Summer 2012

Microbes in the Oil Field

Automated Drilling

Seismic Detection of Fractures

Logging Through the Bit

Oilfield Review

Oilfield drilling machinery has evolved from hand tools to robotics. Rig controls have expanded from throttles on individual machines into integrated systems. What once was thought to be applicable only to expensive, deepwater operations is now widely available for conventional land rigs. What comes next? Is the drilling industry ready for automated control of the drilling process?

Years ago, at an SPE/IADC conference, I spoke with Walt Aldred, who was then Schlumberger director of drilling research. My company had just commercialized an integrated rig control system in which the driller was seated in a com-fortable chair surrounded by touch screens and joysticks. From a heated and air-conditioned cabin, drilling crews could run all the rig floor equipment at the touch of a button. However, the operations below the rotary were manual, save that of an autodriller. Schlumberger service engineers used laptops equipped with computer control algorithms to advise the drilling crew and engineers on how to drill more quickly and safely.

We discussed an incident in which the drilling program was initially days ahead of the curve. Then disaster struck. When asked what happened, the driller replied that all was going according to plan, but he believed drilling speed could be increased; unfortunately he did not know all the conse-quences of this action. Walt and I discussed the potential value of connecting the computer control algorithms with the rig controls to assist the driller and prevent errors by the crew. This conversation, and many others, led to the founding of an SPE group focused on automating the drilling process.

Founded in 2007, the SPE Drilling Systems Automation Technical Section (DSATS) has grown to more than 200 members. DSATS has helped advance drilling automation through an impressive volunteer effort that included writing interface standards, giving live demonstrations of multiuser control systems and introducing technology from other industries. In collaboration with SPE scientists and engineers, DSATS frequently hosts workshops and forums and plans new ways to facilitate the development and implementation of this emerging technology.

Today, drilling automation is still in its infancy, but the science and its application are changing rapidly (see “Drilling Automation,” page 18). Two oil companies have announced programs to develop automated drilling rigs and have assembled engineering teams to enable single push-button operations for elements of the drilling process that have fewer unknowns and risks. The teams are driven by a desire to reduce nonproductive time and improve the execu-tion of manual tasks that previously depended on the skill of the individual driller. While machines perform the mundane physical tasks, the driller still controls the process and can focus on downhole conditions and rig floor safety.

Drilling Automation: Generating Greater Reliability and Profitability

1

Oil companies are using their own software algorithms as well as those from other providers. The major service companies, and a few smaller organizations, have written software that controls machinery for isolated drilling or drilling-related tasks. A few drilling contractors have built, or are actively building, “automation ready” rigs. An equip-ment provider has announced the design of a new control system with an open-style architecture to enable all these groups to work together seamlessly. Integrated industry-wide, the automated drilling segments are no longer con-fined to one- or two-company initiatives.

The answer to the earlier question about the drilling industry’s readiness for automated control of the drilling process has to be a resounding “yes.” Interest is focused on automated drilling for several reasons, including high drill-ing cost and the need for greater efficiency and additional personnel. For example, shale and coal gas prospects require many hundreds of new wells; for these and other projects, the supply of experienced drilling crews will not meet the forecasted demand.

The improved reliability of automated drilling equipment and software will overcome the doubts of some hesitant adopters. Efforts to standardize the interoperability of communication protocols and data have culminated in a system architecture that will allow the introduction of data interpretation and process commands from new entrants to our industry. These newcomers bring significant experi-ence from automating other processes once deemed too complex and with too many unknowns.

Although the main efforts are geared toward helping inexperienced drillers, human-in-the-loop techniques will be included to assist, not replace, the driller. As early market movers publish the results of successful automa-tion efforts, other companies will adopt the new technolo-gies, resulting in higher production rates and decreased personnel and operations costs; such added value will pro-mote rapid acceptance and implementation of this emerg-ing technology.

Fred FlorenceProduct Champion for Automation and Drilling OptimizationNational Oilwell VarcoCedar Park, Texas, USA

Fred Florence joined National Oilwell Varco in 1996 and currently is a member of the Corporate Engineering team as Product Champion for Automation and Drilling Optimization. Prior to joining National Oilwell Varco, he worked for Sedco-Forex, now Transocean, where he held various positions in engineering and operations. Fred holds a BS degree in electrical engineering from Southern Methodist University, University Park, Texas, as well as an MA degree in inter-national management and an MBA degree in marketing from the University of Texas at Dallas.

www.slb.com/oilfieldreview

Schlumberger

Oilfield Review

1 Drilling Automation: Generating Greater Reliability and Profitability

Editorial contributed by Fred Florence, Product Champion for Automation and Drilling Optimization, National Oilwell Varco

4 Microbes—Oilfield Enemies or Allies?

Microbial organisms have a long history of coexistence with oilfield operations. Microbes often cause corrosion and reservoir damage, but sometimes they enhance production. Scientists are using new knowledge of microbe identity and chemistry to combat microbial damage and to encourage microbiologically enhanced oil recovery.

18 Drilling Automation

Drilling automation involves much more than rig floor mechanization; with the integration of downhole data with operations, improved drilling performance can mean the difference between economic success and failure. At the same time, in the large numbers of wells whose conditions are understood, the repetitive nature of automated drilling may eliminate the performance variability typically seen from one well to the next within a drilling program.

Dept

h of

cut

Bit torque

Weight on bit

Executive EditorLisa Stewart

Senior EditorsMatt VarhaugRick von Flatern

EditorsRichard Nolen-Hoeksema Tony Smithson

Contributing EditorsDavid AllanErik NelsonGinger OppenheimerRana Rottenberg

Design/ProductionHerring DesignMike Messinger

Illustration Chris LockwoodMike 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 English, Spanish, Chinese and Russian.

© 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:

A driller monitors rig floor and downhole measurements displayed in a Helmerich & Payne FlexRig3® driller’s cabin. The rig features fully integrated variable AC drive technology for the topdrive, drawworks and mud pumps with programmable logic controller–based drilling controls. The rig also includes a topdrive system integrated within the mast that eliminates the need to rig up and down when moving, thereby reducing cycle time and increasing safety and reliability. FlexRig3® is a registered trademark of Helmerich & Payne, Inc.

2

Summer 2012Volume 24Number 2

ISSN 0923-1730

54 Contributors

57 New Books and Coming in Oilfield Review

59 Defining Cementing: Well Cementing Fundamentals

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

3

28 Seismic Detection of Subtle Faults and Fractures

Natural fractures complicate the development and production of hydrocarbon reservoirs. Because they are typically smaller than seismic wavelengths, fractures are difficult to detect and characterize. Advances in seismic processing and visual-ization are helping operators place wells inside fractured formations and manage fractured reservoirs better.

