LT

CP

Hyedua

02

Oct. 25, 2008

PDC 4

3,565

57

18.5

3.1

Vertical

Rotary

1

2

WT

S

X

X

X

1

NO PR

Hyedua

02

Oct. 25, 2008

TCI 527

3,663

98

48.5

2.0

Vertical

Rotary

5

4

BT

A

E

E

E

2

WT TD

Jubilee

02

Apr. 11, 2009

PDC 5

4,215

1,135

126.6

9.0

38

BHA 8

3

4

WT A

X

X

X

1

CT TD

Jubilee

05

July 22, 2009

PDC 5

4,192

1,702

80.5

21.1

49

BHA 12

1

2

WT

S

X

X

X

1

NO TD

Jubilee

11

Aug. 08, 2009

PDC 5

4,213

1,481

90.5

16.4

40

BHA 12

2

3

WT

S

X

X

X

1

NO TD

Jubilee

12

Aug. 31, 2009

PDC 5

4,292

1,349

71.1

19.0

44

BHA 12

3

8

WT

S

X

X

X

2

RO TD

TCI = tungsten carbide insert. Bit grading code: I = inner cutting structure; O = outer cutting structure; C = cone; L = location; S = shoulder; A = all areas; #1, #2, #3 = bearing; E = seals effective; X = no bearings; G = gauge; O = other dull characteristics; LT = lost cutter; NO = no dull characteristics; WT = worn cutters; RO = ring out; R = reason pulled; CP = core point; PR = penetration rate; TD = total depth, casing point.

> Run details in the 121/4-in. section. Compared to the averages from offset wells (brown), the newly designed PDC bit run in J-05, J-11 and J-12 (green) drilled 165% more footage with an ROP increase of 122%. The bit was in good condition when pulled.

They approached the problem by studying the most recent offset well, the J-02, in a follow-up i-DRILL study with a focus on stick-slip and lateral vibrations. Engineers first identified conditions within the well that led to stick-slip and bit whirl and then replicated those conditions in a simulation. After they better understood the drilling dynamics of the well, engineers ran simulations using varying BHA, WOB and rotation speed. From these results they recommended changes in BHA configuration and optimized operating ranges for WOB and rotation speed; they recommended the same bit, but with a motor to assist a push-the-bit RSS. This was used successfully on the next three wells, J-05, J-11 and J-12. Further bit optimization efforts focusing on drilling parameters allowed engineers to maintain these successes using RSS only. These recommendations were applied to the J-05 well, which required a tangent section with a 49° inclination before reaching TD at 4,192 m [13,753 ft]. The results include an ROP improvement from 8.9 to 21.1 m/h [29.2 to 69.2 ft/h] and commensurate savings in rig time of about US$ 1 million/day. When retrieved, the bit, LWD tool and RSS were in good condition due to reduced vibration levels compared with those in J-02. Drilling performance from the three offset wells showed that the new PDC bit drilled 165% more footage with a 122% increase in ROP while drilling the reservoir interval in a single run (above).21 This system was used on the next two wells, J-11 and J-12. Further bit optimization efforts focusing on drilling parameters allowed engineers to maintain these successes using RSS only. Since July 2009, with optimized BHA and parameters, the operator has used bits of the same design to drill all but one 121/4-in. section in a single run.

Summer 2011

Special Needs Cases Some drilling scenarios are inherently more difficult to optimize than others. For example, deep wells often present drillers with a particularly challenging scenario in which the initial hole

must, while it is being drilled, be enlarged, or opened, beyond the size of the bit. To accomplish this, the BHA often includes an underreamer– hole opener tool located above the bit (below). Once drilling commences in a hole section to be

Backreaming cutting structure Stabilizer– gauge pad Formation cutting structure

Z-drive tongue-and-groove actuation

> Underreamer–hole opener. An underreamer is designed so that its cutting structure may be expanded to a size greater than the diameter of the pilot bit once they have both exited the casing shoe and entered the interval to be opened. This concentric reamer includes a one-piece cutter block and extension mechanism design. The tongue-and-groove actuation system traverses beneath the PDC formation cutting structure blocks and opens it to a preselected diameter maintained by the simultaneously opened stabilizer– gauge pad. At the same time, three backreaming cutting structures are locked in place to allow the reamer to open the hole while tripping out, if required. The blocks are locked in place by the tool’s hydraulic system. The single-piece body design increases the tool’s torque and load-carrying capacity, ensuring it can efficiently handle the heavy weight of the rotary steerable system BHA. 20. Murphy D, Tetley N, Partin U and Livingston D: “Deepwater Drilling in Both Hard and Abrasive Formations; The Challenges of Bit Optimisation,”

paper SPE 128295, presented at the SPE North Africa Technical Conference, Cairo, February 14–17, 2010. 21. Murphy et al, reference 20.

13

Vivián Formation 11,000-psi UCS

Reamer 1

Measured depth

Bit Chonta Superior Formation 5,000-psi UCS

Reamer 2 Bit

Reamer 3 Bit

Reamer 4

Chonta Inferior Formation 14,000-psi UCS

Bit

> Four critical scenarios. Engineers identified four critical situations encountered while drilling the tangent section through the Vivián, Chonta Superior and Chonta Inferior formations with a 121/4-in. reamer and 10 5/8-in. pilot bit. The critical scenarios—during which damaging vibrations are most likely to occur—are while the bit and reamer are in Vivián (1), the reamer is in Vivián while the bit is in Chonta Superior (2), the bit and reamer are in Chonta Superior (3) and while the reamer is in Chonta Superior and the bit is in Chonta Inferior (4).

enlarged, engineers send a signal that expands the underreamer’s blades, creating a cutting tool of larger diameter than the internal diameter of the previous casing string. The object of the operation is to forestall reduction of wellbore diameter as numerous, successively smaller casing strings are installed across transitional zones encountered while drilling deep wells. This strategy is also employed extensively in deepwater operations in which many casing strings must be used to control drilling fluid losses as the pore-pressure–fracture-gradient window quickly narrows. A larger diameter wellbore also addresses the challenge of small drilling windows through reduced friction pressures in the annulus, creating a lower equivalent circulating density (ECD). The intended result is a sufficiently large internal clearance through the production casing string to accommodate all necessary completion equipment. Underreaming while drilling may be problematic in some situations. In combination with downhole motors or rotary steerable assemblies, the reamer must be strong enough to hold the added weight of the steering assembly hung below it and yet remain sufficiently pliant to deliver a quality wellbore through sometimes acute trajectory changes. Perhaps greater challenges to the BHA and bit designer, however, are difficulties that arise when the reamer and bit are drilling in formations of differing hardness. This difference may cause them to drill at different

14

speeds, generating torsional and lateral vibrations in the drillstring. In the Pagoreni field, operator Pluspetrol was experiencing vibration problems, which were resulting in unacceptably low ROP and the destruction of expensive downhole measurement tools. The Pagoreni field is located onshore in a folded Andean thrust belt in the southern portion of Peru’s Ucayali river basin. Pluspetrol began developing the field in May 2006. The deviated Pag1001D well reached 10,300 ft [3,139 m] MD about 1 mi [1.6 km] southeast of the surface location and confirmed the presence of commercial quantities of wet gas in the Upper Nia formation. This led the operator to launch a six-well development program aimed at recovering the field’s estimated 3.5 Tcf [99.1 billion m3] of proven and probable recoverable reserves. The vibration problems developed in the first three wells while the operator was drilling a 10 5/8-in. pilot hole that was opened to 121/4-in. using an expandable underreamer. In these wells, the problems were stick-slip and high axial and lateral vibrations while the tangent sections were being drilled. Trial-and-error approaches to BHA changes provided some relief from the axial and lateral vibrations but exacerbated stick-slip severity.22 The troublesome section included the following stratigraphic sequence: • Vivián Formation—hard, fine- to very finegrained, friable quartz sandstone of 11,000-psi [75.8-MPa] UCS

• Chonta Superior—soft calcareous shale and clay of 5,000-psi [34.5-MPa] UCS • Chonta Inferior—hard limestone layers of 14,000-psi [96.5-MPa] UCS. Unable to overcome the drilling dysfunctions through iterative processes, the operator requested that the i-DRILL engineering group at Smith optimize the BHA design, including PDC bit selection, for its fourth well, the Pag1004D. The team began by organizing offset data and information on drilling practices from the three previous problem wells— Pag1001D, Pag1002D and Pag1003D. These offset data were input into the BHA modeling program. The model included the PDC bit, RSS, LWD, expandable reamer and drillstring to the surface drive system. All drillstring dimensions and materials from offset wells, as well as a hole caliper measurement from offset wells, were incorporated into the model. The model was then calibrated using other offset data, including rotation speed, WOB, surface torque and hook load, as well as data from downhole measurements. Simulations were run and adjusted repeatedly until the offset conditions were duplicated to within a statistical match. The simulations allowed engineers to view the interaction of the previous systems and the boreholes and determine the root cause for poor drilling performances in the first three wells. The resulting virtual model was then tested to predict the effects of different bit types, BHA designs, drive mechanisms and operating parameters as a function of hole size and lithology. A series of virtual cases was run to determine the optimal PDC bit profile, blade and cutter count, gauge length, bottomhole patterns and force balance on four bits. Laboratory tests helped determine the most appropriate cutting structures in terms of aggressiveness when used in combination with the 121/4-in. bit with 13-mm [0.51-in.] cutters. Smith technicians were able to make this determination using the IDEAS laboratory to simulate the confining pressure of the specific formations to be drilled. ROP potential was then calculated using an FEA model that considers precise dimensions and properties of the cutting structure, rock hardness, or UCS, lithology and confined pressure based on laboratory tests. Engineers modeled BHA components to test various scenarios aimed at reducing vibrations. For the Pagoreni field, the i-DRILL team identified four critical scenarios with vibrationinducing potential that could be encountered

Oilfield Review

Shale Gas Drilling Challenges Massive gas reserves are being discovered in shale formations around the world. Because they are of extremely low permeability, these shale reservoirs are accessed using long horizontal wellbores, usually drilled with tungsten-carbide PDC bits. The formation is then opened through multiple hydraulic fractures. In the Marcellus shale of the northeastern US, operators found that drilling long lateral wells with conventional PDC bits resulted in premature bit failures and short runs because of bit balling, poor directional behavior and loss of toolface control. Balling was causing plugged bit nozzles and packed bit bodies (right). Cuttings were not being carried back up the annulus but instead were 22. Cassanelli JP, Franco M, Perez J, Paez LC, Pinheiro C and Frenzel M: “Dynamic Simulation: Solving Vibration/ Stick-Slip Issues Achieves Record ROP, Pagoreni Field, Peru,” presented at the Sixth International Seminar on Exploration and Exploitation of Hydrocarbons (INGEPET) Lima, Peru, October 13–17, 2008. 23. Cassanelli et al, reference 22.

Summer 2011

Vivián Formation 11,000-psi UCS

Reamer 1

Reamer

Bit Measured depth

while drilling transition zones between the Vivián, Chonta Superior and Chonta Inferior formations (previous page). These include the following situations: • bit and reamer in Vivián • reamer in Vivián, bit in Chonta Superior • bit and reamer in Chonta Superior • reamer in Chonta Superior, bit in Chonta Inferior. To better understand the dynamics involved in the four scenarios, engineers conducted five in-depth virtual analyses using the four candidate bits in combination with the underreamer: • weight distribution (WOB and weight on reamer) versus ROP • lateral vibration (bit and reamer) versus ROP • torque vibration (bit and reamer) versus ROP • average torque (bit and reamer) versus ROP • risk of stick-slip versus ROP. Based on these analyses, engineers concluded that the most critical scenario occurred when the bit was in the soft Chonta Superior Formation and the reamer in the hard Vivián Formation. That was also the section in which the reamer was least efficient. The worst case for the bit, however, occurred when the reamer was in the Chonta Superior and the bit was in the harder Chonta Inferior (above right).23 Overall, the optimal method to balance the requirements of maximum ROP and reduced vibration through the four challenging scenarios was to use a rotary steerable–compatible six-blade bit design.

Worst scenario for reamer

2 Bit

Chonta Superior Formation 5,000-psi UCS

Reamer 3 Bit

Reamer 4

Chonta Inferior Formation 14,000-psi UCS

Bit

Worst scenario for bit

> Transition drilling conclusions. Based on their analysis, engineers concluded that scenario 2, when the bit is in the relatively soft Chonta Superior Formation and the reamer is in the hard Vivián Formation, is the most critical of all scenarios. Scenario 2 is also the least efficient for the reamer. The worst scenario for the bit is when the reamer is in the soft Chonta Superior and the bit is in hard Chonta Inferior. Based on the resulting scores, the modeling suggested the best bit for each scenario. The study was based on a normalized results equation in which each selected drilling parameter was assigned a specific weight according to the operator importance. In this specific project, an equal weight distribution was made for average ROP, bit, reamer and surface stick-slip, bit and reamer lateral vibration and the change in downhole rotation rate.

accumulating around the bit, creating a potential for stuck drillpipe. All this dramatically reduced ROP and increased drillstring stick-slip. Because the Marcellus shale is a relatively new play, engineers at Smith had to design a bit while having little offset data at hand. Available

history indicated numerous operators with differing drillstring and BHA and bit configurations, making analysis difficult. Drawing on the IDEAS system, however, engineers at Smith offered a design that did improve ROP but did not fully address toolface control and nozzle plugging.

Nozzles

Horizontal borehole wall Junk slots Cutting structures

Bit body

Bit face

Bit face

Cuttings bed

> Nozzle plugging. A common problem in extended-reach shale drilling is the tendency for cuttings to collect in front of the bit face because the drillstring is idle while rig workers are making connections and the pumps are off. If the design of the body and junk slots does not allow for efficient movement of cuttings past the bit when circulation resumes after pumps are turned back on, a buildup of cuttings can occur and push into and plug the nozzles (left). Cuttings can likewise be pinched between the hole and the bit gauge, which prevents proper hole cleaning (right).

15

Matrix body

Steel body Junk slots

Makeup length difference

> Bit solution for the Marcellus shale. Since bit body erosion is of less concern while drilling shales than while drilling more abrasive sands, the bit body could be made of steel. This allowed the designers to use a more streamlined body (top right) because the less brittle steel blades could be made longer and thinner without being subject to failure due to impact breakage. Steel also permits construction of a shorter bit (bottom right) than is possible with a matrix-body bit (bottom left), which enhances its ability to drill through extreme angle changes using a drilling motor.

The initial attempt created a baseline from which engineers could design a second bit. This second iteration met steerability requirements of directional drillers and produced an acceptable ROP through the build section. This made it easier, quicker and less costly to create a curve in the well path at the desired angle, azimuth and build rate. However, ROPs through the 2,000- to 3,000-ft [610- to 914-m] lateral sections, which represented the greatest portion of drilling expense, were less than satisfactory. Engineers knew that drilling with rigs typically available in North America was being slowed by poor hole cleaning due to low hydraulic energy at the bit, which is common when drilling horizontal wells in shale

16

formations. Design iterations that reoriented and repositioned bit nozzles did little to alleviate the problem. Technicians at the Smith IDEAS laboratory could not obtain actual samples of the field rock to be drilled but were able to use DBOS analysis to match the Marcellus rocks with the Wellington and Mancos shales stored in their library. Their design aim was for good steerability through the curve to maintain good toolface control and fewer course corrections while delivering build rates of 8° to 12° per 100 ft [30 m]. They also sought a significant ROP improvement in the lateral sections. IDEAS tests indicated that cutting structures with flatter profiles provide lower resistance to inclination changes; these were

adopted in the design. They also settled on 0.43- to 0.51-in. [11- to 13-mm] diameter cutters because tests showed they had less depth-of-cut (DOC) compared to the larger 0.63- to 0.75-in. [16- to 19-mm] cutters. Greater DOC creates a higher instantaneous torque response, which can cause loss of toolface control and so hinder directional response. Upgrades were also made to the hardfacing materials of the drill bits to better protect the steel from erosive drilling fluid. Designers concluded that cuttings were not being carried away from the bit because the flow areas between cutter blades to the annulus, known as junk slots, were too narrow. To increase this flow area, engineers could increase the height of the bit blades while reducing their width, but that presented a problem. Current bit matrix designs are limited by the aspect ratio (blade height/blade width) because the tungstencarbide matrix is relatively brittle and blades that exceed a certain ratio often break upon impact with the formation. Over time, the bits that were formerly made of steel had been replaced by tungsten-carbide bits, which enabled the bits to withstand the erosive forces created by abrasive formation sand and drilling fluids flowing past the bit body. As a consequence, steel PDC bits are rarely considered for use today, except to drill relatively short, low-cost sections. A solution was found in previous practice. Because shale is characterized by low abrasiveness, steel is sufficiently durable to drill these formations without erosion worries. And, because steel is less brittle than tungsten-carbide matrix, the blades may be extended farther from the bit body with much less potential for breakage due to impact (left). By increasing the height and decreasing the width of the blade, the flow area between the bit body and the borehole wall was dramatically increased and drill cuttings were able to pass more freely into the annulus and away from the cutting structure. Fresh rock was exposed and ROP increased. Using steel, designers could streamline the bit body to make it easier for cuttings to sweep away from the center of the bit toward and into the junk slots. The body diameter of the bit could also be reduced, increasing the distance between the borehole and the bit body at the junk slot. Fluid dynamics were calculated to simulate the at-bit flow regime. This allowed nozzles to be placed and oriented to minimize recirculation at the bit face, ensuring efficient cuttings removal and elimination of balling and plugging. Blade contour angles were also designed to optimize

Oilfield Review

> Fluid flow paths. Once engineers selected the optimal Spear bit design for drilling the Marcellus shale, a computational fluid dynamics program was used to determine how the face of the cutting structure was cleaned and cooled, how effectively the hole was cleaned and how cuttings were evacuated from the bit area and passed up along the annular space. Each color represents the flow path from a specific nozzle. Modeling of fluid flow over the face of the bit (left) indicated good total coverage with no dead spots. A side perspective (right) indicated flow directed cuttings away from the bit rather than recirculating them around the bit body. A computational fluid dynamics program is used to adjust the nozzle count, size, location and orientation until an optimized design is achieved.

fluid flow at, along and above the bit to minimize steel erosion from drilling mud carrying cuttings (left). The resulting hydraulics at the bit face also increased stability and reduced vibrations, which improved ROP and steerability. This newly developed Spear steel PDC drillbit, optimized for use in shale, has been used successfully in the Bakken, Barnett, Marcellus and Eagle Ford shale formations of North America. In the Marcellus application, the target ROP goal for drilling the horizontal leg with an 8 3/4-in. bit was 50 ft/h [15.2 m/h]. The Spear bit achieved ROPs in excess of 65 ft/h [19.8 m/h]. In the Marcellus area, a 6 3/4-in. Spear bit has consistently drilled the horizontal section in one run with ROPs 10% to 20% faster than the best offset well performance. Future Perfection Where once the preoccupation of the oil and gas industry was to find hydrocarbons in economic amounts, today much of its attention is focused on producing remaining and unconventional reserves. That may entail minimizing a surface footprint while drilling horizontally to reach targets kilometers away and hundreds of meters beneath populated or environmentally sensitive areas. Or the challenge may simply be to drill through complex lithology with an ROP that does not destroy project economics.

Summer 2011

Regardless of the motive, reaching many of today’s potential oil and gas reservoirs requires improved drilling efficiencies to maintain economic viability. Much of what stood in the way of better drilling practices is being eroded by the revolution in gathering, organizing and implementing vast amounts of data quickly. The limitations imposed by human inability to use the immense volumes of data available from many and dissimilar sources have been largely overcome by recent quantum leaps in computing power. FEA may be one of the most visible of these new tools for improving drilling efficiency, but there are others on the horizon. For example, while the means are in place to accumulate great amounts of data about drilling operations, operators may not always know the best way to leverage the data to improve drilling performance in future wells. One effort currently underway and now enjoying success in field trials addresses this need by using computer neural networks to learn how to best drill formations in a given field. The first step of this process is to train the neural network with offset data, then use a process that includes interval characterization. The system would then present the driller with real-time predictions about WOB and rotation speed that would maximize bit life. The drilling industry has long discussed automated drilling. Under that general category, drilling operations have seen piecemeal innovations on

the rig floor in the form of iron roughnecks and automated drawworks to perform tasks once done less efficiently by hand. But a truly automated drilling system will be one able to understand and react in real time to the complex, dynamic interactions between bit, BHA, drillstring and the formation. That may be possible soon, but will be of significantly less value if it does not begin with a properly designed bit. —RvF

17

Conveyance—Down and Out in the Oil Field

Well productivity can be greatly enhanced by drilling high-angle wells or by directing the wellbore into multiple targets. In such wells, traditional methods for conveying evaluation, remediation and intervention tools are no longer practical. In response to the challenges presented by complex well trajectories, service companies have developed numerous innovations for accessing and evaluating these complicated wellbores.

Matthew Billingham Roissy-en-France, France Ahmed M. El-Toukhy Perth, Western Australia, Australia Mohamed K. Hashem Saudi Aramco Dhahran, Saudi Arabia Mohamed Hassaan Doha, Qatar Maria Lorente Todor Sheiretov Sugar Land, Texas, USA Matthew Loth Clamart, France Oilfield Review Summer 2011: 23, no. 2. Copyright © 2011 Schlumberger. Blue Streak, EcoScope, FMI, Litho-Density, MaxTRAC, Multi Express, SFL, TLC and TuffTRAC are marks of Schlumberger. IntelliServ is a mark of National Oilwell Varco. 1. Drilling and Production Outlook. Spears & Associates: Tulsa (June 2011): 17. 2. For more on horizontal drilling practices: Bennetzen B, Fuller J, Isevcan E, Krepp T, Meehan R, Mohammed N, Poupeau J-F and Sonowal K: “Extended-Reach Wells,” Oilfield Review 22, no. 3 (Autumn 2010): 4–15.

18

You can’t push a rope. Many a frustrated wireline engineer has uttered those words when logging tools failed to reach the bottom of a well, especially in high-angle wells. But the source of that frustration has been overcome—at least in some respects—by the introduction of new conveyance methods. These developments enable evaluation, completion and remediation not only in high-angle wells but also in long horizontal wellbores, environments that previously presented insurmountable challenges to traditional logging methods. In the days when most wells were vertical, delivering logging tools to total depth and back was a relatively straightforward task. A truckpowered winch containing a spool of cable ran the tools in and retrieved them from the well. The tools were pulled to the bottom of a well by gravity. The cable was also used to communicate with the tools, provide power and send information about the downhole environment back to the surface. This method of conveyance sufficed for openhole logging, cased hole evaluation and running mechanical services, which included perforating. But today, gravity is not the only means of getting tools to the bottom of the well, and cables are not the only means of delivering data to the surface; tool delivery, data transmission and equipment deployment methods abound. This shift in techniques and methodology has developed in large part to meet the needs of wells drilled at high angles. Whereas TD once implied the deepest point in the Earth reached

by a well, the measured depth of horizontal wells often far exceeds their true vertical depth (TVD). In 2010, more than 16,000 horizontal wells were drilled worldwide.1 This number does not include thousands more wells drilled directionally to reach targets far from the surface entry point or reach multiple zones separated by great lateral distances. With today’s technology, drilling engineers can create such complex wellbore geometries that delivering downhole tools to a targeted formation becomes a challenge. These wells require evaluation information when they are drilled, and they will also require some means to access the reservoir for future evaluation and intervention.2 A number of technologies have been developed to address the difficulties created by complex wellbore trajectories. Whereas in the past, the primary consideration was simply which tools to run, today, engineers must also consider how to optimally evaluate, access and perform remedial work for the life of a well. Fortunately, the restrictive reliance on gravity to pull logging tools attached to a cable has been replaced by an expanding battery of methods, equipment and techniques. Petrophysicists and engineers now have a plethora of choices. This article reviews some of these methods and also looks at recently introduced technologies that offer greater flexibility in data acquisition choices.

