Oilfield Review Winter 2011/media/Files/resources/oilfield...2015-06-23Oilfield Review Winter...

Oilfield ReviewWinter 2011/2012

Reservoir Simulation

Digital Slickline

Wellbore Strengthening

Hybrid Rotary Steerable System

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Over time, but particularly in recent decades, the business of finding and producing hydrocarbons has grown steadily more challenging. Technology and technology applications in nearly all segments of the E&P industry have kept pace with the challenge. As a consequence, the industry’s equip-ment, tools, software and workforce skills have long been and remain at the cutting edge of technology development.

Slickline technology, on the other hand, has defied this trend and has changed little since the inception of slick-line operations, testimony to its suitability for live well intervention. Aside from the recent introduction of battery-powered devices and memory sensors, the tools deployed and the information available to the operator during job execution remain essentially what they have been for decades. As measured by current standards, downhole information from slickline technology has been limited in nature, quantity and availability.

Only recently has there been a significant advance in slickline technology, one that incorporates cutting-edge benefits such as real-time visibility and interaction and control, while maintaining the hallmark slickline advan-tage of simplicity.

Often, in our R&D efforts to improve or develop technology applications, we overdesign and thus build complexity into a technology solution. As a consequence, simplicity can elude us and innovations can become overly complex and less effective than the simple systems from which they originated.

A hybrid approach to innovation recognizes the value of simplicity wherein developers deliver a tool that is simple to use but relies on a high level of sophistication and complex-ity that remains in the background and does not require users’ understanding. Perhaps Steve Jobs’s approach to technology—creating usable tools that are not hindered by their own complexity—is the most prominent example of this concept. But appreciation for the value of simplicity in science is not a recent phenomenon; Leonardo da Vinci called simplicity “the ultimate sophistication.”

It is, in fact, the inherent simplicity of slickline that has allowed it to survive relatively unchanged for these many years. Early attempts to introduce significant change to slickline met with mixed results. Scientists delivered a slick wire that could act as a conductor, but the resulting wire was unable to handle the tensile stresses or perform slickline operations in the environment and mode typically required of it. Ultimately, it could not execute the scope of work for which it was intended.

The idea to build on simplicity rather than compromising it, while not losing sight of the role and advantages of slickline, turned out to be the right path. Using standard slickline as its core, engineers developed LIVE* digital slickline. In addition to performing traditional operations,

Slickline for the Information Age

1

the enhanced slickline enables real-time digital telemetry. This, coupled with other innovative components, provides a plethora of capabilities, each of which can be applied with considerable advantage to the mechanical, remedial and measurement applications of slickline.

Mechanical applications are the most commonly used of slickline services. The ability to deliver relevant, in situ downhole measurement data to the surface in real time promises to have significant impact on those mechanical operations, ensuring operators a means by which to per-form interventions in a more controlled, risk-managed approach. In addition, digital slickline services provide a digital record of all operations—information that is increasingly in demand. Perhaps most importantly, these well intervention advances may play a sizeable role in the industry’s efforts to increase recovery factor.

The idea of insulating a standard slickline to allow digi-tal telemetry is a simple one; achieving it has proved more difficult. The barrier to success was creating an insulated slickline—developing a method for bonding the wire and the insulator so that they would remain intact and opera-tional despite the rigors of repeated bending cycles, high tension stresses and shocks imposed in the inherently hos-tile environments.

After years of attempts, however, engineers have suc-ceeded in delivering a slickline that meets these demands, while providing enhancements and advantages necessi-tated by today’s E&P industry (see “Slickline Signaling a Change,” page 16).

Digital slickline provides many of the advantages of electric line, retains the simplicity and the relatively smaller footprint of traditional slickline and lends itself to well intervention optimization with minimal risk. This remarkable technology is certain to gain a secure place in the industry.

Stuart MurchieMarketing and Technical Manager, SlicklineSchlumberger Oilfield ServicesRoissy-en-France, France

Stuart Murchie began his Schlumberger career in well testing in Aberdeen in 1984 after graduating from the University of Dundee, Scotland, with a BS degree in mechanical engineering. In 1988, he transferred to Wireline, where he held various field operation positions in Asia followed by a posting in Paris as new technology manager for Wireline and Testing. In 1999, he was appointed vice president of Data & Consulting Services, based in Houston. He next served as QHSE manager for Oilfield Services North and South America, then moved to Thailand as the managing director for Oilfield Services Central East Asia. He returned to the UK in 2004 as managing director for Oilfield Services UK and Ireland. In 2005, he became personnel manager for Schlumberger Integrated Project Management, and then regional vice president for the Europe/Africa/Caspian area. Now based in Roissy-en-France, Stuart assumed his current posi-tion as Marketing and Technology Manager for Slickline services in 2011.

An asterisk (*) indicates a mark of Schlumberger.

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www.slb.com/oilfieldreview

Schlumberger

Oilfield Review1 Slickline for the Information Age

Editorial contributed by Stuart Murchie, Marketing and Technical Manager, Slickline, Schlumberger Oilfield Services

4 Reservoir Simulation: Keeping Pace with Oilfield Complexity

The drive to get the most from each reservoir is spurring developers to create increasingly sophisticated reservoir simulators. Whereas the earliest reservoir simulators of the 1930s were physical models containing oil, sand and water, today’s simulators use high-performance computing hard-ware and modern software engineering to handle fields of great complexity, and at great speed. A next-generation sim-ulator integrates several new technologies in one package, including a new well model, advanced gridding, a scalable parallel computing foundation, an efficient linear solver and a field management module. These capabilities help operators make better forecasts and, ultimately, better field development decisions.

16 Slickline Signaling a Change

Slickline has remained essentially unchanged since its incep-tion and, as a logical consequence, so have its uses. The recent introduction of digital slickline promises to change that by combining electric line capabilities with the strengths and simplicity of traditional slickline. Case histories from both the shallow and deep ends of the Gulf of Mexico demonstrate the potential of the new system.

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Executive EditorLisa Stewart

Senior EditorsMatt VarhaugRick von Flatern

EditorTony Smithson

Contributing EditorsDavid AllanTed MoonGinger OppenheimerRana Rottenberg

Design/ProductionHerring DesignMike Messinger

Illustration Chris LockwoodTom McNeffMike MessingerGeorge Stewart

PrintingRR Donnelley—Wetmore PlantCurtis Weeks

Oilfield Review is published quarterly and printed in the USA.

Visit www.slb.com/oilfieldreview for electronic copies of articles in multiple languages.

© 2012 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.

About Oilfield ReviewOilfield 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.

On the cover:

An engineer monitors a downhole tool by interpreting signals delivered to the surface in real time through telemetry provided by digital slickline. The display on the computer screen mounted on the otherwise traditional slickline unit may include data that can be used to confirm a specific downhole action such as per-forating or tool setting, or information such as precise depth, downhole pres-sure and temperature, head tension or other critical measurements.

2

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Winter 2011/2012Volume 23Number 4

ISSN 0923-1730

45 Contributors

47 New Books and Coming in Oilfield Review

50 Defining Completion: The Science of Oil and Gas Well Construction

This is the fourth in a series of introductory articles describing basic concepts of the E&P industry.

52 Annual Index

3

26 Stabilizing the Wellbore to Prevent Lost Circlation

For drillers, lost circulation events, during which whole drilling mud is lost to the formation, can range from nuisance to nightmare. To minimize the risks and nonproductive time associated with lost circulation, the industry has developed a suite of wellbore strengthening materials that work to inhibit fracture growth and keep drilling operations on course.

Lost CirculationFigure 1_4

36 The Best of Both Worlds—A Hybrid Rotary Steerable System

Rotary steerable systems provide a cost-effective, reliable and efficient means for drilling complex wellbore trajectories. However, slower positive displacement motors are still used for drilling high-angle wellbores when build rates exceed the capacity of rotary steerable systems. A hybrid rotary steerable system has been developed that combines the capabilities of drilling high build rates with high rates of penetration.

Control unit

Internal geostationaryrotary valve

Stabilizer blades

Gretchen M. Gillis Aramco Services Company Houston, Texas, USA

Roland Hamp Woodside Energy Ltd. Perth, Australia

Dilip M. Kale ONGC Energy Centre Delhi, India

George King Apache Corporation Houston, Texas

Richard Woodhouse Independent consultant Surrey, England

Alexander Zazovsky Chevron Houston, Texas

Advisory Panel

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

SubscriptionsClient subscriptions can be obtained through any Schlumberger sales office. Clients can obtain additional subscrip-tion information and update subscription addresses at www.slb.com/oilfieldreview.Paid subscriptions are available fromOilfield Review ServicesPear Tree Cottage, Kelsall RoadAshton Hayes, Chester CH3 8BH UKFax: (44) 1829 759163E-mail: [email protected]

Distribution inquiriesTony SmithsonOilfield Review12149 Lakeview Manor Dr.Northport, Alabama 35475 USA(1) 832-886-5217Fax: (1) 281-285-0065E-mail: [email protected]

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4 Oilfield Review

Reservoir Simulation: Keeping Pace with Oilfield Complexity

Geologic complexity and the high cost of resource development continue to push

reservoir simulation technology. Next-generation simulators employ multimillion cell

models with unstructured grids to handle geologies with high-permeability contrasts.

Through the use of more-realistic models, these new simulators will aid in increasing

ultimate recovery from both new and existing fields.

David A. EdwardsDayal GunasekeraJonathan MorrisGareth ShawKevin ShawDominic WalshAbingdon, England

Paul A. FjerstadJitendra KikaniChevron Energy Technology CompanyHouston, Texas, USA

Jessica FrancoTotal SALuanda, Angola

Viet HoangChevron Energy Technology CompanySan Ramon, California, USA

Lisette QuettierTotal SAPau, France

Oilfield Review Winter 2011/2012: 23, no. 4. Copyright © 2012 Schlumberger.ECLIPSE and INTERSECT are marks of Schlumberger.Intel®, Intel386™, Intel486™, Itanium® and Pentium® are registered trademarks of Intel Corporation.Linux® is a registered trademark of Linus Torvalds.Windows® is a registered trademark of Microsoft Corporation.

Interest in simulators is not new. People have long used simulators to model complex activities. Simulation can be categorized into three periods—precomputer, formative and expan-sion.1 The Buffon needle experiment in 1777 was the first recorded simulation in the precomputer era (1777 to 1945). In this experiment, needles were thrown onto a flat surface to estimate the

value of π.2 In the formative simulation period (1945 to 1970), people used the first electronic computers to solve problems for military applica-tions. These ranged from artillery firing solutions to the development of the hydrogen bomb. The expansion simulation period (1970 to the pres-ent) is distinguished by a profusion of simulation applications. These applications range from

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games to disaster preparedness and simulation of artificial life forms.3 Industry and government interest in computer simulation is increasing in areas that are computationally difficult, poten-tially dangerous or expensive. Oilfield simula-tions fit all of these criteria.

Oil and gas simulations model activities that extend from deep within the reservoir to process plants on the surface and ultimately include final economic evaluation (above). Numerous factors are driving current production simulation plan-ning to produce accurate results in the shortest possible time. These include remote locations, geologic complexity, complex well trajectories, enhanced recovery schemes, heavy-oil recovery and unconventional gas. Today, operators must make investment decisions quickly and can no lon-

ger base field development decisions solely on data from early well performance. Operators now want accurate simulation of the field from forma-tion discovery through secondary recovery and final abandonment. Nowhere do these factors come into sharper focus than in the reservoir.

This article describes the tools and processes involved in reservoir simulation and discusses how a next-generation simulator is helping oper-ators in Australia, Canada and Kazakhstan.

Visualizing the ReservoirThe earliest reservoir simulators date from the 1930s and were physical models; the interaction of sand, oil and water could be directly viewed—often in vessels with clear sides.4 Early physical simulators were employed when reservoir behav-

ior during waterfloods surprised operators. In addition to physical simulators, scientists used electrical simulators that relied on the analogy between flow of electrical current and flow of res-ervoir fluids.

In the early 1950s, although physical simula-tors were still in use, researchers were starting to think about how a reservoir might be described analytically. Understanding what happens in a reservoir during production is similar in some respects to diagnosing a disease. Data from vari-ous laboratory tests are available but the com-plete disease process cannot be viewed directly. Physicians must deduce what is happening from laboratory results. Reservoir engineers are in a similar position—they cannot actually view the subject of their interest, but must rely on data to

1. Goldsman D, Nance RE and Wilson JR: “A Brief History of Simulation,” in Rossetti MD, Hill RR, Johansson B, Dunkin A and Ingalls RG (eds): Proceedings of the 2009 Winter Simulation Conference. Austin, Texas, USA (December 13–16, 2009): 310–313.

2. Buffon’s needle experiment is one of the oldest known problems in geometric probability. Needles are dropped on a sheet of paper with grid lines, and the probability of the needle crossing one of the lines is calculated. This

> Production simulation. A reservoir engineer takes static and dynamic data (bottom right ) and develops input for a reservoir simulator (bottom left ). The reservoir simulator, whose primary task is to analyze flow through porous media, calculates production profiles as a function of time for the wells in the reservoir. These data are passed to a production engineer to develop well models and a surface network simulator (top left ). A facilities engineer uses the production and composition data to build a process plant model with the help of a process simulator (top right ). Finally, data from all the simulators are passed to an economic simulator (right ).

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probability is related directly to the value of π. For more information: Weisstein FW: “Buffon’s Needle Problem,” WolframMathWorld, http://mathworld.wolfram.com/BuffonsNeedleProblem.html (accessed July 25, 2011).

3. Freddolino PL, Arkhipov AS, Larson SB, McPherson A and Schulten K: “Molecular Dynamics of the Complete Satellite Tobacco Mosaic Virus,” Structure 14, no. 3 (March 2006): 437–449.

4. Peaceman DW: “A Personal Retrospection of Reservoir Simulation,” in Proceedings of the First and Second International Forum on Reservoir Simulation. Alpbach, Austria (September 12–16, 1988 and September 4–8, 1989): 12–23.

Adamson G, Crick M, Gane B, Gurpinar O, Hardiman J and Ponting D: “Simulation Throughout the Life of a Reservoir,” Oilfield Review 8, no. 2 (Summer 1996): 16–27.

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6 Oilfield Review

tell them what is happening deep below the Earth’s surface. Production and other data are used to build analytical models to describe flow and other reservoir characteristics. In a reser-voir model, the equations that describe fluid behavior arise from fundamental principles that have been understood for more than a hundred years. These principles are the conservation of mass, fluid dynamics and thermodynamic equi-librium between phases.5

When these principles are applied to a reser-voir, the resulting partial differential equations are complex, numerous and nonlinear. Early ana-lytical derivations for describing flow behavior in the reservoir were constrained to simple models, whereas current formulations show a more com-plex picture (below).6 While formulation of the equations for the reservoir has always been straightforward, they cannot be solved exactly

and must be solved by finite-difference methods.7 In reservoir simulation, there is a trade-off between model complexity and ability to con-verge to a solution. Advances in computing capa-bility have helped enhance reservoir simulator capability—especially when complex models and large numbers of cells are involved (next page).8

Computing hardware advances over the past decades have led to a steady progression in simu-lation capabilities.9 Between the early 1950s and 1970, reservoir simulators progressed from two dimensions and simple geometry to three dimen-sions, realistic geometry and a black oil fluid model.10 In the 1970s, researchers introduced compositional models and placed a heavy empha-sis on enhanced oil recovery. In the 1980s, simula-tor development emphasized complex well management and fractured reservoirs; during the 1990s, graphical user interfaces brought enhanced

ease of use. Nearing the end of the 20th century, reservoir simulators added features such as local grid refinement and the ability to handle complex geometry as well as integration with surface facili-ties. Now, simulators can handle complex reser-voirs while offering integrated full-field manage-ment. These models—known as next-generation simulators—have taken advantage of several recently developed technologies, including paral-lel computing.

Parallel Computing—Divide and ConquerOne of the hallmarks of current reservoir simula-tors is the use of parallel computing systems. Parallel computing operates on the principle that large problems like reservoir simulation can be broken down into smaller ones that are then solved concurrently—or in parallel. The shift from serial processing to parallel systems is a direct result of the drive for improved computational performance.

In the 1980s and 1990s, computer hardware designers relied on increases in microprocessor speed to improve computational performance. This technique, called frequency scaling, became the dominant force in processor performance for personal computers until about 2004.11 Frequency scaling came to an end because of the increasing power consumption necessary to achieve higher frequencies. Hardware designers for personal computers then turned to multicore processors—one form of parallel computing.

The kind of thinking that would eventually lead to parallel processing for reservoir simula-tors, however, began around 1990. In an early experiment, oilfield researchers demonstrated that an Intel computer with 16 processors could efficiently handle an oil-water simulation model.12 Since then, the use of parallel computer systems for reservoir simulation has become more commonplace.

As prices for computing equipment have decreased, it has become standard practice to operate parallel computing systems as clusters of single machines connected by a network. These multiple machines, operating in parallel, act as a single entity. The goal in parallel com-puting has always been to solve large problems more quickly by going n times faster on n proces-sors.13 For a host of reasons, this ideal perfor-mance is rarely achieved.

To understand the limitations in parallel net-works, it is instructive to visualize a typical sys-tem used by a modern reservoir simulator. This system might have several stand-alone comput-ers networked through a hub and a switch to a

> Reservoir simulation evolution. One of the first attempts to analytically describe reservoir flow occurred in the early 1950s. Researchers developed a partial differential equation to describe 1D flow of a compressible fluid in a reservoir (top). This equation is derived from Darcy’s law for flow in porous media plus the law of conservation of mass; it describes pressure as a function of time and position. (For details: McCarty DG and Peaceman DW: “Application of Large Computers to Reservoir Engineering Problems,” paper SPE 844, presented at a Joint Meeting of University of Texas and Texas A&M Student Chapters of AIME, Austin, Texas, February 14–15, 1957.) Recent models developed for reservoir simulation consider the flow of multiple components in a reservoir that is divided into a large number of 3D components known as grid cells (bottom). Darcy’s law and conservation of mass, plus thermodynamic equilibrium of components between phases, govern equations that describe flow in and out of these cells. In addition to flow rates, the models describe other variables including pressure, temperature and phase saturation. (For details: Cao et al, reference 6.)


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controller computer and a network server.14 As each of the individual computers works on its portion of the reservoir, messages are passed between them to the controller computer and over the network to other systems. In parallel ter-minology, the individual processors are the paral-lel portions of the system, while the work of the controllers is the serial part.15 The overall effect of communications is the primary reason why ideal performance in parallel systems can be only approached but not realized. All computing sys-tems, even parallel systems, have limitations.

The maximum expected improvement that a parallel system can deliver is embodied in Amdahl’s law.16 Consider a simulator that requires 10 hours on a single processor. The 10-hour total time can be broken down into a 9-hour part that is amenable to parallel processing and a 1-hour part that is serial in nature. For this example, Amdahl’s law states that no matter how many processors are assigned to the parallel part of the calculation, the minimum execution time cannot be less than one hour.

Because of the effect of serial communica-tions, in reservoir simulation there is often an opti-mal number of processors for a given problem. Although the data management and housekeeping parts of the system are the primary reasons for a departure from the ideal state, there are others. These include load balancing between processors, bandwidth and issues related to congestion and delays within various parts of the system. Reservoir simulation problems destined for parallel solution must use software and hardware that are designed specifically for parallel operation.

The Next GenerationSince 2000, a petroleum engineer could choose from a number of reservoir simulators. Simulators were numerous enough that the SPE supported frequent projects to compare them.17 Although the simulators differ from one another, their struc-tures have common roots, which lie in serial com-puting and reliance on simple grids. An example of this type of reservoir simulator is the ECLIPSE simulator.18 The ECLIPSE simulator has been a benchmark for 25 years and has been continually updated to handle a variety of reservoir features. Like microprocessors, however, reservoir simula-tors have reached a point at which the familiar tools of the past may not be appropriate for some current field development challenges.

Scientists have developed new reservoir tools—the next-generation simulators—to broaden the

5. Brown G: “Darcy’s Law Basics and More,” http://bioen.okstate.edu/Darcy/LaLoi/ basics.htm (accessed August 23, 2011).

Smith JM and Van Ness HC: Introduction to Chemical Engineering Thermodynamics, 7th Edition. New York City: McGraw Hill Company, 2005.

6. Cao H, Crumpton PI and Schrader ML: “Efficient General Formulation Approach for Modeling Complex Physics,” paper SPE 119165, presented at the SPE Reservoir Simulation Symposium, The Woodlands, Texas, February 2–4, 2009.

7. Finite-difference equations are used to approximate solutions for differential equations. This method obtains an approximation of a derivative by using small, incremental steps from a base value.

8. Intel Corporation: “Moore’s Law: Raising the Bar,” Santa Clara, California, USA: Intel Corporation (2005), ftp://download.intel.com/museum/Moores_law/Printed_Materials/ Moores_Law_Backgrounder.pdf (accessed October 17, 2011).

Fjerstad PA, Sikandar AS, Cao H, Liu J and Da Sie W: “Next Generation Parallel Computing for Large-Scale Reservoir Simulation,” paper SPE 97358, presented at the SPE International Improved Oil Recovery Conference in Asia Pacific, Kuala Lumpur, December 5–6, 2005.

9. Watts JW: “Reservoir Simulation: Past, Present, and Future,” paper SPE 38441, presented at the SPE Reservoir Simulation Symposium, Dallas, June 8–11, 1997.

10. In the black oil fluid model, composition does not change as fluids are produced. For more information see: Fevang Ø, Singh K and Whitsun CH: “Guidelines for Choosing Compositional and Black-Oil Models for Volatile Oil and Gas-Condensate Reservoirs,” paper SPE 63087, presented at the SPE Annual Technical Conference and Exhibition, Dallas, October 1–4, 2000.

11. Scaling, or scalability, is the characteristic of a system or process to handle greater or growing amounts of work without difficulty. For more information: Shalom N: “The Scalability Revolution: From Dead End to Open Road,” GigaSpaces (February 2007), http://www.gigaspaces.com/files /main/Presentations/ByCustomers/

> Computing capability and reservoir simulation. During the past four decades, computing capability and reservoir simulation evolved along similar paths. From the 1970s until 2004, computer microprocessors followed Moore’s law, which states that transistor density on a microprocessor (red circles), doubles about every two years. Reservoir simulation paralleled this growth in computing capability with the growth in number of grid cells (blue bars) that could be accommodated. In the last decade, computing architecture has focused on parallel processing rather than simple increases to transistor count or frequency. Similarly, reservoir simulation has moved toward parallel solution of the reservoir equations.


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white_papers/FromDeadEndToOpenRoad.pdf (accessed September 13, 2011).

Flynn LJ: “Intel Halts Development of 2 New Microprocessors,” The New York Times (May 8, 2004), http://www.nytimes.com/2004/05/08/business/intel-halts-development-of-2-new-microprocessors.html (accessed Sept 13, 2011).

12. Wheeler JA and Smith RA: “Reservoir Simulation on a Hypercube,” SPE Reservoir Engineering 5, no. 4 (November 1, 1990): 544–548.

13. Speedup, a common measure of parallel computing effectiveness, is defined as the time taken on one processor divided by the time taken on n processors. Parallel effectiveness can also be stated in terms of efficiency—the speedup divided by the number of processors.

14. Baker M: “Cluster Computer White Paper,” Portsmouth, England: University of Portsmouth (December 28, 2000), http://arxiv.org/ftp/cs/00040004014.pdf (accessed July 16, 2011).

Each of these computers in the parallel configuration may have either a single core or multiple core microprocessors. Each individual core is termed a parallel processor and can act as an independent part of the system.

15. The serial portion is often called data management and housekeeping.

16. Barney B: “Introduction to Parallel Computing,” https//computing.llnl.gov/tutorials/parallel_comp/ (accessed September 13, 2011).

17. Christie MA and Blunt MJ: “Tenth SPE Comparative Solution Project: A Comparison of Upscaling Techniques,” paper SPE 66599, presented at the SPE Reservoir Simulation Symposium, Houston, February 11–14, 2001.

18. Pettersen Ø: “Basics of Reservoir Simulation with the Eclipse Reservoir Simulator,” Bergen, Norway: University of Bergen, Department of Mathematics, Lecture Notes (2006), http://www.scribd.com/doc/36455888/Basics-of-Reservoir-Simulation (accessed September 13, 2011).

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technology to handle the greater complexity now present in the oil field. These simulators take advantage of several new technologies that include parallel computing, advanced gridding techniques, modern software engineering and high-perfor-mance computing hardware. The choice between the next-generation simulators and the older ver-sions is determined by field complexity and busi-ness needs. Next-generation tools should be considered if the reservoir needs a high cell count to capture complex geologic features, has exten-sive local grid refinements or has a high permea-bility contrast.

In addition to handling fields of greater com-plexity, the next-generation simulator gives the operator an important advantage—speed. Many reservoir simulations involve difficult calcula-tions that can take hours or days to reach com-pletion using older tools. The next-generation simulators can reduce calculation times on com-plex reservoirs by an order of magnitude or greater. This allows operators to make field devel-opment decisions in time and with confidence, thus maximizing value and reducing risk. Shorter runs lead to more runs, which in turn leads to operators having a better understanding of the reservoir and the impact of geologic uncertain-ties. Shorter run times also allow the simulator to be used more dynamically—it can evaluate development scenarios and optimize designs as new data and information become available.

One of the next-generation tools available now, the INTERSECT reservoir simulator, is the result of a collaborative effort between Schlumberger and Chevron that was initiated in late 2000.19 Total, which also collaborated on the project from 2004 to 2011, assisted researchers in developing the thermal capabilities of the soft-ware. Following the research phase and a subse-quent development phase, Schlumberger released the INTERSECT simulator in late 2009. This sys-tem integrates several new technologies in one package. These include a new well model, advanced gridding, a scalable parallel computing foundation, an efficient linear solver and effective field management. To fully understand this simu-lator, it is instructive to examine each of these parts, starting with the new model for wells.

Multisegment Well ModelThe INTERSECT simulator uses a new multiseg-ment well model to describe fluid flow in the well-bore.20 Wells have become more complex through the years, and models that describe them must reflect their actual design and be able to handle a variety of different situations and equipment. These include multilateral wells, inflow control devices, horizontal sections, deviated wells and annular flow. Older, conventional well models treated the well as a mixing tank that had a uniform fluid com-position, and the models thus reflected total inflow to the well. The new multisegment model over-comes this method of approximation, allowing each branch to produce a different mix of fluids.

This well model provides a detailed descrip-tion of wellbore fluid conditions by discretizing the well into a number of 1D segments. Each seg-ment consists of a segment node and a segment pipe and may have zero, one or more connections with the reservoir grid cells (left). A segment’s node is positioned at the end farthest away from the wellhead, and its pipe represents the flow path from the segment’s node to the node of the next segment toward the wellhead. The number of segment pipes and nodes defined for a given well is limited only by the complexity of the par-ticular well being modeled. It is possible to posi-tion segment nodes at intermediate points along the wellbore where tubing geometry or inclina-tion angle changes. Additional segments can be defined to represent valves or inflow control devices. The optimal number of segments for a given well depends on a compromise between speed and accuracy in the numerical simulation.

An advantage of the multisegment model is its flexibility in handling a variety of well configu-rations, including laterals and extended-reach wells. The model also handles different types of inflow control devices, packers and annular flow. The new multisegment well model is, however, only the beginning of the story on the INTERSECT simulator and others like it. The next step splits the reservoir into smaller areas, called domains.

19. DeBaun D, Byer T, Childs P, Chen J, Saaf F, Wells M, Liu J, Cao H, Pianelo L, Tilakraj V, Crumpton P, Walsh D, Yardumian H, Zorzynski R, Lim K-T, Schrader M, Zapata V, Nolen J and Tchelepi H: “An Extensible Architecture for Next Generation Scalable Parallel Reservoir Simulation,” paper SPE 93274, presented at the SPE Reservation Simulation Symposium, Houston, January 31–February 2, 2005.