44 Logging Through the Bit

High-angle or extended-reach well trajectories sometimes cause operators to forgo openhole logging. However, without petrophysical data, operators have scant information for making important decisions that could affect the producibility of their wells. By deploying small-diameter logging tools through specially developed drill bits, operators are obtaining the data they need for evaluating reservoirs and optimizing completions.

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

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: editorOilfieldReview@slb.com

SubscriptionsClient subscriptions can be obtained through any Schlumberger sales office. Additional subscription information can be found 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: subscriptions@oilfieldreview.com

Distribution inquiriesTony SmithsonOilfield Review12149 Lakeview Manor Dr.Northport, Alabama 35475 USA(1) 832-886-5217Fax: (1) 281-285-0065E-mail: DistributionOR@slb.com

4 Oilfield Review

Microbes—Oilfield Enemies or Allies?

Microbes have a long history in the oil and gas industry. New molecular analysis

methods, coupled with increased knowledge of microbe identity and chemistry, have

led to advances in combating microbiologically influenced corrosion and reservoir

damage. Scientists are also using these advances to develop new methods for

microbiologically enhanced oil recovery and bioremediation.

Zdenko AugustinovicDONG E&PHoersholm, Denmark

Øystein BirketveitM-I SWACOBergen, Norway

Kayli ClementsMike FreemanM-I SWACOHouston, Texas, USA

Santosh GopiM-I SWACOAccra, Ghana

Thomas IshoeyGlori Energy, Inc.Houston, Texas

Graham JacksonHusky Energy Inc.Calgary, Alberta, Canada

Gregory KubalaSugar Land, Texas

Jan LarsenMaersk OilCopenhagen, Denmark

Brian W.G. MarcotteTitan Oil Recovery, Inc.Los Angeles, California, USA

Jan ScheieM-I SWACOStavanger, Norway

Torben Lund SkovhusDanish Technological InstituteAarhus, Denmark Egil SundeStatoilStavanger, Norway

Oilfield Review Summer 2012: 24, no. 2. Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Sonny Espey, M-I SWACO, Houston; and Dietmar Schumacher, Geo-Microbial Technologies Inc., Ochelata, Oklahoma, USA.AERO is a registered trademark of Glori Energy, Inc.

We live in a natural world of extremes in size and scale. Topographical extremes range from moun-tains to deserts to ocean trenches. These extremes include a place so small that we cannot directly view it: the unseen world of microbes.

Microbes are the most abundant life form on the planet—no other life form approaches them in terms of numbers, diversity or habitat. Microbes were the first link in the evolutionary chain and are an essential part of the Earth’s biota.1 Microbes catalyze important transforma-tions in the biosphere, produce key components of the atmosphere and represent a large fraction of the genetic diversity on this planet. The num-ber of microbial cells on Earth has been esti-mated at 4 to 6 × 1030 cells, and this aggregate mass contains 350 to 550 × 1015 g of carbon. Microbes are distributed everywhere, including places that are hotter, colder, drier and deeper than humans can tolerate. This wide distribution suggests that oil exploration and production operations must always contend with microbes.

Microbes have a long history in the oil field. Analysis of produced water from shallow reser-voirs in the 1930s and 1940s showed abundant populations.2 Despite these findings, scientists at the time believed that temperature, pressure and salinity in most reservoirs were too hostile for

microbes to thrive. Initiation of North Sea oil and gas production in the 1960s, however, demon-strated that early assumptions were incorrect. Microbes in these reservoirs not only lived in extreme conditions, they produced hydrogen sul-fide [H2S]. Souring, or increases in H2S, resulted from injection of sulfate-rich seawater in North Sea reservoirs and ultimately led to corrosion of both surface and downhole equipment. Formation plugging by biomass during waterflood operations was another early negative effect of microbes.3

However, not all of the early production-related experiences with microbes were nega-tive. Some operators found that injection of sugar-based materials that resident microbes could use as food caused an increase in oil pro-duction, although results were often temporary and inconsistent.4 In the past several decades, much of the oilfield research on microbes focused on short-term strategies to either mitigate nega-tive effects or enhance positive ones—but that work was based on a partial understanding of microbiological mechanisms.

The ability to control and harness microbes is key to some of the major advances in microbial oilfield science. This progress has been aided by new analytical methods that give a more complete picture of microbe identity, quantity,

1. Whitman WB, Coleman DC and Wiebe WJ: “Prokaryotes: The Unseen Majority,” Proceedings of the National Academy of Sciences 95, no. 12 (June 9, 1998): 6578–6583.

2. Bass C and Lapin-Scott H: “The Bad Guys and the Good Guys in Petroleum Microbiology,” Oilfield Review 9, no. 1 (Spring 1997): 17–25.

3. Chang CK: “Water Quality Considerations in Malaysia’s First Waterflood,” Journal of Petroleum Technology 37, no. 9 (September 1985): 1689–1698.

4. Rassenfoss S: “From Bacteria to Barrels: Microbiology Having an Impact on Oil Fields,” Journal of Petroleum Technology 63, no. 11 (November 2011): 32–38.

Summer 2012 55

positive characteristics. Case studies from Canada and the US demonstrate how these techniques are employed in production environments.

behavior and function. Advances include simple chemicals added to injection water that provide environmentally safe control of reservoir souring and associated corrosion as well as new direc-tions for microbiologically enhanced oil recovery (MEOR). Other progress includes bioremediation research that allows safe disposal of oilfield solid waste into ordinary soil.

This article focuses on microbes in the oil field and describes techniques for their analysis and for controlling their negative effects and harnessing

6 Oilfield Review

The Microbial WorldBiological classification systems have evolved in tandem with methods for microbe detection. In the early 1800s, what was not a mineral or plant was considered an animal. The discovery that bacteria could be considered either plant or ani-mal led to reformulations of the biological classi-fication system for living organisms that continue to the present era. Proposed more than 30 years ago, today’s accepted classification into three pri-mary domains has its roots in molecular analysis methods, including genome sequencing.5 The three domains are bacteria, archaea and eucarya (left). Bacteria and archaea—collectively called prokaryotes—are the organisms that affect the oil field (below left).