Oilfield Review

Wir el i ne

Coil ed T ubin g

Log ging Too ls o n

Dril lp ip e

Dow nho le T ract or

Logg ing W hile Dril ling

Summer 2011

19

Disdavantages

Pipe conveyed

Cable-pipe conveyed

Cable conveyed

Advantages Wirelinegravity conveyance

• Suitable

for both formation evaluation and production services • Largest selection of tools • Fast

• Gravity

Downhole tractors

• Compatible

with wireline, slickline and coiled tubing conveyance • Highest operational efficiency for horizontal intervention • Requires minimal number of field personnel

• Not

Pumpdown conveyance

• High

success rate operational efficiency • Low cost

• Requires

Slickline

• Highest

operational efficiency of all conveyance methods • Low cost

• Primarily

Coiled tubing conveyance

• Suitable

for a variety of logging, stimulation, perforating and mechanical services • High success rate • Ability to access horizontal and deviated wells

• Primarily

Drillpipe combined with wireline

• Highest

success rate in difficult conditions • Gravity independent • Supports most conventional formation evaluation tools • Highest temperature and pressure rating • Maintains well control

• Not

DrillpipeLWD

• Highest

chance of success in difficult conditions • Gravity independent • Maintains well control

• Not

Drillpipewireless

• High

• Limited

• High

success rate in difficult conditions • Gravity independent • Highest efficiency among drillpipe conveyance methods • Maintains well control

dependent to hole irregularities

• Vulnerable

suitable for every well a cased hole service • Retrieval risks with horizontal intervention • Expensive downhole equipment • Primarily

a return or exit path for the fluid • Limited applicability cased hole intervention • Gravity dependent • Limited tool offerings cased hole and producing well intervention • Limited reach due to helical lockup • Large footprint and crew requirements compared with those of other intervention methods suitable for producing wells

• Time-consuming • Limited

reach in very difficult conditions • Not suitable for fragile tools • Complications due to presence of logging cable suitable for cased hole or intervention in producing wells • Expensive • Smaller selection of tools compared with wireline tool offering logging time • Relatively slow • Expensive downhole equipment • Limited

> Conveyance methods.

and hybrid solutions that blend elements of the Getting to the Bottom Conveyance consists of more than the mecha- other. The various methods come with trade-offs, nisms of pulling and pushing tools downhole. Its strengths and weaknesses, so there is rarely a greater purpose is to address the challenges cre- perfect solution. Cable-conveyed tools have a long history. The ated by wellbore environments. These challenges include deploying tools at the surface, overcom- first electric log, acquired at Pechelbronn field in ing frictional forces, maneuvering past obstacles Alsace, France, on September 5, 1927, was run on Oilfield Review a cable. The survey instrument was lowered 300 m and adapting to unforeseen downhole conditions. SUMMER Flexibility and adaptability are important factors 11[980 ft] into the well, and subsurface measureConveyance Fig. Table 1 that engineers consider when deploying tools ments were plotted by hand as the tool was slowly ORSUM11-CONVY Table 1 downhole, but their tool choices often dictate the retrieved using a manually operated winch (next page, top right). For the next 50 years, the logging method of conveyance. Conveyance methods can be grouped into two industry remained tethered to a cable, even as logbasic types: cable conveyed and pipe conveyed ging tools evolved to include extremely complex (above). Within both categories are variations measurements that demand high data rates.3

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Surface units used for acquisition also became more and more sophisticated. But the well logging landscape experienced its most dramatic transformation in the 1980s with the introduction of logging-while-drilling (LWD) tools. LWD tools are an integral part of the drillstring bottomhole assembly (BHA). In the early days, measurements were fairly basic; they included gamma ray and resistivity, followed by the addition of porosity measurements. The tools communicate via a series of pressure pulses transmitted through the circulating drilling mud to convey commands downhole and deliver data to the surface. These pressure pulses are encoded with data about well conditions, the status of the BHA and the formations encountered by the bit. Mud pulse telemetry transmits data at rates that are several orders of magnitude lower than those achieved using logging cables; but, given the time required for drilling operations, this method has generally proved to be sufficient. Other transmission methods are available; for example, electromagnetic telemetry is used as an alternative to mud pulse telemetry in air or foam drilling. And more recently, wired drillpipe, which can send data using an imbedded transmission cable, has been introduced. Wired drillpipe promises high data rates: 57,000 bits per second compared with 10 bits per second with mud pulse telemetry. Commercial transmission systems, such as the IntelliServ Broadband Network, are currently available, although this technology has yet to replace mud pulse telemetry as the method of choice for service companies and operators. Whichever method is used, the ability to acquire real-time data from near the bit not only offers a substitute for wireline logging, but also has led to a revolution in the application of rotary steerable drilling systems, ushering in a new age of horizontal and extended-reach drilling.4 Using real-time information provided by LWD tools, directional drillers can remotely steer and guide the bit to specific targets, making precise corrections in wellbore trajectory. As well trajectories shifted from vertical to horizontal, LWD data, in many cases, supplanted traditional wireline logging for formation evaluation. Meanwhile, the quality and scope of LWD data have improved, and sophisticated tool offerings are now available while drilling. For instance, the EcoScope multifunction LWD service offers resistivity, porosity, azimuthal density, ultrasonic caliper, capture spectroscopy and azimuthal

Oilfield Review

gamma ray measurements in one compact tool (below right).5 Instead of a chemical radioactive source for neutrons, the tool uses a pulsed neutron generator powered by a turbine, which is driven by circulating mud. The tool also includes a variety of sensors that provide information to improve drilling operations. Logging companies can perform advanced services such as seismic, acoustic and magnetic resonance logging while drilling. Pressure measurements and sampling, which have long been exclusively in the wireline logging domain, can now be carried out with LWD tools as well. Engineers developing log evaluation programs, however, have more to consider than measurement technology when deciding on which services to run. For example, temperature and pressure limits are generally lower for LWD tools. And there are size limitations because LWD tools are designed for specific ranges of borehole diameters, whereas wireline tools can be used in a much broader range. There are also higher costs associated with deploying LWD equipment for long periods of time during the drilling process compared to logging with wireline tools. Although the gap between wireline and LWD offerings continues to narrow, there are some services that are not available while drilling. These include high-data-rate services, such as the FMI formation microimager tool, tools requiring high power, such as sidewall coring tools, and other technologies that have yet to migrate to LWD platforms. Eventually, the rig moves on to drill the next well, and LWD tools can no longer be used for data transmission. Even if they were available, LWD tools were not developed to perform cased hole services. Wireline tools are needed to evaluate and access the reservoir, although getting them to the bottom of horizontal and high-angle wells is problematic. Thus, alternative means of conveyance have been developed to deliver these tools. 3. For more on advances in cable-logging systems: Alden M, Arif F, Billingham M, Grønnerød N, Harvey S, Richards ME and West C: “Advancing Downhole Conveyance,” Oilfield Review 16, no. 3 (Autumn 2004): 30–43. 4. For more on rotary steerable drilling: Williams M: “Better Turns for Rotary Steerable Drilling,” Oilfield Review 16, no. 1 (Spring 2004): 4–9. 5. Japan Oil, Gas and Metals National Corporation (JOGMEC), formerly Japan National Oil Corporation (JNOC), and Schlumberger collaborated on a research project to develop LWD technology that reduces the need for traditional chemical sources. Designed around the pulsed neutron generator (PNG), EcoScope service uses technology that resulted from this collaboration. The PNG and the comprehensive suite of measurements in a single collar are key components of the EcoScope service that deliver game-changing LWD technology.

Summer 2011

> Birth of an industry. The first logging operation, which used a handoperated winch similar to the one shown, was performed in 1927 at the Pechelbronn field in Alsace, France. Using a spool of cable containing a conductor wire, operators lowered a survey instrument into the well and recorded resistivity measurements at the surface. Hand-plotted data were presented versus depth, and this first well log launched a new industry.

Holding on or Cutting the Wire Drillers can negotiate high-angle and difficult wellbores because drillpipe is stiff and heavy. This is not the case with tools at the end of a wireline. In the past, when TD could not be reached with logging tools because of well conditions,

engineers developed and attempted various methods to get past obstructions. Operators have welded chains to the bottom of tools hoping that the chain would pile up on a ledge and eventually fall off and pull the tool downhole. Weight bars, friction-reducing wheels and rollers have

Porosity Sigma Spectroscopy Neutron gamma density Annular pressure while drilling

Azimuthal density and photoelectric factor Oilfield Review

SUMMER 11 Conveyance Fig. 1 ORSUM11-CONVY 1

Azimuthal natural gamma ray

2-MHz and 400-kHz resistivity

Ultrasonic caliper Three-axis shock and vibration Inclination

> Logging-while-driling tools. The EcoScope multifunction LWD service is a reflection of the advances that have taken place in drillpipe-conveyed logging services. This compact tool provides the basic measurements of a wireline triple-combo log—resistivity, density porosity, neutron porosity and gamma ray—plus neutron capture spectroscopy. Using neutrons produced from a pulsed neutron generator (PNG), capture spectroscopy provides crucial information about lithology and mineralogy. Formation evaluation data are acquired as well as information about drilling operations, including shock, vibration, annular pressure while drilling and tool inclination.

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Before Deployment

Logging truck

After Deployment Connection to drillpipe

Ejector Logging cable outside drillpipe

Logging cable setup in CSES

Deployment head

Drillpipe Cable clamp Cable side entry sub (CSES) Logging cable inside drillpipe

Packoff seal assembly Check valve

Casing shoe

Wet-connect adaptor

Multi Express tools Concentric housings

Logging string

Horizontal openhole section

Receiver and shoe

Receiver and shoe

> Tough logging conditions. Before LWD tools were widely available, the TLC system conveyed wireline tools via drillpipe. Logging tools are attached to the drillpipe using a crossover adaptor with a wet-connect device. Tools are run in the hole to the bottom of casing, and a mating connector, attached to the logging cable, is threaded through a side entry sub and pumped down the drillstring until it engages the downhole connector. Once communication and power are established, the tools are pushed out into open hole and down to the bottom of the well. Because the cable is exposed above the side entry sub, it is not allowed to exit the bottom of casing for fear of damage to the cable, and extreme care must also be exercised while running in the hole to avoid crushing the cable. The logging tools, which are at the end of the drillpipe, are also at risk of being damaged in open hole. Most wireline logging tools can be run using this system.

A modified technique, logging while fishing been developed to facilitate tool movement. Schlumberger engineers even designed an articu- (LWF), uses a concept similar to the TLC system. lated bottom nose that could be manipulated Should a conventional wireline logging tool from the surface to locate the wellbore path become stuck in the well while logging, a cut-andwhen the tools stopped on ledges or where the thread fishing operation is performed to engage hole exhibited large washouts. These attempts to the stuck tool with a grapple attached to the end of overcome geometry and borehole irregularities drillpipe. The severed cable is reconnected at surface to provide power and communication to the typically met with limited success. Oilfield Review downhole tools, and then data are acquired as the However, before the widespread acceptance SUMMER of LWD tools, methods existed for conveying con- 11pipe and tools are pulled out. This operation has Conveyance Fig. 3performed when crucial data were needed ventional openhole logging tools at the end of been ORSUM11-CONVY 3 drillpipe. Among them was the TLC tough logging but hole conditions made logging impossible. Both TLC and LWF methods are still in use conditions system. Logging tools, minus the cable, were attached to the end of the drillpipe today, offering the capability to acquire informaand pushed to the bottom of casing. Next, a spe- tion that would otherwise be unobtainable. cially designed connector, attached to the logging However, the process of running in the hole and cable, was pumped down through the inside of logging can be slow. Perhaps more significant, the pipe (above left). A wet-connect device the operator has little control over the tools at latched onto the downhole toolstring to provide the end of the drillpipe during TLC operations. power and communication to the tools. The drill- Drillers must also take precautions to avoid dampipe then pushed the tools into the open hole and aging the exposed logging cable and the tools while running them in the hole. Compared with on to the bottom of the well.

22

Deployment head Multi Express tools

> Carrier conveyed logging. Special logging tools can be conveyed inside a protective carrier and run in hole on drillpipe (left). Once the desired depth is reached, the tools are ejected through the bottom of the drillpipe (right). The tools then acquire data, which are stored in memory, as the drillpipe is pulled out of the hole. At surface, data are read and merged with a depth-time reference log. Conventional depth-based logs are generated from the merged data. The tools must have small diameters to fit inside the carrier; one example, the 21/4-in. Multi Express service provides a triple-combo toolstring plus a sonic tool option. Oilfield Review This carrier conveyance system permits fluid circulation and pipe rotation SUMMER 11 while running into the well and while logging.Fig. 4 Conveyance

ORSUM11-CONVY 4

drillpipe and BHAs, the relatively fragile logging tools can be easily crushed or damaged. Engineers have designed specialized hardware and protective equipment as accessories to protect the tools, but a risk associated with pushing exposed tools through open hole remains.

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Telemetry–Neutron–Gamma Ray Tool Length 3.1 m [10.2 ft], weight 33.1 kg [73 lbm]

Litho-Density Tool Length 3.1 m [10.2 ft], weight 40.8 kg [90 lbm]

Sonic Tool Length 4.3 m [14.4 ft], weight 40.8 kg

Audio-Temperature Tool Length 2.0 m [6.5 ft], weight 20.4 kg [45 lbm]

Spherically Focused Resistivity Tool Length 3.8 m [12.5 ft], weight 30.4 kg [67 lbm]

Induction Resistivity Tool Length 4.9 m [16.0 ft], weight 40.8 kg

> Multi Express platform. The compact, lightweight Multi Express platform offers gamma ray–neutron (thermal and epithermal), Litho-Density, sonic, audio-temperature, spherically focused resistivity and induction resistivity tools. The sonic tool includes a cement bond logging option and the telemetry cartridge includes a casing collar tool.

Even with protective hardware, openhole logging tools may encounter ledges, bridged sections of open hole and large washed-out wellbores, making it impossible to push the tools to bottom. Drillers often attempt pipe rotation to get around obstructions, which is not an option when tools are attached with TLC operations. A recent adaptation of the TLC concept has been developed that uses drillpipe to convey logging tools. The main differences are that the tools are protected inside a carrier while they are being run in the hole and no logging cable is required (previous page, top right). Once the drillstring reaches the logging depth, the field engineer uses an ejection mechanism to deploy battery-powered tools. Extended beneath the bottom of the drillpipe, these tools acquire downhole data, which are stored in memory while the drillpipe is being pulled out of the hole. Pipe movement is recorded versus time during retrieval. At surface, the timebased data from downhole are recovered using a laptop computer and then merged with the depth data from pipe movement to generate conventional depth logs. A logging truck is not required.

Summer 2011

Because they are deployed inside drillpipe, the tools must have a smaller diameter than conventional logging equipment. The recently introduced Multi Express slim, multiconveyance formation evaluation platform is an example of a set of tools that can be deployed using the protective drillpipe carrier. With a 21/4-in. [5.7-cm] diameter, these tools fit inside the 5-in. [12.7-cm] OD carrier with enough clearance to circulate mud Oilfield Review downhole.SUMMER The ability11 to circulate is an important feature forConveyance running drillpipe Fig. 5 into the well, espeORSUM11-CONVY 5 cially in long horizontal openhole sections in which cuttings can accumulate. The Multi Express platform includes induction, Litho-Density, thermal and epithermal neutron porosity and array acoustic tools (above). The induction tool acquires data at two depths of investigation—deep and medium resistivity— and an optional tool section can acquire shallow SFL spherically focused resistivity data. The density tool has an articulated pad and caliper to provide good borehole contact. The compact telemetry–neutron–gamma ray section can

acquire both thermal and epithermal neutron porosity data. It includes a casing collar locator for depth correlation, which can be used with cement bond logging. The sonic tool can be run in openhole mode for borehole-compensated sonic data or in cased hole mode for cement bond logging. While developing this tool platform, engineers focused on minimizing tool length and weight. A triple-combo toolstring—induction, density and neutron tools—consists of three devices of approximately 3 m [10 ft] each and is 9.75 m [32 ft] long when fully assembled. The 4.3-m [14.4-ft] sonic tool can be included as well. The Multi Express family of tools was designed to be handled by one person; the heaviest tool weighs 40.8 kg [90 lbm]. The Multi Express tools are ideal for logging small wellbores, shallow wells and air-filled holes. The platform includes the tools mentioned above plus an audio-temperature tool, which supplies important measurements in coalbed methane and shallow air-drilled tight gas wells. These

23

types of wells can be difficult to evaluate with conventional logging units because the wells have small drilling pads and the rigs move quickly from wellsite to wellsite. Logging engineers can access wells for both openhole logging and cement bond logging using fit-for-purpose logging trucks with integrated masts, such as the Blue Streak high-efficiency unit (left). Drilling and workover rigs are not required when engineers use these small, self-contained logging units. Monocables—logging cables with a single conductor—are generally used instead of multiconductor cables that are common with conventional logging tool systems. With the memory recording option, the Multi Express tools can also be run with cables that have no conductor. This adds the capability of using slickline units for openhole logging, although there is no surface readout using this method. Data acquisition and quality are confirmed after the tools have returned to the surface and the stored information is retrieved. > Fit-for-purpose conveyance. The Blue Streak logging truck is a self-contained unit with its own mast, cable and acquisition system. Conventional openhole logging units commonly use large cables with multiple conductors to provide power, control downhole tools and acquire logging data. The Multi Express tools can be run with a smaller monoconductor cable, which allows a smaller winch and spool. The memory logging mode of the Multi Express tools, utilized with the drillpipe-carrier method, can also be used with slickline units (inset), allowing logging without the need for surface-supplied power.

Oilfield Review SUMMER 11 Conveyance Fig. 6 ORSUM11-CONVY 6 Control cabin

Injector head

Tubing reel

Power pack

> Coiled tubing unit. A CT unit is made up of four basic components: a reel to store and transport the coiled tubing (diameter ranging from 1 in. to 3.25 in.), an injector head designed to drive the CT downhole and retrieve it from the well, a control cabin and a power pack. The tubing may include a monoconductor cable for wireline logging and perforating.

24

Smart Iron Conveyance at the end of pipe is not limited to LWD and TLC operations; pipe-conveyed methods include coiled tubing (CT) logging (below left). This proven system of tool deployment, introduced in the mid-1980s, is often used for production logging (PL) and perforating. CT units may include a cable inside the tubing to provide power to downhole tools and relay real-time measurements to the surface. In the absence of an integrated wire, logging can be performed in memory mode using tools that store data for retrieval once they return to the surface. Perforating, as with conventional tubingconveyed perforating (TCP) operations, can be initiated with surface-applied pressure to activate guns, but the integrated wire gives greater control and offers engineers the option of sending power from surface to fire guns sequentially. A major limiting factor in using CT is that it ceases to make progress, or locks up, beyond about 900 m [3,000 ft] of horizontal section. Lockup occurs because the tubing assumes a helical shape as it comes off the reel, resulting in increased friction between the casing and the tubing. When frictional forces reach a critical point, more tubing can be injected into the well, but the end of the string cannot be pushed deeper into the wellbore. Several options can be employed to extend this limit: CT straighteners reduce residual bend and friction, filling the tubing with nitrogen can provide added buoyancy, friction reducers may extend length capability

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and larger diameter tubing can often go deeper but requires much larger surface equipment.6 ExxonMobil, in developing the Sakhalin Island land-based offshore Chayvo field in Russia, tested a hydraulically actuated CT tractor to extend the reach of operations.7 The field is located offshore, but drilling and production facilities are located on land. To access their wells, ExxonMobil engineers needed to increase the CT range beyond that possible with existing hardware. Although much of the equipment was standard for CT units, engineers made several modifications to accommodate a 35,006-ft [10,670-m] reel of 2 3/8-in. OD coiled tubing. This hydraulic CT tractor was powered and controlled by differential pressure between the tubing and the annulus. The assembly was tested prior to job commencement and had 9,700 lbm [43,148 kg] of pull and nominal operating speed of 950 ft/h [290 m/h]. During the job, a 31,938-ft [9,735-m] well was successfully logged with PL tools and 1,050 ft [320 m] was perforated with 3 3/8-in. [8.57-cm] casing guns.8 Although the operation was a success, engineers discovered that using coiled tubing for frequent PL runs was not viable. Excessive wear experienced by the coil, high cost and poor data quality at low flow rates led to the eventual abandonment of the CT technique for PL logging in the field.9 For routine operations, the industry needed an alternative to logging with a CT unit. Going Around the Bend In 1988, Elf Aquitane made one of the first recorded attempts to log a cased horizontal well with PL tools.10 The operator was developing the Rospo Mare pilot project offshore Italy to produce viscous oil trapped in a karst formation. The company drilled three pilot wells: a vertical, a high-angle deviated and a horizontal well. The vertical and deviated wells penetrated approximately 30 m [100 ft] of formation. The horizontal contacted more than 600 m [1,970 ft] of the reservoir. The surprisingly high productivity obtained in the horizontal well compared with that in the conventional wells led to a pressing need to discover the drainage mechanism. A proper understanding of the production profile would greatly impact future development plans for the field. Elf engineers, in conjunction with field operations staff from Schlumberger, designed an elaborate method to run a PL tool across the producing interval and generate a flow profile. A dual-tubing completion string was installed to allow fluid circulation in one string and to produce the well through the other. The PL tools

Summer 2011

Pumpdown Return side side

Tubing string

Cable Tubing string

Casing Casing shoe

Swab cup

Centralizers

Stinger

7-in. slotted liner

PL tool

> Horizontal production logging. A production log (PL) can provide a flow profile of horizontal wells and identify producing zones. But, in the 1980s, getting tools to TD in a horizontal well was a problem. One early scheme used a dual completion to circulate and flow the well through one string. The other string was used to pump tools down to the bottom of the well. A stiff stinger was attached to the tool and fluid pressure was applied to the swab cups at the top of the stinger to provide locomotion. Although the necessary data were acquired, this type of operation is not feasible in most wells. (Adapted from Joly et al, reference 10.)

were attached to a stiff upper section—a flexibility, efficiency and cost savings to cased stinger—outfitted with swab cups for locomotion hole evaluation and intervention in horizontal (above). Pressure applied to the top of the stinger wells. Within 10 years of Elf’s pumpdown logging forced the tool out the bottom of the tubing until experiment, operators were routinely using tracit reached the end of the horizontal section. A tors for the majority of their well interventions in 600-m [1,970-ft] stinger was necessary to ensure horizontal and high-angle wells.11 the PL tool reached TD while the top of the   6. AL-Amer AA, AL-Dossary BA, AL-Furaidan YA and Hashem MK: “Tractoring—A New Era in Horizontal stinger remained inside the tubing. After a trial Logging for Ghawar Field, Saudi Arabia,” paper SPE run in an onshore horizontal test well, the tech93260, presented at the 14th SPE Middle East Oil Review and Gas Show and Conference, Manama, Bahrain, nique was successfully applied toOilfield Elf’s offshore SUMMER 11 March 12–15, 2005. well and provided essential information for furConveyance Fig. 8  7. Moore NB, Krueger E, Bloom D, Mock PW and Veselka A: ther field development. ORSUM11-CONVY 8“Delivering Perforation Strings in Extended-Reach Wells With Coiled Tubing and Hydraulic Tractor,” paper SPE The complex nature of the design required to 94208, presented at the SPE/ICoTA Coiled Tubing run the PL tool underscores the challenges of Conference and Exhibition, The Woodlands, Texas, USA, April 12–13, 2005. evaluating, completing and performing remediation of wells with horizontal and high-angle tra-   8. Moore et al, reference 7.   9. Fitz DE, Guzmán-Garcia A, Sunder R, Billingham M and jectories. Few operators have the luxury of Smolensky V: “Pushing the Envelope for Production Logging in Extended Reach Horizontal Wells in Chayvo running dual tubing strings just to acquire proField, Sakhalin, Russia—New Conveyance and Flow duction logs, but in the late 1980s there were not Profiling Approach,” paper SPE 103589, presented at the SPE Russian Oil and Gas Technical Conference and many alternatives. Exhibition, Moscow, October 3–6, 2006. This dearth of options for accessing horizon- 10. Joly EL, Dormigny AM, Catala GN, Pincon FP and Louis AJP: “New Production Logging Technique for tal wells was first addressed with the introducHorizontal Wells,” paper SPE 14463, presented at the tion of wired CT units. As ExxonMobil discovered SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, USA, September 22–25, 1985. in the Chayvo field, PL logging on coiled tubing can be expensive, and data quality can suffer. 11. Hallundbæk J, Haukvik J, Østvang K and Skeie T: “Wireline Well Tractor: Case Histories,” paper OTC 8535, Downhole wireline tractors, developed in the presented at the Offshore Technology Conference, Houston, May 5–8, 1997. 1990s, provided an alternative to CT units, adding

25

Continuous Drive Wheels

Tracks

Reciprocating Drive Corkscrew

Hydraulic

Mechanical

> Tractor types. Service companies have developed many different topologies for downhole tractors. Continuous drive units (left) have wheels, tracks and even corkscrew drives. Reciprocating units (right) use locking devices and imitate an inchworm’s motion with an anchor, extend, release and re-anchor movement.