For another example of a next-generation simulator: Dogru AH, Fung LSK, Middya U, Al-Shaalan TM, Pita JA, HemanthKumar K, Su HJ, Tan JCT, Hoy H, Dreiman WT, Hahn WA, Al-Harbi R, Al-Youbi A, Al-Zamel NM, Mezghani M and Al-Mani T: “A Next-Generation Parallel Reservoir Simulator for Giant Reservoirs,” paper SPE 119272, presented at the SPE Reservoir Simulation Symposium, The Woodlands, Texas, February 2–4, 2009.

20. Youngs B, Neylon K and Holmes J: “Multisegment Well Modeling Optimizes Inflow Control Devices,” World Oil 231, no. 5 (May 1, 2010): 37–42.

Holmes JA, Byer T, Edwards DA, Stone TW, Pallister I, Shaw G and Walsh D: “A Unified Wellbore Model for Reservoir Simulation,” paper SPE 134928, presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, September 19–22, 2010.

21. DeBaun et al, reference 19.22. Weisstein FW: “Traveling Salesman Problem,” Wolfram

MathWorld, http://mathworld.wolfram.com/Traveling SalesmanProblem.html (accessed October 12, 2011).

23. Karypis G, Schloegel K and Kumar V: “ParMETIS—Parallel Graph Partitioning and Sparse Matrix Ordering Library,” http://mpc.uci.edu/ParMetis/manual.pdf (accessed July 7, 2011).

Karypis G and Kumar V: “Parallel Multilevel k-way Partitioning Scheme for Irregular Graphs,” SIAM Review 41, no. 2 (June 1999): 278–300.

24. Fjerstad et al, reference 8.25. Hesjedal A: “Introduction to the Gullfaks Field,” http://

www.ipt.ntnu.no/~tpg5200/intro/gullfaks_introduksjon.html (accessed September 26, 2011).

>Multisegment well model. For each segment node in a wellbore, the new well model calculates the total flow in (ΣFIN) and total flow out (ΣFOUT), including any flow between the wellbore and the connected grid cell in the reservoir. Assuming a three-phase black oil simulation, there are three mass conservation equations and a pressure drop equation associated with each well segment. During the simulation, the well equations are solved, along with the other reservoir equations, to give pressure, flow rates and composition in each segment.

Oilfield Review WINTER 11/12 Intersect Fig. 4_2ORWNT11/12-INT 4

ΣFIN

ΣFIN

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Domains and a Parallel, Scalable SolverThe calculation of flow within the reservoir is the most difficult part of the simulation—even for simulators using parallel computing hardware. The number of potential reservoir cells is many times larger than the number of processors available. It is natural to parallelize this calculation by dividing the reservoir grid into areas called domains and assigning each one to a separate processor. Partitioning a structured Cartesian grid into seg-ments containing equal numbers of cells while minimizing their surface area may be a straightfor-ward process; partitioning realistic unstructured grids, however, is more difficult (right). Realistic grids must be used to model the heterogeneous nature of a reservoir that has complex faults and horizons. The grids must also have sufficient detail to delineate irregularities such as water fronts, gas breakthroughs, thermal fronts and coning near wells. These irregularities are usually captured by the use of local grid refinements. Partitioning unstructured grids with these complex features and numerous local refinements is challenging; to address this, next-generation simulators typically use partitioning algorithms.21

The objective of partitioning the unstructured grid is to divide the grid into a number of seg-ments, or domains, that represent equal compu-tational loads on each of the parallel processors. Calculating the optimal partitioning for unstruc-tured grids is difficult, and the solution is far from intuitive. Reservoir partitioning is similar to the “traveling salesman problem” in combinato-rial mathematics that seeks to determine the shortest route that permits only one visit to each of a set of cities.22 Unlike the traveling salesman who is concerned only about minimizing his time in transit, partitioning of the reservoir must be guided by the physics of the problem. To this end, the INTERSECT simulator employs the ParMETIS reservoir partitioning algorithm.23 The advan-tages of partitioning a complex reservoir grid to balance the parallel workload become obvious by considering simulation of the Gullfaks field in the Norwegian sector of the North Sea.24

Gullfaks, discovered in 1979 and operated by Statoil, is a complex offshore field that has 106 wells producing about 30,000 m3/d [189,000 bbl/d] of oil.25 This field is highly faulted with deviated and horizontal wells crossing the faults. An INTERSECT simulation of this field developed several domain splits so that different numbers of parallel processors could be evalu-ated for load balancing (right). When compared

> Reservoir grids. Reservoir simulators may lay out the grid in either a structured pattern (upper left ) or as an unstructured pattern (lower right ). Structured grids have hexahedral (cubic) cells laid out in a uniform, repeatable order. Unstructured grids consist of polyhedral cells having any number of faces and may have no discernable ordering. Both grid types partition the reservoir space without gaps or overlaps. Structured grids with many local grid refinements around wells are usually treated as unstructured. Similarly, when a large number of faults are present in a structured grid, it becomes unstructured as a result of the nonneighbor connections created.


Well

Structured Reservoir Grid

Unstructured Reservoir Grid

> Gullfaks domain decomposition. The highly faulted nature of the Gullfaks field and the number of wells and their complexity result in complicated reservoir communication and drainage patterns. The simulator takes these factors into account and develops a complex, unstructured grid in preparation for partitioning (left ). Fine black lines define individual cell boundaries; vertical lines (magenta) represent wells. Different colors denote varying levels of oil saturation from high (red) to low (blue). This unstructured grid is split into eight domains using a partitioning algorithm for an eight-processor simulation (right ). In the partitioned reservoir, different colors denote the individual domains. Only seven colors appear in the figure—one domain is on the underside of the reservoir and cannot be viewed from this angle. The primary criterion for the domain partition is an equal computational load on each of the parallel processors.


Gullfaks Field Unstructured Grid Gullfaks Field Domain Split

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10 Oilfield Review

with an ECLIPSE simulation on Gullfaks using eight processors, the INTERSECT approach decreased computational time by more than a factor of five. Runs with higher numbers of pro-cessors showed similar improvements and con-firmed the scalability of the simulation.

Proper domain partitioning is only part of the next-generation simulation story. Once the reser-voir cells are split to balance the workload on the parallel processors, the model must numerically solve a large set of reservoir and well equations. These equations for the reservoir and wells form a large, sparsely populated matrix (left).

Although the equations generated in the sim-ulator are amenable to parallel computation, they are often difficult to solve. Several factors contribute to this difficulty, including large sys-tem sizes, discontinuous anisotropic coefficients, nonsymmetry, coupled wells and unstructured grids. The resultant simulation equations exhibit mixed characteristics. The pressure field equa-tions have long-range coupling and tend to be elliptic, while the saturation or mass balance equations tend to have more local dependency and are hyperbolic. The INTERSECT simulator uses a computationally efficient solver to achieve scalable solution of these equation systems.26 It is based on preconditioning the equations to make them easier to solve numerically. Preconditioning algebraically decomposes the system into subsys-tems that are then manipulated based on their particular characteristics to facilitate solution. The resulting reservoir equations are solved numerically by iterative techniques until conver-gence is reached for the entire system including wells and surface facilities (left).27

The solver provides significant improvements in scalability and performance when compared with current simulators. A major advantage of this highly scalable solver is its ability to handle both structured and unstructured grids in a gen-eral framework for a variety of field situations (next page, top).

26. Cao H, Tchelepi HA, Wallis J and Yardumian H: “Parallel Scalable Unstructured CPR-Type Linear Solver for Reservoir Simulation,” paper SPE 96809, presented at the SPE Annual Technical Conference and Exhibition, Dallas, October 9–12, 2005.

27. The linear solver consumes a significant share of system resources. In a typical INTERSECT case, the solver may use 60% of the central processing unit (CPU) time.

28. Güyagüler B, Zapata VJ, Cao H, Stamati HF and Holmes JA: “Near-Well Subdomain Simulations for Accurate Inflow Performance Relationship Calculation to Improve Stability of Reservoir-Network Coupling,” paper SPE 141207, presented at the SPE Reservoir Simulation Symposium, The Woodlands, Texas, February 21–23, 2011.

>Matrix structure. A matrix of the linearized reservoir simulation equations is typically sparse and asymmetrical (left ). The unmarked spaces represent matrix positions with no equation, while each dot represents the derivative of one equation with respect to one variable (right ). The nine points inside the red square (right ) represent mass conservation equations for gas, water and oil phases. The points on the off-diagonal (left ) represent equations for connections between cells and their neighboring cells in adjacent layers. Points near the vertical and horizontal axes (left ) represent the well equations.


Column number

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ber

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Equations for cell-nearest neighbors

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>Numerical solution. The complete set of fundamental reservoir equations can be written in finite- difference form (top). These equations describe how the values of the dependent variables in each grid cell—pressure, temperature, saturation and mole fractions—change with time. The equations also include a number of property-related terms including porosity, pore volume, viscosity, density and permeability (see DeBaun et al, reference 19). Numerical solution of this large set of equations is carried out by the Newton-Raphson method illustrated on the graph. A residual function R(x) that is some function of the dependent variables is calculated at x0 (dashed black line marks coordinate position) and x0 plus a small increment (not shown). This allows a derivative or tangent line (black) to be calculated, that when extrapolated, predicts the residual going to zero at x1. Another derivative is calculated at x1 that predicts the residual going to zero at x2. This procedure is carried out iteratively until successive calculated values of R(x) agree within some specified tolerance. The locus of points at the intersection of the derivative line and its corresponding value of x describe the path of the residual as it changes with each successive iteration (red).


xn0 x2 x1 x0

Solution variable x

Tolerance

Resi

dual

, R(x

)

ΔtΔr

Vρ ρρφ( (o + +Soxi gyig SwWiw

_(qo + qg + qw ) + =S

Δxyz Δp ΔPcgo ΔZ( ( _ _oxi + T

kro γoμoρ

γgΔxyz Δp ΔZ( ( _ + gyiTkrgμg

ρ

γw ΔZ (Δxyz Δp ΔPcgo( _ _ ΔPcwo_

wwiTkrwμw

ρ

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Surface networksimulator

INTERSECT field management

Reservoir A, using the ECLIPSE reservoir

simulator

Reservoir B, using the INTERSECT reservoir

simulator

>Multiple reservoir coupling. The field management module can link independent Reservoirs A and B and surface facilities (center ) via network links. In this example, Reservoir A (lower left ) is using the ECLIPSE simulator on a Microsoft Windows desktop computer while Reservoir B (lower right ) is using the INTERSECT system on a Linux parallel cluster. The surface network simulator, running on a Microsoft Windows desktop, is handling surface facilities for this network (upper right ). The FM module (top) that controls all of these simulators may be a desktop or local mainframe computer.

Field Management WorkflowAn improved field management workflow is one of the components of the INTERSECT simulator package. Field management tasks include design of and modifications to surface facilities, sensitivity analyses and economic evaluations. Traditionally, field management tasks have been distributed among the various simulators—including a reservoir simulator, process facilities simulator and economic simulator. The isolation of the simulators in the traditional workflow tends to produce suboptimal field management plans.

The field management (FM) module in the INTERSECT simulator addresses the weaknesses of traditional methods with a collection of tools, algorithms, logic and workflows that allow all of the different simulators to be coupled and run in concert. This provides a great deal of flexibility; for example, the module would allow two isolated, offshore gas reservoirs to be linked to a single surface processing facility for modeling and evaluation.28

At the top level, the module executes one or more strategies that are the focal point of the whole framework. Strategies, which consist of a list of instructions and an optional balancing action, can encompass a wide variety of scenarios that might affect production. These strategies may include factors that affect subsurface deliverability such as reservoir performance, well performance and recovery methods. Other strategies affecting production may include surface capability and economic viability. After the strategy is selected, the FM module employs tools to create a complete topological representation of the field including wells, completions and inflow control devices. Once the strategy has been set and the field topology is defined, the module uses operating targets and limits to set well balancing actions and potential field topology changes. An important feature of the FM workflow is the ability to control multiple simulators running on different machines and operating systems and in different locations (right).

Chevron and its partners used the INTERSECT simulator in their field development of a major gas project off the coast of Australia. The large capital outlays envisioned for this project required a nextgeneration simulator that could run cases quickly on large, unstructured grids characterized by highly heterogeneous geology.

> INTERSECT simulation scalability. This simulation system has been used in a variety of offshore and onshore field scenarios including large gas condensate fields and fields with significant faulting. Scalability—measured as the run time on 16 processors divided by the run time on n processors, or speedup—is calculated as a function of the number of processors. The diagonal straight line (dashed) represents ideal scaling.


16 50

Number of processors, n100 150 200 250 300

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oces

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Ideal scalingFractured carbonate oil fieldHighly faulted supergiant fieldOffshore supergiant fieldMassive gas condensate fieldLarge onshore oil fieldHighly faulted oil field

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> Gorgon project, offshore Australia. The Gorgon project includes the Gorgon and IO/Jansz subsea gas fields that lie 150 to 220 km [93 to 137 mi] off the mainland. Gas is moved from the fields by deep underwater pipelines (black) to Barrow Island, about 50 km off the coast. There, the raw gas is stripped to remove CO2 and then either liquefied to LNG for export by tanker or moved to the mainland by pipeline for domestic use. On the mainland, gas from Barrow Island is transported through an existing pipeline (blue) that gathers gas from other producing areas nearby.


0 km

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Better Decisions—Reduced UncertaintyThe Gorgon project—a joint venture of Chevron, Royal Dutch Shell and ExxonMobil—will pro-duce LNG for export from large fields off the coast of northwest Australia.29 This project will take subsea gas from the Gorgon and IO/Jansz fields and move it by underwater pipeline to Barrow Island about 50 km [31 mi] off the oast (above). Chevron—the operator—is building a 15 million–tonUK [15.2 million–metric ton] LNG plant on Barrow Island to prepare the gas for

export to customers in Japan and Korea. Engineers at Chevron knew that one of the chal-lenges would be to dispose of the high levels of CO2 separated from the raw gas.30 Chevron will meet this challenge by removing the CO2 at the LNG plant and burying it deep beneath the sur-face of Barrow Island (below). Gorgon will be capable of injecting 6.2 million m3/d [220 MMcf/d] of CO2 using nine injection wells spread over three drill centers on Barrow Island.

With billions of dollars of capital and LNG rev-enues at stake, Chevron and its partners under-stood from the start that the engineers developing the business case would need to know how much the project would yield and for how long. Extensive reservoir modeling and simulation were the solutions to this challenge. Some of Chevron’s simulations on an internal serial simu-lator with fine grid models of individual Gorgon formations were taking 13 to 17 hours per run. Early in the project, Chevron decided that migra-tion to the INTERSECT simulator would be required for timely project development.

Although some computer models require a minimal amount of input data, that cannot be said for reservoir simulators. These simulators employ large datasets and typically use purpose-built migrators to move the data from one simula-tor to another. For Gorgon, Chevron used internal migrating software to transform input from their internal simulator to the corresponding INTERSECT input dataset. These data were used to develop history-matching cases at data centers in Houston and in San Ramon, California, USA.31 The results from these cases showed that both simulators were producing equivalent results—although taking very different amounts of CPU time to do it. This process was repeated on high-performance, parallel computing clusters at the Chevron operations center in Perth, Western Australia, Australia.

As Chevron project teams in Australia began advanced project planning, the INTERSECT sim-ulator reduced simulation times by more than an order of magnitude. In one Gorgon gas field simu-lation with 15 wells and 287,000 grid cells, serial run times with the internal simulator were six to eight hours, while the INTERSECT system reduced run times to under 10 minutes with

> CO2 disposal. As natural gas is produced from the various reservoirs in the Gorgon project (left ), it is fed to a CO2 stripping facility located near the LNG plant (middle). Stripped natural gas (orange) flows to liquefaction and an associated domestic gas plant (not shown), while the extracted CO2 (blue) is compressed and injected into an unused saline aquifer 2.5 km [1.6 mi] beneath the surface for disposal. Conditions in the CO2 storage formation are monitored by seismic surveys and surveillance wells (right ).


Gorgon projectgas fields

CO2

CO2 disposal

CO2 stripping

LNG plantLNG product

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excellent scalability. In addition to this simula-tion, Chevron has used the INTERSECT simulator on other fields in the Gorgon area including Wheatstone, IO/Jansz and West Tryal Rocks. Both black oil and compositional models have been used with grids ranging from 45,000 to 1.4 million cells. INTERSECT simulation times on these cases using the Perth cluster ranged from 2 min-utes to 20 minutes depending on the case.

Next-generation reservoir simulation on geo-logic scale models with fast run times has enhanced decision analysis and uncertainty management at Gorgon.

Reducing Simulation TimeReduction of reservoir simulation execution time was also a key factor for Total at their Surmont oil sands project in Canada. Surmont, located in the Athabasca oil sands area about 60 km [37 mi] southeast of Fort McMurray, Alberta, Canada, is a joint venture between ConocoPhillips Canada and Total E&P Canada (right).32 The project was initiated in 2007 with a production of 4,293 m3/d [27,000 bbl/d] of heavy oil; it is expected to reach full capacity of 16,536 m3/d [104,000 bbl/d] in 2012.

At Surmont, the highly viscous bitumen in the unconsolidated reservoir is produced by steam-assisted gravity drainage (SAGD). In this pro-cess, steam is injected through a horizontal well, and heated bitumen is produced by gravity from a parallel, horizontal producing well below the injector. Typically, one steam chamber is associ-ated with each injector and producing well, and a SAGD development consists of several adjacent well pairs.

From a simulations point of view, at the start of SAGD operations, the individual steam cham-bers are independent of each other and simula-tions can be performed on individual SAGD pairs. As the heating and drainage proceed, this inde-pendence between well pairs ceases because of pressure communications, gas channeling and aquifer interactions. Including all well pairs in a typical SAGD development quickly leads to multi-million-cell models that could not be run in a rea-sonable time frame with commercial thermal simulators.33 Total turned to the INTERSECT new-generation simulator to model the full-field, nine-pair SAGD operation at Surmont.

The model describes an oil sands reservoir with an oil viscosity of 1.5 million mPa.s [1.5 million cp] and 1.7 million grid blocks with heterogeneous cell properties.34 The model includes external heat sources and sinks to describe the interaction with

over- and underburden material. The producers are controlled by maximum steam rate, maximum liq-uid rate and minimum bottomhole pressure (BHP). The injectors are controlled by maximum injection rate and maximum BHP.

The INTERSECT system was used to model the first three years of SAGD operations at Surmont

on a parallel computer cluster. To test its speed and scalability, the software was used on different parallel hardware configurations ranging from 1 to 32 processors. These tests proved the ability of this application to handle this large heteroge-neous model quickly enough to support opera-tional decisions. For example, using 16 processors,

29. Flett M, Beacher G, Brantjes J, Burt A, Dauth C, Koelmeyer F, Lawrence R, Leigh S, McKenna J, Gurton R, Robinson WF and Tankersley T: “Gorgon Project: Subsurface Evaluation of Carbon Dioxide Disposal Under Barrow Island,” paper SPE 116372, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Western Australia, Australia, October 20–22, 2008.

30. Raw gas from the Gorgon fields has about 14% CO2.31. To ensure that two reservoir simulators are producing

equivalent results, a user may employ a technique called history-matching. Each simulator will run the same case, and the oil or gas production rates, as a function of time, will be compared. If they match, the two cases are deemed equivalent. This technique can also be used to calibrate a simulator to a field where long-term production data are available.

> Surmont project. The Surmont oil sands project is located southeast of Fort McMurray, Alberta, Canada, within the greater Athabasca oil sands area. Depending on the topography and the depth of the overburden, oil sands at Athabasca may be produced by surface mining or steam-assisted processes such as SAGD.


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Edmonton

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32. Handfield TC, Nations T and Noonan SG: “SAGD Gas Lift Completions and Optimization: A Field Case Study at Surmont,” paper SPE/PS/CHOA 117489, presented at the SPE International Thermal Operations and Heavy Oil Symposium, Calgary, October 20–23, 2008.

33. Total initially tried a commercial, thermal simulator to model operations at Surmont. Case run times were very long—45 hours—making this approach impractical.

34. The oil is modeled using two pseudocomponents— one light and one heavy.

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14 Oilfield Review

the INTERSECT simulator executed the Surmont case in 2.6 hours.35 Parallel scalability is also good—10 times faster on 16 processors compared with a serial run. In addition to predicting flow performance from SAGD operations, the system can also give information on profiles of important variables such as pressure and temperature in the steam chambers (below). In preparation for fully deploying the INTERSECT technology at Surmont, Total is confirming these results on the most cur-rent version of the simulator.

Conserving ResourcesAs operators continue to push into remote areas in search of resources, next-generation simula-tors will be there to aid in planning and develop-ment. A case in point is the new Chevron Tengiz field in the Republic of Kazakhstan, at the shore of the Caspian Sea. Tengiz is a deep, supergiant, naturally fractured carbonate oil and gas field with an oil column of about 1,600 m [5,250 ft] and a production rate of 79,500 m3/d [500,000 bbl/d].36 The Tengiz field is expansive, covering an area of

about 440 km2 [170 mi2], and contains an esti-mated 4.1 billion m3 [26 billion bbl] in place.

The challenge for Chevron in modeling Tengiz was the field’s geologic complexity coupled with the need to reinject large quantities of H2S recov-ered from the production stream. This required combining detailed geologic information with information on the distinctly different flow behaviors between fractured and nonfractured areas of the field. To assist in current field man-agement and support future growth, Chevron developed an INTERSECT case that encom-passed the 116 producing wells. The model con-tained 3.7 million grid blocks in an unstructured grid that included more than 12,000 fractures.37 Chevron has experienced improved efficiency using the new simulator at Tengiz; simulations that once took eight days now take eight hours.38 More-realistic geologic input leads to more-accu-rate production forecasts that allow engineers to make better field development decisions. In addi-tion to their use in the development of new fields, next-generation simulators may also aid recovery of additional oil and gas from older fields.

The world energy markets rely heavily on the giant reservoirs of the Middle East. The largest of these reservoirs—Ghawar—was discovered in 1948 and has been producing for 60 years.39 Ghawar is a large field, measuring 250 km [155 mi] long by 30 km [19 mi] wide. Simulation of a reservoir the size of Ghawar is challenging because of the fine grid size that must be employed to capture the heterogeneities seen in high-resolution seismic data. Using fine grid sizes can reduce errors in upscaling (next page).

To handle reservoirs the size of Ghawar and the other giant fields that it owns, Saudi Aramco has developed a next-generation reservoir simu-lator.40 In one Ghawar black oil simulation, the model used more than a billion cells with a 42-m [138-ft] grid and 51 layers with 1.5-m [5-ft] spac-ing.41 Using a large parallel computing system,

35. This case used 16 processors—four multicore processors each having four cores built into the chip.

36. Tankersley T, Narr W, King, G, Camerlo R, Zhumagulova A, Skalinski M and Pan Y: “Reservoir Modeling to Characterize Dual Porosity, Tengiz Field, Republic of Kazakhstan,” paper SPE 139836, presented at the SPE Caspian Carbonates Technology Conference, Atyrau, Kazakhstan, November 8–10, 2010.

37. The Tengiz simulation also couples the reservoir and well models to surface separation facilities to maximize plant capacities as part of development planning.

38. Chevron Corporation: “Envisioning Perfect Oil Fields, Growing Future Energy Streams,” Next*, no. 4 (November 2010): 2–3.

Chevron is also using the INTERSECT system to reduce run time in field scale models for thermal recovery processes. For more information, see:

> Steam chambers. The nine steam chambers at Surmont are located at a depth of 300 m [984 ft] near the bottom of the oil sands reservoir. These chambers have a lateral spacing of about 100 m [328 ft] and a length of nearly 1,000 m [3,281 ft]. Each chamber has a pair of wells—one steam injector (magenta) and a parallel producing well (not shown). INTERSECT simulation of a thermal process such as SAGD also yields information on temperature profiles in the steam chambers. At Surmont, the temperature varies from more than 230°C [446°F] (red areas) at the core of the chamber to ambient temperature at the periphery (blue areas). Gaps along the length of the chambers reflect permeability differences in the oil sands. The operator monitors temperature in the steam chambers during production. While the steam chambers are relatively small, the SAGD process is efficient. Once the chamber growth reaches the rock at the top of the reservoir, thermal efficiency drops because of heat transfer to the overburden.


10 66

Temperature, °C

122 178 234

Lim K-T and Hoang V: “A Next-Generation Reservoir Simulator as an Enabling Tool for Routine Analyses of Heavy Oil and Thermal Recovery Process,” WHOC paper 2009-403, presented at the World Heavy Oil Congress, Puerto La Cruz, Venezuela, November 3–5, 2009.

39. Afifi AM: “Ghawar: The Anatomy of the World’s Largest Oil Field,” Search and Discovery (January 25, 2005), http://searchanddiscovery.com/documents/2004/afifi01/ (accessed September 29, 2011).

40. Dogru et al, reference 19.41. Dogru AH, Fung LS, Middya U, Al-Shaalan TM, Byer T,

Hoy H, Hahn WA, Al-Zamel N, Pita J, Hemanthkumar K, Mezghani M, Al-Mana A, Tan J, Dreiman W, Fugl A and Al-Baiz A: “New Frontiers in Large Scale Reservoir Simulation,” paper SPE 142297, presented at the SPE Reservoir Simulation Symposium, The Woodlands, Texas, February 21–23, 2011.

42. Dogru AH: “Giga-Cell Simulation,” The Saudi Aramco Journal of Technology (Spring 2011): 2–7.

43. Farber D: “Microsoft’s Mundie Outlines the Future of Computing,” CNET News (September 25, 2008) http://news.cnet.com/830113953_3-10050826-80.html (accessed August 4, 2011).

44. Dogru et al, reference 41.45. Bridger T: “Cloud Computing Can Be Applied for

Reservoir Modeling,” Hart Energy E&P (March 1, 2011), http://www.epmag.com/Production-Drilling/Cloud-Computing-Be-Applied-Reservoir-Modeling_78380 (accessed August 11, 2011).

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this model simulated 60 years of production his-tory in 21 hours.42 The results were compared with an older simulation run using a 250-m [820-ft] grid and a given production plan. The older simulator predicted no oil left behind after sec-ondary recovery; the new simulator revealed oil pockets that could be produced using infill drill-ing or other methods. This example shows how next-generation simulators may facilitate addi-tional resource recovery.

Although a primary goal of next-generation simulators has been to more completely describe reservoirs through reduced grid size and upscaling, scientists are also pursuing other technology innovations. Improved user inter-faces and new hardware options for reservoir simulation are imminent.

These improved user interfaces embody a con-cept known as spatial computing. Spatial comput-ing relies on multiple core processors, parallel programming and cloud services to produce a vir-tual world controlled by speech and gestures.43 This concept is being tested for controlling large

reservoir simulations with hand gestures and ver-bal commands rather than with a computer mouse.44 To test this concept, a room is equipped with cameras and sensors connected to large screens on the walls and a visual display on a table. Using hand gestures and speech, engineers man-age the simulator input and output. If needed, the system can be used in a collaborative manner via a network with engineers and scientists at other locations. This kind of system has vast possibili-ties—it tends to mask computing system complex-ity and allows the engineers and scientists to freely interact with the reservoir simulation.

Just as ideas such as spatial computing will enhance the user interface, new hardware utili-zation concepts that go beyond onsite parallel computing clusters will add to reservoir simula-tion capability. Clusters of parallel computers are expensive and the associated infrastructure is complex and difficult to maintain. Some opera-tors are discovering that it may be useful to use cloud computing to communicate with multiple clusters in many locations.45 Using this approach, the operator can add system capacity as the

situation dictates rather than depending on a fixed set of hardware. This approach allows the user to communicate with the cloud system via a “thin client” such as a laptop or a tablet. Reservoir modeling tools using this technology have already been developed, and more will follow.