Fossils of prokaryotic organisms that lived 3.5 billion years ago have been found in Western Australia and South Africa; for 2 billion years they were the only form of life on Earth. Larger and more-complex eucaryotic cells did not appear until much later—about 1.5 to 2 billion years ago. The archaea and bacteria that consti-tute the prokaryotes differ from the cells in com-plex eucaryotic organisms such as plants and animals. Prokaryotic cells have no compartmen-talized nucleus, and each cell is capable of inde-pendent existence.6 Unlike plants and animals, prokaryotes are not typically thought of as organ-isms able to interact with their environment, but that view may be changing. Researchers have shown that many bacteria have cell to cell com-munication through signaling molecules called autoinducers. This signaling is called quorum sensing and allows the microbes to monitor and respond to their surroundings.7

Prokaryotes are found everywhere on Earth and thrive in extreme habitats. From hot springs, arid deserts and ocean depths to polar caps and underground formations, these single-cell organ-isms withstand conditions that humans cannot.8 These microbes may remain dormant for thou-sands of years but can reactivate rapidly—often in days or weeks. Their wide distribution in a vari-ety of habitats and conditions means that microbes are always present during E&P activi-ties. Some microbes are indigenous to reservoirs, while others may be introduced during drilling, workover or waterflood. These single-cell life forms have an innate tendency to cling to rock and metal surfaces and may assemble into masses called biofilms. Microbe-generated bio-films provide a safe harbor for growth and may eventually lead to serious problems in both equipment and reservoirs (next page).

> Tree of life. Life on Earth is divided into three primary domains—bacteria (left, blue), archaea (middle, pink) and eucarya (right, green). This classification encompasses the entire realm of living organisms, from the proteobacteria that contain the digestive disease salmonella to the more familiar plants and animals. Branch order and length are based on genetic sequencing.

Spirochetes

Bacteria Archaea Eucarya

Methanosarcina

Methanobacterium

Methanococcus

Thermococcus

Thermoproteus

Pyrodictium

Halophiles

Entamoeba Slimemolds Animals

Fungi

Plants

Ciliates

Flagellates

Trichomonads

Microsporidia

Diplomonads

Proteobacteria

Cyanobacteria

Planctomyces

Thermotoga

Aquifex

Gram-positivebacteria

Greenfilamentous

Bacteroides

> Bacteria. The bacterial cell is enclosed by a capsule, cell wall and plasma membrane. The interior of the cell is filled with cytoplasm, a homogeneous, gel-like substance. The primary interior component is the nucleoid, which contains the chromosome material. Plasmids, containing deoxyribonucleic acid (DNA), and ribosomes, containing ribonucleic acid (RNA), are other essential interior components. Although not all bacteria are motile, many use a whip-like flagellum to move in aqueous media. Bacteria and other prokaryotes range in size from 10–5 to 10–6 m.

Flagellum

CapsuleCell wallPlasma membrane

Cytoplasm

Ribosome

Plasmid

NucleoidEukaryotes

Viruses

Small moleculesAtoms

Proteins

Prokaryotes

10–3

10–4

10–5

10–6

10–7

10–8

10–9

10–10

Size

, m

Summer 2012 7

New methods for enumeration and identifi-cation of bacteria and archaea have led scien-tists to a better understanding of microbial behavior and chemistry. Their efforts, in turn, have led to more accurate identification of prob-lems caused by microbes as well as better means for their solution. Taken together, these meth-ods give the operator tools to control microbes in places where their effects are harmful and to exploit their positive characteristics.

Enemy and AllyAlthough microbes and humans have existed as both enemy and ally for ages, the roles of microbes in those relationships have been recog-

nized only in the recent past. In the fight against infectious diseases, bacteria were identified about 150 years ago as one of the culprits.9 As industrial allies, microbes played a key role in the leaching of copper from mine drainage water, a practice in the Mediterranean region about 1000 BCE, but their role in the process was unknown until the 1950s.10

The bulk of experience with microbes in oil and gas exploration and production has occurred in the past 75 years. One of the early encounters with microbes in a production environment occurred in the late 1950s during waterflooding.11 Microbes produce high molecular weight polysac-charides that deposit on the sandface and other

formation surfaces as a biofilm.12 This biofilm is the glue that holds the microbes together. Given the right conditions, the microbes will continue to grow, divide and plug rock pores, thus decreas-ing the effectiveness of water injection in displac-ing oil. As a result, early water quality control methods included membrane filtration and the use of strong oxidizing agents as biocides.13 Later waterflood control applications employed nonox-idizing biocides.

Shortly after operators learned to manage microbe plugging during waterflooding, they encountered another significant problem—microbiologically influenced corrosion (MIC)—corrosion caused by microbial action.14 This type

5. Woese CR and Fox GE: “Phylogenetic Structure of the Prokaryotic Domain: The Primary Kingdoms,” Proceedings of the National Academy of Sciences 74, no. 11 (November 1, 1977): 5088–5090.

Woese CR, Kandler O and Wheelis ML: “Towards a Natural System of Organisms: Proposal for the Domains Archaea, Bacteria and Eucarya,” Proceedings of the National Academy of Sciences 87, no. 12 (June 1, 1990): 4576–4579.

Todar K: “Todar’s Online Textbook of Bacteriology,” http://www.textbookofbacteriology.net (accessed May 24, 2012).

6. Although the bacteria and archaea that make up the prokaryotes are similar in size and structure, their genome structures and metabolism differ.

7. Taga ME and Bassler BL: “Chemical Communication Among Bacteria,” Proceedings of the National Academy of Sciences 100, supplement 2 (November 25, 2003): 14549–14554.

> Biofilm formation. The growth of biofilms is a stepwise process that begins with the transport of microbes to a metal or rock surface (A). The microbes absorb organic molecules from their surroundings to form a film (B) composed of exopolymers—sugars—that allow the microbes to stay attached to the surface as well as to each other (C). As the biofilm expands (D), its size gives the interior microbes protection from biocides. Eventually, when the biofilm grows to a certain size, some microbes are released (E) to form new areas of growth.

Biofilm

Metal or rock surface

Microbes

A B C D E

8. Bass and Lapin-Scott, reference 2. Danish scientists have discovered microbes living in

undisturbed sediments that are more than 86 million years old. The microbes consume oxygen in quantities too small to be directly measured. For more: Bhanoo SN: “Deep-Sea Microbes That Barely Breathe,” The New York Times (May 21, 2012), http://www.nytimes.com/2012/05/22/science/deep-sea-microbes-that-barely-breathe.html (accessed May 22, 2012).

9. Santer M: “Joseph Lister: First Use of a Bacterium as a ‘Model Organism’ to Illustrate the Cause of Infectious Disease of Humans,” Notes & Records of the Royal Society 64, no. 1 (March 2010): 59–65.

10. Brierley CL: “Microbial Mining,” Scientific American 247, no. 2 (1982): 42–50.

11. Lee D, Lowe D and Grant P: “Microbiology in the Oil Patch: A Review,” paper 96-109, presented at the Annual Technical Meeting of The Petroleum Society, Calgary, June 10–12, 1996.

12. Polysaccharides are long carbohydrate molecules composed of repeating units and are common sources of energy for bacteria. For more: Todar, reference 5.

13. Mitchell RW and Bowyer PM: “Water Injection Methods,” paper SPE 10028, presented at the SPE International Petroleum Exhibition and Technical Symposium, Beijing, March 17–24, 1982.