Pulling a Rope Although earlier attempts were recorded, downhole tractors successfully arrived in the oil field in the mid-1990s. In 1996, a device to access horizontal boreholes performed the first tractor service on a well in Norway.12 Developed to perform

well interventions without the high cost associated with CT services, downhole tractors dramatically changed the way North Sea operators planned and managed their fields.13 Prior to 1996, interventions had been performed almost exclusively by CT units. By 2009,

approximately 80% of the interventions performed by one operator had shifted to wireline tractors.14 Not only did this reduce costs, it expanded both the frequency and scope of interventions.

> Climbing the borehole. Engineers designed the reciprocating, gripping mechanism of the MaxTRAC tractor based on rock-climbing gear. The cams located on the extended arms (inset) rotate into position and grip the inside of the casing or borehole. Once the cams are securely locked, the tractor can move forward, but backward movement is nearly impossible.

26

Oilfield Review

Rear anchor locked

Forward anchor free

Tool moving forward

As tool moves forward, front anchor moves into position.

Anchor free

Anchor locked

Tool moving forward

Rear anchor moves into forward position.

Anchor locked, cycle repeats

> Inchworm movement. The MaxTRAC reciprocating system uses a minimum of two synchronized tractor sections, but up to four sections can be combined. Locomotion is achieved when the rear gripping section locks (red) and pushes the tool forward until it is fully extended as the forward anchor, which is free (black), moves into position and locks in place (red). The rear anchor then releases and the front section pulls the assembly forward. After the tractor advances, the rear section again locks in place, and the toolstring is pushed forward. These actions are repeated until the tool reaches TD or the desired depth.

Service companies offer a variety of downhole tractors. They include tractors with rotating wheels, motorized tracks and corkscrew designs (previous page, top). In a departure from these systems, Schlumberger engineers developed a reciprocating gripping mechanism for the MaxTRAC downhole well tractor system (previous page, bottom). This 2 1/8-in. [5.4-cm] diameter tool has a maximum pull of approximately 4,448 N [1,000 lbf] while exerting 13,335 N [3,000 lbf] maximum force on the casing or borehole wall. It can advance at 670 m/h [2,200 ft/h] while pulling 2,224 N [500 lbf] and operates in hole sizes that

Summer 2011

range from 2.44 in. [6.20 cm] to 11.3 in [28.7 cm]. It has the ability to log in forward direction or, with some specific limitations, in reverse while being retrieved by wireline. The reciprocating grip system uses cams to grip the inside of the casing or borehole. This Oilfield Review design is similarSUMMER to devices 11 used to secure ropes during rock climbing: Once the cam11is in position, Conveyance Fig. ORSUM11-CONVY 11lock more backward pull causes it to expand and securely in place. It can easily be pushed forward, but it is almost impossible to pull backward. The tractor requires at least two gripping sections,

but more can be added as needed. With each power stroke, the tool moves forward in inchworm fashion (above). The MaxTRAC tractor has been deployed in a number of openhole and cased hole applications and, with the TuffTRAC cased hole services tractor, holds a number of 12. Hallundbæk J: “Well Tractors for Highly Deviated and Horizontal Wells,” paper SPE 28871, presented at the SPE European Petroleum Conference, London, October 25–27, 1994. 13. Schwanitz B and Henriques K: “The Development of Wireline-Tractor Technology,” The Way Ahead 5, no. 2 (2009): 18–20. 14. Schwanitz and Henriques, reference 13.

27

World’s longest openhole tractor pass

4,238 m (13,904 ft) Two descents for a total of 8,476 m (27,808 ft)

World’s deepest PL on tractor

8,650 m (28,380 ft)

Most cumulative distance traversed using a tractor in a single well

85,987 m (282,109 ft)

> MaxTRAC-TuffTRAC records.

operational records (above). Should the tool ever lose power, the arms with the gripping cams automatically return to a retracted position for ease of tool retrieval.

Loss of power to the tool is not the only concern when engineers design a tractor job. With continuous forward motion, the equipment can eventually reach a point that exceeds the capability of the logging unit to retrieve the tool using the cable. To ensure successful return to surface, the field engineer can model the downhole forces with job-planner software (below). Using information that includes deviation, pushing force, friction and job variations, modeling software provides a go–no-go determination (next page, top right). The planner also determines the number of drive sections needed and helps establish the weakpoint for cable release in the event the tool becomes stuck downhole. The field engineer can fine-tune the model with real-time data.

Cable Tension at Surface

Dogleg Severity as a Function of Measured Depth

Maximum safe pull on cable Dogleg severity Wellbore deviation

60

40 2 20

0

0 0

40

20

0

0 0

10,000

10,000

Depth, ft

Oilfield Review Tractor Force SUMMER 11 Conveyance Fig. Table 2 Maximum force available from tractor ORSUM11-CONVY Table 2

Pseudo-3D Well Profile Projections 0

80

60 500

40

20

5,000 0

10,000

TVD, ft

Tractor force Wellbore deviation

Wellbore deviation, degree

5,000

0

t

5,000 0

0 0

Ea

st, f

Tractor force required to go down, lbf

60

2,000

Depth, ft

1,000

80

Cable tension, retrieving Wellbore deviation Cable tension, moving forward

4,000

Tension, lbf

4

Wellbore deviation, degree

80

Wellbore deviation, degree

6

Dogleg severity, degree/100 ft

Although downhole tractors were originally developed for cased hole intervention, operators have used the MaxTRAC tractor system to run a variety of openhole services. For instance, the FMI tool is often combined with the tractor system for fracture identification. Horizontal wells drilled through fractured reservoirs are difficult to evaluate with LWD services alone because of the high data density required for imaging the factures. The FMI tool can help identify the optimal intervals for production along the horizontal section. The MaxTRAC tractor has also been used in openhole completions to deploy PL tools and to deploy Multi Express tools in both open and cased wells.

10,000 10,000

10,000

Depth, ft

–5,000

0

5,000

North, ft

> Prejob planning. From well data, tractor job planner software provides operational limitations and critical go–no-go analysis before the job commences. The planner can then be updated with downhole data while the tractor is operating. The well profile data (top left) includes deviation and dogleg severity— a measure of how rapidly the wellbore trajectory is changing per unit of distance. Modeled cable tension at the surface indicates whether tension will exceed safe operation limits (top right). The forces acting on the tractor are also modeled (bottom left) to ensure the limitations of the tractor are not exceeded. A pseudo-3D profile, created from client-provided deviation and inclination data, helps visualize borehole geometry (bottom right). The wellbore path (red) is presented versus TVD (blue), surface location (magenta) and north departure (green).

28

Oilfield Review

15. AL-Amer et al, reference 6. 16. AL-Amer et al, reference 6. 17. AL-Amer et al, reference 6. 18. Hashem MK, Al-Dossari SM, Seifert D, Hassaan M and Foubert B: “An Innovative Tractor Design for Logging Openhole Soft Formation Horizontal Wells,” paper SPE 111347, presented at the SPE North Africa Conference and Exhibition, Marrakech, Morocco, March 12–14, 2008.

Summer 2011

Maximum safe pull on cable Well deviation Force to go forward Force to retrieve

Break weakpoint

80

5,000

60

40

20

Wellbore deviation, degree

10,000

Tension, lbf

Tackling a Giant Saudi Aramco has been instrumental in developing tractor technology.15 For the Ghawar field, the largest onshore oil field in the world, engineers have increasingly turned to horizontal, extendedreach and multilateral wellbores as part of the ongoing development program. The expense of using CT units, as well as the difficulty of accessing complex completion geometries for conveying diagnostic and surveillance tools, has led Aramco to investigate alternatives.16 Aramco, which extensively tested various downhole tractors, views them as an enabling technology for intervention services. The company has determined that tractors can effectively log horizontal wells, far exceed the reach of conventional CT units, provide significant cost benefit and offer safer operations compared with complex CT mobilization and deployment.17 However, Aramco’s earlier experience with openhole logging, starting in 2004, was not as positive as with cased hole tractor operations. Aramco and Schlumberger engineers determined that the cams used with the MaxTRAC system could successfully grip in formations with unconfined compressive strength (UCS) greater than 5,000 psi [34.5 MPa]. Below that cutoff, the cams would dig into the formation and lose gripping force. Engineers working with field operations staff developed an add-on kit to distribute the force more uniformly, which maximized the gripping force in soft formations (below right).18 The newly designed gripping assembly was first tested in a 61/8-in. wellbore completion in a formation with a high UCS. A 5,072-ft [1,546-m] horizontal openhole section was successfully logged with a PL toolstring. Eight more openhole wells in high UCS formations were successfully logged before engineers attempted operations in a soft formation. The soft formation candidate, with a 7,553-ft [2,300-m] lateral section, was then logged with PL tools to determine oil entry points and establish a flow profile along the lateral section. The job was successfully completed and the well evaluated using the new design.

0

0 0

1,000

2,000

Depth, m

> Critical decisions. In this plot from the job planner, the MaxTRAC tractor can travel forward with tensions (red curve) that are well below the maximum safe pull (dashed green line). However, the cable tension while retrieving the tool (purple curve) approaches unsafe conditions beyond about 2,000 m [6,560 ft]. Should the tool exceed the maximum safe pull limit, it may not be possible to break the weakpoint and release the cable from the tool should the tool become stuck. The alternative is to not advance all the way to TD but to keep the tension within the safe operating margin. The software provides a high and low range for modeled tensions based on data uncertainty, and downhole data can be used to improve the model as the tool approaches the critical safety point.

Openhole tractors are not suitable for every well, particularly those with long washed-out sections or irregularly shaped boreholes. However, Aramco determined that the use of openhole tractors can deliver significant cost savings over conventional CT logging. Tractors have a much

longer reach than CT units and require fewer personnel and less hardware on location. Today, openhole tractors are in use not only in Saudi Arabia but also in several other locations in the Middle East.

Oilfield Review SUMMER 11 Conveyance Fig. 13 ORSUM11-CONVY 13 Wedge

Gripping action Formation Saddle

Grip geometry locked

Bow springs Direction of grip motion

> Openhole tractor logging. The MaxTRAC tractor gripping mechanism lost traction in soft formations. Saudi Aramco and Schlumberger engineers collaborated on an improved design that could deploy openhole logging tools. An added bowspring with a saddle and wedge (inset) distributed the gripping force more evenly; the tractor was able to successfully navigate in wells with formations that had UCS less than 5,000 psi.

29

Pickup Truck

TuffTRAC (8 drives)

Weight of unit

2,560 kg [5,645 lbm]

277 kg [610 lbm]

Additional radial force

0

4,448 N [1,000 lbf] per wheel

Weight per wheel

640 kg [1,411 lbm]

522 kg [1,152 lbm]

Size of wheel

76 cm [~30 in.]

7.6 cm [3 in.]

Towing capacity

44,927 N [10,100 lbf]

106,757 N [24,000 lbf]

Towing force

4,448 N [~1,000 lbf]

10,676 N [2,400 lbf]

> TuffTRAC pulling power. The TuffTRAC tractor can use up to eight drive wheels (right). In the maximum pull configuration, it has 106,757 N [24,000 lbf] of pulling capacity. For comparison, the pickup truck shown has a towing capacity of 44,927 N [10,100 lbf].

When the Going Gets Tough Logging is not the only operation that takes place in horizontal wells. Initial completion operations often use drilling or workover rigs to run TCP guns, which can traverse extremely long intervals. However, after the rig has moved on, remedial perforating in horizontal wells can be difficult to perform. CT units are an option for this task but they have depth limitations. Tractor

tools have been used to run and position perforating guns, but the shock that the downhole equipment can receive—up to 20,000 gn—can damage sensitive electronic and mechanical components. Recognizing the need for a more robust tractor for perforating services, Schlumberger engineers designed the TuffTRAC cased hole services tractor. Tool movement is accomplished using

Oilfield Review SUMMER 11 Conveyance Fig. 15 ORSUM11-CONVY 15 > Qualification testing. The TuffTRAC tractor was designed to withstand the rigors of perforating. The tool was attached to loaded casing guns, which were fired at the surface, shown here, without significant damage to the tool. The design-for-purpose and qualification testing resulted in a robust system that has been proved in the field.

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mechanically powered wheels (above). The TuffTRAC tool is bigger and stronger than the MaxTRAC tractor and has a much simpler design; it has minimal downhole electronics. Maximum running speed is 975 m/h [3,200 ft/h] and maximum pulling force is 10,676 N [2,400 lbf]. It is designed primarily for perforating and cement evaluation. The TuffTRAC system also offers traction control, which dynamically adjusts the gripping force while the tractor is in forward motion. The TuffTRAC equipment is currently the only tractor qualified for perforating that can reverse out of the well. This has proved beneficial in horizontal well sections where guns were trapped by debris in the wellbore. On at least one occasion, surface-applied tension was not sufficient to free the guns because the high angle of the well prohibited pulling force from being transmitted to the tools. By moving in reverse, the tractor was able to free the guns, which were then retrieved without a costly fishing operation. Although perforating can damage electronics and mechanical components, the TuffTRAC service has demonstrated that properly engineered solutions can mitigate some of the effects of high explosives (left). Tested to extreme limits, this new tractor design has been field qualified. In one North Sea well that had initially been com-

Oilfield Review

100

XX,400

90

XX,600

80

Well profile Phase 2 perforation Phase 1 perforation Inclination, degrees

TVD, m

XX,800 XY,000 XY,200

70 60 50

XY,400

40

XY,600

30

XY,800

XX,000

XX,250

XX,500

XX,750

XY,000

XY,250

XY,500

XY,750

Inclination, degree

XX,200

20

MD, m

> Well profile for North Sea injector. The operator perforated this well in two stages. Together the stages covered approximately 1,250 m. Holes were spaced approximately 7 m apart across the intervals. A total of 180 shots were attempted. Only one shot failed to fire. During the course of 12 descents, the tractor tool traversed 8,670 m.

pleted as a commingled oil producer from two separate zones, only water was being produced. Engineers ran the TuffTRAC system to set two plugs, ran 73.1 m [240 ft] of 2 7/8-in. high shot density guns in four runs and made six trips to retrofit sand screens. For this single intervention, the tractor traversed 22,500 m [73,819 ft] without incident. The procedures resulted in resumption of oil production without a costly workover and recompletion. In another North Sea horizontal well, an operator needed to perforate approximately 1,250 m [4,100 ft] of reservoir section for a water injection project. One objective was to achieve a particular perforation hole size in heavy-wall 6 5/8-in. liner with one shot every 7 m [23 ft]. The plan called for perforating in two phases across separate intervals (above). The two phases included 90 holes per interval for a total of 180 shots. Because of logistics and cost, it would have been difficult to justify perforating with TCP guns using a CT unit—180 shots would have required at least 1,250 m [4,101 ft] of gun stock. For limited-entry perforation operations such as this, engineers at Schlumberger Rosharon Completions Center (SRC), in Texas, USA, have developed an addressable-switch perforating system that uses radio-safe detonators and allows up to 40 singleshot carriers to be run in a single descent. The system requires surface power to communicate with and detonate each shot. Because the TuffTRAC tractor is combinable with the addressable-switch system, field engineers were able to

Summer 2011

run as many as 20 single-shot carriers per descent to perforate the Phase 1 interval and as many as 33 single-shot guns for the Phase 2 interval. During the execution of the job, the tractor traversed a total of 8,670 m [28,450 ft] in the course of 12 descents. Although CT perforating was an option, using more than 1,250 m of gun stock to perforate 180 holes was neither cost-effective nor an efficient use of resources. Another option would have been multiple runs—perhaps as many as 60—with a conventional switched-gun system. The application of this new technology greatly reduced the Oilfield Review number of runs, equipment SUMMER 11 wear and the time on location for personnel. Conveyance Fig. 17

ORSUM11-CONVY 17

Change Brings Opportunity Game-changing technology often creates a bridge to better methods of operation and offers a wider range of choices. For instance, in many developing countries, telephone service providers are investing in cellular phone systems rather than traditional landline infrastructures. The benefits to consumers include smart phones and wireless internet access, which go far beyond eliminating the inconvenience of being tied to a telephone cord. In a similar fashion, LWD tools have changed the way operators approach drilling. Memory logging has changed the way data acquisition is carried out while simultaneously offering a broader range of opportunities. In the near future, wired drillpipe promises to provide even greater opportunities.

Wireless downhole communication may become more readily available to the oil and gas industry, and there are already commercial systems that communicate with downhole tools via radio waves. Depth and data limitations for wireless systems exist at present, but controlling downhole devices and receiving data without the use of cables and wires open new possibilities and applications for operators and service companies. LWD tools, coiled tubing and downhole tractors create opportunities in drilling, completions and production that previously did not exist. The oil and gas service industry continues to develop new methods that reduce costs, decrease equipment requirements and minimize the number of personnel on location. As conveyance techniques evolve, they introduce opportunities to improve production and, in general, function more efficiently than earlier methods. If you can’t push a rope, you may be able to pull it. Or perhaps, in the future, it may be easier just to cut the rope completely. —TS

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Basic Petroleum Geochemistry for Source Rock Evaluation

As the search for oil and gas prospects grows increasingly complex, more E&P companies are turning to geochemistry to evaluate a component that is central to the success of each well: the source rock.

Kevin McCarthy Katherine Rojas Houston, Texas, USA Martin Niemann Roissy-en-France, France Daniel Palmowski Aachen, Germany Kenneth Peters Mill Valley, California, USA

Every oil or gas play originates from source rock. The viability of each play—conventional or unconventional, oil or gas—depends on its source rock. Without this source of petroleum, all other components and processes needed to exploit a play become irrelevant. A source rock can be broadly defined as any fine-grained, organic-rich rock that is capable of generating petroleum, given sufficient exposure to heat and pressure. Its petroleum-generating potential is directly related to its volume, organic

richness and thermal maturity.1 Although its volume—a function of thickness and areal extent—must not be discounted, this article focuses on the other two characteristics. Organic richness refers to the amount and type of organic matter contained within the rock. Thermal maturity refers to a source rock’s exposure to heat over time. Heat increases as the rock is buried deeper beneath successive layers of sediment. It is the thermal transformation of organic matter that causes a source rock to generate petroleum.

Artur Stankiewicz Clamart, France Oilfield Review Summer 2011: 23, no. 2. Copyright © 2011 Schlumberger. For help in preparation of this article, thanks to Nicholas Drenzek, Cambridge, Massachusetts, USA. FLAIR is a mark of Schlumberger. Rock-Eval is a mark of the Institut Français du Pétrole. Rock-Eval 6 is a mark of Vinci Technologies SA. 1. In this article, the term “petroleum” refers not only to crude oil, but also to the fluid in either its liquid or gaseous state. Also, the term “hydrocarbons,” which tends to be used casually in the oil industry, will be treated as a loose equivalent to “petroleum.” 2. Kerogen is the particulate organic matter disseminated within sedimentary rocks that is insoluble in common organic solvents. Bitumen is a thermally degraded derivative of kerogen, but is soluble in organic solvents. The exact relationship between kerogen, bitumen and the hydrocarbons that evolve during heating of organic matter is still a subject of investigation. For more on these components: Peters KE, Walters CC and Moldowan JM: The Biomarker Guide, 2nd edition. Cambridge, England: Cambridge University Press, 2005. 3. Magoon LB and Dow WG (eds): The Petroleum System— From Source to Trap. Tulsa: The American Association of Petroleum Geologists, AAPG Memoir 60, 1994.

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Vertical drilling

Vertical drilling Extended-reach drilling

Coalbed methane

Nonassociated gas Associated gas Seal Conventional structural trap

Sandstone reservoir

Oil

Gas in tight sand Shale source rock

Conventional stratigraphic trap

> Petroleum systems. A conventional petroleum system requires four components: source rock, reservoir rock, trap and seal—and two processes: petroleum generation and migration. Timing between petroleum migration and creation of the reservoir, trap and seal is also critical. Unconventional systems require, at a minimum, the deposition of source rock and sufficient overburden to achieve thermal maturity.

Oilfield Review

The mechanisms by which oil and gas are generated vary from basin to basin depending on sedimentary facies, burial history, tectonics and other geologic processes; however, the general model is fairly straightforward. Following deposition of organic-rich sediments, microbial processes convert some of the organic matter into biogenic methane gas. Greater depths of burial are accompanied by increases in heat in accordance with the basin’s geothermal gradient. This heat causes the organic matter to gradually transform into an insoluble organic matter known as kerogen. The kerogen continues its

Summer 2011

alteration as heat increases; these changes, in turn, result in an evolution of the petroleum compounds that are subsequently generated. Further heating converts the kerogen, yielding bitumen and petroleum.2 The kerogen becomes more depleted of hydrogen as it gives off petroleum. Increasing maturity also causes initially complex petroleum compounds to undergo structural simplification—typically starting with oil, then wet gas and ending at dry gas.

This basic model is integral to one of the most fundamental concepts of oil and gas exploration: the petroleum system.3 This concept accounts for the generation, expulsion, migration and accumulation of oil and gas—and source rock lies at its foundation (previous page). In conventional petroleum systems, overburden rock buries the source rock to depths where petroleum is generated. Petroleum generated by thermally mature source rock is expelled into a porous and permeable carrier bed and

33

then migrates into a reservoir rock, where it becomes structurally or stratigraphically trapped beneath an impermeable seal.4 However, the requisite processes of petroleum generation, expulsion, migration and trapping are not always carried to completion, as evidenced by the myriad of dry holes drilled into clearly delineated traps. Ongoing advances in production technology are opening new plays to exploration and development. Resource plays, exemplified by the boom in shale gas production, are founded on unconventional petroleum systems, where source rock also serves as reservoir and seal. Petroleum generated in this self-contained petroleum system does not migrate but remains trapped within the micropores and fractures of the low-permeability source rock.5 Oil shales are yet another variation on the resource play; operators who exploit these source rocks must apply heat to produce the oil.6

The world’s remaining oil and gas resources are becoming more challenging to find and develop. As the industry targets these resources, the need to thoroughly understand and characterize all components of prospective petroleum systems becomes more acute. Thus, in addition to assessing the reservoir, trap and seal of their prospects, E&P companies must evaluate the petroleum-generating capacity of the source rock. Petroleum geochemistry is improving the efficiency of exploration and production through characterization of the elements and processes that control the richness and distribution of petroleum source rocks, thus providing valuable input for basin and petroleum system modeling. This article describes basic geochemical principles and techniques used by geoscientists to evaluate source rock quality, quantity and maturity.

Sunlight and oxidation Sea level High concentration of organic matter Dissolved matter Particulate matter Colloidal matter Flocculates to particulates

Sediment

Clays Shells, skeletons

Bottom feeders

> Organic matter in the water column. Organic matter in solution may be adsorbed onto clay particles that sink slowly through the water. Colloidal organic matter flocculates before it settles. Particulate matter may simply drop to the bottom. (Modified from Barker, reference 8.)

4. For more on petroleum systems: Al-Hajeri MM, Al Saeed M, Derks J, Fuchs T, Hantschel T, Kauerauf A, Neumaier M, Schenk O, Swientek O, Tessen N, Welte D, Wygrala B, Kornpihl D and Peters K: “Basin and Petroleum System Modeling,” Oilfield Review 21, no. 2 (Summer 2009): 14–29. 5. It is not unusual for source rocks that are exploited for their shale gas to also be effective sources of conventional hydrocarbons in other parts of the basin. 6. For more on oil shales: Allix P, Burnham A, Fowler T, Herron M, Kleinberg R and Symington B: “Coaxing Oil from Shale,” Oilfield Review 22, no. 4 (Winter 2010/2011): 4–15. 7. Jacobson, SR: “Petroleum Source Rocks and Organic Facies,” in Merrill RK (ed): Source and Migration Processes and Evaluation Techniques. Tulsa: AAPG (1991): 3–11.

34

  8. Barker C: Organic Geochemistry in Petroleum Exploration. Tulsa: American Association of Petroleum Geologists, AAPG Course Note Series no. 10, 1997.   9. Jacobson, reference 7. Eh is a measure of the oxidation-reduction state of a solution; pH is a measure of its acidity or alkalinity. 10. Demaison GJ and Moore GT: “Anoxic Environments and Oil Source Bed Genesis,” AAPG Bulletin 64, no. 8 (August 1980): 1179–1209. 11. Jacobson, reference 7. 12. Palacas JG: “Characteristics of Carbonate Source Rocks of Petroleum,” in Magoon LB (ed): Petroleum Systems of the United States. US Geological Survey Bulletin 1870. Washington, DC: US Government Printing Office (1988): 20–25. 13. Jones RW: “Comparison of Carbonate and Shale Source Rocks,” in Palacas JG (ed): Petroleum Geochemistry and Source Rock Potential of Carbonate Rocks. Tulsa: The American Association of Petroleum Geologists, AAPG Studies in Geology 18 (1984): 163–180.