New technology for reservoir simulation is emerging on several fronts. Foremost are next-generation reservoir simulators that produce more-accurate simulations on complex fields with reduced execution time. Other technologies such as spatial and cloud computing are on the near horizon and will allow scientists and engi-neers to interact more naturally with the simula-tions and potentially add hardware capability at will. These developments will give operators more-accurate forecasts, and those improved forecasts will lead to better field development decisions. —DA

> Grid resolution. Areal grid size plays an important role in capturing reservoir heterogeneity and eliminating errors caused by upscaling. Overhead photos of the Colosseum in Rome illustrate this concept. If the area of interest is the Colosseum floor (dashed box, upper left), then a 50 m x 50 m [164 ft x 164 ft] grid is appropriate to capture what is required. Choice of a larger 250 m x 250 m [820 ft x 820 ft] grid (dashed box, right) includes driveways, streets, landscaping and other features not associated with the focal point of interest. In the case of the Colosseum, use of the larger grid to capture properties associated with the floor would introduce errors.


250 m

50 m

©2011 Google-Imagery ©2011 Digital Globe, GOIEYE

©2011 Google-Imagery ©2011 Digital Globe, GOIEYE

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16 Oilfield Review

Slickline Signaling a Change

Well intervention techniques have long been dependent on mechanical and

hydraulic systems for actuation and measurement. As a consequence, the outcomes

of many downhole operations—for which depths were often approximate—

depended as much on the skill of the operators as on the design of the tools.

For one intervention method, these limitations were eliminated when engineers

developed digital slickline.

Matthew Billingham Vincent ChateletStuart MurchieRoissy-en-France, France

Morris CoxNexen Petroleum USA Inc.Houston, Texas, USA

William B. PaulsenATP Oil & Gas CorporationHouston, Texas

Oilfield Review Winter 2011/2012: 23, no. 4. Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Blaine Hoover, Buddy Dearborn, Chuck Esponge, Douglas Guillot and Scott Milner, Broussard, Louisiana, USA; Farid Hamida, Rosharon, Texas; and Fabio Cecconi, Pierre-arnaud Foucher and Keith Ross, Roissy-en-France, France.D-Jar, D-Set, DSL, D-Trig, FloView, GHOST, Gradiomanometer, LIVE, LIVE Act, LIVE Perf, LIVE PL, LIVE Seal, LIVE Set, PS Platform, Secure and UNIGAGE are marks of Schlumberger.

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Slickline operations in oil and gas wells have been performed for more than 75 years, and until recently, practices have changed little. Technicians and engineers in the field perform basic downhole operations through manipulation of downhole tools attached to the end of a single-strand thin wire called a slickline; the name dis-tinguishes it from a conducting cable used in electric line or a braided cable used for heavier mechanical work. These downhole operations may be as simple as running a gauge ring to TD or more complex wellbore maintenance and pro-duction optimization procedures such as setting or pulling valves and plugs. Operations also include removing production-hindering debris such as sand or paraffin from the well. More recently, devices with electronic memory have been run on slickline to gather data for pressure transient surveys or production logging.

Slickline has remained a staple of well inter-vention because it is cost-effective, reliable, effi-cient and logistically uncomplicated. It is deployed with relative ease using compact equip-ment that may be moved to and situated at a well-site of nearly any size located anywhere in the world. It may be used in all types of wells, includ-ing HPHT, sour gas, high-angle and flowing. On locations with space or weight limitations, slick-line is often the only feasible intervention option.

But the simplicity of slickline is also the source of its drawbacks. Engineers designed slickline initially to perform rudimentary mechanical operations. At that time, absolute depth was not an essential consideration for such operations. Drillers could not place tools pre-cisely, and as a consequence, it was difficult to verify a tool’s precise downhole location. For some operations, particularly perforating or the setting of isolation tools, knowledge of exact tool depth is critical. Similarly, to ensure sensitive instruments and other tools are not damaged during setting or pulling operations, or to confirm the intended downhole action, it is sometimes imperative that a force—which must fall within a narrow range—be delivered downhole. Using slickline, it is impossible to determine with any certainty exact tool depth or amount of force delivered downhole.

All tubulars, wires and cables stretch to some extent as they are moved into and out of a well. Stretch in slickline wire, however, is significantly greater than that of other conveyance methods. Therefore, depth measurements taken using a mechanical device and displayed at the surface may not accurately represent the tool location. Indeed, displayed information is not a measure-ment of tool depth but of how much wire has been

spooled on or off the drum. As a consequence, the standard accuracy for slickline depth measuring systems is about 30 cm/300 m [1 ft/1,000 ft].1 This degree of accuracy is often sufficient for slickline operations for which depth is reckoned to within a few feet of some fixed point in the completion string. In wells that have no downhole marker, the margin of error may be unacceptable. Engineers have devised systems to correct for stretch as well as other variables, but such corrective measures are based on data estimates only, and sophisti-cated operations typically require more accuracy than these systems could deliver.

In addition, wellbore deviation can cause considerable inaccuracies in the weight indica-

tor readings at the surface; these readings are the only indicator of forces being applied down-hole. Typically, the weight downhole is measured using a load cell attached to a wellhead and then to a pulley through which the slickline is directed from the drum to the top of the lubricator (above). As the angle of deviated wells has increased, along with the number of such wells, there has been a corresponding increase in the frequency and degree of inaccurate weight read-ings. Such depth and weight inaccuracies may

1. King J, Beagrie B and Billingham M: “An Improved Method of Slickline Perforating,” paper SPE 81536, presented at the SPE 13th Middle East Oil Show and Conference, Bahrain, April 5–8, 2003.

> Basic slickline rig-up. A load cell, which is attached to a sheave, is activated by tension in the wire running through the sheave. The wire runs from the slickline drum to the sheave, which redirects it upward at an acute angle. It is turned 180° by a second sheave and fed into the stuffing box where it enters the well through the lubricator. The wireline valve above the Christmas tree contains opposing rams (not shown) that may be closed to seal against each other without removing the wire, thus providing a pressure barrier alternative in the event the stuffing box sealing mechanism fails.

Oilfield Review WINTER 11/12 Slickline Fig. 1 ORWNT11/12-SLKLN 1

Stuffing box

Lubricator

Sheave

Slickline drum

Load cell

Sheave

Christmastree

Wirelinevalve

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18 Oilfield Review

lead to extended operation times or, in more complex well completions, to operational issues. In slickline perforating, for example, placing a gun a few feet above or below target depth may mean the difference between producing water, oil or gas—or nothing at all.

In recent years, engineers have developed numerous improvements to traditional slickline equipment. Most of these are incremental changes applied to tools run on slickline rather than to the wire itself. Battery-powered elec-tronic tools, which acquire and store data in memory, have overcome some slickline shortcom-ings pertaining to actuation and confirmation of downhole actions. But once these tools have been deployed, they do not provide real-time downhole data or give the operator the ability to change settings, such as the depth or temperature at which triggers are activated. As a result, battery-operated tools cannot address the time and effi-ciency shortcomings that characterize many traditional slickline operations.

The most ambitious attempt to overcome these hurdles—using the slickline itself to deliver two-way signals between the tool and the surface—has been pursued for decades. Such a solution could be used to provide operators with precise tool

depth, tool status, downhole weight, wire tension and wellbore data such as pressure and tempera-ture measurements in real time.

Despite many years of effort, manufacturers had been unable to develop an acceptable solu-tion using a slickline wire and equipment. That changed when engineers at Geoservices, a Schlumberger company, developed DSL digital slickline services.

This article describes enhancements made to slickline in the form of battery-powered and memory tools that allow engineers to expand slickline applications to include accurate depth measurements for perforating and production logging. Also discussed is DSL technology, which is an engineering breakthrough, rather than a slickline enhancement. Using telemetry over slickline, coupled with battery-powered elec-tronic tools that incorporate a memory and telemetry interface, DSL services allow com-mands and data communication between the sur-face and downhole without compromising the mechanical integrity of the wire. These features expand slickline capabilities significantly by offering accurate depth correlation, tool status information and tool control to the operator in real time; this is critical to delivering precise, efficient and low-risk operations on slickline-

conveyed mechanical, remedial and measure-ment operations.

Upgrading SlicklineHistorically, depth accuracy has critically limited the scope of slickline operations that use conven-tional measuring devices. The primary factors affecting depth accuracy are elastic stretch, tem-perature, buoyancy, slickline and toolstring fric-tion against the wellbore wall, lift and measuring wheel precision. The variety of sizes and materi-als used for slickline wire may also impact mea-surement readings. The most common slickline wire diameters are 0.092, 0.108 and 0.125 in. [2.34, 2.74 and 3.18 mm]. The materials from which they are manufactured—depending on their application—include carbon steel, stainless steel alloys and nickel- and cobalt-based alloys.2

Elastic stretch—the factor that causes the most variability in slickline depth accuracy—is a function of line tension and the modulus of elasticity of the wire.3 Length measurements may be increased or decreased by out-of-tolerance or poorly calibrated measuring wheel diameters. Changes in measuring wheel diameters can result from wheel wear, debris buildup or the disparity in the temperatures at which the measuring wheel was manufactured or

> Battery-powered tools. The PS Platform service is a suite of battery-powered tools that can perform both memory and surface readout operations. The GHOST gas holdup optical sensor tool (top left) uses four sapphire optical probes to measure gas and liquid holdups, bubble count, average hole caliper measurements and bearing. The Gradiomanometer specific gravity profile tool (top second from left) measures the average density of the wellbore fluid and wellbore deviation, from which water, oil and gas holdups can be derived. The bubble count from the FloView holdup measurement tool (top center) identifies first fluid entry, water holdup and bubble count and includes a centralizer and average hole caliper measurements. The UNIGAGE pressure gauge system carrier (top second from right) contains a crystal quartz gauge that offers the option of a high-resolution pressure measurement. The optional inline spinner (top right ) provides a bidirectional fluid velocity measurement inside the tubing. The basic measurement sonde (bottom left ) provides gamma ray (GR) and casing collar locator (CCL) data for correlation, plus pressure and temperature measurements. The flow-caliper imaging tool (bottom right ) measures the average fluid velocity, water and hydrocarbon holdups and bubble count from four independent probes. It also provides dual-axis X-Y caliper measurements and relative bearing measurements. Well deviation and accelerometer measurements provide the deviation correction for the measured fluid density.

Oilfield Review WINTER 11/12 Slickline Fig. 2ORWNT11/12-SLKLN 2

7.1 ft[2.2 m]

GHOST Tool

Basic Measurement Sonde Flow-CaliperImaging Tool

Gas holdup, gas andliquid bubble count,

average caliper, bearingDensity, deviation

Batteries and recorder, gamma ray,casing collar locator,

temperature, pressureFlowmeter, X-Y caliper,

water holdup, bubble count,relative bearing, centralizer

Water holdup, bubblecount, centralizer,average caliper

Quartz pressuregauge

Flowmeter

FloView Tool UNIGAGECarrier

BidirectionalInline Spinner

GradiomanometerTool

4.8 ft[1.5 m]

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Winter 2011/2012 19

calibrated and the temperature at which it operates. Measurement errors can be in excess of 0.6 m [2.0 ft] at well depths of 3,000 m [10,000 ft].4 Temperature differences in the hole also affect wire length as the wire is lowered into the well. Unless wellbore tem-perature gradients remain constant, or temperature and measurement variations are included in depth corrections, it is difficult to compensate for this vari-able. In addition, buoyancy, friction and lift—which are functions of wellbore parameters such as fluid viscosity, flow rate, fluid type, deviation, tortuosity and wellbore geometry—affect tension measure-ments at the surface.

Although minimal differences in measure-ment occur at shallow depths, discrepancies may increase and become more significant with increasing depth. In recent years, engineers have addressed the depth accuracy issue through the development of electronic measurement devices that attempt to automatically correct for wire stretch.

Another slickline limitation has been the mechanical means by which tools are activated. Engineers addressed this issue through develop-ment of battery-powered tools. These tools, which store downhole data in memory that is accessed once the tool returns to the surface, may perform downhole slickline operations when activated by a timer or a when a signal is generated through a predefined cable movement sequence. Memory devices have been used in remedial services, such as perforating and device setting, and have been used in measurement services such as pro-duction logging, while offering a cost or access advantage over electric line.

Battery-powered electronic triggering can enable safe detonation of explosives used for tub-ing and casing cutting and perforating, and elec-tromechanical setting tools can replace explosive devices. The industry has welcomed electronic fir-ing heads because they can be programmed to dis-arm automatically on retrieval to the surface if the pressure window that is a condition of their arm-ing has been selected correctly.5 These concerns were formerly met using mechanically or hydrauli-cally actuated firing heads.

The industry has also embraced the use of nonexplosive, electronically actuated setting tools

in environments where logistics associated with explosives are restrictive or complex. Firing delays or pressure windows are two examples of safety measures added to traditional devices. But these add complexity and compromise precision because of variations in downhole conditions such as temperature and pressure and because of the time the tool has spent downhole. Electronic firing heads are immune to these variations and provide improved accuracy and control.6

Many services that were performed using elec-tric line or coiled tubing are now possible as slick-line services because of battery-operated tools. These include sensors for pressure, temperature, gamma ray (GR), casing collar locator (CCL), flow-meter, caliper, bubble count, tool orientation, water holdup and gas holdup (previous page).

Despite these improvements, engineers con-tinued to seek the next major advance in slickline capabilities—a method by which they could send signals to, and receive data from, downhole tools in real time. Their objective was to gain the versatility and accuracy of electric line telemetry communication without sacrificing the advan-tages of slickline.

For example, because slickline is a single component it is naturally balanced and so lends itself to operations such as jarring. In contrast, jarring with electric line may lead to destruction of the insulator between the conductor and the cable’s armor.7 Electric line includes an outer and inner set of protective armor wires wound in opposite directions around the central conduc-tors (above right). This creates an inherent torque level within the cable that must be man-aged to avoid wire damage, particularly in deep or highly deviated wells. This damage may take the form of overlapping outer armor, or wires, that quickly wear and break and then hang up in pressure control equipment. When an overlap-ping wire breaks, it unravels as it enters wellhead pressure control equipment, which results in an extensive operation to remove the stranded armor wire.

The sealing mechanism at the top of the slickline lubricator also offers an advantage over that used for braided or electric line. A slickline stuffing box is far less complex than

the grease tube assembly used for braided or electric line. A rubber packing element main-tains a pressure seal even when a wire passes through it (below). It is thus easier to rig up than a braided cable grease-control flow-tube

2. Larimore DR and Kerr WL: “Improved Depth Control for Slickline Increases Efficiency in Wireline Services,” Journal of Canadian Petroleum Technology 36, no. 8 (August 1997): 36–42.

3. Modulus of elasticity is the ratio of longitudinal stress to longitudinal strain.

4. Larimore and Kerr, reference 2.5. A pressure window is a preset condition that allows the

tool to arm only when it is at a pressure greater than surface pressure.

6. Goodman KR, Bertoja MJ and Staats RJ: “Intelligent Electronic Firing Heads: Advancements in Efficiency,

> Armored electric cable. Cables used for electric line, or wireline, operations include multiple armored and insulated conductors. In this case, seven insulated wire conductors are packaged within a semiconductive jacket. The wires and insulators are wrapped in inner and outer sets of armor wound onto the bundle in opposite directions.


Inner armor

Semiconductivejacket

Insulatedconductors

Outer armor

> Simple pressure control. A slickline stuffing box (orange) is a relatively simple sleeve lined with sections of polymer packing (black) that act as a pressure seal against the wire as it moves out of the wellbore, through the pressurized lubricator and the stuffing box, into the atmosphere and up and over the sheave. When tightened, a packing nut (red) compresses the packing against the wire, increasing the sealing force. The same sealing mechanism holds pressure as the slickline is going into the well.


Sheave

Flexibility, and Safety,” paper SPE 103085, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, September 24–27, 2006.

7. Slickline jarring uses a downhole mechanical device called a jar to deliver an impact load to another downhole component. Jars include a lower section attached to a tool or other component, and an upper section that can travel freely. The jar may be opened upward and then quickly lowered to use the weight of the toolstring to deliver a downward blow to the lower section. In reverse, the slickline is reeled in at high speed to deliver an upward force to the lower section of the jar.

44581araD5R1.indd 4 2/17/12 9:36 PM

20 Oilfield Review

assembly, which requires grease to be injected across flow tubes at a pressure greater than that of the wellhead during the entire operation. Electric line operations performed under pres-sure require additional equipment, including a grease pump and a grease supply, which have implications for logistics and the environment. In addition, because moving the line through the grease tubes may break the grease seal, braided cable is restricted to running speeds of about 1,200 to 3,000 m/h [4,000 to 10,000 ft/h] in and out of the well. The mechanical slickline tools can be run at a faster rate without losing the pressure seal, saving valuable rig time.

A Matter of Live and DepthWhile a true slickline telemetry system eluded engineers for decades, they were able to develop a power–telemetry slickline link using coaxial cable. However, because the cable sacrifices the tensile strength and inherent robustness that are essential to slickline applications, the technology has been abandoned.

Developing an insulator was the stumbling block to slickline telemetry, and engineers were further challenged to find a method to bond the insulating material to the wire. In 2002, engi-neers at Geoservices began work on a telemetry system based on previously developed MWD electromagnetic technology. However, telemetry

was not the issue; the challenge was finding an insulating material and a method by which it could be bonded to wire that would allow it to survive the rigors of slickline operations. Initially, the team tested seven polymers, based on their resistance properties, as insulation material can-didates. Under well conditions, however, these coatings did not adhere to the wire.

After years of effort, researchers developed a complex wire-coating material and an exacting bonding procedure. The finished product is made continuous, uniform and with a precise diameter to within 0.002 in. [0.05 mm] throughout its length.8 Applied to standard 0.108- and 0.125-in. [2.74- and 3.25-mm] stainless steel alloy line, the outside diameter of the coated slickline is 0.138 and 0.153 in. [3.51 and 3.89 mm], respectively.

The resulting LIVE digital slickline retains all the strengths of the original wire upon which it is built. The system maintains tool power require-ments delivered from batteries and uses the slick wire as a telemetry conduit rather than as an electrical conduit. Because engineers designed the service to be a digital telemetry system rather than an electrical conduit, they were able to reduce insulation performance requirements and so hasten development. Engineers created another advantage by not sending power through the slickline. This feature eliminates concerns

about transmission reliability through an electric line, associated accessories such as sinker weights and the point at which the wire is con-nected to the toolstring. But the mechanical demands on the insulation-wire bond remain sig-nificant; the wire deployed using standard slick-line equipment must withstand the rigors of spooling on and off the drum, running around sheaves and through pressure-control equip-ment. It must also endure an often punishing downhole environment, and when it emerges from the well through the stuffing box, it is exposed to instantaneous decompression from wellhead to atmospheric pressure.

In 2009, those hurdles had been overcome and the first commercial jobs were performed successfully in Africa, France, Italy and Indonesia. Since that time, various applications within digital slickline services have been per-formed in France, Indonesia, China, the US and Saudi Arabia.

The core of the LIVE toolstring includes the computer baseboard management controller (BMC) that handles the telemetry downhole; delivers surface readouts of shock, line tension, deviation and movement in real time; and con-firms the success of operations such as perforat-ing (below). Surface equipment includes a slickline unit furnished with a computer and transceiver, pressure control equipment and the

> Surface confirmation of detonation. Multiple measurements displayed at the surface show the instantaneous effects of the firing of perforating guns just before 03:29:00. The shock curve (red) indicates a negative acceleration of more than 100 gn. At the same time, head tension (purple) increases from approximately 80 lbf [356 N] to more than 120 lbf [534 N] and pressure (blue) drops from 1,364 psi [9.4 MPa] to about 1,220 psi [8.4 MPa]. Tool movement is apparent on the CCL curve (green) immediately after gun detonation as the tool moves in the tubing, creating voltage across the CCL coil. Oscillation of the cable and gun after detonation is reflected in both the head tension and pressure curves. After the guns are fired, a decrease in temperature (orange) indicates cooler fluid is entering the tubing from the annulus. These indicators are independent verifications that the gun has been detonated on command.


Acce

lera

tion,

gn

CCL,

mV

Tem

pera

ture

, °F

Tubi

ng p

ress

ure,

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1,350

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Time, h:min:s

03:28:45 03:29:00 03:29:15 03:29:30 03:29:45 03:30:00

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Winter 2011/2012 21

digital line. Optional core downhole equipment includes a depth correlation cartridge, which delivers real-time CCL and GR measurements to provide depth accuracy during any slickline ser-vice; a digital pressure-temperature gauge may also be added for downhole measurements.

LIVE digital slickline services are divided into the typical intervention service classifica-tions: mechanical, remedial and measurement.The mechanical LIVE Act digital slickline ser-vices include conventional tools deployed as they would be on a standard slickline. Remedial ser-vices include LIVE Set setting services, which are nonexplosive, hydraulically set plug and retainer services; LIVE Seal sealing services, which use nonelastomeric sealing for monobore comple-tions; and LIVE Perf perforating, punch and pipe cutting services.9 The measurement segment of the service is the LIVE PL comprehensive suite of production logging tools. These services are run in conjunction with the core and optional tools and with real-time measurement and control.

In addition, LIVE services expand on tradi-tional capabilities and requirements by adding the digital D-Jar downhole adjustable jar, which can be commanded to repeatedly activate and deliver a specific force downhole. When using tra-ditional hydraulic or mechanical jars, operators rely on their experience and a weight indicator to determine jar action downhole. The D-Jar tool, in contrast, provides control and efficiency to jar-ring operations without requiring trips to the sur-face to adjust the impact force. It does so through repeated upward jarring using elasticity of the cable to store energy while the jarring action is delivered via the electrically triggered mechani-cal firing function. Downhole tension and shock are measured and monitored at the surface dur-ing operation, which allows an optimized jarring force without unnecessary stress on the tool-string or jarring of components. Engineers set jarring force by adjusting cable tension, which can be reset when and as often as necessary.

The digital controlled release (DCR) tool is another LIVE tool that may be added to any digi-tal slickline operation. In the event the toolstring becomes stuck downhole and cannot be freed, conventional slickline options include using a cutter bar to sever the wire as close to the tool-string as possible. The resulting fishing job may require numerous runs to gather, cut and retrieve any wire that remains in the well, sometimes fol-lowed by attempts using a braided wireline to latch onto and retrieve the stuck tool. This can be problematic if wire remains on top of the object

8. “GEM-Line Goes LIVE,” GeoWorld—The Geoservices Group Magazine 54 (December 2010): 4–7.

9. Punchers are perforating devices designed to penetrate the inner tubing string without damaging the surrounding casing.

being retrieved or the fishing neck has been dam-aged. Often, it requires numerous attempts to determine the nature and amount of the debris that is on top of the stuck tool and to then remove it before the stuck tool can be latched onto and retrieved. In contrast, the DCR tool provides a controlled separation of the toolstring assembly at or near the tool head, which instead of leaving wire behind, leaves only a defined internal and external fishing neck profile (above).

LIVE Set digital slickline setting services pro-vide a means for setting devices such as casing and tubing plugs and cement retainers without using traditional explosives-based systems. Using

> Digital controlled release. In the event a slickline tool becomes stuck, a signal from the surface decouples the DCR tool, allowing the operator to pull the top portion of the tool and all the wire from the hole, leaving clean internal and external fishing neck profiles facing upward (bottom). Depending on the DCR tool’s position in the well, or other factors affecting access, the operator may then use a cable wire or coiled tubing and either a fishing tool with collets that latch an internal profile (left) or an overshot-type tool (right) with collets that latch an external profile to retrieve the stuck tool.


Collet

Collets

Internalfishing

neckExternalfishing neck

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22 Oilfield Review

the surface-controlled D-Set digital electrohy-draulic setting tool, this service allows placement of downhole components on depth (left). This tool is a battery-powered electrohydraulic power unit that can generate up to 25 tons [249 kN] of force—sufficient to set permanent plugs, packers and other devices. Microhydraulics—miniatur-ized hydraulic pumps—can generate this force with limited power in a small package. Engineers control the depth of the tool accurately using a downhole GR and CCL. The D-Set tool uses a battery-powered electrohydraulic pump to gener-ate the power to create pull or movement, or stroke, necessary to set the device. During the setting sequence, diagnostic motor current, tool-string shock and head tension information is sent to the surface to confirm each step of the process.

The retrievable locking mandrel, one of the most versatile tools in the slickline toolbox, allows well intervention in monobore wells or completions with damaged landing nipples. Traditional slickline locking mandrels feature rubber seals that are extruded outward against the tubing wall for pressure containment. They are activated by an inner mandrel that moves downward behind them at the same time it forces slips to move out and grip the tubing. Engineers use these locking mandrels to carry plugs, pres-sure and temperature sensors and other tools to points in the tubing or casing that do not have landing nipples.

Unlike traditional locking mandrels, the LIVE Seal GeoLock digital sealing service uses a non-rubber kinematic sealing mechanism that does not deform when the tool is set (left). It can thus be used in the presence of gas and at high tem-peratures and pressures for prolonged periods—circumstances that often lead to failure of extruded rubber seals—and can be easily retrieved with standard slickline pulling tools. The anchoring and sealing devices maximize the mandrel’s internal flow area and, when retracted, reduce the mandrel OD while running in and out of the hole.

The GeoLock mandrel is run with the D-Set setting tool and a sequence consisting of central-izing, anchoring and sealing. Engineers can mon-itor the procedure from surface using a time plot of the complete sealing sequence. The tool and mandrel use a calibrated shear disk instead of a shear pin, which ensures a fully open flush tube with no internal restrictions once the tool is set.

Digital slickline also includes LIVE Perf perfo-rating services. With these services, operators can confidently and safely cut pipe for recovery, punch tubing and perforate at specified depths. The ser-vice employs the D-Trig digital activation device,

>D-Set electrohydraulic setting tool. The D-Set electrohydraulic unit contains three principal components: a high-temperature lithium battery, an electronics package and a hydraulic power unit (HPU). The lithium battery provides power. The electronics package converts the DC battery output to three-phase alternating current for the HPU’s electric motor and commands the hydraulic circuit. The battery and electronics package are isolated by means of a pressure barrier from the HPU. The HPU, which consists of the electric motor, microhydraulic pump and a solenoid valve is 54 mm [2.1 in.] in diameter by 510 mm [20.1 in.] in length. A smaller 43-mm [1.7-in.] diameter pump can generate nearly 6 tons [60 kN] of force. Within the HPU, the brushless electric motor is coupled to a fixed-displacement, microhydraulic axial piston pump (not shown). The motor is run at high speed for low-torque requirements, such as tool stroke, and switches to low speed for high-torque needs such as setting a tool or shearing a setting stud. Hydraulic pump output is routed to the tool’s mechanical section (not shown) through surface-controlled solenoids.


Microhydraulicpump

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Electricmotor

Pressurebarrier

Electronicspackage

Lithium battery

Hydraulic power unit

> Setting without profiles. With a GeoLock mandrel, tools may be set in smooth tubulars having no internal setting profiles. When the tool is in the running position, the slips and seal elements (inset, bottom) are retracted, which minimizes the mandrel’s outside diameter and allows it to pass through tubing. Once the tool has been run to the desired depth, it is set using a LIVE D-Set digital setting tool or explosive setting tool to compress the tool, forcing cones to travel beneath the slips and seals. This expands the seals (inset, top) against the tubing wall. The mandrel may be retrieved using an electric or hydraulic tool that latches and returns the cones, seals and slips to their original positions.


Cone

Sealelements

set

Sealelementsretracted

Slips

44581araD5R1.indd 7 2/17/12 9:36 PM

Winter 2011/2012 23

which allows surface-controlled activation of both explosive and nonexplosive devices. Like other DSL equipment, the D-Trig device uses the depth correlation cartridge real-time GR or CCL data to achieve accurate depth control. It is equipped with multiple fail-safe systems and is compatible with most industry perforating, punching and set-ting technologies.