14. The literature on microbes associated with oilfield environments uses numerous acronyms for microbe-driven processes such as MIC or MEOR. It is not uncommon to encounter both “microbial” and “microbiologically” as the initial term in these acronyms, depending on the reference—the terms are essentially equivalent.

8 Oilfield Review

of corrosion can occur anywhere in the produc-tion environment—in downhole tubulars, in top-side equipment and in pipelines. This type of corrosion can cause ruptures that seriously impede operations (above). Reports in the 1980s showed that sulfate-reducing bacteria (SRB) were the cause of MIC.15 SRB typically live in an anaerobic, aqueous environment and use organic acids and hydrogen from decomposing biomass

as nutrients, oxidizing the nutrients while reduc-ing the sulfate in the water to H2S. The role of SRB in initiating MIC is complex and involves not only biofilms that trap corrosive microbial waste products but also electrochemical reactions at the metal surface. Early explanations pointed toward an SRB produced enzyme that removes cathodic hydrogen from steel, which causes rapid pitting of the surface.16

MIC is a common occurrence in the oil field, and to control it, operators usually treat injected and produced water to mitigate microbial action. Complete sterilization of the water is impossible, and microbe control strategies have usually been directed toward disinfection—that is, reduction of microbe numbers to acceptable levels by killing a large portion of the population with a biocide.

>Microbiologically influenced corrosion (MIC). Operated by DONG E&P, the Siri platform (center) is located in the North Sea 220 km [137 mi] west of the Danish coast and is flanked by the smaller Cecilie (left) and Nini (right) satellite platforms. Five fields—Siri, Nini, Nini East, Cecilie and Stine—produce from reservoirs 1,800 to 2,200 m [5,900 to 7,220 ft] below sea level. Seafloor lines between the three structures and wells carry oil and gas, gas for lift, and injection water for pressure support. In 2007, a 25.4-cm [10-in.] water injection line ruptured (inset) 3 km [2 mi] from the Siri platform. Subsequent investigation revealed that the MIC deposit at the rupture site was a mixture of iron sulfide and other corrosion by-products plus microbes and polysaccharide slime. These deposits allow sulfate-reducing prokaryotes (SRPs) and other troublesome microbes to grow protected from biocides. (Adapted with permission from DONG E&P.)

Cecilie

NiniSiri

Water injection

Stine

Water injectionGas liftMultiphaseOilUmbilical

13 km9 km

32 km

Oil storage

15. Cord-Ruwisch R, Kleinitz W and Widdel F: “Sulfate-Reducing Bacteria and Their Activities in Oil Production,” Journal of Petroleum Technology 39, no. 1 (January 1987): 97–106.

16. Lee et al, reference 11.

17. Campbell S, Duggleby A and Johnson A: “Conventional Application of Biocides May Lead to Bacterial Cell Injury Rather Than Bacterial Kill Within a Biofilm,” paper NACE 11234, presented at the NACE Corrosion Annual Conference and Exposition, Houston, March 13–17, 2011.

18. Maxwell S and Campbell S: “Monitoring the Mitigation of MIC Risk in Pipelines,” paper NACE 06662, presented at the NACE Corrosion Annual Conference and Exposition, San Diego, California, USA, March 12–16, 2006.

19. Eckert R and Skovhus TL: “Using Molecular Microbiological Methods to Investigate MIC in the Oil and Gas Industry,” Materials Performance 50, no. 8 (August 2011): 50–54.

Summer 2012 9

If the biocide is a strong oxidizing agent such as chlorine, it is added to the injection water con-tinuously. Nonoxidizing biocides, typically used in current operations, are added intermittently (right). Each batch of biocide kills a portion of the microbe population, but the survivors may recover between doses. Recent research has shown biocides may not be as effective as previ-ously thought—they may only injure or inhibit but not kill microbes.17

Although biocides can be effective in combat-ing MIC, there are reports of equipment failure in spite of treatment, and examination of these inci-dents revealed that the biocide application was erratic and haphazard.18 Until recently, unlike with common corrosive agents, there were no effective tools to predict and quantify the risk of corrosion influenced by microbes. The juncture of genome-based test methods and the inadequa-cies of biocides and their risks has led to a new approach in managing MIC in production envi-ronments. This approach uses molecular micro-biological methods (MMMs) and represents a fundamental change in assessing microbe effects.19 These methods—fluorescence in situ hybridization (FISH), quantitative polymerase chain reaction (qPCR) and a microbe staining technique using a fluorescent stain known as 4’,6-diamidino-2-phenylindole (DAPI)—allow scientists to gain a more complete understanding of identities, quantities and behaviors of the microbes involved in MIC.

To appreciate the significance of these meth-ods, it is important to understand how microbes were handled in the laboratory prior to the intro-duction of MMMs. Traditional microbiological methods for identification and enumeration relied on serial dilution and cultivation in nutri-ent media for relatively long periods—often up to 30 days. Even after these long periods, less than 10% of the viable microbes could be cultured. It is no surprise that laboratory results based on tradi-tional serial dilution and culturing methods did not correlate well with field results.

In contrast, results from application of FISH, DAPI and qPCR techniques reveal nearly com-plete identities and distribution of the microbes of interest in oil production systems. These new methods utilize a combination of microscopy, analysis of cell genetic material and enzymatic reactions to give a complete enumeration of microbes present in the sample (right). In addi-tion, the results are available in days rather than weeks. These methods permit scientists to more completely understand the chemistry of MIC on a

> Biocide treatment. Offshore topside equipment is commonly treated with biocides to prevent MIC and precipitation of iron sulfide from produced H2S. In the North Sea, engineers treated a reclaimed oil sump tank with glutaraldehyde to obtain data showing how the biocide and H2S concentrations changed with time. The sump tank effluent was analyzed for residual glutaraldehyde and sulfide as a marker for H2S. Data from the study show expected results after biocide treatment. As the high concentration of biocide kills troublesome microbes, the sulfide concentration drops sharply. At the highest concentration of biocide, the sulfide concentration reaches a minimum. Both trends reverse as the biocide is flushed from the system. Biocide is reapplied when the sulfide returns to a threshold level.

1 2 3Time, d

Sulfide

Biocide

Sulfi

de, p

pm

Bioc

ide,

ppm

0 0

200

400

600

800

1,000

1

5

4

3

2

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>Molecular microbiological methods. These laboratory methods allow characterization and determination of the relative proportions of microbes present in oil production systems. Traditional microbe culturing using serial dilution produces the most probable number (MPN) of microbes, which may represent only a small fraction of the total number actually present. In contrast, MMMs represent a trio of new methods—FISH, DAPI and qPCR—that divide the microbe population into organisms that are active, inactive and dead. FISH analysis involves staining and microscopy to examine living, or active, microbes. The fluorescent stain, DAPI, binds to DNA and quantifies both active and inactive microbes. The qPCR method employs an enzymatic reaction that gives additional information on all the microbial groups. When these methods are used together, scientists obtain a complete enumeration and characterization of the microbes in a sample. (Adapted with permission from DTI Oil & Gas, Danish Technological Institute.)