Source Rock Fundamentals Source rocks result from a convergence of physical, biochemical and geologic processes that culminate in the formation of finegrained sedimentary rocks containing carbonand hydrogen-rich organic matter. The amount and type of organic material incorporated into a source rock are controlled, in part, by environmental and depositional conditions. Source rocks form where environmental conditions support biologic activities that produce large quantities of organic matter, where depositional conditions concentrate this matter and where postdepositional conditions permit its preservation.7 Organic content is controlled largely by biologic productivity, sediment mineralogy and oxygenation of the water column and sediment. Biologic contributions to organic content range from hydrogen-poor woody fragments to hydrogenrich algal or bacterial components. From these, a variety of organic compounds may be created. Within the water column, organic matter may exist in solution, in colloidal form or in particulate form, the highest concentrations of which are found near the water’s surface.8 The route from the water surface to its eventual incorporation into the sediment varies for each form (left). The organic matter is subjected to various chemical and biologic processes as it descends through the water column to the water/sediment interface. Oxygen in the water column supports biologic productivity of organic matter but also promotes biodegradation and oxidation. The matter can also be altered by physical abrasion or chemical changes in water Eh and pH.9 Once this matter settles to the bottom, bacteria, worms and other bottom feeders take in what they can metabolize, converting some of it to simple molecules. The net result of biodegradation and oxidation is a reduction in organic richness, leaving only relatively resistant organic materials to be incorporated into the sediment. 14. Macerals are microscopically recognizable constituents of organic matter found in coals and kerogen, analogous to mineral constituents in a rock. 15. Tissot B, Durand B, Espitalié J and Combaz A: “Influence of Nature and Diagenesis of Organic Matter in Formation of Petroleum,” AAPG Bulletin 58, no. 3 (March 1974): 499–506. 16. Klemme HD and Ulmishek GF: “Effective Petroleum Source Rocks of the World: Stratigraphic Distribution and Controlling Depositional Factors,” AAPG Bulletin 75, no. 12 (December 1991): 1809–1851. 17. Vandenbroucke M: “Kerogen: From Types to Models of Chemical Structure,” Oil & Gas Science and Technology—Revue de l’Institut Français du Pétrole 58, no. 2 (2003): 243–269. 18. Tissot et al, reference 15.

Oilfield Review

Kerogen type

General environment of deposition

Source material

I

Mainly algae

Lacustrine setting

II

Mainly plankton, some contribution from algae

Marine setting

III

Mainly higher plants

Terrestrial setting

IV

Reworked, oxidized material

Varied settings

> Kerogen types. Kerogen can be classified by its source material.

7 cm

> Undisturbed sediments. Fine laminations, or varves, in this core sample denote successive deposits in quiet waters with no disturbance from bottom dwellers.

Within this depositional setting, oxygen and energy levels are perhaps the most critical aspects controlling the concentration and preservation of organic matter in the sediment. Oxygen-depleted, or anoxic, sediments provide the best media for preserving organic matter. Low oxygen levels create a reducing environment that shelters organic material from oxidation while also restricting the activity of bottom feeders. Anoxic conditions are evidenced by source rocks that have minute laminations, or varves (above). These features are indicative of persistent, stagnant anoxic water above the sediment, as well as an absence of bioturbation, thus implying a hostile environment for sediment-churning bottom feeders that graze on organic matter.10 These conditions are also closely linked with low-energy depositional environments. Because quiet waters reduce the exchange of oxygen and organic matter, they create an environment in which anoxic conditions can exist. These low-energy environments permit the deposition of finer-grained sediments as well. Thus, there is a relationship between grain size and organic content in source rocks. Source rocks do not form in high-energy environments—such as beaches or sand bars—where sands are typically

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deposited.11 Wave action oxygenates the deposit and flushes clay-sized materials and small particles of organic material away from the sands then deposits them together in quieter waters. Sands, therefore, generally contain only small amounts of organic matter relative to shales. Mineralogy also plays an integral role in source rock development. Minerals, transported and precipitated in the sediment, can react with organic compounds and ultimately dilute the relative concentration of organic matter within the sediment. This dilution may affect a source rock’s capacity to generate and expel petroleum. Although many organic-rich source rocks are argillaceous, carbonates (typically marls) can also make excellent source rocks and reservoirs. Some carbonates may contain as much as 10% to 30% total organic carbon (TOC), unlike shales, which may contain less than 5%.12 In general, quality source rocks—whether carbonate or shale—share a number of common characteristics. They form in anoxic, or highly reducing, environments, are generally laminated, have moderate to high TOC and contain organic matter exemplified by atomic hydrogen/carbon ratios exceeding 1.2.13 Although deposited under anoxic conditions, these fine-grained, organic-rich sediments are still missing a critical component: thermally mature kerogen. The formation of mature kerogen requires heat. Thermal Transformations Sediment slowly cooks as pressure and temperature increase with burial depth. Given sufficient heat, pressure and time, the sediment lithifies and the organic matter contained within transforms into kerogen. Kerogen can be classified into four types, based on provenance, as indicated by specific macerals (above right).14 It can also be classified on the basis of hydrogen, carbon and oxygen content. Each type has a distinct bearing on what kind of petroleum, if any, will be produced.15

Type I kerogen is generated predominantly from lacustrine environments and, in some cases, marine environments. It is derived from algae, plankton or other matter that has been strongly reworked by bacteria and microorganisms living in the sediment. Rich in hydrogen and low in oxygen, it is oil prone but, depending on its stage of thermal evolution, can also produce gas. Responsible for less than 3% of the world’s oil and gas reserves, Type I kerogens are not common.16 An example of Type I kerogen is found in the Green River Formation of the western USA. Type II kerogen is typically generated in reducing environments found in moderately deep marine settings. It is derived primarily from the remains of plankton that have been reworked by bacteria. Rich in hydrogen and low in carbon, this kerogen can generate oil or gas with progressive heating and maturation.17 Renowned examples of Type II kerogen include the Kimmeridge Clay of the North Sea and the Bazhenov Formation of Siberia. Certain depositional environments promote increased incorporation of sulfur compounds, resulting in a variation known as Type II-S kerogen. This variation is seen in the Monterey Formation of California, or the La Luna Formation of Venezuela. The significance of this type is that generation of oil starts much earlier, thought to be caused by kinetic reactions involving sulfur-bearing compounds. Type III kerogen is derived primarily from terrigenous plant debris, which has been deposited in shallow to deep marine or nonmarine environments. Type III kerogen has lower hydrogen and higher oxygen content than Types I or II; consequently, it tends to generate dry gas. Most coals contain Type III kerogens. Type IV kerogen is derived from residual organic matter found in older sediments that have been reworked after erosion. Prior to final deposition, this kerogen may have been altered by subaerial weathering, combustion or biologic oxidation in swamps or soils. This type of kerogen has high carbon content and is hydrogen poor. Considered a form of dead carbon, Type IV kerogen has almost no potential for generating oil or gas.18

35

Biomarkers

Immature zone Oil window

Diagenesis Catagenesis

Oil

Gas window

Wet gas

Metagenesis

Increasing depth and temperature

Biogenic methane

Dry gas

Hydrocarbons generated

> Thermal transformation of kerogen. The generation of hydrocarbons in source rocks is controlled primarily by temperature as the kerogen content evolves from reactive carbon to dead carbon. Gas is given off during early diagenesis, primarily through biologic activity. Catagenesis takes place with further burial, during which oil and gas are given off. With increasing depth and temperature, any remaining oil is cracked during metagenesis, initially giving off gas, followed by simpler forms of dry gas. The process varies somewhat from one kerogen type to another. (Modified from Tissot et al, reference 15.)

In general, hydrogen-rich kerogens are responsible for generating both oil and hydrocarbon gas; those with lesser amounts of hydrogen will generate mainly hydrocarbon gas. After hydrogen is depleted from the kerogen, generation of hydrocarbons will cease, regardless of the amount of available carbon.19 As temperature and pressure increase during burial, organic materials emit oil and gas. Overall, this thermal maturation process produces a series of progressively smaller hydrocarbon molecules of increasing volatility and hydrogen content, culminating with methane gas. And, as the kerogen evolves through thermal maturity, its chemical composition progressively changes, transforming it into a carbonaceous residue of decreasing hydrogen content.20 The thermal maturation process can be divided into three stages (above). • Initially, the sediment is subjected to diagenesis. In its broadest sense, this term encompasses all natural changes in sediments occurring

36

from the moment of deposition until just before the onset of significant thermal alteration processes.21 For source rocks, however, this stage is characterized by alteration of organic matter, typically at temperatures below about 50°C [122°F].22 During diagenesis, oxidation and other chemical processes begin to break down the material. If deposited under anoxic conditions, this material may be converted by methanogenic bacteria into dry gas.23 With increasing temperatures and changes in pH, the organic matter is gradually converted to kerogen and, in lesser amounts, bitumen. • The source rock matures with increasing heat, and it undergoes catagenesis. During this stage, petroleum is generated as temperature increases to between 50°C and 150°C [122°F and 302°F], causing chemical bonds to break down within the kerogen.24 Within this oil window, Type I and II kerogens produce both oil and gas, while Type III kerogens produce mainly hydrocarbon gas. Further increases in burial depth, temperature and pressure force the source rock into the upper part of the gas window, where secondary cracking of the oil molecules produces wet gas containing methane, ethane, propane and heavier hydrocarbons.25 • Metagenesis marks the final stage, in which additional heat and chemical changes convert much of the kerogen into methane and a carbon residue. As the source rock moves farther into the gas window, late methane, or dry gas, is evolved, along with nonhydrocarbon gases such as carbon dioxide [CO2], nitrogen [N2] and hydrogen sulfide [H2S]. These changes take place at temperatures ranging from about 150°C to 200°C [302°F to 392°F].26 These stages have a direct bearing on source rock maturity. Thermally immature, or potential, source rocks have been altered by diagenesis but have yet to be exposed to sufficient heat for thermally generated petroleum. Thermally mature, or effective, source rocks that are (or were) in the oil window, have been subjected to thermal processes necessary to produce petroleum and are actively generating petroleum. Thermally postmature, or spent, source rocks have entered the gas window and have already generated petroleum; in so doing they have exhausted all hydrogen necessary for further oil or gas generation.27 Although maturation is largely related to increasing burial depths caused by continual sedimentation within a basin, it can also be locally or regionally influenced by heat flow arising from crustal tectonics, proximity to igneous

bodies and natural radioactive decay within the crust. The geologic processes that control subsidence and uplift also affect maturation within a basin. Maturation can be interrupted if the basin is subjected to uplift, only to continue when subsidence resumes. At the depths drilled by E&P companies, the petroleum-generation process is often incomplete, leaving the source rock with a degree of generating potential.28 Thus, rock samples obtained from the subsurface may contain generated hydrocarbons along with organic matter that is reacted incompletely. Some of these reactions can be observed and measured in the laboratory, where pyrolysis of organic matter parallels changes in the subsurface and provides a useful technique to characterize organic matter. Basic Source Rock Analysis Some petroleum compounds within source rock are released at temperatures lower than those needed to break down the kerogen. By monitoring the compounds released during a steady increase in temperature, geochemists can determine the amount of generated petroleum relative to a rock’s total potential. In addition, the temperature corresponding to the maximum evolution of gas gives an indication of source rock maturity. Geoscientists employ a variety of techniques to evaluate the hydrocarbon-generating capacity of source rocks. Geochemical testing of outcrop samples, formation cuttings, sidewall cores and conventional cores can help determine the amount, type and thermal maturity of organic matter present in the rock.29 The results help geoscientists ascertain whether, how much, when and what kind of petroleum might have been generated as well as determine what secondary processes may have occurred following the expulsion of hydrocarbons from the source rock. Carbon is an essential element of any organic compound, and one way to assess the organic richness of a rock is to measure its carbon content.30 Because the oil or gas potential of a formation is related to its carbon content, the TOC measurement is a priority in source rock assessment. This initial carbon assessment is followed by other screening procedures such as pyrolysis and vitrinite reflectance analysis. These tests allow rapid evaluations for large numbers of rock samples and may be supplemented by more extensive test methods. TOC values can be obtained using a directcombustion technique that requires only 1-g [0.0022-lbm] samples of rock.31 The samples are

Oilfield Review

pulverized and treated to remove any carbon found in carbonate samples, or other contaminants. They are then combusted at 1,200°C [2,192°F] using a high-frequency induction furnace. Carbon contained in the kerogen is converted to CO and CO2. The evolved carbon fractions are measured in an infrared cell, converted to TOC and recorded as mass weight percent of rock.32 The TOC measurement assesses three components. Carbon from extractable organic matter (EOM) is derived mostly from the thermal cracking of kerogen. This carbon is found within the oil and gas that the rock has generated but has not yet expelled. At the other extreme is residual carbon, which makes up that portion of kerogen having no oil- or gas-generating potential because its highly condensed chemical structure contains so little hydrogen. Convertible carbon contained within the kerogen represents the remaining petroleum-generating potential of a rock. The capacity to generate petroleum depends largely on the chemical composition of this convertible carbon fraction.33 The TOC measurement is the first screen for quantifying organic richness. TOC values provide only a semiquantitative scale of petroleum-generating potential. TOC indicates the quantity, but not the quality, of the organic matter. If this initial screening test demonstrates sufficient organic content, the rock should undergo additional tests to ascertain organic matter quality and maturity. One of these tests was developed by the Institut Français du Pétrole, whose Rock-Eval pyrolysis analyzer has become an industry standard in source rock assessment.34 A major breakthrough in petroleum geochemistry, this programmed pyrolysis technique subjects rock samples to high temperatures, enabling researchers to obtain results that would have taken millions of years in a sedimentary basin. This technique requires only 100 mg [0.00022 lbm] of pulverized rock and can analyze a sample in a matter of minutes (above right). The latest version of the Rock-Eval apparatus uses both pyrolysis and oxidation ovens to heat samples in a programmed series of stages ranging from 100°C to 850°C [212°F to 1,562°F].35 Sample analyses are automated, and results are computed before they are tabulated and output to a log. During Rock-Eval pyrolysis, samples are heated under an inert atmosphere of helium or nitrogen. A flame ionization detector (FID) senses organic compounds emitted during each stage of heating. Sensitive infrared (IR) detectors

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> Pyrolyzer. This Rock-Eval 6 pyrolysis analyzer records gases evolved from the source rock during a programmed heating process. (Photograph courtesy of Vinci Technologies SA.)

19. Baskin DK: “Atomic H/C Ratio of Kerogen as an Estimate of Thermal Maturity and Organic Matter Conversion,” AAPG Bulletin 81, no. 9 (September 1997): 1437–1450. 20. Hood A, Gutjahr CCM and Heacock RL: “Organic Metamorphism and the Generation of Petroleum,” AAPG Bulletin 59, no. 6 (June 1975): 986–996. 21. For more on diagenesis: Ali SA, Clark WJ, Moore WR and Dribus JR: “Diagenesis and Reservoir Quality,” Oilfield Review 22, no. 2 (Summer 2010): 14–27. 22. Peters et al, reference 2. 23. Rice DD and Claypool GE: “Generation, Accumulation, and Resource Potential of Biogenic Gas,” AAPG Bulletin 65, no. 1 (January 1981): 5–25. 24. Peters et al, reference 2. 25. Cracking is a process in which high temperature and pressure act upon large, heavy hydrocarbon molecules, causing them to split into smaller, lighter components. Under such conditions, oil can be transformed into a gas. 26. Peters et al, reference 2. 27. Peters KE and Cassa MR: “Applied Source Rock Geochemistry,” in Magoon LB and Dow WG (eds): The Petroleum System—From Source to Trap. Tulsa: The American Association of Petroleum Geologists, AAPG Memoir 60 (1994): 93–120. 28. Barker C: “Pyrolysis Techniques for Source-Rock Evaluation,” AAPG Bulletin 58, no. 11 (November 1974): 2349–2361. 29. Fresh cores work best; outcrop samples tend to be degraded through weathering and are less desirable.

30. By definition, organic compounds are those that contain carbon (with the exception of carbides, carbonic acid, carbonates, carbon oxides and cyanides). Within the realm of geochemistry, carbon is divided into a number of classes. Geochemists define organic carbon as that which is derived from biogenic matter, whereas inorganic carbon is derived from mineral matter. For more on the organic carbon model: Jarvie DM: “Total Organic Carbon (TOC) Analysis,” in Merrill RK (ed): Source and Migration Processes and Evaluation Techniques. Tulsa: AAPG (1991): 113–118. 31. For a description of other techniques used for measuring TOC, see Appendix C of Peters and Cassa, reference 27. 32. A TOC of 1% means there is 1 gram of organic carbon in 100 grams of rock. 33. Jarvie, reference 30. 34. Pyrolysis involves heating of organic matter in the absence of oxygen. In this application, pyrolysis causes hydrocarbons to crack into simpler, lighter compounds. For more on this technique: Espitalié J, Madec M, Tissot B, Mennig JJ and Leplat P: “Source Rock Characterization Method for Petroleum Exploration,” paper OTC 2935, presented at the Ninth Annual Offshore Technology Conference, Houston, May 2–5, 1977. 35. Other variations on this method use different temperature ranges and heating times. For more on the Rock-Eval 6 technique: Lafargue E, Espitalié J, Marquis F and Pillot D: “Rock-Eval 6 Applications in Hydrocarbon Exploration, Production and in Soil Contamination Studies,” Oil & Gas Science and Technology—Revue de l’Institut Français du Pétrole 53, no. 4 (July–August 1998): 421–437.

37

FID and IR signals

Pyrolyzable carbon Vaporization Pyrolysis decomposition

Residual carbon

Mineral carbon

Oxidation

Carbonate decomposition

S5

Tmax S2 S3MINC S4CO2

S3CO2 S1 300

300

389

S3CO 472 556

Hydrocarbons (FID)

S4CO 405 472 538 Temperature, °C

639 CO2 (IR)

605

672

CO (IR)

738

805

851

850

Temperature programming

> Programmed pyrolysis results. Free hydrocarbons are measured by the S1 peak, and residual hydrocarbons are measured by the S2 peak. Tmax of 472°C [882°F] corresponds to the temperature recorded when the S2 peak was achieved. CO, CO2 and mineral carbon components of the S3 measurement are also displayed. CO2 is proportional to the amount of oxygen present in organic matter and provides input for calculating an important index used in determining maturity and kerogen type. Pyrolysis results are computed to determine amounts of pyrolyzable carbon, residual carbon, mineral carbon and TOC. (Illustration courtesy of Vinci Technologies SA.)

measure CO and CO2 during pyrolysis and oxidation. A thermocouple monitors temperatures. These measurements are recorded on a chart known as a pyrogram (above). The results help geochemists characterize the type of organic matter in a source rock and determine the thermal evolution of a sample and its residual hydrocarbon-generating potential.36

Source rock quality

TOC, %

Rock samples are heated in stages, initially held at a constant 300°C [572°F] for several minutes, followed by programmed heating at 25°C [45°F] per minute to a peak temperature of about 850°C [1,562°F]. During the first stage, any free oil and gas previously generated by the bitumen are distilled and released from the rock. During the next stage, hydrocarbon compounds

Pyrolysis S2, mg hydrocarbons/g rock

EOM weight, %

Hydrocarbons, ppm

None

< 0.5

0.2

> 1,200

Very good

>5

> 10

Product type

Hydrogen index

Stage

Tmax

Gas

50 to 200

Onset of oil

Gas and oil

200 to 300

Type I kerogen

~445°C

Oil

> 300

Type II kerogen

~435°C

Type III kerogen

~440°C

Onset of gas

~460°C

are generated through thermal cracking of the insoluble kerogen. As temperatures rise, the kerogen releases CO2 in addition to hydrocarbons.37 This controlled heating program is illustrated by a series of peaks on the pyrogram.38 The first peak, S1, corresponds to free oil and gas that evolve from the rock sample without cracking the kerogen during the first stage of heating at 300°C. These hydrocarbons were generated in the subsurface but came to be expelled from the rock only during pyrolysis. S1 represents how many milligrams of free hydrocarbons can be thermally distilled out of one gram of the sample.39 The second peak, S2, corresponds to the hydrocarbons that evolve from the sample during the second programmed heating stage of pyrolysis. These hydrocarbons result from the cracking of heavy hydrocarbons and from the thermal breakdown of kerogen. S2 represents milligrams of residual hydrocarbons in one gram of rock, thus indicating the potential amount of hydrocarbons that the source rock might still produce if thermal maturation continues. This reading can have important implications for the evaluation of oil shales. The Rock-Eval technique yields a variety of CO2 measurements. The S3 peak corresponds to CO2 that is evolved from thermal cracking of the kerogen during pyrolysis, expressed in milligrams per gram of rock. Following pyrolysis, residual organic carbon is oxidized in a separate oven to produce the S4 peak. The S4 measurement can be broken down into carbon dioxide and carbon monoxide components to yield the S4CO2 and S4CO peaks. A separate CO2 peak, designated S5, reflects carbon dioxide derived from decomposition of carbonate minerals in the sample. Pyrolysis temperatures are also recorded and produce a Tmax peak that corresponds to the pyrolysis oven temperature during maximum generation of hydrocarbons. Tmax is reached during the second stage of pyrolysis, when cracking of the kerogen and heavy hydrocarbons produces the S2 peak.40 Knowing the amount of heat necessary to create various chemical compounds in the rock can help geochemists understand the history of the rock and the extent of thermal maturation it has already undergone. Tmax should not be confused with geologic temperatures, but it can be useful in characterizing thermal evolution of the organic matter.

> Source rock evaluation criteria. Evaluation of source rock potential must be based on the appraisal of multiple factors.

38

Oilfield Review

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gas generation by determining the quantity, type and maturation of organic matter. The power of Rock-Eval and TOC analyses in wellbores is a direct function of close sample spacing, thus requiring samples at every 10 m

[33 ft] of depth, regardless of lithology.43 However, pyrolysis is not intended for use without supporting geochemical analysis. For critical samples, interpretations from pyrolysis results should be verified by other methods.

Products given off from kerogen maturation CO2, H2O Oil Wet gas Dry gas No hydrocarbon potential Increasing maturation

Type I

1.5 Type II

Hydrogen index

Important Indices Taken together, these pyrolysis measurements provide insight into the chemical makeup and maturity of the organic matter contained within the source rock (previous page, bottom left). The relationship between these components forms the basis for various indices used in the interpretation of rock characteristics.41 • The hydrogen index, HI, is derived from the ratio of hydrogen to TOC; it is defined as 100 2 S2/TOC. The HI is proportional to the amount of hydrogen contained within the kerogen, and high HI indicates a greater potential to generate oil. Kerogen type can be inferred from this index as well. • The oxygen index, OI, is derived from the ratio of CO2 to TOC; it is defined as 100 2 S3/TOC. The OI is related to the amount of oxygen contained in the kerogen and can be useful in tracking kerogen maturation or type. • The production index, PI, is derived from the relationship between hydrocarbons generated during the first and second stages of pyrolysis; it is defined as S1/(S1 + S2). This relationship is used to characterize the evolution of the organic matter because PI tends to gradually increase with depth for fine-grained rock. It also tends to increase with source rock maturation prior to hydrocarbon expulsion, as thermally degradable components in kerogen are converted to free hydrocarbons. Anomalously high values of S1 and PI can also be used to identify petroleum accumulations or stained carrier beds. • The petroleum potential represents the maximum quantity of hydrocarbons that a sufficiently matured source rock might generate; it is defined as the sum of S1 + S2. It therefore accounts for the quantity of hydrocarbons that the rock has already generated (S1) and those that the rock could still produce if maturation continues (S2). It is expressed as kilograms of hydrocarbons per metric ton of rock. These indices are particularly useful in tracking kerogen type and maturation. When plotted on a Van Krevelen diagram, Type I kerogens have a high HI and low OI (right). Type III kerogens are characterized by low HI and high OI. Between these two extremes lie the Type  II kerogens. During maturation, the OI tends to decrease while HI initially remains nearly constant. As the kerogen enters the oil window, HI decreases. PI tends to increase with burial depth.42 This type of information provides geochemists with valuable clues for evaluating a rock’s potential for oil and

1.0

Type III

Type IV 0.5

0

0.1

0.2

0.3

Oxygen index

> Kerogen maturation. A modified Van Krevelen diagram shows changes to kerogen brought on by increased heat during burial. The general trend in the thermal transformation of kerogen to hydrocarbon is characterized by generation of nonhydrocarbon gases; it then progresses to oil, wet gas and dry gas. During this progression, the kerogen loses oxygen primarily as it gives off CO2 and H2O; later, it begins to lose more hydrogen as it evolves hydrocarbons.