The D-Trig activation device represents a sig-nificant advance in slickline triggers because it can be correlated in real time with surface read-out GR and CCL when deployed in combination with the depth correlation cartridge tool (right). This tool can fire all Schlumberger through- tubing perforating guns, hollow carrier guns, casing and tubing cutters and some third-party systems. The D-Trig system can also be used to initiate explosive setting tools.

The combination of the D-Trig system and the baseboard management controller (BMC), and other devices such as a quartz pressure gauge, enhances downhole shot detection. Crews can confidently identify misruns prior to retrieving the tools to surface. Within the BMC, shock detection and head tension changes give conclu-sive evidence that a device has fired. This can also be confirmed with downhole pressure and temperature measurements.

Another safety feature of the D-Trig service is a fuse that can be blown to disarm the trigger under certain conditions including disagree-ment between the microprocessors, drift in clock frequency within electronics, low BMC battery voltage and excessive time gaps in com-munication; the fuse can also be blown by opera-tor command.

When engineers replace high explosives with exploding bridgewire detonators or exploding foil detonators, the system becomes immune to early detonation caused by a number of factors:•radiofrequencyradiation•impressedcurrentcathodicprotection•electricwelding•high-tensionpowerlines.

The introduction of LIVE PL production log-ging services changed the industry’s dependence for these surveys on battery-operated memory tools or electric line. Arguably the most powerful tool for diagnosing the health of a well, produc-tion logs provide in situ measurements that describe the nature and behavior of fluids in the borehole during production or injection; produc-tion logs also help engineers determine which zones are contributing to fluid flow. But at wells with surface locations where space, weight or accessibility limits exclude use of large electric line units, the only option for obtaining a produc-tion log has been a battery-powered memory

slickline tool. The LIVE PL service offers an alternative to the larger electric line unit and delivers more accurate depth correlation than is possible with memory tools; in addition, the ser-vice sends logging data to the surface in real time while simultaneously storing it in memory.

Additionally, when engineers perform tran-sient buildup tests with digital slickline, they can monitor downhole pressure and temperature in real time and detect when the well has reached maximum bottomhole pressure (BHP). Obtaining this information in real time can reduce shut-in times. Data can therefore be used efficiently for reservoir monitoring, updating models and diag-nosing certain individual well conditions such as the existence and location of water sources.

Two for One Combining real-time downhole measurements with traditional slickline creates numerous ben-efits. For example, one operator discovered inherited wellbore schematics were in error. Had engineers chosen to shoot tubing perforations as originally planned, based on depths displayed on the schematic and without a CCL and GR for cor-relation, they would have tried and failed to puncture a blast joint located where the well schematic showed the target tubing joint. In this case, changes were made immediately as the job was progressing based on real-time GR and CCL data seen on the surface, allowing engineers to carry out the operation without additional time and, more importantly, without error.

> Digital trigger. The D-Trig device is controlled by redundant dual microprocessors and incorporates multiple fail-safe systems. A signal sent from surface is received by the tool, which generates a pulse to fire the detonator of the cutter or explosive tool (not shown). The device includes a battery that can fire either third-party exploding bridgewire detonators or Schlumberger Secure detonators. A separate smaller battery is mounted in the baseboard management controller (not shown) to power the electronics within the electronics cartridge. This design allows for a safety fuse to be placed between the firing battery and detonator (not shown) and adds a level of security to operations. In addition, a safety sub is placed between the detonator and the D-Trig tool and includes a safety pressure switch that automatically grounds the detonator when the device is at atmospheric pressure. The D-Trig device shown is electrically plugged into the detonator using a single spring monopin box connection.


Battery

Electronics cartridge

Safety fuse

Safety pressure switch

Spring monopin box connection

44581araD5R1.indd 8 2/25/12 3:30 PM

24 Oilfield Review

In addition to risk management, efficiency and precision advantages, LIVE digital slickline services also enable engineers to perform certain types of jobs—operations that once required use of traditional slickline and electric line with a unit and a crew for each—with a single digital slickline unit and crew. For example, engineers often use both conventional electric line units with surface readouts to gather real-time mea-surements, and a slickline unit to perform mechanical operations on the same well. When performing such interventions in each of four producing zones, engineers traditionally first use a slickline unit to prepare the well for logging by running gauge rings, installing plugs and shifting sliding sleeves. They then run production logs using a separate electric line unit. This move-ment of equipment and personnel can lead to complicated logistics, high costs, increased

potential risks and lengthy operating time. Because LIVE digital slickline services can per-form the full scope of work, the single unit and crew cuts logistics and manpower requirements by half and reduces risks while saving significant overall rig time (above).

ATP Oil & Gas Corporation engineers seeking to capitalize on these efficiencies selected DSL services for a recompletion operation at Eugene Island Block 71, offshore Louisiana, USA. The zone isolation and recompletion operation was performed from the deck of a jackup vessel by first setting a through-tubing cast iron bridge plug and dumping 50 ft [15 m] of cement in 27/8-in. tubing to shut off a depleted lower zone at 12,790 to 12,875 ft [3,898 to 3,924 m].

Once the lower zone was plugged, the opera-tor planned to perforate a shallower interval at 12,668 to 12,678 ft [3,861 to 3,864 m] using six

shots-per-foot perforating guns (next page). Because the shallower target sand was thin, depth precision and accuracy were critical and could be achieved efficiently and in real time through the use of CCL and GR, an option for-merly available only with electric line. Because other parts of the operation, such as dump bail-ing the cement, required slickline tools, two crews would have been required to perform numerous rigging operations and equipment moves on the deck of the vessel. Using the LIVE depth correlation package with the LIVE Perf services, a single unit and crew accomplished the plug back and perforation operations. Total cost as a result of time saved was US$ 80,000 below the original authorization for expenditure.

In this instance, the operator realized savings by reducing the time required to mobilize and move electric line and slickline units on and off the well and around the deck and by eliminating the standby costs associated with a second crew. In other cases, there may be additional savings because space and weight requirements are reduced when only one unit is deployed, allowing the operator to hire a less expensive lift vessel with reduced deck capacity. In some instances, because of the slickline equipment’s relatively small footprint and light weight, an operator may be able to place the unit directly on the deck of a platform too small to accommodate larger, heavier electric line equipment. This may elimi-nate the cost of a service vessel entirely, resulting in significant savings.

Cost reduction as a function of time can quickly multiply depending on environment. For example, in relatively shallow waters, interven-tions may be performed from the deck of lift boats for which the day rate ranges from about US$ 4,000 to as much US$ 40,000 as a function of water-depth capabilities and deck space. However, savings can skyrocket when work is slated for water beyond lift boat depth capabili-ties, which is about 60 m [200 ft], in relatively calm waters such as offshore West Africa and in the Gulf of Mexico. The cutoff depth is even shal-lower in areas of typically rougher waters such as the North Sea.

In deeper waters, an operator may use a semi-submersible or dynamically positioned drilling unit whose costs are much higher than jackup vessels. And in deep and ultradeep water, opera-tors must use specially designed deepwater drill-ing units. The day rate for these giant units is around US$ 1 million. Saving a few days or even a few hours to perform slickline and electric line work can quickly yield significant savings.

> Single-unit logging operation. Typically, operators use a slickline unit to prepare a well for logging by first performing gauge ring runs, installing plugs and locking out the surface-controlled subsurface safety valve (SSV). They then use an electric line unit to acquire production log data. For one typical operation requiring a static pressure gradient, drawdown and shut-in pressure and temperature survey for each producing zone, the operator scheduled the program to take 168 hours using slickline and electric line independently. By using DSL services to perform both conventional slickline and electric line surface readout operations, the operator saved more than 10 hours and eliminated an extra crew and logging unit.


Day

1

2

3

4

5

6

7

Rig up and runfirst gauge ring.

Digital Slickline Slickline Plus Electric Line

Performstatic gradient

survey andfirst shut-in.


survey and flow well.


survey, flow welland perform buildup.

Install plugs, shift sliding sleeves and

run fourth gauge ring.

Perform buildup survey and rig down.

10 hours saved

Run second gauge ring.

Run third gauge ring.

Install plugs, shiftsliding sleeves and run fourth gauge ring.

Close sliding sleeve,install SSV and rig down.

44581araD5R1.indd 9 2/17/12 9:36 PM

Winter 2011/2012 25

In the deepwater Green Canyon area of the Gulf of Mexico, Nexen Petroleum USA leased the deepwater rig Ocean Saratoga to plug and aban-don (P&A) a well in about 900 ft [275 m] of water, about 100 mi [160 km] off the Louisiana coast. Typically, this phase of the P&A operation would have required preparatory work on slickline, fol-lowed by tubing punching and tubing cutting, which require accurate depth correlation using electric line. Nexen engineers turned to digital slickline to perform all P&A operations using a single slickline unit. Their objective for this high-cost environment was considerable savings through operational efficiencies—such as fewer rig-up and rig-down operations.

Digital slickline was used successfully for depth correlation and the subsequent tubing punching operation at 10,030 ft [3,057 m]. Tool shock measurements displayed at the surface in real time clearly indicated the successful firing of the puncher. The operator benefited from the value of a smooth, depth-correlated puncher oper-ation, and as a result, realized significant savings in this high-cost environment. Some of these sav-ings were achieved because the operator was not forced to pay standby costs for two crews when unforseen delays idled the rig for several days.

Executing such interventions with digital slickline instead of electric line also reduces risk because its pressure control equipment is less complex. During pressure control events, if it becomes necessary to cut the line, it is easier to cut slickline than thicker electric line that may be across the wellhead.

A Very Large NicheAs operating environments become increasingly more challenging in places such as the Gulf of Mexico and the North Sea, operators are actively seeking ways to control costs. Digital slickline, which offers the robust simplicity of slickline while maintaining the versatility of electric line, is poised to play a significant role in that quest. Its suitability for P&A operations will no doubt draw particular attention as aging wells in the North Sea and the Gulf of Mexico drive a push by regulators for large-scale platform decommissioning.

Engineers are likely to adopt digital slickline technology as part of a well’s completion strat-egy. It maintains the basic simplicity and famil-iarity of slickline and is thus far less intrusive than other recent innovations such as intelligent completions or monobore wells, whose complex-ity sparked years of resistance from an industry as concerned with the cost of failure as with potential benefits. A failure of an intelligent well or a monobore installation may result in loss of

an entire wellbore and almost certainly in the loss of many thousands of dollars spent in repair costs and delayed production. In contrast, the worst-case scenario of a digital slickline opera-tion failure is lost time while an electric line unit is brought in to finish the job.

In a post-Macondo world, operators are eager to seize any safety advantage, which means the benefits of digital slickline may be more than cost and time savings. Because digital slickline often allows a single crew with a single unit to provide services that once required two units and crews, it can significantly ease personnel and equip-ment movement logistics and thereby enhance safety and reduce environmental risk. This may be especially important in remote locations where transportation is difficult and offshore, where space, weight and environmental consid-erations are paramount.

There are also some simple but important and practical advantages to choosing digital slickline over electric line for certain offshore operations. For example, several industry efforts to develop riserless intervention techniques on subsea wells are ongoing. Slickline may have an edge over wireline in this application because it is very dif-ficult to manage a grease seal during subsea riserless operations. In this environment, the slickline-style stuffing box used in conjunction with digital slickline could prove to be one of the critical components that brings deepwater riser-less intervention into the mainstream. This tech-nology upgrade is long overdue for a service that has been used since the turn of the last century; digital slickline services may soon move from technology trial status to best practice. —RvF

>Wellbore schematic. Operator ATP Oil & Gas decided to plug the reservoir C sand at its Eugene Island Block 71 field and move uphole to perforate the B sand. Because the B sand is just 10 ft [3 m] thick, depth accuracy was critical. Obtaining that level of accuracy traditionally required the use of an electric logging unit for perforating. For this operation, the crew used only a LIVE digital slickline unit to first set a cast-iron bridge plug in the lower tubing string, dump 50 ft of cement on top of it and perforate the casing across the thin B sand precisely on depth. Unless otherwise marked, all depths are measured depth (MD).


60-in. by 48-in. casing at 224 ft

16-in. casing at 810 ft

10 3/4-in. casing at 3,970 ft

75/8-in. casing at 12,032 ft

5 1/2-in. packer at 12,487 ftB sand perforations12,668 ft to 12,678 ft MD12,070 ft to 12,080 ft TVD

C sand perforations12,790 ft to 12,875 ft MD12,144 ft to 12,200 ft TVD

D upper sand perforations13,448 ft to 13,472 ft MD12,588 ft to 12,604 ft TVD

5 1/2-in. packer at 12,700 ft

Cast-iron bridge plug

Isolation packer at 12,886 ft

Isolation packer at 13,311 ft

Sump packer at 13,482 ft

13,802 ft MD12,817 ft TVD

5 1/2-in. casing at 13,802 ft

Sliding sleeve at 12,870 ft

50 ft of cement

Sliding sleeve at 13,449 ft

44581araD5R1.indd 10 2/17/12 9:36 PM

26 Oilfield Review

Stabilizing the Wellbore to Prevent Lost Circulation

Lost circulation—the loss of whole drilling mud to the formation—raises significant

costs and risks to drillers around the world and threatens to pose greater challenges

in the future. The industry is meeting this threat with diverse wellbore strengthening

materials that work by different mechanisms but share a common goal: to stop

fracture growth and keep drilling mud in the wellbore.

John CookCambridge, England

Fred GrowcockOccidental Oil and Gas CorporationHouston, Texas, USA

Quan GuoHouston, Texas

Mike HodderM-I SWACOAberdeen, Scotland

Eric van OortShell Upstream AmericasHouston, Texas

Oilfield Review Winter 2011/2012: 23, no. 4. Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Raul Bermudez, Clamart, France; Jim Friedheim, Houston; Guido Leoni, Ravenna, Italy; and Mark Sanders, Aberdeen. Losseal is a mark of Schlumberger.MPSRS is a mark of M-I, l.l.c.

Over the past century, the oil and gas industry has made great strides in developing drilling tech-nologies and techniques that make well construc-tion a cost-effective and safe enterprise. However, as new hydrocarbon sources are found in increas-

ingly remote and geologically complex reservoirs, the industry continues to develop technologies to meet wellbore integrity challenges that present safety hazards and economic risks to the long-term viability of a well.

1. Dodson T: “Identifying NPT Risk,” Keynote presentation at the Atlantic Communications Drilling and Completing Trouble Zones Forum, Galveston, Texas, USA, October 20, 2010.

2. Redden J: “Advanced Fluid Systems Aim to Stabilize Well Bores, Minimize Nonproductive Time,” The American Oil & Gas Reporter 52, no. 8 (August 2009): 58–65.

3. Growcock F: “Lost Circulation Solutions for Permeable and Fractured Formations,” Proceedings, Southwestern Petroleum Short Course 54 (2007): 175–181.

4. ECD is a function of the hydrostatic head generated by the mud density and the frictional pressure losses that the mud pump must overcome to move fluid and cuttings up the wellbore.

> Comprehensive lost circulation management program. The bottom three tiers of the pyramid focus on lost circulation prevention. Best drilling practices may encompass implementing accurate geomechanical models to calculate the risk of hole collapse or lost circulation and may also make use of expandable casing, managed pressure drilling or casing-while-drilling techniques. Drilling fluid selection includes the implementation of drilling fluid with the proper rheological properties to minimize or cure lost circulation. Wellbore strengthening materials consist of specially formulated and sized particulate materials that enter a fracture and arrest its propagation by isolating it from the wellbore. The top tier is devoted to remediating losses though the use of lost circulation materials such as cure or stop-loss pills.


1-column = 2.34 inches wide1 1/2-column = 3.67 inches wide2 column = 4.84 inches wide3 column = 7.34 inches wide

Setup 1.5 hrsFig 1 11.0Fig 2 1.5

14.0 - 910.00

Lost circulation materials

Remediation

Prevention

Wellbore strengthening materials

Drilling fluid selection

Best drilling practices

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Winter 2011/2012 2727

In the Gulf of Mexico alone, wellbore integrity issues in the form of stuck pipe, wellbore collapse, sloughing shales and lost circulation account for as much as 44% of nonproductive time (NPT) that prevents progress of the drill bit toward its target.1 The financial ramifications of wellbore integrity–related NPT are so great that operators may add 10% to 20% to authorizations for expenditures to cover the anticipated downtime.2

Lost circulation, in which drilling fluid, or mud, flows partially or completely into a forma-tion through areas known as thief zones, is a com-mon contributor to NPT (right). These zones effectively steal drilling fluid from the wellbore. Although the fluid has several purposes, those most affected by lost circulation are the needs to maintain hydrostatic pressure in the annulus and prevent formation fluids from entering the bore-hole during the drilling process.

To counter this phenomenon, a comprehen-sive lost circulation management program pro-vides a staged approach to mitigating fluid losses, depending on the severity of the problem. One such approach is a four-tiered strategy consisting of both prevention and remediation measures (previous page). Industry experience has proved that it is often easier and more effective to pre-vent the occurrence of losses than to attempt to stop or reduce them once they have started.

Fluid losses occur typically through fractures induced by the drilling process. These fractures tend to propagate easily because the pressure required to lengthen a fracture is often lower than that required to initiate it.3 Therefore, remediation is commonly considered a contin-gency to be used only after preventive measures have failed.

This article reviews the drilling conditions that contribute to lost circulation events and explains why lost circulation threatens to become a greater contributor to NPT than it has been in the past. The article also discusses lost circula-tion prevention through the use of wellbore strengthening materials and describes various schools of thought within the industry on mecha-nisms for stabilizing the wellbore and preventing fracture propagation.

Lost Circulation FundamentalsLost circulation events arise most commonly as a consequence of the method used to drill a well. Traditionally, wells are drilled in an overbalanced condition in which drilling fluid, or mud, is circu-lated down the drillstring, through the bit and up the annulus.

Mud weight, or density, is the primary source of hydrostatic pressure in a well. When circulat-ing through the wellbore, the mud contributes to a pressure in the wellbore that can be expressed in terms of the equivalent circulating density (ECD).4 In an overbalanced state, this ECD helps create a hydrostatic pressure in the wellbore that is greater than the pore pressure of the exposed formation. A drilling fluid of insufficient density may yield a hydrostatic pressure that is lower than the pore pressure. This may lead to a kick: an unplanned influx of formation fluids into the wellbore. Most kicks are managed using established well kill operations, but in rare instances an uncontrolled kick may manifest itself in the form of a blowout, with associated

risks to wellhead equipment and potential injury to rig personnel.

Other obstacles to the safety and economic viability of the well may arise if the hydrostatic pressure is too low to support the rock face at the wellbore. Drilling mud must be heavy enough to counter the instability in the borehole that is created when rock is removed through the drilling process. If the driller selects a drilling mud of insufficient density, the result may be wellbore instability and, in extreme cases, well-bore collapse.

Conversely, a drilling fluid with an excessively high mud weight exerts a hydrostatic pressure that may exceed the formation’s mechanical

>Mechanisms for drilling fluid egress from the wellbore. During circulation of drilling mud back to the surface (green arrows), the fluid comes into contact with the wellbore. In traditional drilling practices, the pressure in the wellbore exceeds that of the formation, which prevents formation fluids from entering the wellbore. In one method of fluid loss from the wellbore, a filtration process takes place in the permeable rock, whereby the liquid component of the drilling mud moves into the rock, leaving the solid particulates and emulsion droplets to collect on the wellbore wall and form a filtercake. The low permeability of this cake keeps the volume of fluid lost by leakoff very low, and this is not considered a lost circulation event. Lost circulation occurs if the rock is naturally fractured, vugular or highly porous. If the wellbore pressure is higher than the rock’s tensile strength, fractures will form. Each of these cases results in the loss of large volumes of drilling fluid (white arrows) into thief zones. In severe cases, an appreciable quantity, or even all, of the drilling fluid enters the formation, propagating further fracture growth (inset).

FiltercakeWellbore

Fracture


Fluid losses

Thief zone

Fluid leakoff

Filtercake

Fracture

Wellbore cross section

Formation

Drillingfluidflow

Drillpipe

44581araD6R1.indd 2 2/21/12 12:00 AM

28 Oilfield Review

integrity, forcing drilling fluid into natural frac-tures (above). Naturally occurring fractures may be present in any type of formation, but they occur most commonly in geologic settings with ongoing tectonic activity.

Lost circulation management can also be quite challenging when fractures are induced during the drilling process.5 Fracture creation results from tensile failure, which occurs when the stress exerted on the formation exceeds the

hoop stress around the wellbore and the tensile strength of the rock, most commonly because of excessive mud density or wellbore pressure.6

Typically, a pressure-integrity or extended leakoff test (XLOT) measures the ability of the for-mation and wellbore to sustain pressure. Engineers conduct the test after a new casing string has been run and cemented, immediately after drilling out beneath the casing shoe. To initiate the test, the rig crew shuts in the well and pumps fluid into the wellbore to gradually increase the pressure exerted on the formation (below left).

The driller must stay within a pressure regime that avoids a kick or a lost circulation event; an XLOT can provide insight into that pressure regime. The upper limit on ECD is typically repre-sented by the fracture gradient (FG), the pres-sure in the well that would cause the surrounding formation to fracture, creating potential loss of fluid from the well. FG is not defined precisely; some drillers identify FG as the pressure at which a fracture is initiated (Pleakoff), others may select the more conservative value of the fracture clo-sure pressure (Pclosure), and some select a pres-sure for FG between these two parameters.

The lower limit on ECD is normally deter-mined by either the pore pressure (Ppore) or the wellbore collapse pressure (Pcollapse), below which the flow of formation fluids into the wellbore causes causes such severe mechanical instability problems that operations must be modified or halted. The range between the upper and lower limits is the mud weight window or drilling margin. These upper and lower limits are influenced by in situ rock stress orientations and magnitudes, pore pressure, rock strength and wellbore orientation. These parameters vary with wellbore depth and act to significantly change the size of the mud weight window (next page, left).

To avoid lost circulation or wellbore instability events, drillers pay close attention to maintaining the ECD within the confines of the mud weight window. Failure to do so causes the wellbore’s physical stability to change along a continuum of possible profiles, ranging from formation fluid influx to severe or total drilling fluid losses and even wellbore collapse (next page, right).

Whether lost circulation occurs while drilling, running casing, or completing and cementing the well, its impact on well construction costs is sig-nificant, representing an estimated US$ 2 to 4 bil-lion annually in lost time, lost drilling fluid and materials used to stem the losses. The US Department of Energy reports that on average 10% to 20% of the cost of drilling high-pressure, high-temperature wells is expended on mud losses.7

> Types of lost circulation events. The upper formation experiences loss of drilling mud (white arrows) into natural fractures that were intersected by the wellbore. The middle formation exhibits the propagation of a fracture that was hydraulically induced by the drilling process. The lower formation highlights losses caused by seepage.


Wellbore

> Pressure thresholds. During the initial stages of an extended leakoff test (XLOT), pressure increases linearly with the volume of fluid pumped. As more fluid is pumped into the wellbore, the pressure increase eventually departs from linearity at the leakoff pressure (Pleakoff) point, which also leads to initiation of a fracture. The fracture propagates until the formation breakdown pressure (Pbreakdown) is reached. The pressure curve falls off quickly at this point, and fractures propagate in a more controlled fashion at a lower and somewhat steady pressure called the fracture propagation pressure (Ppropagation). If pumping is stopped, pressure in the fracture will bleed off to the formation, which lowers pressure in the fracture and causes the fracture to close at the fracture closure pressure (Pclosure). When pumping resumes, pressure builds again and the fracture can reopen at the reopening pressure, (Preopening), which is similar to Pclosure. The fracture will then resume propagating at a pressure similar to Ppropagation. An XLOT curve may not exhibit this shape or possess a peak or plateau. The shape is driven by a host of factors, including in situ stresses in the rock, pore pressure, inherent rock strength and wellbore orientation.


Pumps off

Pumps on

Pleakoff

Pbreakdown

Ppropagation

Pclosure Preopening

Pres

sure

Time

44581araD6R1.indd 3 2/21/12 12:00 AM

Winter 2011/2012 29

Circulation Risks in Complex ReservoirsWorldwide, the portion of NPT attributable to lost circulation is increasing as drillers pursue more complex and technically challenging prospects than have been attempted in the past. For exam-ple, to reach isolated reservoirs located at a sig-nificant horizontal distance from the surface well pad, operators are increasingly implementing extended-reach drilling (ERD) techniques.8 These wells present unique fluid management challenges because drilling margins change dra-matically, depending on location in the wellbore.

In the vertical section of the wellbore, while the section is being drilled to the next casing shoe, the mud weight may safely reside in a wide envelope with no danger of wellbore instability,

formation fluid ingress to the wellbore or drilling fluid egress to the formation. However, as the well becomes more inclined, the minimum required ECD increases because friction losses increase. In addition, the influence of drilling parameters on ECD may increase because of the great length of the ERD well. These factors can decrease the drilling margin significantly—in some cases to as low as 60 kg/m3 [0.5 lbm/galUS] or less—which elevates the risk of lost circulation. This is espe-cially true in ERD wells drilled into unconsoli-dated formations with relatively low FGs.

Deepwater drilling in the Gulf of Mexico and offshore Brazil and West Africa has introduced lost circulation challenges beyond narrow drill-ing margins. These challenges include high ECDs and drilling fluid that is cooled by the near- freezing seawater surrounding the drilling riser. Additionally, the cost of lost circulation and NPT is exacerbated by the use of synthetic-base muds (SBMs) that range from US$ 100 to US$ 200 per barrel and by high rig time costs.9

5. M-I SWACO Technical Service Group: “Chapter 1: Fundamentals of Lost Circulation,” Houston: M-I SWACO, Prevention and Control of Lost Circulation (March 17, 2011): 1:1–7.

6. Hoop stress refers to the stress acting circumferentially around a wellbore, which is generated as a result of removing the rock volume when the wellbore is created. For more information: Fjaer E, Holt RM, Horsrud P, Raaen AM and Risnes R: Petroleum Related Rock Mechanics, 2nd ed. Amsterdam: Elsevier (2008): 139–140.

>Pressure gradient regimes in a wellbore. In Interval A, the ECD window, or mud weight window (purple shading) is bordered by the pore pressure (blue) and the fracture gradient (FG) (red). In a depleted interval (B), in which production from the interval leads to a reduction in pore pressure, the mud weight window narrows and both pore pressure and FG shift to lower pressures. In an interval with a mechanically weak formation (C), the lower limit of the mud weight window is defined by wellbore collapse pressure (green) and not pore pressure. In Interval D, pore pressure is high and FG is low, resulting in a very narrow mud weight window, which would present a challenge to controlling the ECD.


Overburden pressureFracture gradient

Pore pressureWellbore collapsepressure

ECDwindow

A

B

C

D

Dept

h

Pressure

>Wellbore profiles as functions of mud weight. If the drilling mud weight, or ECD, is closely monitored and maintained within the wellbore’s stable ECD window (green line), an in-gauge hole is ensured, with no fluids entering or exiting the wellbore (top center). If the ECD drops below this stable window, the wellbore enters an instability regime, in which reservoir fluid begins to exert pressure on the hole to begin hole deformation (top, second from left). The ECD continues to drop and reaches the pore pressure (Ppore). Below this pressure, the formation fluid (red arrows, top left) enters the wellbore unabated and may cause wellbore collapse and the uncontrolled release of production fluids to surface via the wellbore. The other end of the ECD continuum (orange line, right) begins with a mud weight that is too high, which causes the drilling mud to induce fracture formation or enter existing fractures (top, second from right). If the ECD is too high, the formation breakdown pressure (Pbreakdown) is reached; above this pressure, severe fluid losses occur (top right).


Uncontrolledfluid influx

Wellboredeformation

In-gaugehole

Stable ECD window

Safe window

ECDLow High

Severe fluidlosses

Fluid flow intofractures

Ppore Pbreakdown

Wellbore Wellbore Wellbore

Wellbore

WellboreWellbore

7. Growcock F: “How to Stabilize and Strengthen the Wellbore During Drilling Operations,” SPE Distinguished Lecturer Program (2009/2010), http://www.spe.org/ dl/docs/2010/FredGrowcock.pdf (accessed September 21, 2011).