Dead

Active

Inactive

Microbe Characterization and Relative Proportions

MPN: most probable number

FISH: flourescence in situhybridization

DAPI: 4’,6-diamidino-2-phenylindole

qPCR: quantitative polymerasechain reaction

10 Oilfield Review

metal surface. By using MMMs, scientists discov-ered that corrosion involves not only SRB but also other microbes that contribute to H2S and meth-ane [CH4] production (above).20

This complexity in MIC is illustrated by recent laboratory work on topside equipment in the Danish sector of the North Sea. In 2008, a pro-duced water separator in the Halfdan field

showed high corrosion rates in the carbon steel water outlet piping. The pipe showed severe metal pitting and scaling, and scientists deter-mined that MIC was the cause (next page).21 The microbes responsible for corrosion problems at Halfdan field are not the only varieties that can cause MIC in production systems. Acid-producing bacteria (APB) are microbes that produce organic acids under certain conditions. These acids can cause the pH to drop enough to create conditions favorable to corrosion on metal surfaces such as those of submersible pumping components.22 Control of APB is typically accom-plished by biocide disinfection that may aid in control of SRB as well.23

New Theories and SolutionsThe H2S produced during MIC in the wellbore and reservoir by sulfate-reducing prokaryotes (SRPs) contributes to reservoir souring.24 There are new and effective ways to control souring, but souring is not a new problem for producers. Some reservoirs are sour as a result of high levels of H2S that have been present over geologic time frames. Many reservoirs are sour, however, as a conse-quence of seawater injection for secondary recov-ery.25 The SRPs that live near the wellbore and in the reservoir have simple needs for growth—they require sulfate, carbon and nutrients. Seawater is rich in sulfate, and reservoir formation water usually contains abundant short-chain fatty acids that supply the carbon and other nutrients.26 Add a suitable temperature regime, inject seawater and the end result is inevitable—souring.

Exactly how and to what extent souring occurs have been recently challenged, and the picture may not entail simple microbe growth from water injector all the way to produced water

outlet.27 New research relies on data that show the amount of H2S produced is consistent with production only in the immediate vicinity of the wellbore but not throughout the formation. Scientists have concluded that elevated levels of heavy metals, water-soluble hydrocarbons and microbe activity by-products inhibit microbe growth in the reservoir. Another result of this research is a model showing how H2S produced in the vicinity of the wellbore moves through the reservoir. Early theories relied on a simple mixing-zone model that predicted rapid H2S breakthrough. Data show the opposite—several reservoir pore volumes must be displaced before H2S breakthrough. This newer model assumes that most of the H2S generation takes place in a biofilm near the injector and that the reservoir is merely a zone for transport and adsorption.

Regardless of how it occurs, souring creates many problems for the industry, including corro-sion of pipelines and topside equipment, reser-voir plugging from sulfides, health risks from H2S toxicity and increased refining costs.28 The effects of souring are serious enough that oilfield pro-ducers have investigated several ways to control it. These include biocides, nanofiltration to remove sulfate and manipulation of injection water salinity levels to inhibit microbe growth. Because processes such as nanofiltration have high capital costs, biocides have usually been the first choice for controlling microbial growth to prevent souring.

New methods employed for control of reser-voir souring have helped scientists further under-stand microbial identities and their chemistry during secondary recovery. Although earlier inves-tigations into souring focused almost exclusively on SRB, seawater and reservoir formations con-

20. Larsen J, Rasmussen K, Pedersen H, Sørensen K, Lundgaard T and Skovhus TL: “Consortia of MIC Bacteria and Archaea Causing Pitting Corrosion in Top Side Oil Production Facilities,” paper NACE 10252, presented at the NACE Corrosion Annual Conference and Exposition, San Antonio, Texas, USA, March 14–18, 2010.

21. Skovhus TL, Holmkvist L, Andersen K, Pedersen H and Larsen J: “MIC Risk Assessment of the Halfdan Oil Export Spool,” paper SPE 155080, presented at the SPE International Conference and Exhibition on Oilfield Corrosion, Aberdeen, May 28–29, 2012.

22. Adams DL: “Microbiologically Influenced Corrosion of Electrical-Submersible-Pumping-System Components Associated With Acid-Producing Bacteria and Sulfate-Reducing Bacteria: Case Histories,” paper SPE 136756, presented at the SPE Latin American and Caribbean Petroleum Engineering Conference, Lima, Peru, December 1–3, 2010.

23. Bagchi D, Periera AP, Chu J, Smith JP and Scheie J: “Successful Mitigation of Microbiologically Influenced Corrosion in Waterflood Pipelines and Process Equipment,” in Blackwood DJ (ed): Proceedings of Corrosion Asia 2000. Singapore: Corrosion Association Singapore (2000): 55–65.

> Corrosion reactions. A complex set of reactions underlies the production of MIC on a metal surface. These reactions are strongly influenced by sulfate-reducing prokaryotic and methanogenic respiration (blue and red paths, top). This set of reactions is best illustrated by listing the net reactions for sulfate reduction and CH4 production (bottom). In the net sulfate reduction reaction, iron [Fe], H2S and the sulfate ion [SO4

2–] combine to give FeS and water. In the net CH4 production reaction, Fe, H2S and carbon dioxide [CO2] combine to give FeS, water and CH4. (Adapted from Larsen et al, reference 20.)

FeS

Net reactions

H2S

CO2

Methanogens

Metal

WaterSulfate-reducingprokaryotes

SO42–

CH4

H2Fe2+

H+

Fe0

S2–

e–

4Fe0 + 3H2S + SO42– + 2H+ 4FeS + 4H2O

n4Fe0 + 4H2S + CO2

4FeS + 2H2O + CH4

24. Larsen J, Sørenson K, Højris K and Skovhus TL: “Significance of Troublesome Sulfate-Reducing Prokaryotes (SRP) in Oil Field Systems,” paper NACE 09389, presented at the NACE Corrosion Annual Conference and Exposition, Atlanta, Georgia, USA, March 22–26, 2009.

25. Kuijvenhoven C, Bostock A, Chappell D, Noirot JC and Khan A: “Use of Nitrate to Mitigate Reservoir Souring in Bonga Deepwater Development Offshore Nigeria,” paper SPE 92795, presented at the SPE International Symposium on Oilfield Chemistry, Houston, February 2–4, 2005.

26. Bass and Lapin-Scott, reference 2.27. Sunde E and Torsvik T: “Microbial Control of Hydrogen

Sulfide Production in Oil Reservoirs,” in Ollivier B and Magot M (eds): Petroleum Microbiology. Washington, DC: ASM Press (2005): 201–214.