36. Espitalié J and Bordenave ML: “Rock-Eval Pyrolysis,” in Bordenave ML (ed): Applied Geochemistry. Paris: Éditions Technip (1993): 237–261. 37. Peters KE: “Guidelines for Evaluating Petroleum Source Rock Using Programmed Pyrolysis,” AAPG Bulletin 70, no. 3 (March 1986): 318–329. 38. Early papers sometimes referred to these peaks as P1, P2 and P3. For example, Espitalié et al, reference 34, distinguished between the P1, P2 and P3 peaks and the area beneath each peak, designated as S1, S2 and S3,

respectively. However, modern pyrolysis analyzers automatically calculate these areas and annotate them on the pyrogram, and the peaks are now commonly referred to as S1, S2 and S3. 39. Espitalié et al, reference 34. 40. Peters and Cassa, reference 27. 41. Espitalié et al, reference 34. 42. Espitalié et al, reference 34. 43. Peters and Cassa, reference 27.

39

Vitrinite

20 µm

> Vitrinite in bituminous coal. The amount of light reflected by vitrinite macerals is a key test for determining the thermal maturity of a rock. The intensity of light reflected from a sample is measured at hundreds of points along a microscopic sampling area, then a statistical analysis determines the amount of vitrinite in the sample and its thermal maturity. This photograph was taken in incident white light, with the sample in an oil immersion. [Photograph courtesy of the US Geological Survey Energy Resources Program: “2011 Photomicrograph Atlas,” http://energy.usgs.gov/Coal/OrganicPetrology/ PhotomicrographAtlas.aspx (accessed July 7, 2011).]

Other Evaluation Methods Vitrinite reflectance is a key diagnostic tool for assessing maturation. Vitrinite, a maceral formed through thermal alteration of lignin and cellulose in plant cell walls, is found in many kerogens (above). As temperature increases, vitrinite undergoes complex, irreversible aromatization reactions that increase reflectance.44 Vitrinite reflectance was first used to determine the rank, or thermal maturity, of coals. This technique is now used to help geochemists evaluate kerogen

Thermal alteration index

maturity over temperatures corresponding to early diagenesis through metamorphism—a range spanning the sequence of petroleum generation, preservation and destruction in rocks.45 Reflectivity (R) is measured by a microscope equipped with an oil-immersion objective lens and photometer.46 Vitrinite reflectance measurements are carefully calibrated against glass- or mineral-reflectance standards, and reflectance measurements represent the percentage of light reflected in oil, designated as Ro. When a mean

Color of organic matter

Associated hydrocarbons

1: none

Yellow

Liquid hydrocarbons to dry gas

2: slight

Orange to brownish yellow

Liquid hydrocarbons to dry gas

3: moderate

Brown

Liquid hydrocarbons to dry gas

4: strong

Black

Dry gas

5: severe

Black, with additional evidence of metamorphism

Dry gas to none

> Thermal alteration ratings. Maturity of source rocks can be ascertained through changes in the color of spores and pollen contained in the rock. (Modified from Staplin, reference 47.)

40

value of vitrinite reflectivity is determined from multiple samples, it is commonly designated as Rm. As indicators of thermal maturity, Ro values vary with the type of organic matter. And because the temperature range of the gas window extends beyond that of oil, Ro values for gas will show a corresponding increase over those of oil. Thus, high maturation values (Ro > 1.5%) generally indicate the presence of predominantly dry gas; intermediate maturation values (1.1%  95

1 1.5

Percent fixed carbon

> Conodont alterations. Conodonts change color with heat; their color can be linked to vitrinite reflectance. (Data from Harris, reference 50.)

Laboratory Sampling manifold Mud logging unit Sample chamber

Chromatogram

Propane

FID gas unit

Chromatograph

Ethane

Shale shaker

Methane

44. Peters and Cassa, reference 27. 45. Senftle JT and Landis CR: “Vitrinite Reflectance as a Tool to Assess Thermal Maturity,” in Merrill RK (ed): Source and Migration Processes and Evaluation Techniques. Tulsa: AAPG (1991): 119–125. 46. The terms reflectance and reflectivity tend to be used interchangeably, with the former being more common. However, reflectance is a ratio of the light reflected from a surface to the light directed onto that surface—the ratio of reflected radiation to incident radiation. This value can change, up to a point, depending on the thickness, and hence, opacity, of a surface. If that surface is thick enough to prevent light from being transmitted through the surface, then reflectance reaches a maximum. This is the reflectivity of a surface. 47. The TAI is set forth in Staplin FL: “Sedimentary Organic Matter, Organic Metamorphism, and Oil and Gas Occurrence,” Bulletin of Canadian Petroleum Geology 17, no. 1 (March 1969): 47–66. 48. Anders D: “Geochemical Exploration Methods,” in Merrill RK (ed): Source and Migration Processes and Evaluation Techniques. Tulsa: AAPG (1991): 89–95. 49. Found in Late Cambrian and Triassic formations, conodonts were long suspected of being fossilized teeth. In the early 1990s, this supposition was verified through the aid of electron microscopy. For more on conodont research: Zimmer C: “In the Beginning Was the Tooth,” Discover 14, no. 1 (January 1993): 67–68. 50. Harris AG: “Conodont Color Alteration, An OrganoMineral Metamorphic Index, and Its Application to Appalachian Basin Geology,” in Scholle PA and Schluger PR (eds): Aspects of Diagenesis. Tulsa: Society of Economic Paleontologists and Mineralogists, SEPM Special Publication 26 (1979): 3–16. For the seminal paper on CAI, see: Epstein AG, Epstein JB and Harris LD: “Conodont Color Alteration— An Index to Organic Metamorphism,” Washington, DC: US Government Printing Office, US Geological Survey Professional Paper 995, 1977. 51. Noble RA: “Geochemical Techniques in Relation to Organic Matter,” in Merrill RK (ed): Source and Migration Processes and Evaluation Techniques. Tulsa: AAPG (1991): 97–102.

Conodont alteration index

Total gas

with heat they change progressively to light brown, then dark brown, black, opaque white and crystal clear. Alteration from pale yellow to black is thought to result from carbon fixing within the organic matter contained in the fossil structure. The color changes with carbon loss and release of water from the crystal structure. Experimental data show that color alteration begins at about 50°C [122°F] and continues to about 550°C [1,022°F]. The CAI can be determined by comparing samples against a set of laboratory-produced conodont color standards to estimate a temperature range. Conodont color alteration has been correlated with other optical indices and with percent fixed carbon (above right). Another screening method measures the composition and concentration of light hydrocarbons released from drill cuttings.51 Fine-grained formation cuttings, typical of those produced by source rocks, may retain hydrocarbons even after they arrive at the surface, making good samples for this type of analysis. This technique, known as gas chromatography, can be carried out at the wellsite or under strictly controlled conditions at a laboratory (right).

> Formation cuttings analysis. At the well, cuttings are collected from the drilling mud after circulating to the surface (red arrows) and passing over the shale shaker. In the mud logging unit, the cuttings are evaluated under a microscope, and mud gas is analyzed by an FID and gas chromatograph. Gas from the cuttings may also be analyzed in a laboratory. For transport to the laboratory, the cuttings are sealed in sample jars containing water. Gas expelled from the cuttings will accumulate above the liquid surface. This gas is commonly referred to as headspace gas. At the laboratory, the gas is drawn from the container then injected into the sampling port of a gas chromatograph. As the gas passes through the chromatograph’s capillary column, it splits into separate compounds, with each compound taking a little longer to move through the system than its predecessor. Each compound exits the column individually, to be analyzed by an FID or other detector. The results are recorded on a chart known as a chromatogram (bottom right).

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Compound separation

Ionization

Ion separation

Ion detection

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> Biomarker analysis. Biomarker carbon structures are directly related to precursor molecules of specific biological substances. The smallest markers are found at a molecular level and can only be determined through GCMS. With this method, separate compounds are drawn through the gas chromatograph capillary column then pass to an ionizer. There, a metallic filament ionizes each compound. The quadrupole analyzer filters the ions based on their mass/charge ratio. The electron multiplier detects every ion of the selected mass filtered through the quadrupole analyzer.

A gas chromatograph evaluates gas liberated during the drilling process and records individual peaks for methane (C1), ethane (C2), propane (C3), isobutane (iC4) and normal butane (nC4); a single peak is typically recorded for pentanes (iC5 and nC5) and heavier hydrocarbons (C5+). Determining the composition and concentration of these gases helps geoscientists evaluate the types of hydrocarbons that may be produced within a prospective reservoir. Gas chromatography (GC), when supplemented by mass spectrometry (MS), can provide a detailed analysis of organic compounds found in trace amounts (above). Geochemists commonly use this technique, referred to as GCMS, for identifying the masses and relative concentrations of organic compounds known as biological markers. Biomarkers constitute molecular fossils and are synthesized only through biogenic processes.52 Their organic structures can be classified into basic groups, which, in turn, contain members having variations of the same basic structure. These groups can be related to certain types of organisms and can help geochemists ascertain the environment in which such an assemblage might have been deposited. Biomarker compositions reflect the type of organic matter incorporated into the sediment as well as chemical changes that occurred subsequent to deposition. The combination of precursor molecules and their chemical reactions varies from one basin or field to another, producing a

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biomarker distribution that can be unique to a particular location. By comparing oil to samples of potential source rock, this chemical fingerprint can help link oil to its source.53 Because biomarker patterns tend to change systematically with respect to time and temperature, they can help geochemists infer maturation trends. When potential source rocks have not been encountered in a basin, indirect correlations between oil and source rock may be obtained through source-related biomarker ratios.54 These biomarker ratios help geochemists infer source rock thermal maturity, lithology, depositional environment, organic matter input and age. For example, the biomarkers contained in a specific crude oil might indicate that its source rock was a marginally mature, clay-poor marine carbonate of Devonian age that contained algal and bacterial organic matter deposited under anoxic conditions. Biomarkers can also supplement maturity indicators such as vitrinite reflectance and spore coloration.55 Beyond the Basic Toolkit Though source rocks have been studied extensively for the past 50 years, the recent move to exploit plays centered on gas shales and oil shales has spurred a resurgence of geochemical research and development. This resurgence has prompted expanded utilization of established techniques as well as the development of new tools.

The past decade, in particular, has seen a renaissance in petroleum system modeling tools. Source rock kinetics, a key input for these models, characterizes the chemical reactions and petroleum compounds generated during thermal maturation of a rock. Two pyrolysis techniques that have proved useful in simulating maturation processes are microscale sealed vessel and gold tube confined pyrolysis.56 Using these techniques, scientists are able to scrutinize processes such as oil-to-gas cracking (OTGC), in which application of temperatures greater than 150°C causes existing oil to break down into gas. OTGC investigations have, in turn, led to the tracking of thermally resistant carbon molecules, known as diamondoids, for determining how gas is generated from oil under high-temperature conditions.57 52. Noble, reference 51. 53. This type of geochemical fingerprint can also be used to compare one oil to another; it has proved useful in tracking “mystery” oil slicks at sea to the vessels responsible for discharging oil wastes. 54. Peters KE and Fowler MG: “Applications of Petroleum Geochemistry to Exploration and Reservoir Management,” Organic Geochemistry 33, no. 1 (2002): 5–36. 55. Noble, reference 51. 56. Horsfield B, Disko U and Leistner F: “The Micro-Scale Simulation of Maturation: Outline of a New Technique and Its Potential Applications,” Geologische Rundshau 78, no. 1 (1989): 361–374. Hill RJ, Tang Y, Kaplan IR and Jenden PD: “The Influence of Pressure on the Thermal Cracking of Oil,” Energy & Fuels 10, no. 4 (1996): 873–882. 57. Dahl JE, Moldowan JM, Peters KE, Claypool GE, Rooney MA, Michael GE, Mello MR and Kohnen ML: “Diamondoid Hydrocarbons as Indicators of Natural Oil Cracking,” Nature 399, no. 6731 (May 6, 1999): 54–57.

Oilfield Review

Mineral grains

Kerogen Pores Mineral grains Kerogen

Pyrite Pyrite 1 µm

> Scanning electron microscope with a backscatter image of a Barnett Shale sample at 1,000× magnification. In the shale sample (right), amorphous organic matter (dark gray), consisting primarily of kerogen is seen as large continuous lenses or small, finely dispersed packets interwoven in a complex mineral matrix (lighter gray components). Pyrite, a product of shale thermochemical maturation, is also present (small white crystals). Pores of varying size and shape (small black spots) can be seen in both the kerogen and mineral components, but are more prevalent in the former. The sample was milled using an argon ion polisher then imaged using a scanning electron microscope (left) to reveal the complex organic-mineral-pore architecture characteristic of such mudrock deposits. (Graphic courtesy of Nicholas Drenzek, Schlumberger-Doll Research Center and Natasha Erdman, JEOL USA, Inc.)

The analysis of stable isotopes of carbon and other elements such as hydrogen, oxygen or sulfur is also seeing increased application in organic geochemistry. Recent observations of ethane carbon isotopes have led to interesting correlations between dry gas and overpressured zones within gas shales. Isotope plots show a rollover, or reversal, in maturity that runs contrary to trends normally tied with depth. The origin of these reversals is unknown, but a trend toward high production rates has been observed in wells that exhibit rollover. Scientists are also focusing on the physical structure of kerogen within the mineral matrix of source rocks. The formation of secondary permeability and porosity in organic-rich shales during in situ maturation is believed to be a key enabler for production of shale gas in many source rocks (above). Organic petrography, utilizing basic and advanced microscopy techniques to focus on organic matter, is therefore seeing a revival in kerogen evaluation.

Summer 2011

Beyond the laboratory, new techniques for monitoring gases encountered during drilling are helping geoscientists determine the composition of hydrocarbons, locate fluid contacts and aid in the identification of compositional gradients in reservoirs. The FLAIR fluid logging and analysis service extracts gas from drilling mud under constant pressure, flow, volume and temperature conditions. Part of the Schlumberger Geoservices suite of mud logging services, the FLAIR system first samples gas that has been circulated to surface then separates it into individual components to provide a quantitative analysis of gases from C1 to C5 and semiquantitative information on the C6 to C8 components. Isotope analysis can provide information regarding the origins and characteristics of the hydrocarbons encountered during drilling. Using δ13C/CH4 ratios, which are originally related to petroleum generation,mud logging analysts can provide E&P companies with preliminary information concerning the source rock, including its kerogen type and thermal maturity.

While operators devote much of their exploration efforts to studying the depositional and structural characteristics of a prospect, many are also concerned with the processes that control the formation of oil and gas. Geochemical reactions and the conversion of organic matter are integral to petroleum generation; the characterization of organic matter, in turn, is becoming increasingly critical for the development of new plays. These tools are proving instrumental in opening new frontiers of exploration. —MV

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Technology for Environmental Advances

Wasim Azem Al-Khobar, Saudi Arabia

New technologies play key roles in helping the E&P industry find and produce

John Candler Joanne Galvan Mukesh Kapila M-I SWACO Houston, Texas, USA

also help the industry work with greater care for the environment.

Johana Dunlop Paris, France Andrey Fastovets Singapore Adun Ige Rosharon, Texas Ed Kotochigov Gatwick, England Cristina Nicodano M-I SWACO Aberdeen, Scotland Ian Sealy Sugar Land, Texas Paul Sims Clamart, France Oilfield Review Summer 2011: 23, no. 2. Copyright © 2011 Schlumberger. For help in preparation of this article, thanks to Diana Andrade, Aberdeen; Kamel Bennaceur, Paris; Kayli Clements, M-I SWACO, Houston; Harald Fosshagen, M-I SWACO, Fyllingsdalen, Norway; Paul Handgraaf, Thermtech, Bergen, Norway; David Harrison and Theresa Winters, Sugar Land; Tony McGlue, Gatwick, England; and Rene Vollebregt, Barendrecht, the Netherlands. Opening image (AS17-148-22727_2 from http://eol.jsc.nasa. gov/scripts/sseop/photo.pl?mission=AS17&roll= 148&frame=22727) is courtesy of Earth Sciences and Image Analysis Laboratory, NASA Johnson Space Center, Houston. CleanPhase, ClearPhase, EcoLibrium, EverGreen, FlexSTONE, FUTUR, IRMA, Maximus, Monowing, PhaseTester, ProMotor, Q-Marine, Q-Marine Solid, REDA, SmartWeir, SpeedStar 519 SWD and WhaleWatcher are marks of Schlumberger. AQUALIBRIUM, CLEANCUT, ISO-PUMP, RECLAIM and HAMMERMILL are marks of M-I l.l.c. RPA and TORR are marks of ProSep Inc. TCC is a mark of Thermtech. X-BOW is a mark of the Ulstein Group.

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hydrocarbons more efficiently and effectively. Many recent advances in technology

Stewardship of the Earth’s resources is vital today. Practices that fail to maintain the Earth’s natural environment—whether deli­ b­ erate or unintentional—have now become unacceptable. Companies in many industries have developed new technologies to mitigate environmental impacts. The oil and gas industry is viewed by many with suspicion, particularly with regard to envi­ ronmental impact management. The Hollywood image of oil discoveries that are signaled by well blowouts is still imprinted in many people’s minds, and major events such as the Macondo disaster in the Gulf of Mexico, although rare, renew those impressions. However, enormous strides have been made by the oil and gas industry to improve environmental stewardship, and the pace of “green” developments in the industry has increased dramatically over the past few years. The industry has found ways to reduce its need for resources by more efficient use of those resources. By adopting smaller surface footprints, lower emissions and more-benign chemicals, companies are reducing adverse impacts on the ecosystem. Throughout the process of hydrocar­ bon exploration and production, industry actions have reduced the volumes of waste materials such as liquids or drill cuttings and found better ways to process and dispose of those materials it does use. While no single technology solves all environ­ mental problems, even small improvements help reduce impact on the environment.

Development of new products and services may be driven by a desire both to meet or exceed compliance limits and to discontinue or decrease a negative environmental impact, but in many cases, the fundamental performance characteris­ tics—such as noise levels in a seismic streamer— are also improved in the process. By incorporating a holistic view of the purpose of a technology and its environmental impact, engineers applying fundamental scientific and engineering princi­ ples often discover better solutions. For example, rather than building a large, centralized wastewater treatment center to treat flowback water in shale plays, M-I SWACO, a Schlumberger com­ pany, examined the footprint of the entire opera­ tion and realized the impact of trucks moving to and from the centralized plant could be avoided. This led them to develop onsite water-recycling technologies. As an oilfield service company, Schlumberger has developed many products and services that help mitigate environmental impact in E&P activities. Operating companies and others in the industry can tell of similar activities. This article follows the exploration and production cycle to highlight some technologies and practices that have made notable advances in mitigating envi­ ronmental impact. Exploring in the Environment The first operationally intensive E&P activity in a prospective area is typically a seismic evaluation. Today, environmental awareness by geophysical companies is a key feature of both marine and land surveys.1

Oilfield Review

The environmental footprint from marine seismic acquisition surveys can be broken into four categories of emissions: acoustic, fluid, gaseous and solid. These sources can come from the vessel itself or from the acquisition process. By addressing each of these issues, the industry can eliminate or mitigate their impact.2 Det Norske Veritas (DNV), an independent foundation with the mission of safeguarding life, property and the environment, has developed a CLEAN-DESIGN class notation whose stipulations reduce a ship’s environmental impact due to air emissions, sea discharges and accidental damage to the ship’s hull.3 In 2009 and 2010, WesternGeco launched

Summer 2011

six new vessels with the DNV CLEAN-DESIGN notation, giving it the largest fleet of seismic vessels of this type. WesternGeco also uses high-quality marine gas oil (MGO) despite its substantially higher cost because it has distinct environmental advantages over the heavy fuel oil (HFO) used by many other seismic vessels. A seismic Oilfield Reviewvessel using HFO emits approximately 9% more SUMMER 11 greenhouse gases than vessels using MGO and about 800% more sulfur ENVIRONMENT Fig. Opener oxides, which are major contributors to acid rain. ORSUM11-ENVRMT Opener New legislation from the International Maritime Organization has introduced much more stringent requirements for future sulfur content in fuels.

WesternGeco manages marine fuel consumption to decrease greenhouse gas emissions through state-of-the-art route design. During transits between surveys, the routers take into account seasonal and regional ocean current regimes and weather. Other efforts include maintaining hydrodynamic efficiency by polishing 1. Gibson D and Rice S: “Promoting Environmental Responsibility in Seismic Operations,” Oilfield Review 15, no. 2 (Summer 2003): 10–21. 2. Fontana PM and Zickerman P: “Mitigating the Environmental Footprint of Towed Streamer Seismic Surveys,” First Break 28, no. 12 (December 2010): 57–63. 3. DNV Managing Risk: “CLEAN-DESIGN,” http://www.dnv. com/industry/maritime/servicessolutions/classification/ notations/additional/clean-design.asp (accessed June 7, 2011).

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> Seismic acquisition. While acquiring a seismic survey, a vessel tows a wide array of streamers. During a wide-azimuth seismic survey, several vessels operate together (inset). Each vessel is towing ten 8-km long streamers. The WesternGeco Magellan, in the inset foreground, features an X-BOW vessel design, which has better fuel efficiency during transits.

ships’ propellers to optimize propulsion, painting vessels’ hulls to deter marine animals from attaching to them and proactive inventory management to reduce weight onboard.

A modern 3D seismic acquisition vessel can deploy 12 or more streamers, each up to 8 km [5 mi] long (above). To maintain crossline separation between the streamers, diverters are

Oilfield Review SUMMER 11 ENVIRONMENT Fig. 1A ORSUM11-ENVRMT 1A

Oilfield Review SUMMER 11 ENVIRONMENT Fig. 1A ORSUM11-ENVRMT 1A

> Solid-filled streamer. A seismic crew member onboard a WesternGeco marine seismic vessel deploys a Q-Marine Solid cable.

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deployed ahead of the seismic spread; use of Monowing deflectors significantly increases the energy efficiency of operations. A vessel equipped with this technology consumes 6,000 to 8,000 L [1,600 to 2,100 USgal] less fuel per day than a vessel with conventional diverter technology.4 In addition, the advanced streamers used with the Q-Marine platform have reduced drag—largely because they have a smaller diameter than conventional streamers—which also contributes to reduced fuel consumption. A seismic survey may include about 30,000 sensors using Q-Marine single-sensor technology. These hydrophone sensors are encased in a strong, watertight polyurethane skin for protection from the marine environment and from stresses incurred during deployment and retrieval. To maintain neutral buoyancy between 6 and 8 m [20 and 26 ft] below the surface of the water, the streamers are filled with a kerosenebase fluid. The streamers are occasionally damaged in use, most often because of shark bites, interaction with commercial fishing gear and streamer collisions with submerged objects. The average lifespan of a streamer skin is about three years. In 1991, the WesternGeco manufacturing facility in Bergen, Norway, found a new supplier of the plastic skins that was able to recycle the skins when they were damaged beyond repair. Most of

Oilfield Review

4. WesternGeco: “Environmental Excellence in Marine Operations,” http://www.westerngeco.com/services/ marine/ecomarine.aspx (accessed June 7, 2011). 5. Groenaas HSG, Frivik SA, Melboe AS and Svendsen M: “A Novel Marine Mammal Monitoring System Utilizing the Seismic Streamer Spread,” paper D047, presented at the 73rd European Association of Geoscientists and Engineers Conference and Exhibition, Vienna, Austria, May 23–26, 2011.