8. For more on extended-reach wells: 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.

9. Synthetic-base muds are nonaqueous, water-internal emulsion drilling fluids in which the external phase is a synthetic fluid rather than oil.

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30 Oilfield Review

The risks of lost circulation events are even greater for deepwater fields that experience depletion-related stress changes, which increase the risk of fault activation and leads to the cre-ation of new lost circulation zones. ERD wells of more than 10-km [6.2-mi] total depth also pres-ent challenges for managing ECD.10

Lost circulation challenges arise when drill-ers target depleted zones within maturing fields. Production from these fields leads to reduced pore pressure in some of the formation layers, which in turn leads to a reduced FG and a requirement for reduced mud densities. Where overlying and interbedded shales are also pres-ent, a high mud density is required to prevent wellbore collapse and possible fluid influx. In such scenarios, the depleted layers must be drilled with a high overbalance, and drillers must take measures to prevent lost circulation. While overbalances as high as 90 MPa [13,000 psi] have been recorded in some Gulf of Mexico forma-tions, more typical values are in the range of 20 to 30 MPa [2,900 to 4,300 psi], such as those observed in the North Sea.11

Framing the ChallengeThe industry has developed a range of technolo-gies and services designed to prevent or mitigate lost circulation. Selecting the proper solution typi-cally begins with classifying the rate or magnitude of fluid loss. These fall into three categories: seep-age, partial fluid losses and severe losses.

The least severe loss, seepage, takes the form of whole mud loss at a rate lower than 1.6 m3/h [10 bbl/h]. Typically these losses arise from flow of fluid into formation pores and not fractures. Seepage losses are usually associated with loss of whole mud into the pore network sys-tem in which filtercake has not yet developed.12 The seepage rate is strictly a function of the over-balance and the permeability of the rock.

To accurately track seepage losses, engineers must account for other volume changes to the drilling mud. These include removal of cut-tings—rock pieces dislodged by the drill bit as it cuts rock to form the wellbore—and evaporation of the fluid portion of the drilling mud at the sur-face. Engineers must accurately determine the drop in drilling mud volume, which is caused by the removal of cuttings and any residual mud on them. Evaporation of the water phase of a water-base mud was a greater problem in the past, when open mud pits—large holes dug into the ground to hold drilling fluid—were used. Environmental concerns have prompted the industry to exchange these pits for closed steel vessels that hold from 160 to 320 m3 [1,000 to 2,000 bbl] of drilling mud.

Drillers verify seepage losses by pulling the drill bit off-bottom, turning off all mixing and nonessential solids removal equipment and then checking mud volumes with and without circula-tion. Once it is established that a volume of drill-ing mud is being lost due to seepage, the operator must decide whether to cure the losses or drill ahead. This decision often depends on the costs of drilling fluid and rig time, the narrowness of the drilling margin and the likelihood of NPT resulting from events such as formation damage or stuck pipe.13

Partial fluid losses—1.6 to 16 m3/h [10 to 100 bbl/h]—represent the next rung of the lost circulation ladder. Drillers face the same decisions for partial losses as they do for seepage losses, but because greater volumes of drilling fluid are lost, the driller more carefully considers remedial measures. The cost of the drilling fluid plays an important role: If the fluid is relatively inexpensive and the mud weight can be reason-ably managed within the drilling margin, drilling ahead without remediation may be considered. The point at which the cost of lost drilling fluids becomes too high to ignore varies from well to well and operator to operator.

When drilling fluids enter the formation through fractures, vugs or caverns at a rate greater than 16 m3/h, the losses are classified as severe. These include total losses, in which no volume of drilling fluid makes the return trip to the surface. The consequences of such events may include well control events and dry drilling events, in which continued drilling after a total loss leads to damage to the drill bit, drillstring or wellbore.

Wellbore Strengthening Fluids experts have developed a variety of meth-ods to enhance the integrity of the wellbore and prevent lost circulation. Collectively, these prac-tices are called wellbore strengthening methods, and include strategies that both alter stresses around the wellbore and minimize fluid losses. Operators employ a number of techniques to pre-vent lost circulation by physical or mechanical means, which are theorized to work in fundamen-tally different ways:•Fracture propagation resistance isolates the

tip of the existing fractures and mechanically increases the fracture reopening pressure, which increases the resistance to fracture propagation.14

•Hoop stress enhancement mechanicallyincreases the near-wellbore stresses and the Pleakoff or, more likely, the Pbreakdown.15

•Thefractureclosurestresstechniquefillsandenlarges fractures while isolating the fracture tip and increasing near-wellbore stresses.16

•Wellbore isolation physically isolates the for-mation from the wellbore pressure.17

While there is no industrywide consensus for which underlying technique is at work, there is agreement that wellbore strengthening is a real phenomenon. The overall effects of these mechanisms is to elevate the pressure at which uncontrolled losses occur and thereby widen the drilling margin. The borehole is then able to withstand greater pressures and, as measure-ment data illustrate, appears stronger, although no actual change in rock strength has occurred. For this reason, some have proposed calling the phenomenon wellbore stabilization or drilling margin extension, but the historical precedent and industry’s long-standing use of the term well-bore strengthening contribute to its continued widespread use.18

These theoretical wellbore strengthening mechanisms share a common component: spe-cifically sized and specially designed particu-lates, which are added to the drilling fluid. Any

> Lost circulation materials. While wellbore strengthening materials (WSMs) are considered a preventive measure for lost circulation challenges, they may be categorized as a specialized subset of lost circulation materials (LCMs). Most LCMs are added to the drilling fluid once a lost circulation event has begun.


MarbleSynthetic graphite

Hard, granular fibers

Lost circulation materials

Wellbore strengthening materials

Most salts

Reactive materials

Most fibersLaminatesPlates

Flakes

Soft granules

44581araD6R1.indd 5 2/21/12 12:00 AM

Winter 2011/2012 31

particulate material that acts to stop or slow mud loss is called a lost circulation material (LCM), and may include soft granules, insoluble salts, flakes or fibers (previous page). Most of these may prove useful to mitigate, or cure, loss of whole mud. Wellbore strengthening materials (WSMs), a category of LCMs, have proved effec-tive not only for mitigating losses but also for preventing them.

Operators choose a WSM based on the desired wellbore strengthening mechanism. A descrip-tion of the principal mechanisms follows.

Fracture propagation resistance (FPR)—The FPR theory of lost circulation prevention posits that LCM is pushed into an incipient or existing fracture to bridge, seal and isolate the fracture tip, thereby increasing the formation’s resistance to fracture propagation. Halting this propagation also stops the lost circulation event.

The mechanism for FPR has its origins in a joint industry project (JIP) known as the Drilling Engineering Association (DEA)-13, which was conducted in the mid-1980s to determine why oil-base mud (OBM) seemed to yield a lower FG than water-base mud (WBM).19 The project found no difference in fracture initiation pressure for dif-ferent fluid types and formulations in intact bore-holes, but noted significant differences for fracture propagation behavior, which was influ-enced by fluid type and composition.

This difference was explained through a phe-nomenon known as fracture tip screenout.20 When fracture growth begins, the wellbore instantaneously loses a volume of drilling fluid into the new void space of the fracture. If the fluid contains LCM, the introduction of fluid into the fracture causes a buildup of LCM that iso-lates, or screens, the fracture tip from the full pressure of the invading mud. The means by which this LCM buildup occurs varies with the type of fluid used (right).

>Mud type, filtercake and fracture propagation. In a system using a WBM (top), the fracture tip is sealed by an external filtercake that builds to prevent effective pressure communication between the drilling fluid and the tip, thus preventing fracture extension. The radial distance from the wellbore that the drilling fluid occupies in the fracture is defined as Rfluid. The thickness of the filtercake that builds up between the drilling fluid and the beginning of the fracture tip is defined as Rcake. The length of the filter tip, Rtip, is measured from the end of Rcake to the outer edge of where the drilling fluid solids (black particles) meet the formation. In a system using an OBM or SBM (bottom), an internal filtercake allows for full pressure communication to the tip, which facilitates fracture extension at lower propagation pressures than with a WBM. Rfluid is defined in the same manner as in a WBM technique. Rtip is the distance between Rfluid and the length of the filter tip, which also incorporates the drilling fluid solids. (Adapted from van Oort et al, reference 10.)


External filtercake

Fracture

Fracture

Rtip

Internal filtercake

Rfluid

Rfluid Rcake Rtip

10. van Oort E, Friedheim J, Pierce T and Lee J: “Avoiding Losses in Depleted and Weak Zones by Constantly Strengthening Wellbores,” paper SPE 125093, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, October 4–7, 2009.

11. Growcock F, Kaageson-Loe N, Friedheim J, Sanders M and Bruton J: “Wellbore Stability, Stabilization and Strengthening,” presented at the Offshore Mediterranean Conference and Exhibition, Ravenna, Italy, March 25–27, 2009.

12. Filtercake is the solid residue deposited on the wellbore when the drilling mud slurry is forced against it under pressure, which occurs during an overbalanced drilling condition.

13. Stuck pipe occurs when the drillpipe is not free to move up, to move down or rotate as needed in the wellbore. Seepage losses increase the risk of differential sticking by generating thicker filtercakes on the wellbore wall, which increases the contact area between the drillpipe and wellbore.

14. Morita N, Black AD and Fuh G-F: “Theory of Lost Circulation Pressure,” paper SPE 20409, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, September 23–26, 1990.

van Oort et al, reference 10.15. Aston MS, Alberty MW, McLean MR, de Jong HJ and

Armagost K: “Drilling Fluids for Wellbore Strengthening,” paper IADC/SPE 87130, presented at the IADC/SPE Drilling Conference, Dallas, March 2–4, 2004.

16. Dupriest F: “Fracture Closure Stress (FCS) and Lost Returns Practices,” paper SPE/IADC 92192, presented at the SPE/IADC Drilling Conference, Amsterdam, February 23–25, 2005.

17. Benaissa S, Bachelot A and Ong S: “Preventing Mud Losses and Differential Sticking by Altering Effective Stress of Depleted Sands,” paper IADC/SPE 103816, presented at the IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, Bangkok, Thailand, November 13–15, 2006.

18. van Oort et al, reference 10.19. Morita et al, reference 14. 20. van Oort et al, reference 10.

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32 Oilfield Review

If a WBM is used, the growth of the fracture leads to a dehydrated cake, or plug, of LCM that isolates the fracture tip and curtails further growth. The use of LCM in a WBM generally causes elevated fracture propagation pressures; the fracture continues to grow only if the mud pressure is high enough to puncture the LCM bar-rier and reach the fracture tip again. However, once this occurs and fracture propagation begins anew, additional LCM begins collecting at the tip until it is sealed again.

Nonaqueous fluids (NAFs), a collective term for OBMs and SBMs, use the emulsified aqueous fluid to penetrate the permeable rock and create a very tight and ultrathin filtercake that is inter-nal to the fracture wall. When a fracture propa-gates in the presence of an NAF, the invert

emulsion quickly seals off fracture faces, which limits fluid loss into the formation. Consequently, very little solid material is deposited in the frac-ture, and a coherent barrier of LCM or mudcake is not built. For NAFs, the result is that the pres-sure near the fracture tip is close to that in the wellbore, whereas for WBMs, the pressure near the fracture tip drops significantly. As a conse-quence, fracture propagation occurs less readily for WBMs than for NAFs, so that the effective FG for WBMs is greater than for NAFs. This translates to narrower drilling margins for an NAF than for a WBM, which may present signifi-cant challenges when constructing wells with low drilling margins.

The DEA-13 project also revealed that the composition and size distribution of particulates in the fluid were critically important to the suc-cess of FPR. Laboratory research conducted out-side of the DEA-13 project resulted in the development of a specialized WSM known as a loss prevention material (LPM) that inhibited fracture tip growth.21

This research showed that the LPM must be present in the mud at all times during drilling because FPR is a continuous, preventive treat-ment method. The findings also suggested that LPM should be present at a size distribution of between 250 and 600 microns [60 to 30 mesh], although subsequent work by Shell—a propo-nent of the FPR method—suggests that size dis-tribution should be a function of the type of formation to be strengthened.22

>WSM recovery. The process to recover WSM for subsequent reuse begins with a flowline that collects drilling fluid solids (including cuttings and WSMs originally pumped downhole for wellbore strengthening) from the wellbore and passes them through shale shakers, which remove very large particles. The remaining fluid and particles (red arrows) are then passed through a screw conveyor and cuttings dryer to remove residual cuttings from the drilling fluid. The fluid then passes through the MPSRS Managed Particle Size Recovery System unit, which further separates the WSM from smaller drill cuttings. A centrifuge conducts the last separation process, removing the very smallest drill cuttings from the WSM (blue arrow). The effluent, or WSM, from the shale shakers, MPSRS unit and centrifuge are sent back to the active system for reintroduction into the wellbore.


Cuttings dryer

Coarse cuttingsdisposal

Fine cuttingsdisposal

Screw conveyor

Shale shakers

MPSRSunit

Flowline

RecoveryEffluent

Centrifuge

To active system

Effluent

Effluent

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Winter 2011/2012 33

The types of WSM deemed most effective in consistently sealing a fracture and minimizing leakoff through the fracture tip include synthetic graphite, ground nut hulls and oil-dispersible cellulose particles. Blends of these materials in various ratios have demonstrated synergistic performance benefits in both laboratory and field trials. These materials must be present in the mud at concentrations ranging from 43 to 57 kg/m3 [15 to 20 lbm/bbl] and are continuously recycled and reintroduced to the wellbore to ensure con-tinuous protection as new sections are drilled.

Field trials have demonstrated the impor-tance of maintaining both the concentration and size distribution of WSM in the mud.23 This need led to the development of in-field WSM recycling equipment, such as the MPSRS Managed Particle Size Recovery System tech-nology. The system removes drill cuttings and low-gravity solids that may negatively impact mud rheology and ECD while recovering WSM in the appropriate size ranges for raising the FPR (previous page).24

Shell introduced the FPR concept with the MPSRS technology in 2006 in Gulf of Mexico sub-sea wells. Lost circulation’s contribution to NPT diminished significantly in these wells over a four-year period (right). This is in contrast to alternative drill cuttings removal systems that are composed of shakers with three levels that are configured in series. Cuttings are removed from the top level (fitted with the coarsest screens), fines are removed from the bottom level (with the finest screens) and most of the coarse, relatively undegraded WSM is trapped on the middle level and shunted back into the active system.25

Hoop stress enhancement: The stress cage concept—A second wellbore strengthening model, the stress cage theory, proposes that the hoop stresses at the edge of the wellbore may be increased by adding a suitable WSM to the drill-ing fluid. A drilling mud pretreated with WSM circulates in an overbalanced state to induce shallow fractures in the near-wellbore region.

These newly created fractures act to com-press the wellbore, generating an additional hoop stress, or stress cage. The WSM-laden mud enters these shallow fractures, and the sized WSM par-ticles begin to collect and bridge close to the wellbore face. Additional buildup of WSM forms a hydraulic seal near each fracture mouth; as a result, no additional mud can enter from the wellbore, and the fluid within the fracture leaks off into the formation.

>NPT attributed to lost circulation. After Shell introduced the FPR mechanism and MPSRS equipment in the third quarter of 2006, lost circulation’s contribution to NPT dropped significantly, from 12% at the onset of the wellbore strengthening strategy to 1% in 2009. Lost circulation fell significantly as a major trouble category in a Shell NPT ranking, from rank 3 to rank 18. (Adapted from van Oort et al, reference 10.)


2006 2007

2008 2009

NPT rank 312%

1% 1%

4%

88% 96%

99% 99%

NPT rank 18

Lost circulation NPTOther NPT

21. Fuh G-F, Morita N, Boyd PA and McGoffin SJ: “A New Approach to Preventing Lost Circulation While Drilling,” paper SPE 24599, presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, October 4–7, 1992.

22. van Oort et al, reference 10. 23. Sanders MW, Young S and Friedheim J: “Development

and Testing of Novel Additives for Improved Wellbore Stability and Reduced Losses,” paper AADE-08-DF-HO-19, presented at the AADE Fluids Technical Conference and Exhibition, Houston, April 8–9, 2008.

Friedheim J, Sanders MW and Roberts N: “Unique Drilling Fluids Additives for Improved Wellbore Stability and Reduced Losses,” presented at the Seminario Internacional de Fluidos de Perforación, Completación y Cementación de Pozos (SEFLU CEMPO) Conference, Margarita Island, Venezuela, May 19–23, 2008.

Tehrani A, Friedheim J, Cameron J and Reid B: “Designing Fluids for Wellbore Strengthening—Is It an Art?” paper AADE-07-NTCE-75, presented at the AADE National Technical Conference and Exhibition, Houston, April 10–12, 2007.

24. van Oort E, Browning T, Butler F, Lee J and Friedheim J: “Enhanced Lost Circulation Control Through Continuous Graphite Recovery,” paper AADE-07-NTCE-24, presented at the AADE National Technical Conference and Exhibition, Houston, April 10–12, 2007.

Butler F and Browning T: “Recovery System,” US Patent No. 7,438,142 (October 21, 2008).

25. Growcock F, Alba A, Miller M, Asko A and White K: “Drilling Fluid Maintenance During Continuous Wellbore Strengthening Treatment,” paper AADE-10-DF-HO-44, presented at the AADE Fluids Conference and Exhibition, Houston, April 6–7, 2010.

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34 Oilfield Review

This leakoff lowers the hydraulic pressure within the fracture, causing it to begin to close. However, the presence of the WSM bridge, wedged at the fracture mouth, prevents total clo-sure and maintains a degree of additional hoop stress. The presence of one or more of these propped fractures increases the hoop stress, and thus a higher wellbore pressure is needed to extend or create additional fractures (below).

Industry research suggests that for this mech-anism to be successful, high concentrations of bridging additives are required; they must be strong enough to resist closure stresses and they have to be appropriately sized to bridge near the fracture mouth rather than deeper into the frac-ture. They must also create an impermeable bridge so that leakoff through the bridge is mini-mized, allowing the pressure within the fracture to drop. Materials such as graphitic blends, mar-ble, nut husks and ground petroleum coke work

well, just as with the FPR mechanism. For a frac-ture opening of 1 mm [0.04 in.], a particle size distribution ranging from colloidal clays up to values approaching 1 mm has been suggested.26

Historically, the WSM was applied as a dedi-cated squeeze in pill form—a relatively small volume (less than 32 m3 [200 bbl]) of fluid added to the wellbore at one time. However, the WSM has been continuously applied to the whole mud when field engineering and logistics permitted it. Stress cage treatments typically require at least 25 kg/m3 [9 lbm/bbl] of WSM in the mud. A solids-recovery system, such as a three-level shaker sys-tem configured in series, may be used to scalp the cuttings and remove the fines while capturing WSM-sized particulates for routing back to the active system. Shakers fitted with coarse (10- to 20-mesh) screens alone may suffice, although these would remove only cuttings and leave WSM and drilled fines in the mud. The buildup of fines

might be tolerable, particularly for strengthening short intervals drilled with solids-tolerant NAF, but removing all unnecessary solids is considered best practice.

Fracture closure stress—A third wellbore strengthening model, fracture closure stress (FCS), was developed in the mid-1990s and is still widely applied in the industry.27 This method has some similarities to the stress cage concept, par-ticularly in how WSM is theorized to plug and wedge open fractures to increase hoop stress near the wellbore and arrest fracture propagation.

However, unlike stress caging—which initi-ates fractures before quickly stopping their growth—FCS is a high-fluid-loss treatment for existing fractures. While the WSM in this method may be applied as a whole mud treatment, it is commonly applied via high-fluid-loss pills.

FCS theory holds that an effective treatment must isolate the fracture tip. Scientists believe this occurs because of rapid drainage of carrier fluid from the mud mixture as the particles are compressed and agglomerate during the squeeze phase and then form a plug in the fracture. The plug quickly becomes immobile and cuts off com-munication between the fracture tip and the wellbore, thus preventing transmission of pres-sure to the tip and halting fracture propagation, allowing an increase in the wellbore pressure and a consequent increase in fracture width.

As a result, it is important that the particles are able to deform, or be crushed, during the application of a squeeze treatment. The ideal WSM should be composed of relatively large par-ticles of similar size and considerable roughness that do not pack well; examples include diatoma-ceous earth and barite.28 Often, more than one FCS treatment is required.

The FCS theory holds that the particulate plug can manifest anywhere in the fracture, not only near the mouth as in stress caging. For this mechanism, although compressive strength of the WSM is not important, high fluid loss is criti-cal because it accelerates formation of the immo-bilized plug. Alternatively, leakoff of filtrate may occur through generation of microfractures or extension of the existing fracture, thus permit-ting deliquefication of the WSM and formation of a plug before the onset of whole mud loss.

Wellbore isolation—As a fourth wellbore strengthening strategy, various methods have been proposed to isolate a wellbore while drilling to seal off the formation in a manner similar to protecting a wellbore with casing.29 In some cases, the WSMs for this application are flexible fluid-loss control materials that have the

> Stress cage concept. In this wellbore strengthening strategy, a fracture is formed and quickly sealed by WSMs (small brown circles) that bridge and seal the fracture mouth. This seal forms a compressive stress, or stress cage, in the adjacent rock, which effectively strengthens the wellbore. For fracture stability to be realized, Ptip—which is, in practical terms, equivalent to Ppore—must be less than Pmud, which is isolated behind the WSM seal.


Pmud

Ptip

Ppore

= Mud pressure= Pressure at fracture tip= Pore pressure

For stability, Ptip ~ Ppore < Pmud

Pmud

Ptip

Ppore Wellbore

Fracture

26. Aston et al, reference 15. 27. Dupriest, reference 16. 28. M-I SWACO Technical Service Group: “Chapter 7:

Wellbore Strengthening Solutions,” Houston: M-I SWACO, Prevention and Control of Lost Circulation (March 17, 2011): 7:1–7.

29. Benaissa et al, reference 17. 30. Karimi M, Moellendick E and Holt C: “Plastering Effect

of Casing Drilling; a Qualitative Analysis of Pipe Size Contribution,” paper SPE 147102, presented at the SPE Annual Technical Conference and Exhibition, Denver, October 30–November 2, 2011.

31. For more information: Lund JW: “Characteristics, Development and Utilization of Geothermal Resources,” Geo-Heat Center Quarterly Bulletin 28, no. 2 (June 2007), http://geoheat.oit.edu/bulletin/bull28-2/bull28-2-all.pdf (accessed October 15, 2011).

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.

32. For more information: Oliver JE: “New Completion System Eliminates Remedial Squeeze Cementing for Zone Isolation,” paper SPE 9709, presented at the SPE Permian Basin Oil and Gas Recovery Symposium of the SPE of the AIME, Midland, Texas, March 12–13, 1981.

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capability of penetrating or sealing the rock. The concept involves reducing the permeability of the rock to near zero by plastering the rock with a material of equal or greater tensile strength.

Various low-fluid-loss materials have been implemented to achieve this effect, which essen-tially attempts to build a cement-like sheath on the wellbore surface. Such a barrier serves to iso-late the wellbore from both fluid invasion and wellbore pressure. Advances in mud chemistry have developed micro- and nanoparticulates that may reduce permeability to a negligible level, but isolation of wellbore pressure remains an elusive goal. The smear effect, which is thought to occur during casing or liner drilling operations, may be considered an example of wellbore isolation because fines are thought to be plastered onto the wellbore walls to create a tight barrier to fluid invasion.30

Some wellbore strengthening techniques defy easy classification. An example is the Losseal lost circulation treatment, an engineered pill that blends a flexible fiber with a firm fiber to syner-gistically bridge fractures and stop fluid loss.

Theoretically, the treatment creates an impermeable grid that prevents fluid from enter-ing the fracture; it is strong enough to withstand additional pressure buildup caused by increasing mud density. The pill can be pumped through a bottomhole assembly or open-ended drillpipe and is applicable in wellbores affected by natural fractures, depleted reservoirs and drilling-induced lost circulation zones.

The Losseal solution has also been applied to lost circulation scenarios outside of the oil and gas industry. Enel Green Power recently used the system to solve a lost circulation problem while drilling a geothermal well in Italy. To extract energy from a geothermal well, the operator drills into high-temperature subsurface zones and injects water, which is heated and pumped back to surface, where it is used to provide a source for home heating or, at higher temperatures, electric-ity generation for industrial applications.31

Geothermal wells drilled previously in the same area passed through a shale section at shal-low depths, followed by a limestone formation where fluid losses ranged from 10 m3/h [63 bbl/h] to total loss of fluid.

Historically, lost circulation solutions in these wells included a remedial squeeze cement job to achieve vertical isolation of a completion inter-val. For the newest well, the operator wished to avoid the additional cost and time associated with a squeeze job. Additionally, in some instances, squeeze jobs had created formation damage that impaired productivity.32

The operator pumped a 32-m3 [200-bbl] Losseal pill to the lost circulation zone and moni-tored the pressure in the wellbore as a function of time. While the pressure initially increased by as much as 200 psi [1.4 MPa] during the pill’s movement through the wellbore, a sudden drop in pressure indicated that the Losseal pill reached the fractures and plugged them. The liner was then run to total depth and cemented in one stage using conventional completion tech-niques. No fluid losses were recorded during this operation, and the pressure reached closely matched what modeling had predicted.

By implementing the single-stage cement job and improving well integrity, the company was able to avoid a cement squeeze job, thus saving three days of rig time. The improved zonal isola-tion and casing protection afforded by having the entire string encased in cement are expected to increase the productive life of the well.

Investigating MechanismsFundamental differences exist among the pro-posed wellbore strengthening mechanisms (above). Because it is impossible to see what takes place in a fracture during a wellbore strengthening treatment, the industry has not reached a clear consensus on the exact mecha-nism at work.

This lack of industrywide agreement has spurred a series of JIPs designed to study the fun-damentals of fracture sealing, develop product solutions and set industry standards for wellbore strengthening investigations.

The initial JIPs were hosted by Shell E&P Company, but now are being led by M-I SWACO, a Schlumberger company. M-I SWACO conducted the first JIP from 2004 to 2006 and counted Shell, BP, ConocoPhillips, Chevron and Statoil among its members. The JIP was designed to first define

the best laboratory-based fracture modeling method that would yield reproducible data. The resulting fracture model was tested with a device used to screen LCM candidates for wellbore strengthening. Acceptable WSMs identified by this method included marble, graphite, ground petroleum coke, nut husks and proprietary cellu-losic blends.

A second JIP, conducted from 2007 to 2010, included several additional operators and focused on clarifying, through laboratory testing, the fundamental differences among the various wellbore strengthening theories. Research priori-ties included comparing sealing at the fracture mouth—hoop stress enhancement—versus seal-ing throughout the fracture (FPR), matching LCM size distribution in relation to fracture width and investigating LCM performance as a function of material type and concentration.

A third industry project, the Research Cooperative Agreement III, began in December 2010 with a focus on developing lost circulation solutions for extreme downhole conditions and for wells in high-value plays.

Numerous operators working in concert have committed resources to research projects dedicated to finding solutions to lost circulation; wellbore strengthening is the focus of that research. As the industry attempts to feed the growing global appetite for energy from increas-ingly expensive and unconventional hydrocarbon resources, it will likely rely on wellbore strength-ening solutions to help operators drill wells more efficiently. —TM

> Differences among wellbore strengthening techniques. A comparison of the tenets of wellbore strengthening techniques reveals some fundamental differences.

Lost CirculationTable 1_3

Application technique

WSM particle type

WSM particle size

WSM particle strength

High fluid loss required?

Fracture tip isolation required?

Formation or closure stress applied?