28. Youssef N, Elshahed MS and McInerney MJ: “Microbial Processes in Oil Fields: Culprits, Problems, and Opportunities,” in Laskin AI, Sariaslani S and Gadd GM (eds): Advances in Applied Microbiology, vol. 66. Burlington, Vermont, USA: Elsevier (2009): 141–251.

29. SRB use anaerobic respiration while NRB use anoxic respiration.

30. Thorstenson T, Bødtker G, Lillebø B-LP, Torsvik T, Sunde E and Beeder J: “Biocide Replacement by Nitrate in Sea Water Injection Systems,” paper NACE 02033, presented at the NACE Corrosion Annual Conference and Exposition, Denver, April 7–11, 2002.

31. Rassenfoss, reference 4.32. Zahner RL, Tapper SJ, Marcotte BWG and Govreau BR:

“What Has Been Learned from a Hundred MEOR Applications,” paper SPE 145054, presented at the SPE Enhanced Oil Recovery Conference, Kuala Lumpur, July 19–21, 2011.

33. Brisbane PG and Ladd JN: “The Role of Microorganisms in Petroleum Exploration,” Annual Review of Microbiology 19 (October 1965): 351–364.

34. Tucker J and Hitzman D: “Detailed Microbial Surveys Help Improve Reservoir Characterization,” Oil & Gas Journal 92, no. 23 (June 6, 1994): 65–68.

Summer 2012 11

tain several other species of microbes, including nitrate-reducing bacteria (NRB). SRB and NRB can live and thrive in the wellbore and formation, provided they have a sufficient carbon source such as short-chain fatty acids.

On the molecular level, SRB reduce the sul-fate to sulfide, and NRB reduce the nitrate to nitrogen.29 SRB and NRB compete for food, and where it is limited, that competition is intense. In the wellbore and reservoir, if oxygen is absent, introduction of nitrate, via injection water, favors NRB growth over SRB growth. Nitrate, in the form of calcium nitrate [Ca(NO3)2], is added to injection water to prevent souring.30 This form of nitrate may be used in place of biocide and has minimal health and environmental impacts. Although nitrate may not completely eliminate the need for biocides, it can reduce the amount of other chemicals needed.31 Using their increased knowledge of SRB and NRB microbe species and chemistry, scientists have improved treatment techniques for souring—the same is true for microbiologically enhanced oil recovery.

Operators have employed MEOR for decades. Much of the past work relied on trial and error and produced mixed results. A more complete understanding of microbe behavior and chemistry is resulting in a resurgence of MEOR field trials. These trials have two common objectives—iden-tify the indigenous microbes in the formation and design formulas for nutrient injection to stimulate their growth; that is, find the helpful microbes and feed them what they like.

Just as there are many types of indigenous microbes, there are several mechanisms microbes employ that may stimulate oil produc-tion from mature wells. First, natural microbe metabolic processes produce downhole gases that may increase pressure and decrease oil vis-cosity. Second, microbes produce surfactants that decrease the surface tension between oil and water. In addition, biomass and polymers from microbes selectively plug oil-depleted areas in the reservoir, diverting fluids into oil-rich zones. Successful MEOR projects typically depend on a combination of these mechanisms rather than any single one.

After reviewing MEOR field trial results, sci-entists have made important observations regarding its application.32 Although MEOR tech-nology has been used in both oil-producing and water injection wells, it probably has the best chance of success in reservoirs with active water injection programs for secondary recovery. Not only does the water provide the energy to push oil

out, but it also distributes the nutrients through-out the system. Data show that MEOR can enhance recovery in reservoirs with a wide range of oil densities—from 16 to 41 degree API gravity and with reservoir temperatures as high as 93°C [200°F] and salinities as high as 142,000 parts per million (ppm) total dissolved solids. It is also possible to apply MEOR to dual-porosity reservoirs if the added nutrients are able to penetrate the matrix and not bypass the formation via high-permeability streaks. In some cases, MEOR treatment may reduce reser-voir souring in addition to stimulating produc-tion. Scientists theorize that the added

nutrients stimulate microbes that outcompete SRPs for food and thereby depress SRP growth. These trials demonstrate that MEOR processes can economically free up oil trapped in mature fields. Although most work to date has been on mature, noneconomic wells, there is potential for application of MEOR at an earlier stage in the life of a producing reservoir.

In addition to using microbes to stimulate pro-duction and mitigate reservoir souring and corro-sion, scientists are using them in exploration via biomonitoring.33 In one application of biomonitor-ing, a grid of shallow soil samples was analyzed for specific microbes.34 Elevated amounts of the target

> Halfdan corrosion. Visual examination of a cross section of the produced-water separator pipe (top) revealed a 2- to 3-cm [0.8- to 1.2-in.] layer of corrosion scale (middle). The scale had an orange outer layer and a black inner layer adjacent to the metal (bottom). Scientists observed areas of severe pitting corrosion at various points on the inner layer. Laboratory studies, including examination by the new MMMs, showed that the outer scale layer was composed of salts, iron oxides and decomposed biomass—primarily SRB and sulfate-reducing archaea (SRA). The inner scale layer was composed of salts, iron sulfides and decomposed biomass that had high levels of methanogens. (Adapted from Skovhus et al, reference 21.)

Outer solidsInner solids

Innersurface

Water separator pipe

2 to 3 cm of corrosion scale

Pitting corrosion

Pipe metal

12 Oilfield Review

microbes indicated microseepage of oil and gas from underground formations (above). Operators use this type of data to rank drilling prospects, characterize heterogeneities and iden-tify bypassed oil.

Controlling and Harnessing MicrobesArmed with these new insights on microbe behavior and chemistry, producers are putting this knowledge to work in the oil field. Statoil is using nitrate to control corrosion and H2S at its Gullfaks platforms in the North Sea.35

The Statoil Gullfaks field is located 175 km [109 mi] northwest of Bergen, Norway. Discovered

in 1979, this field produces about 30,000 m3/d [189,000 bbl/d] of oil from three large plat-forms—Gullfaks A, B and C.36 The platforms started production in the late 1980s and cur-rently use seawater injection for pressure sup-port. The seawater intake depth for Gullfaks A and B is 70 m [230 ft] below the surface; the Gullfaks C intake depth is at 120 m [394 ft]. Injection water volumes vary from 30,000 m3/d [189,000 bbl/d] to 70,000 m3/d [440,000 bbl/d]; the pressure downstream of the pumps is about 20 MPa [2,900 psi]. Injection water undergoes vacuum deaeration to remove oxygen, and the final water temperature downstream of the deaerator is 25°C [77°F].