Summer 2011

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the damaged skins can be refurbished once for their original use, giving them an additional three-year average life as a streamer. The second time a skin is sent for recycling, it can usually be converted to other uses, such as boat or pier fenders. This repurposing extends the useful life of the material another 8 to 10 years, potentially making a 16-year lifespan for the polyurethane. One potential consequence of puncture damage for a streamer skin is that the ballasting fluid can leak into the ocean. Even though the chemical formulation of this fluid enables fast evaporation and minimal exposure to the environment, all incidents of leakage are immediately reported to respective regulatory bodies. Nonfluid streamers have advantages of zero-spill characteristics together with elimination of noise from bulge waves—waves of pressure associated with longitudinal oscillation of fluid along a tube. The Q-Marine Solid seismic streamer system, developed by WesternGeco, produces no fluid discharge if the skin is punctured. In addition to this environmental advantage, the solid system has distinct operational benefits: • Consistent pressure and streamer buoyancy give improved acoustic performance. • The system is less susceptible to water ingress and electrical problems when punctured. The results are less technical downtime and a reduced number of small boat operations to do repairs, reducing exposure of the field crew to hazards. • The solid gel properties contribute to easier streamer construction. The solid-streamer material is a proprietary gel developed by WesternGeco and Schlumberger Cambridge Research in England specifically for use in streamers. The gel has been extensively tested and qualified for use in the most sensitive environmental areas, including the Arctic. It is a liquid when heated, but forms a gel upon cooling to ambient temperature. In addition, the gel is selfhealing and robust under stresses that occur when seismic crews deploy and retrieve the streamers (previous page, bottom). It is chemically stable, and does not trap air during manufacture or repair. Compared with other solid-filled streamers, these attributes improve its noise characteristics. When deployed, the Q-Marine Solid streamers deliver results consistent with the high standards of Q-Marine technology. Single-sensor recording tech-

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> Detection of a whale. Cetacean species have distinct frequency signatures to their calls, such as one from a whale (top). During seismic acquisition, acoustic signals from both the seismic and IRMA positioning arrays are analyzed continuously to check correlation with these acoustic spectra. By using beamforming, which creates constructive interference from the arrays aligned with the azimuth of the signal and destructive interference elsewhere, the WhaleWatcher system can triangulate the sounds to obtain the distance to and bearing to the animal. In this case, a whale was detected 5 km [3 mi] from the vessel at a depth of 30 m [98 ft] in water 250 m [820 ft] deep.

nology and customized noise attenuation using daylight, and they can provide only an inexact those single-sensor data, or digital group forming, estimate of the distance to the sighting. used with Q-Marine Solid acquisition enable outTo address these challenges, WesternGeco standing signal-to-noise performance. Q-Marine developed a technique for cetacean detection Oilfield Review technology has also been expanded to anotherSUMMER area: that 11 is integrated into the seismic acquisition system. detection of nearby marine mammals. WhaleWatcher passive acoustic monitorENVIRONMENT5 Fig. 3 ORSUM11-ENVRMT 3 allows remote observation during Marine seismic acquisition uses airguns to ing technology emit an acoustic signal, but to marine life, airguns seismic operations. The cetaceans use highare simply a source of noise. In many parts of the frequency clicks for echolocation and a middle-toworld, regulations have been established to mini- low-frequency range for communication. These mize disturbance to marine life during seismic sounds overlap the sensitivity range of the hydrosurveys. Dedicated observers are posted on the phones and of sensors in the IRMA positioning vessels to spot marine mammals. However, human system—which uses intrinsic ranging by moduobservers can see the animals only if they surface, lated acoustics—located along the streamers. which occurs at irregular intervals. This behavior Frequency analysis of these data identifies the makes tracking them difficult. In addition, the distinctive calls from various species (above). observers’ effectiveness is limited by weather and

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An animal’s distance and azimuth can be determined accurately because of the large areal spread of the detector arrays in a seismic operation. The signal analysis is enabled by the singlesensor configuration of the Q-Marine pointreceiver seismic acquisition system. Mammal locations are presented on navigation displays throughout the ship in real time, providing a continuous and reliable means of detecting and tracking the cetaceans during limited visibility periods. When marine animals are getting close to the exclusion zone around the seismic source—typically 500 m [1,640 ft]—marine mammal observers can use information from the WhaleWatcher system to make necessary operational decisions, including shutdown. On land, the long-term impact of seismic acquisition is often on vegetation. This can be alleviated by using brush cutters—rather than bulldozers—that leave roots undisturbed, resulting in a more rapid return of the vegetation. In addition, fragile dunes in deserts must be protected, and in the Arctic great care must be taken to avoid damage to permafrost.6 In these and other fragile environments, careful planning is required to minimize the potential for damage. A highly restrictive land seismic survey was recently completed on Barrow Island, a nature reserve 50 km [31 mi] offshore Western Australia. This reserve is home to several species of animals found nowhere else. The island and its surrounding waters, including coral reefs, are important nesting and spawning grounds. It also sits above the Greater Gorgon gas fields. That gas will be converted to liquefied natural gas to take to market, generating CO2 in the process.

The Gorgon project, operated by Chevron, includes injection of the CO2 into a saline reservoir deep beneath the island. The monitoring plan for this carbon storage project includes 4D seismic surveys.7 Although the baseline survey obtained in 2009 covered 135 km2 [52 mi2], the government permit allowed use of only 25 ha [0.25 km2 or 0.1 mi2] of surface area for the acquisition footprint; this is a factor of 10 less area than would be typical for a survey of this size. WesternGeco worked with the operator to mobilize seismic equipment and to complete the survey. All equipment was fumigated before shipment to the island to avoid inadvertent introduction of alien species. A helicopter moved equipment to shot hole locations on the island, and the survey party walked to 13,284 receiver points, covering in aggregate about 42,000 km [26,000 mi] to deploy, by hand, about 200,000 kg [440,000 lbm] of seismic equipment. Drilling rigs for shot holes and other equipment were placed on stilts to minimize disturbance of the vegetation. The survey was acquired successfully and had an excellent safety record. During the survey, the crew had even less environmental impact than allowed by permit, disturbing less than 19 ha [0.19 km2 or 0.07 mi2] of vegetation.8 Drilling with Less Impact The E&P industry has also been successful in reducing the footprint of activities while drilling, the next major activity in the cycle of field development. Through application of advanced technology and innovative practices, companies are taking proactive measures to minimize environ-

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> Thermal mill. The TCC HAMMERMILL system removes contaminating liquids from solid material by frictional heating. The cuttings, or other waste, are fed into a process mill. A series of rapidly rotating arms (rotors) forces the material against the inside wall of the mill. Hammers at the ends of the arms heat the waste by friction. The waste is the hottest part of the system. The oil and water vaporize within seconds and are vented to condensation cells, where the liquids are captured. The solid material, which remains in the mill for several minutes, is clean by the time it exits the processing mill.

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mental impacts from drilling. At the heart of these advances is the recognition by operators that the objective of efficiently finding and producing oil and gas resources is complementary to that of reducing their environmental footprint. Ongoing advances in drilling fluids and wastemanagement techniques have created more options to minimize or recycle waste and to reduce onsite and offsite impacts. Additional programs to address biodiversity protection and to prevent invasive species migration also support the goal of minimizing the footprint of exploration and production operations. Because drilling fluids and drill cuttings typically account for the largest volume of waste from drilling, they have long been the focus of waste-management efforts. Drilling fluids and solids-control equipment are coordinated to efficiently remove drill solids from the wellbore. As the drilling fluid becomes loaded with cuttings fines, its efficacy degrades, so either the amount of fines in the drilling fluid has to be decreased or the fluid has to be disposed of and replaced, both of which ultimately increase the amount of waste material generated. To reduce the source of waste, high-performance drilling fluids can reduce the degradation of cuttings as they travel to the surface and, at the same time, increase rate of penetration and reduce nonproductive time and hole washout. Recycling is another important approach to waste management of drill cuttings and excess drilling fluids. Typical solids-control equipment cannot remove these fine solids. In the past, there were two options: dispose of the finesloaded fluid or dilute the used fluid with additional base fluid. New recovery technology designed instead to reuse water from water-base muds (WBMs) after fines have been removed can result in closed-loop systems and elimination of mud storage in pits. Building on the success of handling fine solids in WBM, M-I SWACO developed the RECLAIM treatment unit. It uses a chemically enhanced solids-removal process to remove most of the fines from nonaqueous fluids.9 The process uses surfactants to weaken the drilling fluid’s emulsion, allowing flocculating agents to agglomerate the fine solids into larger bodies. Those bodies are removed using conventional centrifugal techniques. The RECLAIM process allows reuse of the base fluid, which achieves both economic and environmental objectives. Another approach to fluid recovery is the use of thermal technology to treat the drilling fluid– coated solids to remove and recycle the base fluid. By removing base fluid from the cuttings,

Oilfield Review

  6. Bishop A, Bremner C, Laake A, Strobbia C, Parno P and Utskot G: “Petroleum Potential of the Arctic: Challenges and Solutions,” Oilfield Review 22, no. 4 (Winter 2010/2011): 36–49.   7. Scott KC, Parker DJ, Cairns A and Clulow B: “Setting New Environmental, Regulatory and Safety Boundaries: The 2009 Gorgon CO2 3D Seismic Baseline Survey, Barrow Island, Western Australia,” paper SPE 132931, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Queensland, Australia, October 18–20, 2010.   8. Scott et al, reference 7.   9. Geehan T, Gilmour A and Guo Q: “The Cutting Edge in Drilling-Waste Management,” Oilfield Review 18, no. 4 (Winter 2006/2007): 54–67. 10. Soil amendments are additives such as fertilizer or compost that farmers use to improve soil quality and grow better crops. 11. Vermiculture is the use of various species of worms to decompose organic waste. 12. Geehan et al, reference 9.

Summer 2011

Additive Classification Green Yellow Red Black

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thermal technology reduces the potential environmental impacts from the cuttings. The TCC HAMMERMILL system vaporizes oil coatings from solids without degrading the organic fraction of the drilling fluid. The process mill within the system is a drumshaped chamber about 1 m [3.3 ft] in length and diameter. A rotating shaft with a series of hammer arms generates frictional heat in the solid material (previous page). Prior to starting cleanup, the process operator feeds sand into the chamber and energizes the rotating shaft. The particles are forced by the hammer heads against the inner wall of the chamber, where friction heats them. Once the sand is hot, drill cuttings are injected. The fluids in the cuttings vaporize and vent to condensation cells for recovery. After treatment, the cuttings are clean enough for disposal or for use as construction fill. In addition to cleaning drill cuttings, the TCC HAMMERMILL system can also clean soil and sludge from the bottom of storage tanks. The oilon-cuttings level after treatment is less than 1% total petroleum hydrocarbons. Another recycling and reuse approach for WBM and synthetic-base mud is to convert the cuttings into a soil amendment through soilmanagement techniques and bioremediation.10 This technology has been applied in several locations using a variety of techniques such as farming, composting and vermiculture.11 Responsible treatment and disposal options work in concert with other waste-management strategies. Such disposal frequently requires efficient and safe transportation to centralized waste-management facilities. The CLEANCUT cuttings-handling system keeps the solids flow stream isolated from the environment during transfers and storage. Drill cuttings are transferred pneumatically from the shakers into ISO-PUMP storage and transfer pressure vessels.

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> Progress in replacing chemicals. For Norwegian North Sea E&P operations, chemicals are classified as green (posing little or no environmental risk), yellow (acceptable), red (generally not allowed to be discharged into the sea) and black (banned). Since 2000, the number of chemicals classified as red and black used in Schlumberger operations has declined significantly due to ongoing efforts to use lesshazardous materials. The remaining additives in the red category are used to prevent cement failure; set in cement, the risk of their entering the marine environment is minimal. A slight increase in 2010 of the number of additives in the black category was due to a reclassification of chemicals; replacements are being sought that will bring these additives back into compliance with the lower-risk categories. (The status data are from the beginning of each year listed.)

by the action of living organisms. Bioaccumulation is a general term for the accumulation of organic chemicals in organisms—such as fish—through their respiration, food intake, skin contact or other means. Bioconcentration refers to the uptake of substances into the organism from water alone. Toxicity is the degree to which a substance can cause harmful effects to a species. Developments in green chemistry have been employed on a global scale for many years, and discoveries in one discipline to meet a specific performance goal are quickly shared with other areas. In the mid-1980s the US Environmental Protection Agency added an acute toxicity limit for the discharge of water-base drilling fluids. The new, lower limit generated a rapid progression of shale inhibitors and lubricants; these Green Chemistry OilfieldofReview replaced traditional products that did not meet Green chemistry is based on a philosophy encouraging the design of products SUMMER and pro- 11the toxicity limitation. ENVIRONMENT Fig. 5 In the5North Sea, a significant part of the E&P cesses that replace chemicals having ORSUM11-ENVRMT a higher hazard with others that pose a lower hazard, business is built around chemicals that are inherwhile achieving the same function. In many ently benign to the environment. This has been cases, improving the environmental performance achieved through performing an environmental of a product also reduces the potential for associ- assessment as a first step in the product development process. In addition to its own developated occupational health hazards. The first priority of green chemistry is target- ments, Schlumberger works closely with all major ing components that are hazardous in the envi- chemical suppliers for the development of ronment and, when used, are discharged into the greener chemicals. As a user rather than a manuenvironment. The second priority is to achieve a facturer of chemicals, Schlumberger set a goal to high level of environmental performance in the switch to chemicals that not only conform to high areas of biodegradability, bioaccumulation and environmental standards, but also perform as well as or better than the products they replaced bioconcentration, and toxicity. Biodegradability is a measure of the degree to (above). Although there is a popular conception which an organic substance will be broken down Shipping cuttings from offshore to shore for treatment and disposal can be costly, so companies have turned to injection of cuttings into formations assessed as acceptable for containment and capacity or into the flanks of oil or gas fields.12 In addition to upgrading technologies that handle drilling waste products with less environmental impact, the industry is improving the environmental quality of the fluids themselves, which contain a wide variety of chemicals, each serving a specific purpose within the drilling-fluid composition. In recent years, many fluids used in drilling and throughout a well’s life have been changed to those that perform their operation better while also reducing environmental impacts.

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Oil outlets

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Oil-in-water at inlet, ppm

RPA beds

Send to second stage

20,000

14

12,000

14

20

8,000

12

13

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At limit, caution Within 20-ppm limit 19

ClearPhase unit. Water with residual oil content enters the ClearPhase treatment unit (top) after exiting a three-phase test separator. The water goes through a series of RPA reusable petroleum absorbent beds, which use TORR de-oiling technology—licensed from ProSep Inc.—to coalesce small droplets of oil in water. Within the beds, the oil forms larger drops, which are detached on the downstream side of the bed as flow passes through the vessel. These larger oil drops more easily separate from the water and float to the top in the next settling chamber. The water goes through five RPA beds, each removing more oil. The capacity of the unit to treat water depends on the amount of oil initially present in the water and the flow rate (table, bottom). The numbers in the boxes indicate average oil-in-water concentration (in ppm by volume) at the outlet.

that environmentally improved chemical prod- and appraisal wells typically do not have access to ucts do not work as well as the products they permanent infrastructure for disposal of these replace, the EcoLibrium line of oilfield chemi- materials, so portable systems are required. cals, which resulted from this effort, successfully Oilfield Review Several technologies can now be combined in maintains high performance standards.SUMMER 11a customizable system that can be used for both ENVIRONMENT Fig. 6and well testing. The heart of the system cleanup ORSUM11-ENVRMT 6 is a CleanPhase well-test separator. This separaHandling Cleanup Fluids After an operator drills and completes a new well, tor can handle either large aqueous-phase flow debris and fluids remain in the wellbore, perfora- during cleanup or large oil-phase flow during the tions and producing formation. The debris and reservoir test by optimizing the height of the oil fluids are often removed by temporarily producing layer using SmartWeir phase separation technolthe well. The flow rate of produced fluids and ogy.13 In addition, a PhaseTester portable unit can gases may be measured at the same time to deter- accurately and continuously evaluate simultanemine the production and reserve characteristics ous flow of water, oil and gas during cleanup and of the well and reservoir. Materials produced dur- well testing. When it is possible to reinject the ing this process can contain large volumes of fluids, either in the same or another formation, brine, oil and gas, which must be treated to mini- the well production rate can be tested without mize their environmental impact. Exploration discharge to the environment.14

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Produced water can be further treated to meet discharge standards by using a ClearPhase mobile testing discharge unit (left).15 This treatment system can reduce oil-in-water from 20,000 parts per million (ppm) by volume to less than 20 ppm even at flow rates up to 5,000 bbl/d [794 m3/d]. This meets or exceeds waterdischarge requirements of most countries in which oil companies operate. If local regulations demand levels beyond the capability of the unit at expected flow rates, the effluent can be sent to a second treatment unit to achieve the environmental standard. The coalescing media used inside the ClearPhase unit are reusable, so there are no by-products—such as filters—from the water treatment. Often during cleanup and testing, oil and gas must be flared for a brief period when there is no access to a production line. Burner design can minimize the environmental impact generated during flaring by enabling complete combustion of the hydrocarbons, eliminating fallout and smoke. For example, the EverGreen effluent burner is a single-head, 12-nozzle oil burner used for onshore and offshore well testing and cleanup with minimal environmental impact. Complete combustion is achieved because the nozzle array optimizes air influx to reach the heart of the flame. The ingested surrounding air provides 60 times more oxygen to facilitate combustion compared to that provided by compressed air feeding a burner. The head is also fitted with an automatic shutoff valve that prevents oil spillage at the beginning and end of a burning run. The EverGreen burner efficiently burns all types of oil, including most heavy and waxy oils. It can also operate effectively with up to 25% water cut, which makes it ideal for cleanup operations. Efficient Production A major part of any well is the cement sheath around the outside of the casing. Filling the space around the casing with cement provides a barrier, not only between the wellbore and adjacent formations, but between strata in the subsurface. The cement sheath prevents hydrocarbons and saline water from migrating along the wellbore to other formations, particularly to freshwater aquifers hundreds, or more commonly thousands, of feet above producing formations. Although well cementing has long been standard industry practice, service companies continually develop new cements and cementing practices to improve zonal isolation. This is particularly true for gas-storage wells.

Oilfield Review

Summer 2011

For example, a well in the Nizhnevartovsk region in Russia was producing with a third-party ESP at only about 650 m3/d [4,100 bbl/d], much less than its flow potential. It experienced frequent ESP failures and workovers. That pump was replaced with a REDA Maximus ESP with an integrated ProMotor system (below). The ProMotor unit is assembled and filled with a high-dielectric-capacity oil at a factory, saving the operator time needed to install an ESP at the rig and eliminating any potential error resulting from human intervention at the wellsite. Furthermore, filling Maximus motors, protectors and integrated ProMotor units at the factory improves system reliability and simplifies ESP system installation. This is advantageous in the extreme cold conditions common for Siberian winters or in any other adverse ambient conditions that can negatively affect the quality of the installation. The ProMotor unit was deployed

92 days

457 days

with a high-efficiency REDA factory-shimmed compression pump. This novel design extends pump longevity by transferring all the axial thrust generated by pump stages to a high-load protector bearing, and, unlike conventional compression design, does not require setting the shafts during assembly at the wellsite. Production from the well increased to 1,100 m3/d [6,900 bbl/d], a 70% increase over results from the previously used pump. After 890 days of stable production, the unit was pulled for a selective workover operation but showed minimal wear on both the motor and the pump. The unit was rebuilt, serviced with new oil, and installed in another well in the field. The increased production and longer run life of this ESP system mean more energy is harvested with less environmental exposure than with use of the previous pump system.

61 days

890 days

1,400 1,200

1,000

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Natural gas is becoming more in demand as a resource, in part because burning it produces less CO2 than burning other fossil fuels. However, gas is more difficult to store than oil because of the lower energy density of gas. The large volume needed for gas storage is available underground in depleted reservoirs located close to gasconsumption centers.16 The wells serve for both injection and production, so they cycle between high and low pressure, as does the storage formation. In addition, the life of a gas-storage unit can be much longer than that of a field producing gas. Thus, the cement surrounding the well must be able to withstand extreme pressure and temperature cycles, and must do so for a long time. FUTUR active-set cement provides a more secure solution than conventional cements.17 The FUTUR blend includes a component that, when exposed to hydrocarbon, generates a self-healing sealant that swells to close gaps or flow paths in the cement, assuring the sheath’s integrity. In many formations, fracturing is necessary for the wells to economically produce oil or gas. One such formation is the Marcellus Shale in the US, which is an unconventional gas play. Wellbore fracturing uses large quantities of water, much of which flows back to surface at the end of the operation. Fracturing five Marcellus wells per week, one operator used an average of 150,000 bbl [24,000 m3] of water for each job. The company recovered about 125,000 bbl [20,000 m3] of water weekly from these operations. The operator was committed to reusing this water to conserve freshwater resources and decrease local truck traffic moving water to and from wellsites. M-I SWACO provided this operator with the AQUALIBRIUM water management service to remove suspended solids from the flowback fluids. After pilot testing several types of equipment, M-I SWACO designed a system that met the operator’s specifications for water conditioning. Equipment placed at two locations in the field treated about 1,800,000 bbl [286,000 m3] of water during field development, avoiding the need to obtain this water from local supplies. Once wells are on production, companies strive for efficient operations to improve economics; in many cases, there is an added environmental benefit. For example, many wells require some form of artificial lift to bring liquids to the surface, because the formation pressure has declined, the water cut has increased or both. Improving the efficiency and extending run life of electric submersible pumps (ESPs) decreases both the amount of energy needed to produce the liquids to surface and the frequency of well workovers, which minimizes negative environmental impact.

800

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> Improved lift in Nizhnevartovsk. A third-party brand of ESP was replaced several times, after 92, 457 and 61 days of operation. The REDA Maximus unit, installed (red dot) after the third failure, produced fluids at significantly higher levels. After operating for 890 days, the unit was pulled for a scheduled maintenance shutdown. Inspection showed minimal wear, so the unit was serviced and returned to operation in another well in the same field.

13. Sims P: “The Next-Generation Separator: Changing the Rules,” Oilfield Review 22, no. 3 (Autumn 2010): 50–54. 14. Hollaender F, Filas JG, Bennett CO and Gringarten AC: “Use of Downhole Production/Reinjection for Zero-Emission Well Testing: Challenges and Rewards,” paper SPE 77620, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, September 29–October 2, 2002. 15. Arnold R, Burnett DB, Elphick J, Feeley TJ III, Galbrun M, Hightower M, Jiang Z, Khan M, Lavery M, Luffey F and Verbeek P: “Managing Water—From Waste to Resource,” Oilfield Review 16, no. 2 (Summer 2004): 26–41.

16. Bary A, Crotogino F, Prevedel B, Berger H, Brown K, Frantz J, Sawyer W, Henzell M, Mohmeyer K-U, Ren N-K, Stiles K and Xiong H: “Storing Natural Gas Underground,” Oilfield Review 14, no. 2 (Summer 2002): 2–17. Brown K, Chandler KW, Hopper JM, Thronson L, Hawkins J, Manai T, Onderka V, Wallbrecht J and Zangl G: “Intelligent Well Technology in Underground Gas Storage,” Oilfield Review 20, no. 1 (Spring 2008): 4–17. 17. For more on FUTUR cement: Bellabarba M, Bulte-Loyer H, Froelich B, Le Roy-Delage S, van Kuijk R, Zeroug S, Guillot D, Moroni N, Pastor S and Zanchi A: “Ensuring Zonal Isolation Beyond the Life of the Well,” Oilfield Review 20, no. 1 (Spring 2008): 18–31.

Oilfield Review SUMMER 11 ENVIRONMENT Fig. 7 ORSUM11-ENVRMT 7

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Heat exchanger

Central monitoring

Makeup water reservoir Cooling Power generation Heat distribution

Injection well

4,000 to 6,

Sedimen ts

Production well

Crystallin

e rocks

000 m ted Stimula re tu frac system

500 to 00

1,0 m

o 1,00

500 t

0m

> An engineered geothermal system in hot, dry rocks. Heat is harvested from below surface by drilling into a section of deep, crystalline rocks. Water injected into a well (blue) fractures the deep reservoir. Production wells (red) are drilled into the fractured zone. Injected water absorbs heat as it flows from the injection well to the production wells. The heat is recovered at surface, and after treatment, the water is reinjected in a continuous cycle.

Efficiency of wells with artificial lift has also energy resources without the cost and environbeen addressed by development of a variable- mental impact of drilling more wells. speed drive that matches the pumping speed to At the end of its productive life, a field is reservoir deliverability. The SpeedStar 519 SWD decommissioned. Local regulations vary around low-voltage variable-speed drive (LVD) uses an the world, but the principle is to prevent a wellintegral sine-wave output filter. This system helps bore from providing a path for contamination of the motor operate more efficiently, at lower tem- the surface or of freshwater aquifers.19 This is perature and with less vibration, resulting in a accomplished by filling the borehole with cement. longer run time for the downhole system. The For example, FlexSTONE cement is a long-term near-unity input power factor also ensures higher zonal isolation solution.20 It is engineered to resist efficiency than a typical LVD.18 Higher efficiency, cracking under changing stress conditions in a and therefore lower cost for production, helps field, such as occur as pore pressures equilibrate AUT09–RVF–10 extend the life of wells—producing additional after production ends. It can also be designed to 18. Power factor is the ratio of the real power used by an AC device and the apparent power, which is the product of the circuit current and voltage. Reactive loads in the circuit affect the level of nonproductive power in the system. 19. Barclay I, Pellenbarg J, Tettero F, Pfeiffer J, Slater H, Staal T, Stiles D, Tilling G and Whitney C: “The Beginning of the End: A Review of Abandonment and Decommissioning Practices,” Oilfield Review 13, no. 4 (Winter 2001/2002): 28–41.