Category

Continuous in mud orpill squeeze

Important

Important

Somewhat important

No

No

No

Stress Cage

Continuous in mud

Important

Important

Unimportant

No

Yes

No

Fracture PropagationResistance

Continuous in mudor pill squeeze

Unimportant

Unimportant

Unimportant

Yes

Yes

Yes

Fracture ClosureStress

Lost CirculationTable 1_3

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36 Oilfield Review

The Best of Both Worlds—A Hybrid Rotary Steerable System

The transition from vertical to horizontal drilling has been spurred by evolving

technology that led the industry away from a dependency on conventional bottomhole

assemblies and whipstocks and toward mud motors and rotary steerable systems.

The latest innovation is a hybrid design that combines the performance capabilities of

a rotary steerable system with the high build rates of a positive displacement motor.

Edwin FelczakAriel TorreOklahoma City, Oklahoma, USA

Neil D. GodwinKate MantleSivaraman NaganathanStonehouse, England

Richard HawkinsKe LiSugar Land, Texas, USA

Stephen JonesKaty, Texas

Fred SlaydenHouston, Texas

Oilfield Review Winter 2011/2012: 23, no. 4. Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Elizabeth Hutton and Emmanuelle Regrain, Houston; and Edward Parkin, Stonehouse, England. DOX, Drilling Office, IDEAS, PERFORM Toolkit, PowerDrive Archer, PowerDrive X5 and PowerPak are marks of Schlumberger.

The shortest distance between two points is a straight line. However, it may not be the fastest, or most economical, when it comes to directional drilling. E&P companies increasingly turn to complex well trajectories to hit distant targets,

intersect fractures, penetrate multiple fault blocks or reach deep into a reservoir. Although more difficult to drill than other profiles, these well paths often improve drainage efficiency by increasing wellbore exposure to the pay zone.

Kickoff point

TD

PowerDrive Archer rotary steerable systemPositive displacement motorConventional rotary steerable system

Landing point

Landing point TD

Kickoff point

PPPPPPCPC

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Complex horizontal and extended-reach tra-jectories are just the current apex in the evolu-tion of directional drilling. The first nonvertical wells were not intentionally drilled that way, but by the late 1920s, drillers began to figure out how to point a wellbore in a particular direction. Since then, directional drilling technology has progressed beyond a reliance on basic bottom-hole assemblies for influencing the course a bit might take, to using surface-controlled rotary steerable systems that precisely guide the bit to its ultimate destination. During the past decade, the development of new drilling technologies has continued to gain momentum.

This article describes advances that led to the development of rotary steerable systems and focuses on one of the latest steps in their evolution: the PowerDrive Archer rotary steerable system. This hybrid system produces the high build rate of a positive displacement motor with the rapid rate of penetration of a rotary steerable system.

A Brief HistoryThe intentional deviation of wellbores came into practice during the late 1920s as operators sought to sidetrack around obstructions, drill relief wells and avoid surface cultural features; directional drilling techniques were even employed to keep vertical holes from turning crooked.

In part, the ability to drill deviated wells arose from the development of rotary drilling and roller cone bits. The design of these bits causes them to drift laterally, or walk, in response to various formation and drilling parameters such as formation dip and hardness, rotary speed, weight on bit and cone design. In some regions, experienced drillers recognized the natural ten-dency of a bit to walk in a somewhat predictable manner. They would frequently try to build a cer-tain amount of lead angle to compensate for anticipated drift between the surface location and bottomhole target (below left).

Drillers also found that modifications to the rotary bottomhole assembly (BHA) could change a drillstring’s angle of inclination. By varying stabilizer placement, drillers could affect the

balance of the BHA, prompting it to increase, maintain or decrease wellbore inclination from vertical, commonly referred to as building, hold-ing or dropping angle, respectively. The rate at which a rotary BHA builds or drops angle is affected by variables such as distance between stabilizers, drill collar diameter and stiffness, for-mation dip, rotary speed, weight on bit, formation hardness and bit type. The ability to balance the BHA against these factors can be crucial for reaching a planned target.

A BHA configured with a near-bit stabilizer beneath several drill collars will tend to build angle when weight is applied to the bit (below). In this configuration, the collars above the stabi-lizer will bend, while the near-bit stabilizer acts as a fulcrum, pushing the bit toward the high side

> Lead angle, plan view. Rotary cone bits tend to walk to the right. Knowing this, drillers sometimes used a lead angle to orient the wellbore to the left of the target azimuth.

Target azimuth

Surface location

S 20° E Lead line

Lead angle

Target

N

> Using a BHA to change inclination. By strategic placement of drill collars and stabilizers in the BHA, directional drillers can increase or decrease flexibility, or bowing, of the BHA. They use this flexibility to their advantage as they seek to build, drop or hold angle. A fulcrum assembly (upper frame, top) uses a full gauge near-bit stabilizer and sometimes a string stabilizer. Bowing of the drill collars above the near-bit stabilizer tilts the bit upward to build angle (lower frame, left). A pendulum assembly (upper frame, middle) has one or more string stabilizers. The first string stabilizer acts as a pivot point that lets the BHA bow beneath it, thus dropping angle (lower frame, right). A packed assembly uses one or two near-bit stabilizers and string stabilizers to stiffen the BHA (upper frame, bottom). By reducing the tendency to bow, the packed assembly is used to hold angle.

Fulcrum assembly Pendulum assembly

Stabilizer

Near-bit stabilizer Buildin

g

angle

Droppin

g

angle

Near-bit stabilizersFirst string stabilizerSecond string stabilizer

Near-bit stabilizerDrill collarFirst string stabilizer

Fulcrum (Angle-Building) Assembly

Packed (Angle-Holding) Assembly

Second string stabilizer

Bit

Pendulum (Angle-Dropping) Assembly

First string stabilizer

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38 Oilfield Review

of the borehole. Another type of BHA is used to drop angle. This variation uses one or more stabi-lizers; the collars below the lowest stabilizer in the BHA act as a pendulum, which allows gravity to pull the bit toward the low side of the bore-hole. Upon reaching the desired angle, the driller may use a different BHA to hold angle. The packed BHA utilizes multiple stabilizers, spaced along its length, to increase stiffness.

Drillers employ other mechanical means to help divert a well from its vertical path, most notably the whipstock. Simple in principle, this long steel ramp is concave on one side to hold and guide the drilling assembly. Used in either open or cased holes, the whipstock is positioned at the desired depth, oriented to the desired azi-muth, then anchored in place to provide a guide to initiate, or kick off, a new well path (above).

While early techniques allowed some degree of control over wellbore inclination, they provided little azimuthal control. They were also inefficient, requir-ing multiple trips in and out of the hole to install a whipstock or to change BHA configurations.

The early 1960s witnessed a significant change in directional drilling when a BHA with a fixed bend of approximately 0.5° was paired with a downhole motor to power the drill bit.1 Drilling mud supplied hydraulic power to a motor that

turned the bit.2 The motor and bent sub offered much greater directional control than was possi-ble with earlier BHAs, while significantly increas-ing the angle of curvature that a driller was able to build. Early assemblies had fixed tilt angles and required a trip out of the hole to adjust the angle of inclination.

These steerable motors operate on the tilt-angle principle. The bent sub provides the bit offset needed to initiate and maintain changes in course direction. Three geometric contact points—the bit, a near-bit stabilizer on the motor and a stabilizer above the motor—approximate an arc that the well path will follow.3

Some motors use a downhole turbine; others use a helical rotor and stator combination to form a positive displacement motor (PDM). The basic PDM with bent sub has evolved, leading to the development of a steerable motor. Modern steerable motor assemblies still use PDMs, but include surface-adjustable bent housings (below right). A typical steerable motor has a power-generating section, through which drilling fluid is pumped to turn a rotor that turns a drive shaft and bit. The surface-adjustable bend can be set between 0° and 4° to point the bit at an angle that differs only slightly from the axis of the well-bore; this seemingly minor deflection is critical to the rate at which the driller can build angle. The amount of wellbore curvature imparted by the bent section depends, in part, on its angle, the OD and length of the motor, stabilizer place-ment and the size of drill collars relative to the diameter of the hole.

Steerable motors drill in either of two modes: rotary mode and oriented, or sliding, mode. In rotary mode, the drilling rig’s rotary table or its topdrive rotates the entire drillstring to transmit power to the bit. During sliding mode, the drill-string does not rotate; instead, mud flow is diverted to the downhole motor to power the bit. Only the bit rotates in sliding mode—the nonro-tating portion of the drillstring simply follows along behind the steering assembly.

Different motors may be selected on the basis of their ability to build, hold or drop angle during rotary mode drilling. Conventional practice is to drill in rotary mode at a low number of revolu-tions per minute (RPM), rotating the drillstring from the surface and causing the bend to point equally in all directions, thereby drilling a straight path. Inclination and azimuth measure-ments can be obtained in real time by measure-ment-while-drilling (MWD) tools to alert the driller to any deviations from the intended course. To correct for those deviations, the driller must switch from rotary to sliding mode to change wellbore trajectory.

The sliding mode is initiated by halting rota-tion of the drillstring so the directional driller can orient the bend in the downhole motor to point in the direction, or toolface angle, of the desired tra-jectory. This is no small task, given the torsional forces that can cause the drillstring to behave like a coiled spring.4 After accounting for bit torque, drillstring windup and contact friction, the driller must rotate the drillstring in small increments from the surface while using MWD measurements as a reference for toolface direction. Because a drillstring can absorb torque over long intervals, this process may require several rotations at the surface to turn the tool just once downhole. When the proper toolface orientation is confirmed, the driller activates the downhole motor to com-mence drilling in the prescribed direction. This process may need to be repeated several times during the course of drilling because reactive torque that is generated as the bit cuts into the rock may force reorientation of the toolface.

> Cased hole whipstock. This cylindrical steel ramp (green) is run in the hole to a predetermined kickoff depth and oriented azimuthally. A window mill opens a hole in the casing, which is dressed by the watermelon mill. This assembly is then pulled and replaced by a drilling BHA.

Casing

Cement

New borehole

Watermelonmill

Window mill

Cement plug

Whipstock

> Positive displacement motor. Downhole motors, such as this PowerPak steerable motor, provide much more directional control than conventional BHAs.

Power section

Surface-adjustablebent housing

Stabilizer

Bit

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Winter 2011/2012 39

Each mode brings distinct challenges. In rotating mode, the bend in the drilling assembly causes the bit to rotate off-center from the BHA axis, resulting in a slightly enlarged and spiral-shaped borehole. This gives the wellbore rough sides that increase torque and drag and may cause problems while running in the hole with completion equipment—especially through long lateral sections. Spiral boreholes may also affect logging tool response.

In sliding mode, the lack of rotation intro-duces other difficulties. Where the drillstring lies on the low side of the borehole, drilling fluid flows unevenly around the pipe and impairs the mud’s capacity to remove cuttings. This, in turn, may result in the formation of a cuttings bed, or a buildup of cuttings on the low side of the hole, which increases the risk of stuck pipe. Sliding also decreases the horsepower available to turn the bit, which, combined with sliding friction, decreases the rate of penetration (ROP) and increases the likelihood of differential sticking.

In extended-reach trajectories, frictional forces may build until there is insufficient axial weight to overcome the drag imposed by drill-pipe against the wellbore. This makes further drilling impossible and leaves some targets out of reach. Additionally, switching between sliding and rotating modes can create undulations or doglegs that increase wellbore tortuosity, thus increasing friction while drilling and running casing or completion equipment.5 These undula-tions may also create low spots, or sumps, where fluid and debris collect, impeding flow after the well is completed.

A number of these problems were addressed in the late 1990s with the development of a rotary steerable system (RSS). The single most impor-tant aspect of the RSS is that it allows for continuous rotation of the drillstring, thereby

eliminating the need to slide while drilling direc-tionally. RSS tools provide a nearly instantaneous response to commands from the surface when the driller needs to change downhole trajectory. Early on, these systems were utilized primarily to drill extended-reach trajectories, in which the ability to slide steerable motors had been limited by hole drag. These jobs often resulted in improved ROPs and hole quality over previous systems (above). Today, the RSS is widely used for its performance drilling, hole cleaning and accu-rate geosteering capabilities.

Revolutionary SteerablesRotary steerable systems have evolved consider-ably since their introduction. Early versions uti-lized mud-actuated pads or stabilizers to cause changes in direction—a design concept that con-tinues to enjoy success to this day. With a depen-dence on contact with the borehole wall for

directional control, the performance of these tools can sometimes be affected by borehole washouts and rugosity. Later versions included designs that relied once again on a bend to pro-duce changes in toolface angle, thereby reducing borehole environmental influences on tool per-formance.6 Thus, two steering concepts were born: push-the-bit and point-the-bit.

The push-the-bit system pushes against the borehole wall to steer the drillstring in the desired direction. One version of this RSS uses a bias unit with three actuator pads placed near the bit to apply lateral force against the forma-tion (below). To build angle, each mud-actuated pad pushes against the low side of the hole as it

1. McMillin K: “Rotary Steerable Systems Creating Niche in Extended Reach Drilling,” Offshore 59, no. 2 (February 1999): 52, 124.

2. Unlike conventional rotary drilling techniques, in which rotation of the entire drillstring is required to drive the bit, the drillstring does not rotate when a mud motor is employed. Instead, the mud motor relies on hydraulic power supplied through the circulation of drilling mud to turn a shaft that drives the bit.

3. Allen F, Tooms P, Conran G, Lesso B and Van de Slijke P: “Extended-Reach Drilling: Breaking the 10-km Barrier,” Oilfield Review 9, no. 4 (Winter 1997): 32–47.

4. Downton G, Hendricks A, Klausen TS and Pafitis D: “New Directions in Rotary Steerable Drilling,” Oilfield Review 12, no. 1 (Spring 2000): 18–29.

5. A dogleg is an abrupt turn, bend or change of direction in a wellbore.

6. Schaaf S, Pafitis D and Guichemerre E: “Application of a Point the Bit Rotary Steerable System in Directional Drilling Prototype Wellbore Profiles,” paper SPE 62519, presented at the SPE/AAPG Western Regional Meeting, Long Beach, California, USA, June 19–23, 2000.

> Comparison of borehole quality. Caliper displays show how a positive displacement motor created a spiralled borehole (top), while the rotary steerable system drilled a much smoother bore (bottom).

> Push-the-bit RSS. Pads extend dynamically from a rotating housing to create a side force directed against the formation, which in turn, causes a change in the drilling direction.

Stabilizer

Control unit Bias unit

Bit

Extended pad

When pads push againstthe high side, the bit

cuts toward the low side.

Extended pad

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40 Oilfield Review

rotates into position; to drop angle, each pad pushes against the high side. Driller commands sent downhole by mud pulse telemetry direct the timing and magnitude of pad actuation. A control unit positioned above the bias unit drives a

rotary valve that opens and closes the mud sup-ply to the pads in concert with the drillstring rotation. The system synchronously modulates the extension and contact pressure of the actua-tor pads as each pad passes a certain orientation point. By applying hydraulic pressure each time a pad passes a specific point, the pad forces the drillstring away from that direction, thus moving it in the desired direction.

A point-the-bit system uses an internal bend to offset the alignment between tool axis and borehole axis to produce a directional response.7 In a point-the-bit system, the bend is contained within the collar of the tool, immediately above the bit (left). Point-the-bit systems change well trajectory by changing the toolface angle. The trajectory changes in the direction of the bend. This bend orientation is controlled by a servomo-tor that rotates at the same rate as the drillstring, but counter to the drillstring rotation. This allows the toolface orientation to remain geostationary, or nonrotating, while the collar rotates.8

The latest development in the evolution of these rotary steerables—the PowerDrive Archer high-build-rate RSS—is a hybrid that combines performance features of both push-the-bit and point-the-bit systems (below).

The Hybrid RSSUntil recently, RSS assemblies were unable to deliver well profiles as complex as those drilled by steerable motor systems. However, the PowerDrive Archer rotary steerable system dem-onstrated its capability to attain high dogleg severities (DLSs) while achieving ROPs typical of rotary steerable systems.9 Just as important, it is a fully rotating system—all external tool compo-nents rotate with the drillstring, enabling better hole cleaning while reducing the risk of sticking.

Unlike some rotary steerables, the PowerDrive Archer RSS does not rely on external moving pads to push against the formation. Instead, four actuator pistons within the drill collar push against the inside of an articulated cylindrical steering sleeve, which pivots on a universal joint to point the bit in the desired direction. In addi-tion, four stabilizer blades on the outer sleeve above the universal joint provide side force to the drill bit when they contact the borehole wall, enabling this RSS to perform like a push-the-bit system. Because its moving components are internal—thus protected from interaction with harsh drilling environments—this RSS has a lower risk of tool malfunction or damage. This design also helps extend RSS run life.

An internal valve, held geostationary with respect to toolface, diverts a small percentage of mud to the pistons. The mud actuates the pistons that push against the steering sleeve. In neutral mode, the mud valve rotates continuously, so bit force is uniformly distributed along the borehole wall, enabling the RSS to hold its course.10

Near-bit measurements, such as gamma ray, inclination and azimuth, allow the operator to closely monitor drilling progress. Current orien-tation and other operating parameters are relayed to the operator through a control unit, which sends this information uphole via continu-ous mud pulse telemetry. From the surface, the directional driller sends commands downhole to the control unit located above the steering unit. These commands are translated into fluctuations in mud flow rates. Each command has a unique pattern of fluctuations that relate to discrete points on a preset steering map, which has been programmed into the tool prior to drilling.

Operators have been quick to capitalize on the capabilities of the PowerDrive Archer steer-

> Point-the-bit RSS. A bit shaft is oriented at an offset angle to the axis of the tool. This offset is held geostationary by a counter-rotating servomotor.

Power-generatingturbine

Motor

Sensor packageand control system

Bit

Mud flow

Bit shaft

> PowerDrive Archer rotary steerable system. This hybrid system combines actuator pads with an offset steering shaft—all located inside the drill collar for protection from the downhole environment.

Steering unit

Bias unit

Control unit

Internal geostationaryrotary valveStabilizer

blades

Internal universal joint Internal actuator pistonsStabilizer blades

44581araD7R1.indd 5 2/17/12 9:40 PM

Winter 2011/2012 41

ing system. Because it can drill the vertical, curved and horizontal sections, it can attain com-plex 3D trajectories and drill from one casing shoe to the next in just one run.

Putting It to the Test Until recently, steerable PDMs tended to domi-nate the realm of high-dogleg drilling projects. Despite their directional capabilities, drilling with PDMs may consume a lot of rig time. With this approach, a conventional rotary BHA is typi-cally used to drill the vertical section of the well. Upon reaching the kickoff point (KOP), the driller trips out of the hole to change the BHA. A PDM is then installed, with a bent housing set to the angle needed to drill the curve. After landing the bit in the target formation, the driller again trips out to dial down the angle of the adjustable bent housing to a less aggressive build rate, then trips back into the hole to drill the lateral sec-tion. This process results in a good deal of flat time, in which the bit is not on bottom and not actively drilling.

Using the PowerDrive Archer RSS, an opera-tor can drill the vertical, curved and lateral sec-tions with a single BHA, thereby increasing drilling efficiency, ROP and borehole quality. And by circumventing the practice of alternating between sliding and rotating modes, drilling with the RSS achieves lower borehole tortuosity, drag and friction caused by poor hole quality. This permits drilling of longer lateral sections that reach farther into the reservoir.

The PowerDrive Archer RSS has been used in a wide range of environments, onshore and off, from the US to the Middle East and Australia. The high-build-rate capabilities first demonstrated in shale plays are now used to help drillers maintain trajectories through problematic unconsolidated formations. Throughout a variety of plays, opera-tors are beginning to appreciate the flexibility in designing and revising well trajectories that this hybrid RSS affords.

One such play, the Marcellus Shale in the Appalachian basin of North America, spans an area estimated to be approximately 3.5 times larger than that of the Barnett Shale, which has proved to be one of the most prolific sources of unconventional gas in the US. The Devonian-age Marcellus Shale contains an estimated 363 Tcf [10.3 trillion m3] of recoverable gas. Ultra Petroleum Corporation is engaged in exploration and development of this play.11

In the past, operators completed Marcellus wells using vertical boreholes, which provided comparatively little exposure of the source rock to the wellbore. However, horizontal drilling

technology has significantly changed the eco-nomics of gas production in the Marcellus play, with horizontal wells drilled from multiwell pads and completed with multistage fracture stimula-tion of the lateral section. Operators frequently used air to drill the vertical section, then switched to mud drilling upon reaching the KOP. After setting 95/8-in. casing, they kicked off an 83/4-in. hole, building angle with a PDM before landing the well within the Marcellus interval. To drill the curved and lateral sections, a PDM might drill for 90% or more of the interval in slid-ing mode. This approach has several drawbacks, including lower ROP, poor hole cleaning and tor-tuous well paths—and often required trips out of the hole to adjust the bent housing when geologic uncertainties forced well path corrections.

Drilling in this play can involve complex 3D well profiles, high curvature rates and direction-ally challenging formation dips that affect DLS. Ultra Petroleum recognized the potential for such problems in a recent project and selected the PowerDrive Archer RSS to meet these chal-lenges, drill the wells quickly and place them in the productive zones of the formation. In 2010, Ultra began an aggressive drilling campaign,

having identified numerous targets within this play. The company drilled the first Marcellus well using a steerable PDM to establish a bench-mark. The next 10 wells were drilled using the PowerDrive Archer RSS. Some of these wells were kicked off from vertical with a long turn in azimuth of 90° or more to line up with the target while simultaneously building angle at rates up to 8°/100 ft [8°/30 m]. Geologic uncertainties near the landing point sometimes called for cor-rective action, often requiring higher build rates (above).

7. Bryan S, Cox J, Blackwell D, Slayden F and Naganathan S: “High Dogleg Rotary Steerable System: A Step Change in Drilling Process,” paper SPE 124498, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, October 4–7, 2009.

8. Al-Yami HE, Kubaisi AA, Nawaz K, Awan A, Verma J and Ganda S: “Powered Rotary Steerable Systems Offer a Step Change in Drilling Performance,” paper SPE 115491, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Western Australia, Australia, October 20–22, 2008.

9. A dogleg is typically quantified in terms of dogleg severity, which is measured in degrees per unit of distance.

10. Bryan et al, reference 7.11. Auflick R, Slayden F and Naganathan S: “New

Technology Delivers Results in Unconventional Shale Play,” presented at the Mediterranean Offshore Conference and Exhibition, Alexandria, Egypt, May 18–20, 2010.

> Three-dimensional trajectory. In this Marcellus Shale well, the operator used the PowerDrive Archer RSS to kick off from vertical, drill a 3D curve with more than 100° change in azimuth, then hold the tangent section. Uncertainty in the geologic model forced the operator to change the landing point by more than 70 ft [21 m]. Once the geologic marker was identified, the RSS quickly built angle to 16°/100 ft [16°/30 m] to reach the target, then the operator switched to a 2° build rate to a create a soft landing within the reservoir section.

Reservoir section

Kickoff point

TD

Landingpoint

Tangent section

Change in azimuth

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42 Oilfield Review

With one exception, the wells drilled subse-quent to the benchmark PDM well realized sig-nificant savings in rig time. In addition, all completion strings were run without incident. The hybrid RSS was also able to reach farther

into the target section, resulting in more than a twofold increase in production rates.

A different resource play has been receiving attention in central Oklahoma, USA, where Cimarex Energy Company has been drilling the

Woodford Shale. Cimarex selected PathFinder, a Schlumberger company, to utilize the PowerDrive Archer RSS in drilling the curve section of the company’s Kappus 1-22H well. Using this RSS to drill the 83/4-in. hole with an 8°/100 ft build rate, the operator achieved an 80% increase in ROP over that of previous wells drilled with PDMs. Having attained a smooth wellbore through the curve, the operator was able to switch to a PowerDrive X5 RSS, which drilled a 4,545-ft [1,385-m] lateral section to TD in just one run. A fast ROP through the curve, combined with high build rate and smooth drilling operations in the lateral section resulted in a savings of 10 drilling days (left).

The high-build-rate capability of this hybrid RSS makes for a shorter curved section, enabling operators to design trajectories with deeper KOPs. A deep KOP lets the operator expand the length of the vertical section, which typically drills faster than the curved section. An operator in the Middle East used the PowerDrive Archer RSS to drill an 81/2-in. curve section for 846 ft [258 m] at a build rate of 7.6°/100 ft [7.6°/30 m]. After meeting the objectives for this well, the operator selected the same system to drill a sec-ond well.

The second well required a more aggressive build rate, but in carrying out this plan, the oper-ator was able to boost overall ROP by drilling through a longer vertical section before kicking off, which enabled a rapid ROP through the verti-cal section. After drilling the 121/4-in. section, the operator set casing and kicked off the 81/2-in. sec-tion. The hybrid RSS consistently maintained an 11°/100-ft [11°/30-m] DLS and drilled the 742-ft [226-m] interval in a single run of 15 hours (left). The well was landed within 1 ft [0.3 m] vertically and 3.8 ft [1.2 m] laterally of its intended target. Because the 81/2-in. section was shortened, the operator also saved nearly 700 ft [210 m] of liner. Pushing the kickoff point deeper sharpened the curve, which reduced the amount of drilled foot-age needed to reach the reservoir and allowed drilling engineers to consider downsizing the cas-ing strings to achieve further savings.12

In northwest Arkansas, USA, SEECO, a wholly owned subsidiary of Southwestern Energy Company, tested the performance of the PowerDrive Archer system as it drilled the verti-cal, curved and lateral sections of an Atoka Formation well. The vertical section was drilled,

> Time versus depth curve. To drill the Kappus 1-22H well in the Woodford Shale, Cimarex used the PowerDrive Archer system. The operator was able to drill to TD in 49 days instead of 59, saving 10 days of drilling time against the projected time frame.

5,000

0

15,000

20,000

10,000

604020

Time, days

0

Dept

h, ft

Plan

As drilled

> Shortened curve. The PowerDrive Archer RSS achieved an 11°/100 ft build rate that allowed the operator to extend the vertical section of the trajectory while shortening the curve to reduce drilling time and the amount of liner required.

Conventional kickoff point

Conventional trajectory

PowerDrive Archer

kickoff point

PowerDrive Archer

trajectory

12. Eltayeb M, Heydari MR, Nasrumminallah M, Bugni M, Edwards JE, Frigui M, Nadjeh I and Al Habsy H: “Drilling Optimization Using New Directional Drilling Technology,” paper SPE/IADC 148462, presented at the SPE/IADC Middle East Drilling Technology Conference and Exhibition, Muscat, Oman, October 24–26, 2011.

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then the well was kicked off along the planned azimuth. The driller built angle at 10°/100 ft [10°/30 m] DLS before making a soft landing at the desired target point with an 88.2° inclina-tion. Using an automated inclination hold fea-ture, the RSS drilled ahead, with inclination maintained within 0.5° of the planned trajec-tory. After drilling for about 1,000 ft [305 m], the directional driller nudged the well path upward to follow the general dip of the reservoir, with the RSS building inclination up to 92° before an unexpected fault created an abrupt lateral ter-mination of the reservoir (right).

Planning for Success The success of PowerDrive Archer steering tech-nology can be attributed largely to extensive planning, modeling and testing. BHA design and modeling of bit and BHA response go into each PowerDrive Archer job.

As a first step, Schlumberger drilling engi-neers obtain offset well information from the operator and focus on drilling issues and bit per-formance data. Engineers use DOX Drilling Office integrated software to design a trajectory to land within the designated target zone while optimiz-ing drilling efficiency. This software package integrates trajectory design with drillstring spec-ifications and BHA design, hydraulics, torque and drag. The DOX software lets drilling engineers quickly run multiple scenarios to optimize the well path. A well plan and equipment plan are then formulated to reach the given target, taking into account known drilling issues. Anticollision modeling ensures that the proposed trajectory will avoid nearby wells.