Although Statoil employed stringent filtration and biocides to control injected water quality at Gullfaks, those approaches were not entirely effective. In the early 1990s, Gullfaks A experi-enced high H2S levels in produced gas and water. The high H2S levels, coupled with laboratory data that showed rapid increases in the Gullfaks SRB population from 1994 to 1996, gave Statoil reason to rethink the microbe control strategy.37 A suc-cessful application of nitrate added to injected seawater at Statoil’s Veslefrikk platform in early 1999 provided engineers with the confidence to use it at Gullfaks.38

>Microbial surveys. Soil samples in Osage County, Oklahoma, USA, were analyzed to detect the abundance of butane-utilizing microbes. More than 1,200 samples were analyzed from a grid measuring 3.5 mi [5.6 km] by 7.5 mi [12.1 km] (left). The orange circles indicate samples with the highest 30% of the microbe concentration; the size of the circle is proportional to concentration. The smoothed data are contoured to provide a more informative picture of the microbe distribution (right). The strongest microbial anomaly (purple) corresponds to structural data from a 3D seismic survey covering the same grid area. Several years after the microbial survey was conducted, an operator drilled and completed a producing oil well at the microseepage anomaly. (Adapted with permission from Geo-Microbial Technologies Inc.)

0 km

Low

High

0 mi 1

1

Contoured Microbial Concentrations

Relative microbe

concentration

0 km

0 mi 1

1

Presence ofbutane-utilizing

microbes

Smoothed Microbial Concentrations

Summer 2012 13

In late 1999, Statoil switched from biocide to nitrate to treat the injected seawater for reser-voir microbe control at the Gullfaks B and C plat-forms.39 Nitrate was added to the injection water at 30 to 40 ppm as a 45 weight percent solution of Ca(NO3)2. At both platforms, scientists observed decreases in SRB counts about one month after the start of nitrate injection. Decreases in the SRB population were accompanied by increases in the NRB counts. These changes in microbe dis-tribution are consistent with how these two microbe groups compete for nutrients. As nitrate injection continued, the changes in microbe dis-tribution led to major changes in the corrosion rate (right). Engineers also noted decreases in H2S levels in the produced water at Gullfaks (below right). Tangible benefits for Statoil include reduction of H2S in the produced water in most parts of the field and a 50% decrease in cor-rosion rates on metal coupons in the seawater injection system.

Nitrate controls certain undesirable aspects of microbe behavior, but MEOR does the oppo-site—it exploits microbes’ positive characteris-tics. The rationale for bringing microbes into the oil recovery process is simple—about 80% of the oil currently produced is from fields discovered in the early 1970s. More than 50% of the oil in these fields remains trapped and cannot be economi-cally recovered.40 In the last few years, scientists have developed MEOR processes that use new analytical technology to selectively identify and exploit beneficial microbes living in oil reser-voirs. These MEOR processes have given opera-tors a new tool to inexpensively free oil trapped in mature reservoirs. Husky Energy Inc. used this approach in a pilot oil recovery project in Canada.

35. Sunde E, Lillebø B-LP, Bødtker G, Torsvik T and Thorstenson T: “H2S Inhibition by Nitrate Injection on the Gullfaks Field,” paper NACE 04760, presented at the NACE Corrosion Annual Conference and Exposition, New Orleans, March 28–April 1, 2004.

36. Hesjedal A: “Introduction to the Gullfaks Field,” http://www.ipt.ntnu.no/~tpg5200/intro/gullfaks_introduksjon.html (accessed May 24, 2012).

37. Statoil collected samples of injection water downstream of the vacuum deaerator using a bioprobe. Bioprobes allow collection of samples from a biofilm that deposits on a metal surface within the probe. These instruments are commonly used in oil and gas systems to detect corrosion-causing organisms.

38. Thorstenson et al, reference 30.39. Statoil started nitrate injection at Gullfaks B in

October 1999 and about a month later at Gullfaks C.40. Marcotte B, Govreau B and Davis CP: “MEOR Finds Oil

Where It Has Already Been Discovered,” E&P, (November 4, 2009), http://www.epmag.com/Exploration-Wildcats-Stepouts/MEOR-finds-oil-it already-discovered_47917 (accessed July 15, 2012).

> Gullfaks microbe activity. Before nitrate was used in injection water at Gullfaks B, enrichment cultures from water and biofilm showed a stable and diverse SRB population. Although at lower concentrations, NRB were also present (not shown) and used the same carbon sources as nutrients. After nitrate addition, SRB activity significantly decreased and NRB numbers in the biofilm increased by three orders of magnitude (not shown). Corrosion measurements on carbon steel coupons in the water injection system showed similar trends. Beginning in early 1994, corrosion rates at Gullfaks B rose, peaking shortly before nitrate addition was started. After nitrate addition, corrosion rates trended downward and were reduced by at least half. (Adapted from Sunde et al, reference 35.)

Corro

sion

rate

, mm

/yr

Date

Corrosion rateSRB activity

Nitrate added, Gullfaks B

April1994

May1997

February2000

February2003

SRB

activ

ity,

μg H

2S/c

m2 /

d

0 0

5

10

15

20

25

0.2

0.4

0.6

0.8

1.0

1.2

U K

NORWAY

2000 mi

0 200km

Gullfaks field

North Sea

> Gullfaks H2S production. Statoil engineers measured H2S in the produced water before and after nitrate addition. At Gullfaks C, produced water H2S levels were slowly increasing prior to introduction of nitrate. After nitrate addition, H2S levels fell significantly but only after a delay. This delay is a result of the time it takes H2S to equilibrate in the reservoir. Statoil scientists estimate that several pore volumes must be displaced in the reservoir before a new or reequilibrated H2S value is observed in the producers. Statoil researchers have also developed a reservoir souring model—predicted H2S values are shown for Gullfaks C. The predicted values indicate levels that would have been experienced had there been no nitrate addition. (Adapted from Sunde et al, reference 35.)

Date

0

2

4

6

8

10Nitrate added, Gullfaks C

Nov1997

July1999

Feb2001

Oct2002

Predicted H2SMeasured H2S

H 2S, m

gw

ater

, L

14 Oilfield Review

The Husky pilot MEOR project is located within a field in the southwest corner of Saskatchewan, Canada (left).41 This field, discov-ered in 1952, has a reservoir depth of about 1,200 m [3,940 ft] and an average temperature of 47°C [117° F]. Current production from the field is 60 m3/d [380 bbl/d] of 22 to 24 degree API gravity oil and 4,250 m3/d [150 Mcf/d] of gas. Husky began waterflooding in 1967, and current water injection is 1,300 m3/d [8,200 bbl/d]. In 2010, cumulative oil production from this field reached 3.3 million m3 [21 million bbl] since discovery—estimated to be about 29% of the original oil in place (OOIP).