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20. Abbas R, Cunningham E, Munk T, Bjelland B, Chukwueke V, Ferri A, Garrison G, Hollies D, Labat C and Moussa O: “Solutions for Long-Term Zonal Isolation,” Oilfield Review 14, no. 3 (Autumn 2002): 16–29. 21. For more on geothermal energy: Beasley C, du Castel B, Zimmerman T, Lestz R, Yoshioka K, Long A, Lutz SJ, Riedel K, Sheppard M and Sood S: “Mining Heat,” Oilfield Review 21, no. 4 (Winter 2009/2010): 4–13. 22. Beasley et al, reference 21.

expand when setting, eliminating bulk shrinkage that might lead to a loss of isolation. The wellsite also requires remediation to return it to a natural state. Offshore, regulations in some locations, such as the US Gulf of Mexico, allow toppling of platforms to create artificial reef habitats for marine life. In other locations, such as the North Sea, regulations require platforms be removed and decommissioned at the end of the field’s life. The Future Power Picture Many efforts are underway to develop renewable energy such as solar and wind power and fuels from biomass. However, the timeline for those technologies to generate sufficient energy to meet world demand extends decades into the future. In the intervening years, fossil fuels will remain the primary sources for energy. Greenhouse gases, in particular carbon dioxide, that are generated from use of fossil fuels, will continue to need to be captured and stored. Depleted hydrocarbon reservoirs and deep saline aquifers are among the most likely storage media. The technologies to inject carbon dioxide into these formations, as well as the monitoring methods to assure it doesn’t migrate, are wellknown by the E&P industry. Technologies similar to those used in hydrocarbon operations are needed for production of a huge potential source of energy: geothermal energy. Hot-water sources are already a valuable energy resource in many parts of the world.21 Research is underway to overcome remaining technical obstacles for another geothermal source: deep, hot, dry rocks. This resource also requires methods commonly used in the oil field (above left). Deep wells are drilled, rocks fractured, and water injected and produced. The heat from the water is then harvested and the water is treated and reinjected.22 Continued research and understanding of potential environmental impacts from E&P practices are critical to progress and development of new technologies. Many significant advances have been made to eliminate the use of recognized hazardous constituents and reduce the overall impact on the environment. E&P engineers are striving to achieve environmental goals using basic technologies and will continue to find means to recover and reuse by-products. The continued success of E&P as a pathway of energy development will rely on ongoing commitment by the industry to the principles of reducing the environmental footprint and —MAA minimizing waste.

Oilfield Review

Contributors Guy Arrington, who since 2010 has been President, Bits and Advanced Technologies, a Schlumberger company, has been in the drilling industry for 24 years. He spent 14 years in the drillbit business, working in manufacturing, field engineering and business development in the US and internationally, and later in product and field engineering management. He joined the Schlumberger Drilling and Measurements segment in 2001, first as business development manager and later as vice president for Europe, Central Asia and Africa. Guy was vice president of deepwater operations before managing the Smith Bits and Advanced Technologies integration team during the Schlumberger-Smith merger. He has BS degrees in industrial engineering and mechanical engineering from Texas A&M University. Wasim Azem, based in Al-Khobar, Saudi Arabia, is Schlumberger Testing Services GeoMarket* Manager for Saudi Arabia, Kuwait and Bahrain. He is responsible for delivering service quality with no injuries in operations with one of the biggest oil producers in the world. He joined Schlumberger in 2001 in Kalimantan, Indonesia, and later worked in deepwater areas offshore India supervising high-pressure, high-temperature jobs. He was a manager in Qatar and Yemen, and a regional quality manager for UAE, Oman, Pakistan and Yemen, before taking his current position in 2010. Wasim won a Silver Performed by Schlumberger award in 2010 for multizone testing in an extremely high hydrogen sulfide environment. He obtained a BSc degree in chemical engineering from the American University of Sharjah, UAE, and is studying to obtain an MSc degree in petroleum engineering from HeriotWatt University, Aberdeen. Matthew Billingham, based in Roissy-en-France, France, is Schlumberger Global Slickline Perforation and Remedial Services Domain Champion. He is currently working on solutions for a safe and efficient remedial and explosive service for telemetry-enabled slickline. He began his career in 1994 in Great Yarmouth, England, as a wireline and testing field engineer and has held several positions in a number of locations including Scotland, Norway, Saudi Arabia and Algeria. While serving as tractor, conveyance and mechanical services product champion, he was instrumental in commercializing the MaxTRAC* service and is responsible for the launch and development of TuffTRAC* tractors and the mechanical services tools. Matthew received a BS degree in electrical engineering from the University of Leicester, England, and is currently working on an MS degree in management of the oil and gas industry from Heriot-Watt University, Edinburgh, Scotland. He holds or is joint holder of seven patents in the field of well intervention. John Candler is Manager Environmental Affairs in Houston for M-I SWACO, a Schlumberger company. His responsibilities include managing a bioassay laboratory and a greenhouse gas research laboratory and overseeing management of environmental compliance of regional Health, Safety and Environment managers

Summer 2011

around the world. He joined the industry in 1984 as a sales and service representative scientist at IMCO Services Inc., a predecessor of M-I SWACO. John received several President’s Awards from M-I SWACO and a BP Breakthrough Award. He earned a BS degree in civil engineering from Louisiana State University in Baton Rouge, USA. Prabhakaran Centala, based in Houston, is Director of Engineering with Schlumberger. He began his career as a production engineer for quality control in 1984. Since then, he has worked as a lecturer in instrumentation design and numerical control programming at Bangalore University, Karnataka, India, and has held various research and design engineering positions. Prabhakaran received his BS degree in mechanical engineering from University Visvesvaraya College of Engineering in Bangalore. He holds two MS degrees: one in production and manufacturing systems and another in mechanical engineering from University of Maryland, Baltimore County, USA. He has a PhD degree in mechanical engineering in theoretical and experimental mechanics from University of Maryland, Baltimore County. He has authored and coauthored numerous industry technical papers and holds numerous patents pertaining to drill bits and drillbit design. Vennela Challa is an Engineer III in research and development with Schlumberger in Houston. Her responsibilities include investigating field problems using the IDEAS* drillbit design platform, establishing standard processes and analyses definitions and supporting the global i-DRILL* operations group. Previously, she had been a field engineer in training and an i-DRILL engineer with Smith International. Vennela has coauthored numerous technical papers and presentations. She earned a BTech degree in mechanical engineering from Gayatri Vidya Parishad College of Engineering, Andhra Pradesh, India, and a PhD degree in mechanical engineering from Clarkson University, Potsdam, New York, USA. Johana Dunlop is the Global Citizenship Advisor for Schlumberger, Ltd., working in Paris. She oversees the Schlumberger Global Citizenship framework, which focuses on issues relating to the company’s socioeconomic and environmental footprint, the technology solutions Schlumberger brings to bear on sustainability issues and on community outreach programs. In 1992, she joined Geco-Prakla, later a part of WesternGeco, as a risk manager. She took a sabbatical year in 1997 to volunteer in Armenia with Solidarité Protestante France-Arménie, an aid agency financing and operating a range of emergency aid, socioeconomic development and cultural programs. After returning to Schlumberger, she became manager of communications and development for Schlumberger Excellence in Educational Development (SEED), Inc., and subsequently set up the Global Citizenship domain and managed the Schlumberger Foundation, where she started the Faculty for the Future program. Johana received a BA degree (Hons) in French and classics from Trinity College Dublin, Ireland, and an MSc degree in management from Boston University, Massachusetts, USA. She is an Associate of the Institute of Risk Management in the UK.

Bala Durairajan, based in Houston, is an Engineering Manager with Smith Bits, a Schlumberger company. He joined Smith Bits in 2003 as a project engineer and has since held various positions with the company including project engineer, design engineer and supervisor of design engineering, all involving bit design. Bala holds a BS degree in mechanical engineering from the University of Madras, Chennai, Tamil Nadu, India, and an MS degree in mechanical engineering from Wichita State University, Kansas, USA. Ahmed M. El-Toukhy began his career with Schlumberger in 2000 in Libya, where he worked as an openhole logging engineer. He held several operations and management positions in Scotland, Egypt, Canada and the US, including wireline instructor at the Egypt Training Center. From 2009 to early 2011, he was the wireline product champion for tractors and mechanical intervention and is currently based in Perth, Western Australia, Australia, as the Wireline Operations manager for Australia, New Zealand, Papua New Guinea and East Timor. Ahmed received a BSc degree in mechanical engineering with a major in materials and manufacturing engineering and a minor in business administration from The American University in Cairo, Egypt. Andrey Fastovets is Product Champion Submersible Pumps and Cable in Schlumberger Artificial Lift. He started with Schlumberger in 2003 as a field engineer and since then has held various positions in artificial lift operations and in sales and marketing. Andrey is currently responsible for new electric submersible pump (ESP) stages and REDA Maximus* ESP system development, as well as other projects within the conventional ESP application domain. He earned BS and MS degrees (Hons) in petroleum engineering from Gubkin Russian State University of Oil and Gas in Moscow. Joanne Galvan, Global Chemical Regulatory Compliance Manager, began her career in 2004 working for M-I SWACO. She has been in Houston for most of her career, with a two-year assignment in Aberdeen. Joanne manages the Global Chemical Regulatory Compliance group in Schlumberger and is responsible for development, implementation and management of programs and procedures used to maintain regulatory compliance for chemical development and use worldwide. She obtained a BS degree in biology from the University of Texas, San Antonio, USA, and an MS degree in biology and environmental science from the University of Texas, Brownsville. Ian Garrett, based in London, is Senior Drilling Engineer supporting Ghana deepwater drilling operations for Tullow Oil plc. Ian began his career in 1997 with BP Chemicals as an area mechanical engineer based in Baglan Bay, South Wales. From 1999 through 2008, he was a drilling engineer and senior operations drilling engineer for the North Sea, Algeria and Angola deep water with BP Exploration and Production. Ian received a BS degree in engineering and science technology and a diploma in industrial studies from Loughborough University, Leicestershire, England. He is a chartered engineer and member of the Institution of Mechanical Engineers, UK.

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Mohamed K. Hashem is a Senior Petroleum Engineering Consultant at Saudi Aramco, Dhahran, Saudi Arabia. He began his career in 1975 as a production engineer for GUPCO-Amoco in Egypt and left the company as head of the wireline department to join Saudi Aramco as a production engineer in 1981. He earned a BS degree in petroleum engineering from Cairo University, Giza, Egypt. Mohamed has authored several publications in well stimulation, scale mitigation, LWD logging, production logging and logging tool conveyance. Mohamed Hassaan has been Schlumberger Marketing and Sales Manager in Doha since 2008. He began his career in 1996 as a wireline field specialist in Egypt and moved to Libya in 2001 where he was a field engineer. In 2004, he moved to Saudi Arabia where he served as field service manager and cased hole operations manager before transferring to Qatar. Mohamed has a BS degree in electrical engineering and computer science from the Higher Technological Institute, 10th of Ramadan City, Egypt. He holds a patent for a conveyance aid kit used with downhole logging tools. Adun Ige is Schlumberger Product Champion for Surface Equipment and Downhole Gauges in Rosharon, Texas. She is responsible for global product marketing requirements and leads the development and introduction of new products. In 1999, she joined Schlumberger as a well testing engineer in Baku, Azerbaijan, and since has worked at several locations in the US and in Trinidad and Tobago. Adun spent two years as a field engineer recruiter in the US. She obtained a BS degree in electrical engineering from the University of Lagos, Nigeria, and an MBA degree from the Rotterdam School of Management, Erasmus University, the Netherlands. Mukesh Kapila is Director of Environmental Solutions Applied Research for M-I SWACO in Houston. He is responsible for the research, development and engineering of process-based solutions for the treatment and recovery of valuable products from waste generated by oil and gas activities. He began his career in 1985 as a production engineer and worked for several companies, then for several years he was vice president and owner of SCC Environmental, all in Canada. The focus of his company was development of thermalbased technologies for the remediation of hazardous soils and recovery of oil from drill cuttings. Mukesh joined M-I SWACO in 2000, when he became global manager of mixing technologies before assuming his current position. He received a BEng degree in chemical engineering from the University of Saskatchewan, Saskatoon, Canada. Ed Kotochigov, Marketing Manager for Marine Products in WesternGeco, is based in Gatwick, England. His main responsibilities include understanding industry trends and technology positions and introduction of new products. He joined Schlumberger in 1998 as a marine seismic acquisition engineer, working on several seismic vessels and in London and Houston. In 2003, Ed was cross-trained as a reservoir stimulation engineer, and in this role he was a DESC* design and evaluation services for clients engineer for Chevron and BP in Houston. He returned to WesternGeco in 2006 as operations manager in the Arctic and in South

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America. Ed holds an associate’s degree from the American Institute of Business and Economics, Moscow, and an MS degree in geology and geophysics from the Lomonosov Moscow State University. Maria Lorente, located in Sugar Land, Texas, is Wireline Product Champion for new-generation nuclear tools. She began her career at the Schlumberger Riboud Product Center, Clamart, France, in 2001, working with engineering on the EcoScope* logging-while-drilling service project and then moved to wireline field operations in 2004. She has had various assignments in a number of locations, including Abu Dhabi, Qatar, Peru, Colombia, Ecuador and the US. Maria earned a BS degree in electrical engineering from Universitat Politècnica de València, in Spain, and an MS degree in electrical engineering from École Supérieure d'Électricité (Supélec), Gif-surYvette, France. Matthew Loth, based in Clamart, France, is a Schlumberger Product Champion for various products, including testing acquisition software, new pressure gauges and, most recently, the EnACT* wireless telemetry system. He joined Schlumberger in 1996 as a testing field engineer based in Australia and then China. In 2001, he became instructor for Testing Services based in Pau, France. From 2004 to 2006, Matthew was field service manager in Aberdeen, responsible for surface and subsea testing operations. He holds a BSc degree in mechanical engineering (Hons) from The University of Queensland, Brisbane, Australia. Kevin McCarthy, who joined Schlumberger in 2008, is focused on reservoir water characterization and modeling. Based in Houston, he currently heads the Schlumberger efforts to increase the water analysis business. He earned a graduate degree in aqueous geochemistry from the University of South Florida, Tampa, USA. Prior to graduation, he worked as an environmental scientist focused on hydrogeology and water quality issues on various projects in Florida. Kevin has experience on both ends of the altitude spectrum: deepsea hydrothermal research with Woods Hole Oceanographic Institute in Massachusetts, where he conducts hydrogeologic studies on board the submersible Alvin to depths exceeding 3,700 meters; he was also part of the National Aeronautics and Space Administration (NASA) Phoenix Mars Lander mission, analyzing meteorite samples retrieved from Mars during NASA’s search for water on Mars. Richard Meehan joined Schlumberger Cambridge Research, Cambridge, England, in 1985 to work on the physical properties of shales, drillstring vibrations, borehole seismic studies and while-drilling telemetry systems. In 2000, he moved to Sugar Land, Texas, as a section manager for drilling interpretation products. He subsequently became product line manager for drilling software for Schlumberger information solutions in Houston. In 2006, he began as product development manager for drilling software at Schlumberger Beijing Geoscience Center, China. He returned to the US in 2008 as the integration manager for K&M Technology Group in The Woodlands, Texas. Richard is now the Drilling Answer Products Manager for the drilling group. He received a BS degree in mechanical engineering from the University of

Strathclyde in Glasgow, Scotland, and an MS degree in thermal power from the Cranfield Institute of Technology in Bedfordshire, England. Cristina Nicodano is Vice President of Environmental Solutions, Process and Emerging Technologies at M-I SWACO in Aberdeen. She started with Dowell Schlumberger in 1994 as a cementing engineer in Aberdeen and later transferred to Port Harcourt, Nigeria. After working for Terra Expro International Ltd. in Lagos, Nigeria, she joined M-I SWACO, working in Port Harcourt, Dubai and Aberdeen in the Environmental Solutions group. Cristina has a degree as an engineer of industrial technologies, with specialization in technology management, which she earned at Politecnico di Milano, Italy. She also has a master’s degree in management of technological innovation and innovative firm development from a joint program at the Massachusetts Institute of Technology Sloan School of Management, Cambridge, and Politecnico di Milano. Martin Niemann, based in Roissy-en-France, France, is the GeoSciences Group Leader in the Schlumberger Geoservices segment. His work focuses on isotope logging and fluid evaluation while drilling, incorporating geochemical and geologic parameters. Other projects address the application of Geoservices technologies in unconventional resource plays and the incorporation and interpretation of advanced cuttings analyses data for conventional and unconventional reservoirs. He joined Geoservices in 2006. Martin obtained an MSc degree in geosciences from Gottfried Wilhelm Leibniz Universität Hannover, Germany, and a PhD degree in geochemistry from the University of Victoria, British Columbia, Canada. Luis Paez is a Drilling Analysis Manager with Schlumberger and is based in Houston, where he oversees processes for i-DRILL drilling dynamics, DBOS* drillbit optimization system and DBOS real-time application. Luis joined Smith Bits in 1997 as a bit run supervisor. Since then, he has held various technical, engineering and sales positions within the company. He earned a BS degree in petroleum engineering from the Universidad de América, Bogotá, Colombia. He has coauthored numerous technical papers and holds a patent for methods for evaluating and improving drilling operations. Daniel Palmowski is a Senior Geologist for Schlumberger, currently working as a Petroleum System Analyst for Client Consulting in Aachen, Germany. Daniel has a master’s degree in geology from the Technische Universität Braunschweig, Germany, and a PhD in geology from The University of Melbourne, Victoria, Australia. Uyen Partin, based in Houston, is an Engineering Project Manager with Schlumberger. Before joining Schlumberger, Uyen was an engineering supervisor with Smith and, previous to that position, was a consultant with Quorum Business Solutions in Austin, Texas. She has coauthored numerous SPE papers. Uyen obtained a BS degree in mechanical engineering from The University of Texas at Austin.

Oilfield Review

Kenneth Peters is Science Advisor for Schlumberger, based in Mill Valley, California, USA. He has 33 years of experience working for Chevron; Mobil; ExxonMobil; the US Geological Survey; University of California, Berkeley; Stanford University and Schlumberger. He is principal author of The Biomarker Guide (Cambridge University Press, 2005) and leads the Basin and Petroleum System Modeling Industrial Affiliates Program at Stanford University, California. Ken is the 2009 recipient of the Schlumberger Henri Doll Prize for Innovation. He is also the 2009 recipient of the Alfred E. Treibs Award, presented by the Geochemical Society to scientists whose contributions have had a major impact on organic geochemistry. He holds BS and MS degrees in geology from the University of California, Santa Barbara, and a PhD degree in geochemistry from the University of California, Los Angeles. Katherine Rojas joined Schlumberger in 2002 after receiving a doctorate degree in petroleum geochemistry from Newcastle University, Newcastle-upon-Tyne, England. She is currently a Reservoir Fluids Domain Champion at a phase behavior laboratory in Houston where she is involved in setting up commercial reservoir geochemistry services. Previously, she spent time in operations as a well testing field engineer and as geochemistry team lead in the Schlumberger DBR Technology Center, in Edmonton, Alberta, Canada. Katherine received a BS degree in geology from the University of Leeds, England, and an MSc degree in petroleum geochemistry from Newcastle University. Ian Sealy, Schlumberger Environmental Manager in Sugar Land, Texas, is responsible for environmental management systems and environmental programs throughout the Schlumberger organization. He joined Schlumberger in 1979 as a wireline field engineer and worked in field and operations management assignments in Europe and Africa. He then moved to the Health, Safety and Environment organization where he worked in Europe and North America. Ian earned a bachelor’s degree in electronic engineering from University College London. He is in a PhD program at the Centre for Environmental Strategy, University of Surrey, England, doing research in environmental and sustainability management systems. Steven Segal, based in Houston, is the Schlumberger Marketing and Technology Manager for Bits and Advanced Technologies, a position he has held since August 2010. Prior to this, he served as the North America marketing manager for Schlumberger Drilling and Measurements. He joined Schlumberger in 1991 as a field engineer in Aberdeen. Over the past 19 years, he has held numerous field, technical and managerial roles in directional drilling in the US, Abu Dhabi, North Africa, England, Venezuela and Canada. Steven obtained a BS degree in engineering from the Université Paris-Sud 11, Orsay, France, and an MS degree in electrical engineering from the University of Nottingham, England.

Summer 2011

Todor Sheiretov is Conveyance Systems Architect at the Schlumberger Conveyance and Surface Equipment Center in Sugar Land, Texas. He began his career with Schlumberger in 1997 and has worked as development engineer and project manager of downhole tractor projects, including MaxTRAC and TuffTRAC tools, and drillpipe conveyance systems for wireline tools. Before that, he was a mining equipment design engineer for the state-owned Bulgarian ore-mining industry and then worked as an assistant professor at the University of Mining and Geology in Sofia, Bulgaria. Todor earned MS degrees in mechanical engineering from both the University of Mining and Geology in Sofia and the University of Illinois at Urbana-Champaign, USA. He also holds PhD degrees in mining engineering from the University of Mining and Geology in Sofia and mechanical engineering from the University of Illinois at Urbana-Champaign. Paul Sims is a Schlumberger Product Champion based in Clamart, France. He is responsible for leading new product development and the introduction of surface testing and memory gauge technology. He joined Schlumberger in 2004 as a field engineer in Australia before becoming field service manager there and then location manager for East Malaysia, Brunei and the Philippines. Paul received bachelor’s degrees in petroleum engineering and in finance, both from the University of Western Australia in Perth. Artur Stankiewicz, based in Clamart, France, is Schlumberger Reservoir Fluids Domain Head and Advisor for Reservoir Fluids and Geochemistry. Prior to joining Schlumberger in 2010, he worked 12 years for Shell in various positions, most recently as subsurface manager in Abu Dhabi. He previously served as a Shell expert in geochemistry fluid properties and flow assurance. At Shell, he led the development and implementation of asphaltene technology while also pioneering an interdisciplinary focus on hydrocarbon fluid properties via the foundation of the fluid evaluation and sampling technologies (FEAST) team. He worked on numerous R&D projects in the US, the Netherlands and UAE. He has written many articles, books and conference abstracts, and has been an invited lecturer, organizer and chair of numerous international meetings and symposia. Artur is a Treasurer and the Chair-Elect of the European Association of Organic Geochemists (EAOG), a member of SPE and AAPG, and is an SPE Distinguished Lecturer for 2011/2012. He holds an MSc degree in geology from the University of Wrocław, Poland, and a PhD degree in geology and organic geochemistry from Southern Illinois University, Carbondale, USA.

diploma in management studies. He also is a chartered engineer and member of the Institution of Mechanical Engineers, UK. Nick Tetley, based in London, is a Global Accounts Manager with Schlumberger. Since joining Smith Technologies in 1994 as a field engineer based in Aberdeen, he has held various management positions in Europe and Algeria. Nick has authored numerous technical articles and holds a BS degree in chemistry and geology from the University of Exeter, Devon, England, and an MS degree in petroleum engineering from Heriot-Watt University in Edinburgh. Sean (Xianping) Wu, who leads the i-DRILL North America team, is a Schlumberger Engineering Manager. Previously, he was a research engineer with ExxonMobil in Annandale, New Jersey, USA, where he investigated drilling vibrations and advanced materials in high-pressure, high-temperature conditions. He then joined Smith International as engineering advisor before moving to his present position. Sean has coauthored numerous professional papers and delivered lectures on BHA modeling. He has a BS degree in mechanical engineering from the University of Science and Technology of China, Hefei, Anhui, China. He earned a PhD degree in materials sciences and engineering from Drexel University, Philadelphia, Pennsylvania, USA. An asterisk (*) is used to denote a mark of Schlumberger.