Hole quality is a critical issue in high DLS or extended-reach wells; poor hole quality may impact the success of a well by hampering efforts to deploy drilling and completion equip-ment through tight curves and may limit the footage that can be drilled through the lateral section. Extensive testing has played an impor-tant role in developing capabilities to deliver high-quality boreholes. One such test involved a series of blocks, each with a different compres-sive strength. These test blocks were arranged side by side to form a rectangle nearly 45 m [150 ft] long. The PowerDrive Archer RSS drilled through the blocks using various combi-nations of bits and power settings to simulate downhole drilling conditions. Once the holes were drilled, a laser caliper measured the bore-hole gauge in each block and consistently found no borehole rugosity (right).

> Two-dimensional curve and lateral section. SEECO developed two drilling scenarios to accommodate uncertainties in Atoka Formation dip. The actual well path (red) differs from the two planned trajectories. Geosteering LWD sensors proved the dip to lie between those assumed in the two plans. Faulting terminated the reservoir and shortened the lateral section considerably. (Adapted from Bryan et al, reference 7.)

2,500

2,000

3,000

0 500 1,000 1,500

Lateral section, ft

Original planAs drilled

Pilot hole

Revised plan

2,000 2,500 3,000

True

ver

tical

dep

th, f

t

> Smooth drilling through test blocks. Laser calipers revealed no borehole rugosity in the borehole drilled by the PowerDrive Archer RSS (bottom). (Photographs courtesy of Edward Parkin, Stonehouse, England.)

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44 Oilfield Review

Although modeling of BHA and bit response has been notoriously difficult, recent advances make it possible to analyze dynamic downhole drilling conditions and compute drillstring stresses. The forces generated by the bit and their effects on BHA steering performance can also be predicted. This is followed by laboratory testing and, finally, field testing to deliver opti-mized BHA and bit designs.

Schlumberger performed finite element anal-ysis and bending moment modeling and analysis on components of the PowerDrive Archer BHA (left). Field testing validated BHA behavior to ensure steerability at high build rates. After the BHA design was finalized, engineers conducted shock and vibration analysis to identify critical resonance frequencies and RPMs to be avoided while drilling. Torque and drag simulations for drilling and tripping operations were run to ensure BHA integrity. Hydraulics modeling was also conducted across various mud weight and flow ranges.

Drillbit technology is another factor that is vital to the success of any well. The bit affects drilling efficiency, or the ability to achieve and maintain a high average ROP. Bit design also impacts steerability, or the ability to place the well in the right part of the reservoir. Push-the-bit systems generally require an aggressive side-cutting bit for delivering doglegs, while point-the-bit systems tend to rely on stabiliza-tion from a less aggressive bit with a longer side gauge. With a hybrid system, using the right bit is especially critical. For this RSS, engineers con-ducted extensive testing to characterize interac-tions between the bit, tools and formation to best match the bit profile to the tools and maxi-mize performance.

Bits for the PowerDrive Archer system can be tailored to enhance steerability and deliver improved ROP for a particular field. The IDEAS integrated drillbit design platform lets drilling engineers optimize bit selection based on model-ing the drilling system overall.13 The IDEAS soft-ware accounts for a wide range of variables in its bit design and BHA optimization packages: •rocktypeandformationcharacteristics•interaction between bit cutter surface and

rock face•contactbetweendrillstringandwellbore•detailedbottomholeassemblydesign•casingprogram•welltrajectory•drillingparameters.

Modeling data were also used as input to a fatigue management system that predicts fatigue life for each component of the BHA. When sub-jected to rotation through high doglegs, BHAswill experience large bending moments. Fatigue life decreases exponentially with increasing build rate and can reduce the life of standard BHA components to a matter of hours. Fatigue modeling and tracking is helping drillers avoid twist offs and other catastrophic failures.

Schlumberger tracks fatigue life automati-cally to ensure integrity of BHA components. With the aid of PERFORM Toolkit data optimiza-tion and analysis software, the wellsite engineer can record RPM, ROP, DLS and other contribu-tors to fatigue, providing real-time fatigue man-agement information and predictions of fatigue life. Monitoring fatigue life is not a trivial task: The position of each component along the well path must be tracked and the bending moment caused by DLS—along with RPM and time—needs to be quantified. Tracking fatigue in real time, including time off-bottom rotating, can sig-nificantly improve the accuracy of the fatigue life estimates. These fatigue data may be monitored remotely at operations support centers, where the data can be reviewed by drilling experts who can advise operators when critical components need to be replaced.

Advances in directional drilling technology are helping operators access hydrocarbons that could not otherwise be produced. The latest gen-eration of rotary steerables is achieving well tra-jectories and step-outs that were previouslyunimaginable, while delivering lower cost and lower risk wells and improving production. These increasingly complex well trajectories are spur-ring the industry to reach further in the search for new reserves. —MV

> Tool joint stress contours. Drillstring tool joint connections are subjected to a variety of loads that affect the fatigue life of a tool. In particular, tool joints are subjected to torque as they are made up on the drill floor, when the pin is screwed into the box (inset). This is followed later by bending moments as the curve section is drilled. Finite element analysis can be used to predict stress along a threaded connection by accounting for the torque and bending moments expected on each job. This plot indicates higher von Mises stress in the pin than in the box when the threaded connection is made up and subjected to a bending moment. This information is useful in predicting the fatigue life of the connection.

1.184 × 105

1.036 × 105

8.880 × 104

7.400 × 104

5.920 × 104

4.440 × 104

2.960 × 104

1.480 × 104

1.257 × 104

von Mises stress,psi

Pin Box

Pin

Box

13. The IDEAS program was developed in the 1990s by Smith Bits, which was later acquired by Schlumberger. For more on bit design using the IDEAS system: Centala P, Challa V, Durairajan B, Meehan R, Paez L, Partin U, Segal S, Wu S, Garrett I, Teggart B and Tetley N: “Bit Design—Top to Bottom,” Oilfield Review 23, no. 2 (Summer 2011): 4–17.

44581araD7R1.indd 9 2/17/12 9:40 PM

Contributors

Winter 2011/2012 45

Matthew Billingham, based in Roissy-en-France, France, is Schlumberger Wireline Operations Manager for Saudi Arabia, Kuwait and Bahrain. Previously, he was the tractor and conveyance product champion for Schlumberger, and was responsible for planning activ-ity, ensuring service quality and guiding the develop-ment of tractor technology. After earning a BEng degree in electrical and electronic engineering from the University of Leicester, England, he spent two years in university-related work before joining Schlumberger in 1994 as a wireline engineer in Great Yarmouth, England. He was involved in developing hor-izontal production logging, downhole conveyance in horizontal wells and perforating techniques as a field service manager for MaxPro* production services in Norway. He subsequently transferred to Algeria as a field service manager for MaxPro services, where he helped update many wireline operations policies. Matthew was a service quality coach in Aberdeen before assuming his current position in 2003.

Vincent Chatelet is Head of the Electronics and Mechanics Department with Schlumberger Geoservices in Roissy-en-France, France. He began his career with Schlumberger as an electronics engineer in 1991. In his 21 years with Schlumberger, he has been a project leader, head of electronics service, and electronics and manufacturing department manager. Vincent received BS and MS degrees in electronics engineering from the Institute Nationale des Sciences Appliquées in Lyon, France.

John Cook, a Scientific Advisor for Schlumberger, works in the drilling department at the Cambridge Research Center, England. Since joining Schlumberger in 1983, he has worked on a wide range of problems involving geomechanics and rock behavior. He holds MA and PhD degrees in materials science and physics, respectively, from the University of Cambridge, England. John is joint author of the geomechanics chapter of the SPE Advanced Drilling and Well Technology handbook and is the author of many SPE and other papers.

Morris Cox began his career in 1985 with Watters Wireline & Snubbing Consultants Inc as a slickline operator and consultant. From 1989 to 2007, Morris worked for Halliburton Energy Services, first as a slick-line operator and then as global project manager. Since 2007, he has been a Senior Completions Engineer for Nexen Petroleum USA Inc. in Houston.

David A. Edwards, who is based in Abingdon, England, is a Principal Software Engineer with Schlumberger and leads the well modeling team in the INTERSECT* simulator group. David began his career in 1988 as a systems engineer with Smith Associates in Guildford, England, and later joined Exploration Consultants Ltd in Henley-on-Thames, England. He earned a BS degree in physics from the University of Warwick, England, and a PhD degree in astrophysics from the University of Oxford, England.

Edwin Felczak is a Schlumberger Drilling Services Sales Engineer for PathFinder in Oklahoma City, Oklahoma, USA. He joined Schlumberger in 2003 and has worked in various positions in the field as well as in testing, quality, coordinating and sales. He has a BS degree in mechanical engineering from Texas A&M University, College Station, USA.

Paul A. Fjerstad is a Reservoir Engineering Advisor in Houston for the Chevron Energy Technology Company. He has more than 25 years of experience in technology development and change management processes and deployment. He is the Chevron INTERSECT Change Management Project Manager responsible for deploy-ment of the next-generation reservoir simulator. Paul began his career in 1985 with Norsk Hydro ASA as a reservoir engineer for North Sea field development and reservoir management planning in Oslo and Bergen, Norway. He was next involved in field develop-ment planning, formation evaluation and prospect evaluation for BP plc in Stavanger. From 1992 to 1994, he was a reservoir engineering advisor to Kuwait Oil Company working on rebuilding oil production capac-ity and evaluating reservoir damages caused by battle. From 1994 to 2001, he led software support, sales and marketing for Schlumberger in Dubai, and prior to joining Chevron in 2005, he was the ECLIPSE* reser-voir simulation software product champion for Schlumberger in the UK.

Jessica Franco is a Reservoir Engineer for Total SA, where she has worked since 2005. She focuses on the numerical design of experiments and has managed thermal simulations for heavy oil and enhanced oil recovery studies. Since 2011, she has been in Angola working on a deepwater field, focusing on new well developments and numerical simulations. Jessica obtained a PhD degree in applied mathematics from the Ecole National Supérieure des Mines de Saint-Etienne, France.

Neil D. Godwin has worked for Schlumberger at Stonehouse Technology Center in England since 2008. He wrote and developed a suite of manuals for the PowerDrive Archer* rotary steerable system and is now creating modular manuals for several precommer-cial products under development in Stonehouse. Before joining Schlumberger, he interned with Lockheed Martin UK, where he wrote technical docu-mentation on military aircraft. Neil holds a BA degree in English and an MA degree in technical communica-tions from the University of Portsmouth, England.

Fred Growcock is the Global Fluids Advisor for Occidental Oil and Gas Corporation in Houston, where he provides technical support to the company’s world-wide drilling fluid field operations. He began his career as a scientist at the US Department of Energy Brookhaven and Oak Ridge National Laboratories in the mid-1970s working on coal liquefaction and gasifi-cation and nuclear reactor safety. He then moved to Dowell Schlumberger to develop acidizing corrosion inhibitors and foamed fracturing fluids. Subsequently, he joined Amoco Production Company to carry out drilling fluids R&D and served as an adjunct professor of chemical engineering at the University of Oklahoma in Norman. He moved to M-I SWACO, a Schlumberger company, to focus on research and provide technical

service support. Fred earned BA and BS degrees in chemistry from The University of Texas at Austin and MS and PhD degrees in physical chemistry from New Mexico State University, Las Cruces, USA. He has authored numerous papers and holds a dozen patents on corrosion inhibitors, drilling fluid systems and com-pletion fluid products. Fred served as a 2009/2010 SPE Distinguished Lecturer.

Dayal Gunasekera is a Reservoir Engineering Marketing Manager for Schlumberger in Abingdon, England. He has more than 25 years of industry experi-ence and has held his current position since 2009. His previous positions include Engineering, Manufacturing and Sustaining competency manager, global software métier manager, Well Services engineering applica-tions manager and FloGrid* program manager; he has also been a petroleum engineering software developer. He is a member of the scientific committee of the European Association of Geoscientists and Engineers European Conference on the Mathematics of Oil Recovery and has served as a member of the SPE Reservoir Simulation Symposium technical committee. Dayal received bachelor’s and master’s degrees in gen-eral engineering from the University of Cambridge, England. He has a doctoral degree in electronic and electrical engineering from the University of Wales, Swansea.

Quan Guo, who is based in Houston, is Manager for Industry Initiatives and a Schlumberger Eureka Technical Career Advisor. He has been with M-I SWACO, a Schlumberger company, since 2003; his current primary technical focus is on geomechanics and subsurface issues related to drilling fluids, well-bore strengthening and shale gas. Previously, he was with Advantek International llc in Houston and TerraTek, Inc, in Salt Lake City, Utah, USA, prior to its acquisition by Schlumberger. He has written more than 50 journal and SPE articles. Quan has been a technical editor for the journal SPE Drilling and Completion and has served on the program committee of several SPE applied technology workshops. He holds a BS degree in mathematics and mechanics from Lanzhou University, China, an MS degree in engineer-ing mechanics from Huazhong University of Science and Technology, Wuhan, Hubei, China, and a PhD degree in mechanical engineering from Northwestern University, Evanston, Illinois, USA.

Richard Hawkins, based in Sugar Land, Texas, is a Product Champion for the PowerDrive Archer rotary steerable system, a position he has held since August 2010. Before this, he served as a drilling ser-vices manager and a directional drilling supervisor for Schlumberger. Richard joined the company in 1996 as an MWD and LWD supervisor in Aberdeen. He obtained a BS degree in mechanical engineering from the University of Lincolnshire and Humberside, Lincoln, England.

44581araD8R1.indd 1 2/20/12 11:57 PM

46 Oilfield Review

Viet Hoang is a Senior Engineering Advisor at Chevron Energy Technology Company in San Ramon, California, USA. He has more than 30 years of experience with Chevron in heavy oil recovery and reservoir simula-tion R&D, as well as geothermal and enhanced oil recovery chemical development and applications. Viet has contributed extensively to reservoir engi-neering and simulation studies for numerous oil and gas recovery and geothermal projects. He has a PhD degree in mechanical engineering from the University of California at Berkeley.

Mike Hodder is Director of the M-I SWACO Aberdeen Research and Technology Centre in Scotland. He has an MS degree in geology and chemistry from the University of Cambridge, England, and has more than 30 years of experience in the drilling fluids business. Mike began his career in research, next became a field engineer and has since worked in various technical and marketing positions in the UK, France and the US. In the late 1990s, Mike established the Dowell Technical Center in New Orleans, which focused on well construction issues such as drilling fluids and cement in deepwater wells.

Stephen Jones is a PathFinder Business Development Manager for Schlumberger in Katy, Texas. In 1999, he joined Schlumberger as a directional drilling supervi-sor in Aberdeen. Previously, he was a field engineer and directional driller for Halliburton Energy Services. Stephen is currently involved in development of high-performance rotary steerable directional drilling solu-tions. He received his BS degree in mechanical engineering and an MS degree in offshore engineering at Robert Gordon University, Aberdeen.

Jitendra Kikani is the Manager for Reservoir Performance Products at Chevron Energy Technology Company in Houston, where he is responsible for R&D in reservoir simulation. He is also the Program Manager for INTERSECT collaboration with Schlumberger. Previously, he held various positions at Chevron, including manager of gas assets in Angola and subsurface manager for flare elimination projects. He has worked for Chevron for more than 15 years, has twice been an SPE Distinguished Lecturer and pub-lished extensively in the areas of reservoir surveil-lance, well testing and permanent downhole gauges. Jitendra earned a BS degree in petroleum engineering from the Indian School of Mines, Dhanbad, Jharkhand, India, an MS degree in mechanical engineering from the University of California at Berkeley and an MS degree in mathematics and a PhD degree in petroleum engineering from Stanford University in California.

Ke Li joined Schlumberger in 2006 as a mechanical engineer and next became a simulation and modeling engineer in the Mechanical Technology and Simulation Group at Sugar Land, Texas. He became the Sugar Land Simulation and Modeling Group Leader in 2011. He obtained a PhD degree in mechanical engineering– engineering mechanics from Michigan Technological University, Houghton, USA. Ke has published numerous journal and conference papers in the areas of solid mechanics, materials modeling and structural analysis.

Kate Mantle, who is based in Stonehouse, England, began her career with Schlumberger as a mud logger in 1989. In 1995, she became a directional driller. Between 1998 and 2007, Kate worked as a consultant directional driller on Schlumberger jobs, and became involved in PowerDrive Archer rotary steerable system operations. In 2008, she worked as service quality engi-neer in the PowerPak* Sustaining Team at Stonehouse Drilling, Rotary steerable and Motors (SDRM). In January 2012, she became Directional Drilling Advisor to the SDRM Archer Operations Support Team. She received a BS degree in geology in 1988 from University College, Cardiff, Wales.

Jonathan Morris is the INTERSECT Program Manager for Schlumberger in Abingdon, England, and has 25 years of experience in the software industry. Prior to his current position, he was lead software architect for the simulation group in Abingdon. Jonathan holds bachelor’s and master’s degrees from the University of Cambridge, England, and an MSc degree from the University of Oxford, England, all in mathematics.

Stuart Murchie began his Schlumberger career in well testing in Aberdeen in 1984 after graduating from the University of Dundee, Scotland, with a BS degree in mechanical engineering. In 1988, he transferred to Wireline, where he held various field operation positions in Asia followed by a posting in Paris as new technology manager for Wireline and Testing. In 1999, he was appointed vice president of Data & Consulting Services, based in Houston. He next served as QHSE manager for Oilfield Services North and South America, then moved to Thailand as the managing director for Oilfield Services Central East Asia. He returned to the UK in 2004 as managing director for Oilfield Services UK and Ireland. In 2005, he became personnel manager for Schlumberger Integrated Project Management and then regional vice president for the Europe/Africa/Caspian area. Now based in Roissy-en-France, Stuart assumed his current position as Marketing and Technology Manager for Slickline Services in 2011.

Sivaraman Naganathan, who is based in Stonehouse, England, works as Schlumberger Europe, Caspian and Africa Area Asset Manager. Sivaraman began his oilfield career in 1995 as an MWD engineer, and has held a vari-ety of positions in the oil and gas industry. He received his BS degree in instrumental and control engineering and MS degree in physics from the Birla Institute of Technology and Science, Pilani, Rajasthan, India.

William B. Paulsen began his career in 1977 with the Red Adair Company as a well control specialist in Houston. He then worked as a sales and service techni-cian at Texas Oilfield Sales & Service Company. In 1997, he became a petroleum consultant for BP Exploration, where he was responsible for field super-vision of remedial well operations in the BP Cusiana and Cupiagua development project in Colombia. He currently works for ATP Oil and Gas Corporation, in Houston, as a Production Superintendent. William manages the decommissioning of pipelines, wellbores and platforms and is responsible for through-tubing recompletions and workovers on shelf properties; he is also involved in deepwater riserless well inter-vention planning.

Lisette Quettier is a Reservoir Simulation Expert at Total SA, in Pau, France, where she has worked since 1981. Her work focuses on reservoir simulation, includ-ing code development, R&D, support, training and knowledge management. She is currently working on

INTERSECT thermal developments and testing. She began her career working on thermal enhanced oil recovery techniques with the development of a simula-tor and on several experimental projects and simula-tion studies on steam injection pilots. Lisette earned a degree in hydraulic engineering from Institut National Polytechnique de Grenoble, France, and a PhD degree in fluid mechanics from Institut de Mécanique des Fluides de Toulouse, France.

Gareth Shaw began his career as a research fellow at Delft University of Technology, the Netherlands. Based in Abingdon, England, he has been an INTERSECT Engine Project Manager with Schlumberger since 2009. Gareth has a BS degree in mathematics from the University of Bristol, England, and MS and doctoral degrees in mathematics from the University of Oxford, England.

Kevin Shaw is a Simulator Product Champion for Schlumberger and a Commercialization Lead for the INTERSECT reservoir simulator. Kevin, who is based in Abingdon, England, joined Schlumberger in 1989. Prior to his current positions, he worked in Abingdon on the commercialization of ECLIPSE software, near wellbore modeling, Avocet* Integrated Asset Modeler and INTERSECT field management system.

Fred Slayden, who is based in Houston, has worked for Schlumberger as a US Land Drilling Manager since 2006. Prior to his career with Schlumberger, he worked for Baker Hughes, Williams Engineering and Weatherford International. Fred has had more than 40 years of experience in the oil industry. He received his BS degree in chemical engineering from Texas A&M University, College Station, and Tarleton State University, Stephenville, Texas.

Ariel Torre joined Schlumberger in 1996 as an MWD specialist in Argentina. He has also worked in Abu Dhabi, Brazil, Qatar and the US. Currently, he works as an Eastern Division Operations Manager for PathFinder in Oklahoma City, Oklahoma. In 1997, Ariel obtained his bachelor’s degree in electronics engineer-ing at Universidad Nacional de Córdoba, Argentina.

Eric van Oort, who has worked at Royal Dutch Shell Company for 20 years, joined the company as a research scientist to focus on wellbore instability in shale formations and the design of novel water-base mud systems. In 1996, he moved to Houston to work as a research team lead at the Shell Bellaire Technology Center and since then has held various senior techni-cal and managerial positions within Shell Oil Company. He currently serves as Well Performance Improvement and Onshore Gas Technology Manager for Shell Upstream Americas in Houston. Eric is a for-mer SPE Distinguished Lecturer, a best paper award recipient from SPE Drilling & Completion and a fre-quent conference organizer, chair, discussion panel member and invited speaker. He holds a PhD degree in chemical physics.

Dominic Walsh began his career in 2001 at Riversoft Ltd in London. Currently, he is based in Abingdon, England, where he works for Schlumberger as an Engine Architect on the INTERSECT simulation project, a position he has held since 2006. He is responsible for the architecture of simulator engines, with particular focus on parallel scalability. Dominic has a BS degree in physics from The Imperial College of Science, Technology and Medicine, London, and a PhD degree in physics from the University of Durham, England.

An asterisk (*) is used to denote a mark of Schlumberger.

44581araD8R1.indd 2 2/20/12 11:57 PM

• TheEvolutionofCulture

• TheEvolutionofCreativity

• Unsustainable

• TheBeginning

• Bibliography,Index

Mr. Deutsch’s previous tome, TheFabricofReality, took a broad-ranging sweep that encompassed evolution as well as knowledge, computation and physics, and earned him a fan base that has been eagerly awaiting his second publication. TheBeginningofInfinity is equally bold, addressing subjects from artificial intelligence to the evolution of culture and of creativity; its conclusions are just as profound. Mr. Deutsch argues that decent explanations inform moral philosophy, political philosophy and even aesthetics. He is provocative and persuasive. Who knows? Perhaps he is also right.

“IntheBeginning—AQuantumPhysicist’s

Long-AwaitedSecondBook,”The Economist

(March24,2011),http://www.economist.com/

node/18438055(accessedOctober3,2011).

David Deutsch’s TheBeginningofInfinity is a brilliant and exhilarating and profoundly eccentric book. It’s about everything: art, science, phi-losophy, history, politics, evil, death, the future, infinity, bugs, thumbs, what have you. . . . Deutsch (who is famous, among other reasons, for his pioneer-ing contributions to the field of quantum computation) is so smart, and so strange, and so creative, and so inexhaustibly curious, and so vividly intellectually alive, that it is a distinct privilege, notwithstanding everything, to spend time in his head.

AlbertD:“ExplainingItAll:HowWeBecamethe

CenteroftheUniverse,”The New York Times

(August12,2011),http://www.nytimes.

com/2011/08/14/books/review/the-beginning-of-

infinity-by-david-deutsch-book-review.

html?pagewanted=all(accessedOctober3,2011).

Winter 2011/2012 47

NEW BOOKS Coming in Oilfield Review

Plug and Abandon. Thousands of onshore and offshore wells around the world are reaching the end of their economic lives. Owners of these wells need to permanently plug and abandon them in a safe and environ-mentally responsible manner. The cost of these operations ranges from a relatively small expense for most onshore wells to millions of US dol-lars for offshore wells with complex infrastructure that must be removed. This article looks at the tools and methods available to support plug and abandon operations.

Jars. For more than 80 years, drill-ing jars have been widely accepted as unglamorous, inexpensive insur-ance against stuck pipe. While the basic technology of jars has changed little, understanding of the dynamics necessary to ensure a successful jarring operation has expanded significantly in recent years. This article looks at the lessons learned and surveys how the industry is solving the challenge of using jars in today’s increasingly complex well configurations.

Mud Logging. Mud loggers monitor a variety of drilling parameters to alert drilling personnel to changes in down-hole drilling conditions. Through examination of formation cuttings, augmented by measurements of drill-ing rates and chromatographic analysis of mud gases, mud loggers often obtain the earliest indicators of reser-voir potential. Recent advances in drilling sensor technology and mud gas analysis are expanding the range of mud logging services.

LWD Sonic Advances. Acoustic LWD tools were first introduced to the oil and gas industry in the mid-1990s, but they have evolved considerably since then. LWD sonic data now include results that were once available only with wireline logging tools. Drilling engineers now use a new quadrupole sonic tool for monitoring accurate pore pressure, determining geomechanical proper-ties and managing drilling fluid for borehole stability. Case studies demonstrate the use of this tool for real-time measurement of geome-chanical properties and for drilling optimization.

The Blind Spot: Science and the Crisis of UncertaintyWilliam ByersPrinceton University Press41 William StreetPrinceton, New Jersey 08540 USA2011. 208 pages. US$ 24.95ISBN:978-0-691-14684-3

Mathematician William Byers maintains that the unpredictable, the uncertain, the unknowable and the ambiguous, rather than a faith in scientific cer-tainty, are what give rise to better science. The author draws on examples from Wall Street to mathematics to illustrate the blind spots in our under-standing and decision making in the sciences, mathematics and technology.

Contents:

• TheBlindSpot

• TheBlindSpotRevealed

• CertaintyorWonder?

• AWorldinCrisis!

• Ambiguity

• Self-Reference:TheHumanElementinScience

• TheMysteryofNumber

• ScienceastheAmbiguousSearchforUnity

• TheStillPoint

• Conclusion:LivinginaWorldofUncertainty

• Notes,References,Index

The author argues that while reconfiguring the human attitude toward embracing uncertainty may be uncomfortable, ultimately it will enable creative opportunity on a massive scale; that an acceptance of ambiguity is ‘the price we pay for creativity.’ Byers suggests that a continuing adherence to certainties may allow the fundamental uncer-tainty of modern culture to manifest itself in a variety of catastrophic ways. . . . Byers incorporates many brilliant thinkers and seminal scien-tific breakthroughs into his discussion,

offering the cogent, invigorating argument that only by embracing uncertainty can we truly progress.

“TheBlindSpot,”Kirkus Reviews(May1,2011),

http://www.kirkusreviews.com/book-reviews/

non-fiction/william-byers/blind-spot-science-

uncertainty/#review(accessedAugust29,2011).

The Beginning of Infinity: Explanations That Transform the WorldDavid DeutschViking Penguin, a member ofPenguin Group (USA) Inc.375 Hudson StreetNew York, New York 10014 USA2011. 487 pages. US$ 30.00ISBN978-1-101-54944-5

Deutsch looks at human progress, especially the rapid changes we’ve made since the Enlightenment. He proposes that the cause of such progres-sion is the quest for good explanations, which have the scope and power to cause change. He also posits that such a quest is the operating principle of not only science but of all successful human endeavor. He explains how this flow of improving explanations has infinite reach.

Contents:

• TheReachofExplanations

• ClosertoReality

• TheSpark

• Creation

• TheRealityofAbstractions

• TheJumptoUniversality

• ArtificialCreativity

• AWindowonInfinity

• Optimism

• ADreamofSocrates

• TheMultiverse

• APhysicist’sHistoryofBadPhilosophy

• Choices

• WhyAreFlowersBeautiful?

44581araD9R1.indd 1 2/20/12 11:56 PM

Why Geology Matters: Decoding the Past, Anticipating the FutureDoug MacdougallUniversity of California Press2120 Berkeley WayBerkeley, California 94704 USA2011. 285 pages. US$ 29.95ISBN: 978-0-520-26642-1

This book gives an overview of Earth’s history from information extracted from ice cores, rocks and other natural archives. Macdougall explores how an understanding of geosciences illuminates many of the world’s present problems—energy availability, freshwater accessibility, agriculture sustainability and biodiversity maintenance— and how we can use geosciences to prepare for the future.