Brian Teggart, based in London, is Tullow Oil plc Well Engineering Manager, Ghana Deep Water. He began his career in 1980 as a drilling engineer with Britoil plc, later purchased by BP, where he progressed to drilling manager. He joined Phillips Petroleum as a senior drilling engineer in 2000. From 2001 to 2006, he worked as drilling engineering supervisor and then drilling superintendent for BHP Billiton in Iran, Australia deep water, Algeria and the UK. From 2006 to 2007, Brian worked for BP as senior drilling engineer at the Shah Deniz gas field in Azerbaijan. He obtained a BS degree in mechanical engineering from City University London, where he also earned a

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Coming in Oilfield Review

Modular Intelligent Completions. The true value in intelligent wells— which were originally conceived as a means to avoid costly well interventions—is as a powerful reservoir management tool. Historically, the cost and complexity of this technology have limited its use to remote, highcost or high-risk wells. An innovative approach that produces smaller, less complex, less costly modular intelligent well systems promises to broaden the technology’s application significantly. Gas Shale Revolution. Producing natural gas from organic-rich shales began as a North American phenomenon, driven by tenacity, technology and an increase in commodity pricing. Success beyond the initial Barnett Shale development piqued global interest in this unconventional resource, especially in Europe and Asia. Identifying reservoir-quality rocks for completion is the goal of an industry faced with logistical, technical and political concerns. The article reviews the current state of gas shale globalization as well as the methods used to evaluate gas shale reservoirs and includes case studies integrating diverse aspects from seismic acquisition to stimulation. Open-Channel Fracturing. Conventional fracturing treatments create a fracture and then prop it open with a continuous matrix of proppant that preserves the production pathway. A fundamental advance in the art of reservoir stimulation creates a network of open channels throughout the proppant pack, improving fracture conductivity by orders of magnitude. This article describes the development efforts behind the approach and presents case histories that demonstrate the significant production improvements achieved by applying this technique. Bioturbation. Bioturbation is the disturbance of sediments or soil by living things. Petroleum geologists are interested in bioturbation because it can affect rock porosity and permeability. Geologists also use it to recognize key sequence stratigraphic surfaces and infer characteristics of the depositional environment. Field examples show that the effects of bioturbation, usually identified in core samples, can have significant impact on hydrocarbon production.

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NEW BOOKS

The authors estimate that maintaining affordable energy will require dedicated research to develop four to five CMO per year for the next 50 years. Although they expertly explain technologies related to current energy exploitation, they perhaps unfairly dismiss hydrogen as an energy carrier requiring energy input equal to energy output. Overall, this book makes an important contribution and is a very compelling read. Highly recommended.

A Cubic Mile of Oil: Realities and Options for Averting the Looming Global Energy Crisis

Ferguson RM: Choice 48, no. 6 (February 2011): 1115.

Hewitt D. Crane, Edwin M. Kinderman and Ripudaman Malhotra Oxford University Press 198 Madison Avenue New York, New York 10016 USA 2010. 297 pages. US$ 29.95 ISBN: 978-0-19-532554-6

The authors, who introduce the volumetric measure cubic mile of oil (CMO), estimate that the world’s current annual energy consumption is 3 CMOs—from all energy sources—and project that by midcentury, the world will consume from 6 to 9 CMOs. The book takes an inventory of the world’s various energy sources and how we use them and projects energy development needs to reach that goal. The authors also look at ways to improve efficiency and conservation measures to reduce future energy demand and suggest that the use of a common measure—the CMO—will help create meaningful dialogue among those having to make critical energy policy choices. Contents: • Introduction • Energy Use: Historical Energy Development and Future Dilemmas; Energy Today; Energy Needs to 2050 • Energy Resources: Our Energy Inheritance: Fossil Fuels; Our Energy Inheritance: Nuclear; Our Energy Income: Geothermal, Wind, Solar and Biomass • The Path Forward: Energy Efficiency and Conservation; The Path Forward • Index Visualizing energy resources, production, consumption rates, and future energy demands by utilizing a cubic mile of oil (CMO) as a base unit gives [the authors] . . . a comprehensible measure for national- and global-scale energy relationships. . . .

Physics of the Future: How Science Will Shape Human Destiny and Our Daily Lives by the Year 2100 Michio Kaku Doubleday, a division of Random House, Inc. 1745 Broadway New York, New York 10019 USA 2011. 416 pages. US$ 28.95 ISBN: 978-0-385-53080-4

Kaku interviewed more than 300 experts, scientists and researchers, including 12 Nobel laureates, to offer a glimpse into the next 100 years. Kaku discusses a variety of developments in fields such as medicine, computers, artificial intelligence, nanotechnology, energy production and astronautics. Basing his predictions on known physics and technology prototypes that currently exist, Kaku extrapolates to his vision of the future. Contents: • Introduction: Predicting the Next 100 Years • Future of the Computer: Mind over Matter • Future of AI: Rise of the Machines • Future of Medicine: Perfection and Beyond • Nanotechnology: Everything from Nothing?

• Future of Energy: Energy from the Stars • Future of Space Travel: To the Stars • Future of Wealth: Winners and Losers • Future of Humanity: Planetary Civilization • A Day in the Life in 2100 • Notes, Recommended Reading, Index However bold his view of the future, Mr. Kaku may be treading too carefully. His problem is that technological prognostications sound credible only if underpinned by physics known today. Yet many technologies now taken for granted would have been impossible but for relativity and quantum mechanics, two theories that upended human understanding of the universe early in the 20th century. If history is any guide, thinking that no such revolution will be wrought again is complacent—and probably wrong. On the other hand, scientific theories cannot be predicted; they must be formulated and confirmed. Call it the futurologist’s paradox. “Suspension of Disbelief,” The Economist 398, no. 8724 (March 12, 2011): 98–99.

Do not rage against the machine. Embrace the machine. That is the core message of Michio Kaku’s Physics of the Future. Despite its title, the book is not so much about physics as it is about gadgets and technology. . . . Much of the terrain Mr. Kaku surveys will be familiar to futurists, but less technically oriented readers are likely to find it fascinating—and related with commendable clarity. The changes that Mr. Kaku expects range from the readily foreseeable to the considerably more esoteric. . . . The future belongs to those who show up. Mr. Kaku’s description of that future is an appealing one. But will we show up? Reynolds GH: “Let’s Hope the Robots Are Nice,” The Wall Street Journal (March 23, 2011), http://online.wsj.com/article/SB100014240527487 04433904576213683603852312.html?mod= WSJ_Opinion_LEFTTopOpinion (accessed April 4, 2011).

Oilfield Review

readers will need a solid grounding in college-level math and physics to wade through this intriguing work. Publishers Weekly: “Nonfiction Review,” (March 28, 2011), http://www.publishersweekly. com/978-0-307-26590-6 (accessed July 6, 2011).

Cycles of Time: An Extraordinary New View of the Universe

Roger Penrose Alfred A. Knopf, a division of Random House, Inc. 1745 Broadway New York, New York 10019 USA 2011. 304 pages. US$ 28.95 ISBN: 978-0-307-26590-6

Penrose, a mathematician, explores new views on three of cosmology’s most profound questions: What, if anything, came before the Big Bang? What is the source of order in our universe? What is its ultimate future? He looks at the basic principles that underlie the behavior of the universe and describes various cosmological models, the role of cosmic microwave background and the status of black holes.

Mr. Penrose does not write books that are, by any measure, easy to read. . . . The early chapters just about anyone should be able to follow, and much of the explanatory content is visual, embedded in wonderful drawings drafted in Mr. Penrose’s own hand. But by the end, even experts will have trouble keeping up. . . . Readers should be forewarned that what they have in their hands is un-refereed research of a sort that may very well not pan out and convince other scientists. A surprising and unorthodox work disguised in the jacket of a popular science book, “Cycles of Time” should prove both deeply enlightening and just as deeply mystifying for anyone who dares to follow along. Woit P: The Wall Street Journal, “In the End Is the Beginning,” (May 27, 2011), http://online.wsj. com/article/SB10001424052748703730804576317 072124312488.html?KEYWORDS=Cycles+of+ Time%3A+An+Extraordinary+New+View+of+the +Universe (accessed June 22, 2011).

Contents: • Prologue • Part 1: The Second Law and Its Underlying Mystery • Part 2: The Oddly Special Nature of the Big Bang • Part 3: Conformal Cyclic Cosmology • Epilogue, Appendices, Notes, Index . . . Eminent Oxford mathematician Penrose . . . finds “a profound oddness underlying the Second Law of Thermodynamics and the very nature of the Big Bang” theory of the universe’s origins. In response, he proposes tweaking the old theory to answer these questions. Armed with some fairly hairy math (logarithms, tensor calculus), Penrose argues that increasing entropy, a natural consequence of the Big Bang, supports space-time models in which an increasing number of hungry black holes should yield matter-spewing white holes as well. . . . Although Penrose makes provocative arguments for his challenging new theory (relegating his denser mathematical explorations to the appendixes),

his joy of learning physics and passion for science to the page. Lecture material includes links to his online videos. Contents: • From the Nucleus to Deep Space • Measurements, Uncertainties, and the Stars • Bodies in Motion • The Magic of Drinking with a Straw • Over and Under—Outside and Inside—the Rainbow • The Harmonies of Strings and Winds • The Wonders of Electricity • The Mysteries of Magnetism • Energy Conservation—Plus Ça Change . . . • X-Rays from Outer Space! • X-Ray Ballooning, the Early Days • Cosmic Catastrophes, Neutron Stars, and Black Holes • Celestial Ballet • X-Ray Bursters! • Ways of Seeing • Appendices, Index MIT’s Lewin is deservedly popular for his memorable physics lectures (both live and on MIT’s Open Course Web site and YouTube), and this quick-paced autobiography– cum-physics intro fully captures his candor and lively teaching style. . . . As joyful as Richard Feynman’s Lectures in Physics (but without the math), this text (written with the aid of University of Hartford historian Goldstein) glows with energy and should please a wide range of readers. Publishers Weekly: “Nonfiction Review,” (March 14, 2011), http://www.publishersweekly. com/978-1-4391-0827-7 (accessed July 6, 2011).

For the Love of Physics: From the End of the Rainbow to the Edge of Time—A Journey Through the Wonders of Physics Walter Lewin with Warren Goldstein Free Press, a division of Simon & Schuster, Inc. 1230 Avenue of the Americas New York, New York 10020 USA 2011. 320 pages. US$ 26.00 ISBN: 978-1-4391-0827-7

Walter Lewin, a pioneer in the field of X-ray astronomy and a professor of physics at The Massachusetts Institute of Technology (MIT), came to be known beyond the classroom through his online MIT lectures. In this part memoir, part physics lecture, he brings

A pioneer in the field of X-ray astronomy, the author has been teaching three core physics courses at MIT since 1966, when he first came to the United States from Holland. . . . The lecture material covered in the book—from Galileo to rainbows to sound waves to electromagnetism—is accompanied by online links to videos of his classroom lectures. In the last third of the narrative, he gives a fascinating account of his own experimental work. A delightful scientific memoir combined with a memorable introduction to physics. Kirkus Reviews: “For the Love of Physics,” (March 15, 2011), http://www.kirkusreviews.com/ book-reviews/non-fiction/walter-lewin/ love-physics/#review (accessed May 19, 2011).

Remembering Einstein: Lectures on Physics and Astrophysics

B.V. Sreekantan (ed) Oxford University Press 198 Madison Avenue New York, New York 10016 USA 2010. 148 pages. US$ 35.00 ISBN: 978-0-198-06449-7

In 2005, UNESCO celebrated the World Year of Physics, commemorating the 100th anniversary of Albert Einstein’s publication of the papers that marked a watershed between classical and modern physics. The Nehru Centre, Mumbai, offered a series of lectures that year to mark the anniversary. This book is a compendium of essays based on those lectures. Contents: • Albert Einstein: His Annus Mirabilis 1905 • Einstein and Light Quanta • Einstein and Cosmology • Role of Relatively in Astronomy and Astrophysics • Cosmology and Dark Energy • Einstein’s Dream and String Theory • Space and Time: From Antiquity to Einstein and Beyond • Why Einstein (Had I Been Born in 1844!)? • Bose-Einstein Condensation: When Atoms Become Waves • Contributors, Index The first essay begins with a mention of the literary origin of the phrase ‘annus mirabilis’ and its connection with Isaac Newton’s own annus mirabilis in 1665. It then presents a . . . summary of Einstein’s five publications in 1905. This essay alone makes the book worth having. . . . On the whole, this book is a very readable discussion of Einstein’s early contributions to modern physics that will be treasured by physics students, professionals, and others who wish to learn more about the ideas that originated in those five 1905 papers. Highly recommended. Spero A: Choice 48, no. 5 (January 2011): 944–945.

Summer 2011

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Business Week) puts a human face on the topic and writes a gripping account—whether one reads it cover to cover or consults individual chapters in any order. . . . Highly recommended. Lovejoy DA: Choice 48, no. 6 (February 2011): 1115.

The Strangest Man: The Hidden Life of Paul Dirac, Mystic of the Atom

Graham Farmelo Basic Books, a member of The Perseus Books Group 387 Park Avenue South New York, New York 10016 USA 2011. 560 pages. US$ 18.99 paperback ISBN: 973-0-465-01992-2

Although considered one of the giants of 20th-century physics and a Nobel Prize recipient for physics with Erwin Schrödinger, Paul Dirac has been a virtual unknown. Farmelo brought this many-faceted man to life through an exploration of both his science and his well-known taciturn nature. Farmelo describes Dirac’s breakthrough theories of quantum mechanics as well as his extremely introverted and quirky nature—the author speculates that Dirac may have been autistic—and places Dirac’s insights in the context of the great age of physics. Contents: • Prologue • The Strangest Man • Notes, Bibliography, List of Plates, Index This biography is a gift. It is both wonderfully written . . . and a thoughtprovoking meditation on human achievement, limitations and the relations between the two. Here we find a man with an almost miraculous apprehension of the structure of the physical world, coupled with gentle incomprehension of that less logical, messier world, the world of other people. . . . The science writing in The Strangest Man isn’t glib, but neither does it require problem-solving on the part of the reader. . . . [The] complexities and unresolvably cubist perspectives make, paradoxically, for the most satisfying and memorable biography I have read in years. Gilder L: “Quantum Leap,” (September 8, 2009), http://www.nytimes.com/2009/09/13/books/ review/Gilder-t.html?pagewanted=1 (accessed May 18, 2011).

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The Climate War: True Believers, Power Brokers, and the Fight to Save the Earth Eric Pooley Hyperion 114 Fifth Avenue New York, New York 10011 USA 2010. 481 pages. US$ 27.99

. . . Using a conversational mode, the author makes a case for the reliability of climate models. . . . Cullen, a senior research scientist, . . . predict[s] global warming effects worldwide on a timescale covering the next 40 years. . . . She makes the case that extreme weather events will become even more frequent and devastating. . . . Cullen explains concepts and terms simply but effectively. . . . Current scholarly research documented in footnotes supports her statements. Though she does not discuss the arguments made against the consensus views held by the scientific community, her presentation is thoughtful and reasonable. Highly recommended. Zipp LS: Choice 48, no. 5 (January 2011): 929.

ISBN: 978-1-4013-2326-4

Looking at the intersection of science, business and politics, the author examines the ecology-versus-economy debate and how US climate policies affect every corner of the globe. Pooley describes the personalities, strategies and intrigue of climate politics by going to every source: environmental leaders and radical activists, a coal-company CEO, media personalities, lobbyists, policy makers and politicians. Contents: • Part One: Bali, December 2007 • Part Two: The Deniers’ Convention • Part Three: True Believers • Part Four: An Uneasy Alliance • Part Five: Breaking the Veto • Part Six: Disaster Training • Part Seven: Repower America • Part Eight: Save the Planet? Save the Economy! • Part Nine: The Path • Epilogue: Copenhagen, December 2009 • Sources and Selected Reading, Notes, Index The science behind climate change is solid. Al Gore made that point clear in his 2006 film An Inconvenient Truth, and virtually all mainstream scientists accept it. However, achieving progress in the fight against global climate change is entirely another matter, and the real role of Gore’s film may have been to begin the erosion of corporate America’s single-minded opposition to action on this critical issue. . . . This book is not about the science. It is a fascinating, well-researched, behind-the scenes account of the political twists and turns and efforts of corporate bosses and climate activists. Pooley (editor, Bloomberg

The Weather of the Future: Heat Waves, Extreme Storms, and Other Scenes from a Climate-Changed Planet Heidi Cullen HarperCollins 10 East 53rd Street New York, New York 10022 USA 2010. 329 pages. US$ 25.99 ISBN: 978-0-06-172688-0

Climatologist Cullen predicts global warming scenarios for seven locations around the world through the next four decades. The author uses climatemodel projections to forecast the weather, describes solutions that several entities have already taken to confront climate change and offers various suggestions to implement now to avoid future catastrophe. Contents: • Part I: Your Weather is Your Climate: Climate and Weather Together; Seeing Climate Change in Our Past; The Science of Prediction; Extreme Weather Autopsies and the Forty-Year Forecast • Part II: The Weather of the Future: The Sahel, Africa; The Great Barrier Reef, Australia; Central Valley, California; The Arctic, Part One: Inuit Nunaat, Canada; The Arctic, Part Two: Greenland; Dhaka, Bangladesh; New York, New York • Epilogue: The Trillionth Ton • Appendix 1: United States Climate Change Almanac • Appendix 2: New York Statistics • Appendix 3: The World’s Most Vulnerable Places • Notes, Index

Oilfield Review

DEFINING EXPLORATION

The second in a series of articles introducing basic concepts of the E&P industry

The Search for Oil and Gas Lisa Stewart Executive Editor The earliest users of petroleum did not have to search for it. Most likely they stepped in gooey tar and it stuck to their feet. These first encounters with petroleum were at seeps, where oil and gas, which are less dense than water, rise from subsurface rock formations to the Earth’s surface. Over time, people found practical applications for petroleum, such as weaponry, waterproofing, lighting and medicine. When surface supplies became scarce, people dug into the ground near the seeps to find more, just as they dug wells near springs to find water. Eventually hands, picks and shovels gave way to drilling methods that today can access much deeper resources. Over the years, petroleum geologists learned to look for hydrocarbons not only where they had been found before, but also where conditions were similar to those of earlier discoveries. For example, they noticed that oil and gas were sometimes found in anticlines, where rock formations that were once flat had been folded into an arched structure. Geophysical techniques, such as seismic surveys, were developed to help detect such structures in the subsurface. However, not all anticlines contain hydrocarbons, and hydrocarbons can accumulate in other structures. To organize their knowledge about the occurrence of oil and gas discoveries, explorationists defined the petroleum system as the geologic elements and processes that are essential for the existence of a petroleum accumulation: • Trap—a barrier to the upward movement of oil or gas • Reservoir—porous and permeable rock to receive the hydrocarbons • Charge—including • Source rock—a rock formation containing organic matter • Generation—temperature and pressure conditions to convert the organic matter into hydrocarbon fluids • Migration—buoyancy conditions and pathways for the fluids to move from the source rock into the reservoir • Seal—an impermeable cap to keep the fluids in the reservoir • Preservation—conditions that maintain the nature of the hydrocarbons. When these elements and processes occur in the proper order, chances are good that a petroleum accumulation exists (right). To find promising exploration targets, experts deploy various technologies to quantify the likelihood that all these conditions are met. Exploration integrates the efforts of all types of geoscientists—geologists, geophysicists, petrophysicists, paleontologists and geochemists—into a coherent evaluation of how the petroleum systems in a basin have evolved. The exploration team interprets data from a multitude of physical measurements made at a wide range of scales. Geologists study outcrops to determine the types of rocks that may be present at depth in the basin. They review aerial photography and satellite imagery to find folds, faults and seeps. From well logs, geologists can characterize the nature of subsurface formations and correlate formations from one well to another, creating Oilfield Review Summer 2011: 23, no. 2. Copyright © 2011 Schlumberger. For help in preparation of this article, thanks to Ian Bryant, Houston.

Land plants and animals

Aquatic plants and animals

Sand

Potential source rock

Mud

Seal Reservoir Burial

Structural trap Oil and gas migration

Effective source rock

Heat

> Requirements for a petroleum accumulation. Sediment deposition in the past (top) may lead to hydrocarbon discoveries in the present (bottom). If the geologic elements—trap, reservoir, charge and seal—are present and the processes occur in the proper order (trap formation followed by hydrocarbon generation, migration and accumulation), a hydrocarbon reservoir may exist. In this case, the reservoir contains gas (red) and oil (green).

maps and 3D models of sedimentary basins. Cores, or samples of rocks taken from boreholes, provide ground truth readings on a fine scale. Geophysicists interpret seismic, magnetic and gravimetric surveys performed on land and at sea to identify trapping structures and potential hydrocarbon indicators. By correlating seismic data with information from wells, geophysicists can determine the depth of a prospective structure. Petrophysicists analyze well log data to determine the volume and types of sediments and fluids present and the ability of the rock to produce hydrocarbons. Paleontologists examine Oilfield Reviewfossils to assign ages and depositional environments to rock sequences. Summer 11 Geochemists assess the potential of the source rock to generate petroleum. Exploration Fig. 1

ORSUM11-EXPLRTN Fig. 1

Summer 2011

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DEFINING EXPLORATION

4,000

Probability of Reservoir Presence

300

150

A

6,000

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Isopach Map: Reservoir Thickness

0.5

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Structure Map: Depth to Top of Formation

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> Mapping the chance of success using a play-based exploration methodology. The top of the reservoir-quality sand (left) features four prospects (white outlines) defined by structural highs on a depth map generated by contouring data from four wells (black dots) and five seismic lines (straight black lines). The deepest closing contour defines the limit of each of the prospects. For each of these structurally defined traps, the probability of reservoir, charge and seal must be established. For example, sand thickness is an indicator of reservoir presence. An isopach map, or thickness map, (middle) is generated by contouring sand thicknesses taken from well logs and extended using a geologic conceptual model that assumes the sands were deposited along an ancient shoreline. Where the sands are thin, there is a low probability of the reservoir being present; where they are thicker, there is a high probability. This information is used to convert the thickness map to a chance of success map for reservoir presence (right) scaled in probability units (0 to 1). The larger prospects A, B and C have a low probability that the reservoir is present (red); the smallest prospect D has the highest chance of success (green). Geoscientists construct similar maps for each element of exploration risk then multiply them together to assess the overall risk for each of the prospects.

Some companies have new-venture teams that are always on the lookout The results of these studies can be put into computer simulations called petroleum system models that determine potential accumulation locations, for new basins to explore. Exploration teams frequently begin investigating volume and content, along with information that will be used to judge their an area once the host country announces an upcoming licensing round. A country offers acreage for lease to exploration companies in return for a fee, chances of success. Typically, exploration geologists focus on a particular region to develop royalties and an obligation to perform additional work, such as acquiring a play, or collection of potential petroleum prospects with similar geology. seismic data or drilling wells. The company with the highest bid typically They use the characteristics of previous discoveries to predict the occur- wins the right to explore that lease area. Before bidding, exploration teams rence of similar but undiscovered accumulations. After collecting and inter- attempt to evaluate lease offerings using all available data. If the bid is sucpreting the available data, geologists identify leads, or features of interest, cessful, the company commissions further data-collection campaigns. Then, on which to focus additional data-collection and interpretation efforts. the exploration team integrates the new data with their previously gathered Leads that have been investigated and found to be potential traps for hydro- information to design a drilling program to test the prospect. Oilfield Review An exploration well drilled in a new area is known as a wildcat. A well carbons are designated as prospects. Summer 11 that encounters significant amounts of petroleum is a discovery. If it does Once the prospects in a region have been identified, exploration experts Exploration Fig. 2 rank them according to risk and reward. To optimize their assets, oil and gas not encounter commercial quantities of petroleum, it is a dry hole, which is ORSUM11-EXPLRTN Fig. 2 exploration and production companies strive to maintain a balanced portfo- usually plugged and abandoned. Once a discovery has been made, appraisal lio of projects with outcomes ranging from high risk, high reward to lower wells may be drilled to define the extent of the field. E&P companies are continually testing new ideas in petroleum explorarisk and reward. A key challenge is to understand the range of potential outcomes in a tion. Recently, prolific reservoirs have been discovered in deep ocean prospect, since there are rarely sufficient data for a firm estimate of how basins, where water depths exceed 3,000 m [10,000 ft]. Oil and gas accumumuch oil or gas might be in an undrilled structure. Geologists calculate a lations have been found beneath salt layers hundreds of meters thick. range of volumes of hydrocarbon reserves by combining information on the Companies have also discovered they can tap into source rocks to produce areal extent and thickness of prospective reservoir rock, the expected oil and gas before these fluids are expelled. The secrets to success in all porosity of that rock and the types of hydrocarbon present in the trap these exploration endeavors are talented people and advanced technology. (above). Detailed 3D seismic surveys can provide images of the subsurface to improve these estimates, but only by drilling a well can an exploration company confirm a structure’s content. 60

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