Contents:

• SetinStone

• BuildingOurPlanet

• CloseEncounters

• TheFirstTwoBillionYears

• WanderingPlates

• ShakyFoundations

• Mountains,Life,andtheBigChill

• ColdTimes

• TheGreatWarming

• ReadingLIPs

• RestlessGiants

• Swimming,Crawling,andFlyingTowardthePresent

• WhyGeologyMatters

• Bibliography,FurtherReading,Index

Macdougall . . . . gives an up-to-date overview of what scientists now know about the history of Earth and explains why Earth’s past is relevant to contemporary human society. The author’s discussion of the history of climate change over the past several billion years and the causes thereof, for instance, is directly applicable to modern debates about climate change. He also addresses ways to apply geology to questions of energy resources, sustainable agriculture, biodiversity, and access to fresh water and presents all in an enjoyable reading style. Highly recommended.

DimmickCW:Choice49,no.2

(October2011):336.

Oilfield Review48

The Techno-Human ConditionBraden R. Allenby and Daniel SarewitzThe MIT Press55 Hayward StreetCambridge, Massachusetts 02142 USA2011. 222 pages. US$ 24.95ISBN: 978-0-262-01569-1

Authors Allenby and Sarewitz argue that humans have always coevolved with their technologies, but today we are additionally transformed by the application of internal technologies such as a reengineered immune system, artificial joints and neurochemical mood enhancers. As a result, the authors say, humans now need to embrace a new “technohuman relationship,” exploring what it means to be human in an era of technological complexity.

Contents:

• WhataLong,TranshumanTripItHasAlreadyBeen

• IntheCause-and-EffectZone

• LevelIandIITechnology:Effectiveness,Progress,andComplexity

• LevelIIITechnology:RadicalContingencyinEarthSystems

• IndividualityandIncomprehensibility

• Complexity,Coherence,Contingency

• KillerApps

• InFrontofOurNose

• Epilogue:TheMuseumofHumanFrailty

• Bibliography,Index

TheTechno-HumanCondition . . . illustrates how technology is a part of all individuals, including their cul-tures and institutions. Allenby and Sarewitz . . . encourage the reader to understand, embrace, and celebrate people’s ignorance of the complexity of techno-human systems in order to begin to manage technological and scientific prowess with rationality, ethics, humility, and responsibility. The authors illustrate th[eir] model by analyzing two. . . systems: rail-roads and modern military technol-ogy. Recommended.

BauchspiesWK:Choice49,no.2

(October2011):323.

The Theory That Would Not Die: How Bayes’ Rule Cracked the Enigma Code, Hunted Down Russian Submarines, and Emerged Triumphant from Two Centuries of ControversySharon Bertsch McGrayneYale University Press302 Temple StreetNew Haven, Connecticut 06511 USA2011. 320 pages. US$ 27.50ISBN:978-0-300-16969-0

Bayes’ Rule, the mathematical theorem formulated in the 1740s by the Reverend Thomas Bayes, links conditional probability to its inverse. The author follows the people who furthered the theorem as well as those who vehemently opposed it; she explores the development of the theorem from its discovery, rise, near demise and rediscovery through its many controversies and successes and concludes with its presentday application to crises characterized by great uncertainty.

Contents:

• PartI.EnlightenmentandtheAnti-BayesianReaction:Causes in the Air; The Man Who Did Everything; Many Doubts, Few Defenders

• PartII.SecondWorldWarEra:Bayes Goes to War; Dead and Buried Again

• PartIII.TheGloriousRevival:Arthur Bailey; From Tool to Theology; Jerome Cornfield, Lung Cancer, and Heart Attacks; There’s Always a First Time; 46,656 Varieties

• PartIV.ToProveItsWorth:Business Decisions; Who Wrote TheFederalist?; The Cold Warrior; Three Mile Island; The Navy Searches

• PartV.Victory:Eureka!; Rosetta Stones

• Appendixes,Notes,Glossary,Bibliography,Index

In a densely packed and engaging book, Sharon Bertsch McGrayne traces the remarkable history of Bayes’ Rule. . . . At times reading like a historical account, at times like investigative journalism, at yet other times like a statistical commentary, Bertsch McGrayne does an admirable job of giving a voice to the scores of famous and non-famous people and

data who contributed, for good or for worse, to its historical perambula-tions to the present day, in the process making the theory come alive through her prose in a way that is very acces-sible to the patient non-statistician.

BottoneM:“TheTheoryThatWouldNotDieby

SharonBertschMcGrayne,”Significance,

http://www.significancemagazine.org/details/

review/1062663/The-Theory-That-Would-Not-

Die-by-Sharon-Bertsch-McGrayne.html(accessed

September14,2011).

The theorem has a long and surprisingly convoluted history, and McGrayne chronicles it in detail. . . . Statistics . . . can be applied to almost any area of science or life, and this litany of applications is intended to be the unifying thread that sews the book into a coherent whole. It does so, but at the cost of giving it a list-like, formulaic feel. More successful are McGrayne’s vivifying sketches of the statisticians who devoted themselves to Bayesian polemics and counterpolemics.

PaulosJA:“TheMathematicsofChangingYour

Mind,”The New York Times(August5,2011),

http://www.nytimes.com/2011/08/07/books/

review/the-theory-that-would-not-die-by-sharon-

bertsch-mcgrayne-book-review.html(accessed

September14,2011).

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Winter 2011/2012 49

Wrestling with Nature: From Omens to SciencePeter Harrison, Ronald L. Numbers and Michael H. Shank (eds)The University of Chicago Press1427 East 60th StreetChicago, Illinois 60637 USA2011. 416 pages. US$ 95.00ISBN: 978-0-226-31783-0

This collection of essays examines the investigation of nature through the millennia and explains the content, goals, methods and practices associated with such investigations. The authors explore the concept of the history of science and attempt to answer the questions “When and where did science begin?”

Contents:

• Introduction

• NaturalKnowledgeinAncientMesopotamia

• NaturalKnowledgeinthe ClassicalWorld

• NaturalKnowledgeinthe ArabicMiddleAges

• NaturalKnowledgeinthe LatinMiddleAges

• NaturalHistory

• MixedMathematics

• NaturalPhilosophy

• ScienceandMedicine

• ScienceandTechnology

• ScienceandReligion

• Science,Pseudoscience,andScienceFalselySo-Called

• ScientificMethods

• ScienceandthePublic

• ScienceandPlace

• Contributors,Index

This tightly focused collection of essays examines the diverse approaches to studying nature from the earliest civilizations to the pres-ent. . . . the editors of this volume of historical essays warn against read-ing modern ideas about the nature of science back into the past. . . . These essays should appeal to a broad audience interested in the diverse origins of modern science. Recommended.

HagenJB:Choice49,no.2(October2011):327.

An Empire of Ice: Scott, Shackleton, and the Heroic Age of Antarctic ScienceEdward J. LarsonYale University Press302 Temple StreetNew Haven, Connecticut 06511 USA2011. 326 pages. US$ 28.00ISBN: 978-0-300-15408-5

While the early Antarctic explorers Amundsen, Scott and Shackleton are known for their individual quests to be the first to reach the South Pole, the author places these single-minded goals into a larger story—that of massive scientific enterprises. Larson looks at the larger scientific, social and geopo-litical context of the era and explores the nascent days of international scientific cooperation.

Contents:

• “ThreeCheersfortheDogs”

• ACompassPointingSouth

• TheEmpire’sMapmaker

• InChallenger’sWake

• TakingtheMeasureofMen

• MarchtothePenguins

• DiscoveringaContinent’sPast

• TheMeaningofIce

• Heroes’Requiem

• Notes,Index

Extremely well written and docu-mented, AnEmpireofIce is a grip-ping account that reads almost like a thriller, demonstrating the explorers’ well-known courage and persistence in the face of atrocious hardship. At the close of another International Polar Year, it demonstrates how international scientific cooperation in the world’s coldest regions came to be established. Highly recommended.

IvesJD:Choice49,no.2(October2011):336.

Bottled Lightning: Superbatteries, Electric Cars, and the New Lithium EconomySeth FletcherHill and Wang, a division ofFarrar, Straus and Giroux18 West 18th StreetNew York, New York 10011 USA2011. 260 pages. US$ 26.00ISBN: 978-0-8090-3053-8

Starting with the invention of the battery and ending with electric cars, the author traces the arc of scientists’ quest to convert stored chemical energy into electrical energy. Lithium, which powers nearly all batteries today, is at the heart of the story; Fletcher travels from the salt flats of Bolivia to univer-sity laboratories to follow the path of this essential element. The book focuses on the environmental movement, the American auto industry, patent wars and government policies, all of which play a part in the shaping of the lithium battery and its uses.

Contents:

• Prologue

• TheElectricians

• FalseStart

• TheWirelessRevolution

• RevivingtheElectricCar

• TheBlankSpotattheHeartoftheCar

• TheLithiumWars

• TheBrink

• TheStimulus

• TheProspectors

• TheLithiumTriangle

• TheGoal

• Epilogue

• Appendix:GlobalLithiumReservesandIdentifiedResources

• Notes,SelectedBibliography,Index

Fletcher, a senior editor at PopularScience magazine, clearly sides with the scientists and engineers who occupy this tightly written book. . . . he hopes they are right, and that the era of oil winds down. But he does not fall into the technology-writer’s trap of becoming gee-whizzy about his subject, which is just the right tone. This is a well-written, smart and—when Fletcher gets

rolling in the last quarter of the book—rollicking story. [He gives] us the history, the science, the business and the characters without veering off into irrelevant territory. . . . Fletcher ends his book with a look at how—211 years after the battery’s inven-tion—we are practically speaking just at the beginning of its potential.

LeVineS:“BookReview:SethFletcher’s‘Bottled

Lightning’,”Foreign Policy(May17,2011),http://

oilandglory.foreignpolicy.com/posts/2011/05/16/

book_review_seth_fletchers_bottled_lightning

(accessedAugust29,2011).

Mr. Fletcher does a good job surveying this old-yet-nascent indus-try in the U.S. . . . Some commentators worry that we’re going to replace our dependence on foreign oil with a dependence on foreign batteries—and foreign lithium. BottledLightning alleviates at least one worry: By taking us to the salt flats of the ‘Lithium Triangle’ in Chile, Bolivia and Argentina, Mr. Fletcher shows us the abundance of the metal and puts to rest any fears of ‘peak lithium.’ . . . Mr. Fletcher makes a good case that the electric-car trend may soon be able to shed its dubious reputation as a public-private hybrid and roll under its own power.

BaileyR:“ChargingAhead,”The Wall Street

Journal(May16,2011),http://online.wsj.com/

article/SB100014240574870373080457631748127

6537422.html(accessedAugust26,2011).

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Oilfield Review50

The fourth in a series of introductory articles describing basic concepts of the E&P industryDEFINING COMPLETION

The Science of Oil and Gas Well Construction

Oilfield Review Winter 2011/2012: 23, no. 4. Copyright © 2012 Schlumberger.

Rick von FlaternSenior Editor

Once a well has been drilled to total depth (TD), evaluated, cased and cemented, engineers complete it by inserting equipment, designed to opti-mize production, into the hole. The driver behind every well completion strategy, whether for a complex or basic well, is to recover, at a reasonable cost, as large a percentage of the original oil in place (OOIP) as possible.

The decision to case and cement a well for production or plug and aban-don it as a dry hole relies heavily on formation evaluation (FE) using open-hole logs. For the purposes of this article, completion refers to all operations following the placement of cement behind the production casing, which is performed after FE.

Once FE log analysis indicates the existence and depth of formations likely to produce commercial volumes of hydrocarbons, steel casing is run in the borehole and cement is pumped behind it. Completion engineers then displace the drilling mud in the well with a completion fluid. This may be a clear fluid or brine formulated to be nonreactive with the formation.

A primary reason to cement casing is to prevent communication between producing zones, thus engineers run a cement bond log (CBL) to ascertain

that the cement sheath between the casing and the borehole wall is without flaws (below left). If gaps exist, engineers remedy the problem by injecting cement through holes made in the casing at the appropriate depths. This is referred to as a cement squeeze job.

Engineers then perforate through the casing and cement sheath into sections of the formation where FE analysis indicates conditions are favor-able for hydrocarbon flow. Perforations are holes made in the casing, usually using small, shaped charges fired from perforating guns. The guns may be lowered into the hole on wireline, tubing or coiled tubing.

Often, these operations leave debris in the well and in the perforations themselves, which may hamper the flow of formation fluids into the bore-hole. To reduce the impact of this debris, engineers may pump a weak acid solution downhole to the affected area to dissolve the debris.

Depending on their knowledge of the formations being completed, opera-tors may then perform a well test. In some instances this is carried out through a drillstem test (DST) valve attached to the bottom of a string of tubing or drillpipe called a workstring. The DST valve can be opened from the surface and the well fluids flowed through a separator—a device that sepa-rates the oil, gas, water and completion fluids at the surface. By measuring rates of water, gas and oil produced, operators gain information with which to make deductions about future well performance. Well tests also give oper-ators extensive information about the character and extent of the reservoir.

Completion engineers may then consider several options, which are determined by formation characteristics. If the formation permeability is low, engineers may choose to create a hydraulic fracture by pumping water and sand or other materials—a slurry—through the perforations and into the formation at high pressure. Pump pressure builds against the unyielding formation until the rock yields and cracks open. The slurry is then pumped into the newly created formation fractures. When the pumps are turned off and the well opened, the water flows out, leaving behind the sand. This prop-pant holds open the newly created fractures. The result is a high-permeabil-ity pathway for the hydrocarbons to flow from the formation to the wellbore.

While oil and gas flow readily through permeable rocks, such formations may be unconsolidated and subject to breaking into small sand particles that may flow into the wellbore with produced fluids. These particles may plug perforation tunnels and stop fluids entering the well. To prevent the migration of these particles through the formation, engineers may inject chemicals into the formation to bind the sand grains together. To prevent sand from entering the wellbore, engineers may also opt for a sand control technique—or a combination of techniques—that includes various types of sand screens and gravel packing systems. Designed to block the migration of sand, these systems allow fluids to freely flow through them.

The next stage in completion includes placing various pieces of hard-ware—referred to as jewelry—in the well; the jewelry is attached to produc-tion tubing. Tubing, the conduit between the producing formation and the surface, is the infrastructure upon which almost all completions are built. Its strength, material and size—weight/unit length and internal diameter—are chosen according to expected production rates, production types, pressures, depths, temperatures and corrosive potential of produced fluids.

> Cement sheath flaws. Cement bond logs can detect negative results from poor cementing practices or designs, which may allow fluid flow (blue arrows) from one zone to another or to the surface. Some causes of flaws include incorrect cement density (top left), poor drilling fluid removal (top right), premature gelation, or setting (bottom left), and excessive fluid loss from the cement slurry (bottom right).

Incorrect Density Poor Drilling Fluid Removal

Premature Gelation Excessive Fluid Loss

ORWIN01_Abandonment_Fig_01_3

Form

atio

n st

rata

Cement

Borehole

Casing

44581araD10R1.indd 1 2/21/12 12:36 AM

Jewelry almost always includes packers, which seal against the inside of the casing. Packers isolate producing zones within the casing-tubing annulus in the same way cement does outside the casing. If the zone being produced is the deepest in the well, fluids flow from the formation below the packer and through the end of the tubing to the surface. In wells with multiple zones, a more common scenario, flow enters the well between an upper and lower packer and into the tubing through perforations or sliding sleeves (below). A sliding sleeve is a valve that is opened or closed mechanically; a

specially designed tool on slickline or coiled tubing moves the valve’s inter-nal perforated sleeve up or down.

Nearly all completions also include safety valves. These come in a vari-ety of forms but all are placed in the tubing within a few hundred feet of the surface. They are designed to automatically shut in the well when the sur-face control system is breached. They can also be closed manually to add an extra barrier between the well and the atmosphere when, for example, the well is being worked on or a platform is being evacuated in preparation for a storm.

With the basic jewelry deployed, many refinements are possible, depend-ing on the specific needs of the field or well. For example, intelligent com-pletions (ICs) are often used in situations or locations where entering the well to change downhole settings is costly or otherwise problematic. ICs include permanent, real-time remote pressure and temperature sensors and a remotely operable flow control valve deployed at each formation.

In other wells, the formation pressure is, or eventually becomes, insuf-ficient to lift the formation fluids out of the well. These wells must be equipped with pumps or gas lift systems. Electric submersible pumps (ESPs) pump fluids to the surface using a rotor and stator. Pump rotor drives can be located on the surface. Reciprocating pumps, called pump jacks, may be used to lift the fluid to the surface through a reciprocating vertical motion.

Gas lift systems pump gas down the annulus between two casing strings. The gas enters the tubing at a depth below the top of the fluid column. This decreases the fluid density enough for buoyancy to lift the fluid out of the well. The amount of gas entering the well may be regulated through a sequence of valves located along the length of tubing, or it may be streamed in at one or more locations.

Also in low-pressure formations, water or gas may be injected down one well to push oil through the formation to producing wells. The producers may be fitted with injection control devices (ICDs) that regulate how much and where fluid enters the wellbore.

Before designing a completion, engineers take into consideration—for every well—the types and volumes of fluids to be produced, downhole and surface temperatures, production zone depths, production rates, well loca-tion and surrounding environment. Engineers must then choose from the most basic openhole completion that may not have even a production casing string, to highly complex multilateral wells that consist of numerous hori-zontal or high-angle wellbores drilled from a single main wellbore, each of which includes a discrete completion.

The indispensible underpinnings of the optimal completion are solid FE, data from nearby offset wells and flexibility. Armed with reliable knowledge of target zones, how nearby wells accessing those formations were completed and how they produced, engineers are often able to plan the basic completion before the well is drilled. But completion engineers know that not every well will behave as expected, so they include contin-gencies in their completion plans and are prepared to implement them. In the end, how a well is completed—the culmination of all the decisions about jewelry and processes—directly impacts the rate at which and how long hydrocarbons will be produced from that well.

> Single-zone and multizone well completions. In the single-zone completion (left), a packer, which forms a seal inside the production casing, hydraulically isolates the tubing string from the region above the packer, called the “backside.” The backside contains completion fluid with corrosion inhibitors to prevent casing corrosion. The multizone completion (right) employs at least two packers that separate the producing zones. Fluids from all zones may be allowed to commingle during production, or production from the upper zone may be shut off by closing a sliding sleeve until operators have determined the fluids may be commingled. Alternatively, operators may choose to allow the lower zone to become depleted, then set a plug (not shown) above the lower zone and open the sliding sleeve to produce only from the upper zone.

Surface casing

Casing-tubingannulus

Production casing

Tubing string

Packer

Packer

Slidingsleeve

PackerPerforations

Cement

Winter 2011/2012 51

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ARTICLES

Basic Petroleum Geochemistry forSource Rock EvaluationMcCarthy K, Rojas K, Niemann M, Palmowski D, Peters K and Stankiewicz A.Vol. 23, no. 2 (Summer 2011): 32–43.

The Best of Both Worlds—A Hybrid Rotary Steerable SystemFelczak E, Torre A, Godwin ND, Mantle K, Naganathan S, Hawkins R, Li K, Jones S and Slayden F.Vol. 23, no. 4 (Winter 2011/2012): 36–44.

Bit Design—Top to BottomCentala P, Challa V, Durairajan B, Meehan R, Paez L, Partin U, Segal S, Wu S, Garrett I, Teggart B and Tetley N.Vol. 23, no. 2 (Summer 2011): 4–17.

Conveyance—Down and Out in the Oil FieldBillingham M, El-Toukhy AM, Hashem MK, Hassaan M, Lorente M,Sheiretov T and Loth M.Vol. 23, no. 2 (Summer 2011): 18–31.

Finding Value in Formation WaterAbdou M, Carnegie A, Mathews SG,McCarthy K, O’Keefe M, Raghuraman B, Wei W and Xian CG.Vol. 23, no. 1 (Spring 2011): 24–35.

Intelligent Completions at the ReadyBeveridge K, Eck JA, Goh G, Izetti RG,Jadid MB, Sablerolle WR and Scamparini G.Vol. 23, no. 3 (Autumn 2011): 18–27.

Managed Pressure Drilling Erases the LinesElliott D, Montilva J, Francis P, Reitsma D, Shelton J and Roes V.Vol. 23, no. 1 (Spring 2011): 14–23.

Open-Channel Fracturing—A Fast Track to Productiond’Huteau E, Gillard M, Miller M, Peña A, Johnson J, Turner M, Medvedev O, Rhein T and Willberg D. Vol. 23, no. 3 (Autumn 2011): 4–17.

Pipeline to MarketAlbert AP, Lanier DL, Perilloux BL and Strong A.Vol. 23, no. 1 (Spring 2011): 4–13.

Reservoir Simulation: KeepingPace with Oilfield ComplexityEdwards DA, Gunasekera D, Morris J,Shaw G, Shaw K, Walsh D, Fjerstad PA,Kikani J, Franco J, Hoang V and Quettier L.Vol. 23, no. 4 (Winter 2011/2012): 4–15.

Shale Gas: A Global ResourceBoyer C, Clark B, Jochen V, Lewis R and Miller CK.Vol. 23, no. 3 (Autumn 2011): 28–39.

Shale Gas RevolutionAlexander T, Baihly J, Boyer C, Clark B,Waters G, Jochen V, Le Calvez J, Lewis R, Miller CK, Thaeler J and Toelle BE.Vol. 23, no. 3 (Autumn 2011): 40–55.

Slickline Signaling a ChangeBillingham M, Chatelet V, Murchie S, Cox M and Paulsen WB.Vol. 23, no. 4 (Winter 2011/2012): 16–25.

Stabilizing the Wellbore to Prevent Lost CirculationCook J, Growcock F, Guo Q, Hodder M and van Oort E.Vol. 23, no. 4 (Winter 2011/2012): 26–35.

Technology for EnvironmentalAdvancesAzem W, Candler J, Galvan J, Kapila M,Dunlop J, Fastovets A, Ige A, Kotochigov E, Nicodano C, Sealy I and Sims P.Vol. 23, no. 2 (Summer 2011): 44–52.

Zapping RocksCarmona R, Decoster E, Hemingway J,Hizem M, Mossé L, Rizk T, Julander D, Little J, McDonald T, Mude J andSeleznev N.Vol. 23, no. 1 (Spring 2011): 36–52.

DEFINING…INTRODUCINGBASIC CONCEPTS OF THE E&P INDUSTRY

Defining Completion: The Scienceof Oil and Gas Well Construction von Flatern R.Vol. 23, no. 4 (Winter 2011/2012): 50–51.

Defining Drilling: Turning to theRight—An Overview of DrillingOperationsVarhaug M.Vol. 23, no. 3 (Autumn 2011): 59–60.

Defining Exploration: The Searchfor Oil and Gas Stewart L.Vol. 23, no. 2 (Summer 2011): 59–60.

Defining Logging: Discovering theSecrets of the Earth Andersen MA.Vol. 23, no. 1 (Spring 2011): 60, 59.

NEW BOOKS The Beginning of Infinity: Explanations That Transform the WorldDeutsch D.Vol. 23, no. 4 (Winter 2011/2012): 47.

The Blind Spot: Science and the Crisis of UncertaintyByers W.Vol. 23, no. 4 (Winter 2011/2012): 47.

Bottled Lightning: Superbatteries,Electric Cars, and the New Lithium EconomyFletcher S.Vol. 23, no. 4 (Winter 2011/2012): 49.

The Climate Fix: What Scientistsand Politicians Won’t Tell You About Global WarmingPielke R Jr.Vol. 23, no. 1 (Spring 2011): 56.

The Climate War: True Believers,Power Brokers, and the Fight toSave the EarthPooley E.Vol. 23, no. 2 (Summer 2011): 58.

A Cubic Mile of Oil: Realities andOptions for Averting the LoomingGlobal Energy CrisisCrane HD, Kinderman EM and Malhotra R.Vol. 23, no. 2 (Summer 2011): 56.

Cycles of Time: An ExtraordinaryNew View of the UniversePenrose R.Vol. 23, no. 2 (Summer 2011): 57.

Earth MaterialsHefferan K and O’Brien J.Vol. 23, no. 1 (Spring 2011): 58.

An Empire of Ice: Scott, Shackleton,and the Heroic Age of AntarcticScienceLarson EJ.Vol. 23, no. 4 (Winter 2011/2012): 49.

The Evolutionary World: HowAdaptation Explains Everything fromSeashells to CivilizationVermeij GJ.Vol. 23, no. 1 (Spring 2011): 56.

For the Love of Physics: From theEnd of the Rainbow to the Edge ofTime—A Journey Through theWonders of PhysicsLewin W and Goldstein W. Vol. 23, no. 2 (Summer 2011): 57.

Geological Methods in MineralExploration and Mining, Second EditionMarjoribanks R.Vol. 23, no. 1 (Spring 2011): 58.

The Geology of StratigraphicSequences, Second EditionMiall AD.Vol. 23, no. 1 (Spring 2011): 57.

Geophysical Characterization of Gas HydratesRiedel M, Willoughby EC and Chopra S (eds). Vol. 23, no. 3 (Autumn 2011): 58.

Geothermal Energy: RenewableEnergy and the EnvironmentGlassley WE.Vol. 23, no. 1 (Spring 2011): 55.

Hidden Costs of Energy: UnpricedConsequences of EnergyProduction and UseThe National Research Council. Vol. 23, no. 1 (Spring 2011): 56.

Information and the Nature ofReality: From Physics toMetaphysicsDavies P and Gregersen NH (eds).Vol. 23, no. 1 (Spring 2011): 55.

Petroleum Resources withEmphasis on Offshore FieldsGudmestad OT, Zolotukhin AB and JarlsbyET.Vol. 23, no. 1 (Spring 2011): 57.

Physics of the Future: How ScienceWill Shape Human Destiny and Our Daily Lives by the Year 2100Kaku M.Vol. 23, no. 2 (Summer 2011): 56.

Plate Tectonics: Continental Driftand Mountain BuildingFrisch W, Meschede M and Blakey R.Vol. 23, no. 3 (Autumn 2011): 58.

Remembering Einstein: Lectures onPhysics and AstrophysicsSreekantan BV (ed).Vol. 23, no. 2 (Summer 2011): 57.

Quantum Man: Richard Feynman’sLife in ScienceKrauss LM.Vol. 23, no. 1 (Spring 2011): 57.

The Strangest Man: The Hidden Life of Paul Dirac, Mystic of the AtomFarmelo G.Vol. 23, no. 2 (Summer 2011): 58.

Street-Fighting Mathematics: TheArt of Educated Guessing andOpportunistic Problem SolvingMahajan S.Vol. 23, no. 1 (Spring 2011): 56.

The Techno-Human ConditionAllenby BR and Sarewitz D.Vol. 23, no. 4 (Winter 2011/2012): 48.

The Theory That Would Not Die:How Bayes’ Rule Cracked theEnigma Code, Hunted Down Russian Submarines, and EmergedTriumphant from Two Centuries ofControversyMcGrayne SB.Vol. 23, no. 4 (Winter 2011/2012): 48.

The Unfinished Game: Pascal, Fer-mat, and the Seventeenth-CenturyLetter That Made the World ModernDevlin K.Vol. 23, no. 1 (Spring 2011): 58.

The Weather of the Future: Heat Waves, Extreme Storms, and Other Scenes from a Climate-Changed PlanetCullen H.Vol. 23, no. 2 (Summer 2011): 58.

Why Geology Matters: Decodingthe Past, Anticipating the FutureMacdougall D.Vol. 23, no. 4 (Winter 2011/2012): 48.

Wrestling with Nature: From Omens to ScienceHarrison P, Numbers RL and Shank MH (eds).Vol. 23, no. 4 (Winter 2011/2012): 49.

52 Oilfield Review

Oilfield Review Annual Index—Volume 23

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