Husky teamed with Titan Oil Recovery to investigate the feasibility of using MEOR to recover crude oil trapped in this field. The Titan technology is simple—identify and quantify microbes that are indigenous to the reservoir.42 Using these data plus results from other field tests, Titan engineers formulated a nutrient mix-ture to release in the reservoir by way of the water injection system. The engineers theorized that the injected nutrients would stimulate changes in certain species of resident microbes, allowing the microbes to affect the interfaces between oil, water and rock to release small droplets of oil into the active flow channels.

Husky applied the Titan process in two steps—batch nutrient treatment of a single well followed by water injection to spread nutrients to nearby wells. For the single-well treatment, Husky injected 1.3 m3 [8.2 bbl] of nutrients and 13 m3 [82 bbl] of injection water through the wellbore, then shut in the well for a week. When the well was returned to production, results were encouraging—oil production increased from 1.2 to 4.1 m3/d [7.5 to 25.8 bbl/d] and water cut decreased from 94% to 80%. Because these results showed that the nutrients were appropriate for the reservoir and its resident microbes, Husky shifted its focus to the water injector for treating nearby wells in the pilot area.

Starting in early 2008 and using procedures similar to treatment of the single well, Husky injected the custom nutrient via the water injector in the pilot area. After three weeks, the closest producing well showed a significant oil production increase and a corresponding decrease in water cut (left). After an appropriate interval to allow underground transit of nutri-ents, engineers observed these positive results at

> Husky-Titan pilot location. The pilot area encompassed four producing wells and one water injector in the Saskatchewan, Canada, field. Nutrient injection was carried out in two steps. Husky first used Well A to confirm the laboratory-derived nutrient formula by batch treating the well. The operator next used Injector B to deliver the nutrients while production was monitored at nearby Wells C, D and E. (Adapted from Town et al, reference 41.)

Well C

Well A

Well D

Well E

Pilot area

Injector B

Water injectorProducing well

C A N A D A

U N I T E D S T A T E S

MEOR pilot

Saskatchewan

0 km

0 mi 1

1

> Husky-Titan pilot results. From early 2007 until the beginning of 2008, oil production at Well C in the Saskatchewan MEOR pilot was reasonably steady, between 2 and 4 m3/d [13 and 25 bbl/d]. The water cut for the same period was about 95%. After the first and subsequent nutrient injections at Injector B, oil production at Well C increased to 7 to 9 m3/d [44 to 57 bbl/d]. For the same period, water cut fell to about 88%. Because Well C was not treated directly, the pilot confirmed response through the reservoir from injector to producer. (Adapted from Town et al, reference 41.)

Date

0

2

4

6

875

85

95

65

55

70

80

90

100

60

50

10

12

14

Jan2007

Aug2007

Feb2008

Sep2008

Mar2009

Wat

er c

ut, %

Nutrient Injections at Injector BTreatment

1Treatment

2Treatment

3

Oil p

rodu

ctio

n, m

3 /d Oil production

Water cut

Summer 2012 15

other wells in the pilot area. In addition, engi-neers used the same treatment in wells and injectors outside the pilot area, achieving posi-tive results, which confirmed the response from injector to producer.

Success with microbe stimulation to enhance oil production from a mature waterflood was also seen at a field in Kansas, USA.43 The Stirrup field, discovered in 1985, is located in the southwest corner of Kansas. The reservoir depth is about 5,200 ft [1,600 m], and current production is 490 bbl/d [78 m3/d] of 38 to 41 degree API gravity oil. The initial reservoir pressure was 1,650 psi [11.4 MPa] and had declined to less than 100 psi [0.69 MPa] at the start of waterflood in 2003. Primary recovery from the Stirrup field was cal-culated at 19.1 million bbl [3.04 million m3] of oil, and waterflood is estimated to add another 2.8 million bbl [0.44 million m3], for an ultimate recovery of about 15% of the OOIP. In mid-2010, Glori Energy, in collaboration with Statoil, tested the AERO activated environment for recovery of oil technology in the Stirrup field to see if there was potential to boost recovery based on micro-bial stimulation (right).

Detailed characterization of the existing microbe population using both traditional and genome-based techniques was the first step in implementing the AERO technology at Stirrup. Once Glori Energy had characterized the indig-enous microbe population, engineers devel-oped a custom nutrient formulation and micro- bial inoculant.

Glori Energy started the AERO technology pilot at Stirrup in May 2010 by continuously injecting the custom nutrient using two of the water injectors. The initial test pattern for the pilot included two injectors and five producing wells. After several months of operation, it was clear that water from one of the injectors was not entering the test pattern, so that injector was withdrawn from the pilot. Some of the five test wells experienced similar problems when follow-up work showed that injectors not included in the test pattern program were influencing perfor-mance. Since this field does not have a dedicated system for separation and testing, evaluation can be made only on a well-by-well basis. Stirrup Well 12-2 demonstrated the predominant response. Analysis of the data from Well 12-2 suggests that

41. Town K, Sheehy AJ and Govreau BR: “MEOR Success in Southern Saskatchewan,” paper SPE 124319, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, October 4–7, 2009.

> AERO technology. Glori Energy has theorized that the AERO technology stimulates oil production in four steps. The microbes in the reservoir use existing oil as a carbon source to produce surfactants that reduce the oil-water surface tension, helping to release trapped oil (top left). The microbes then multiply and block some existing water flow paths, thereby forcing the opening of new flow paths that move trapped oil out of the reservoir (top right). When some of the trapped oil has been released and the local carbon source depleted, the microbes disperse and former water flow paths reopen (bottom left). If the stimulated microbes are active and have sufficient nutrients, the process is continuously repeated until trapped oil is brought to the surface and production increases (bottom right). (Adapted with permission from Glori Energy.)

Microbes reduce oil-water tension.

Microbes

Water

Flow path

Rock grain

Oil releasedinto pore

Oil trappedin pore

Microbes affect preferential flow.

Microbes disperse. New water flowpaths open.

42. Analysis for resident microbes is typically carried out on produced water samples.

43. Bauer BG, O’Dell RJ, Marinello SA, Babcock J, Ishoey T and Sunde E: “Field Experience from a Biotechnology Approach to Water Flood Improvement,” paper SPE 144205, presented at the SPE Enhanced Oil Recovery Conference, Kuala Lumpur, July 19–21, 2011.

16 Oilfield Review

the AERO treatment, when properly applied, is capable of significantly boosting ultimate recov-ery (below).

Microbes on the SurfaceWhile many microbe applications are designed for the subsurface, others contribute to shallow and surficial processes such as the management of oilfield waste or remediation of production from oil sands and spills.

Oil and gas production generates a variety of vapor, liquid and solid waste that not only must meet governmental regulations but also be dis-

posed of in a safe and environmentally responsi-ble manner. Microbes are currently playing an important role in disposal of these waste streams, particularly in the realm of solid waste. Two solid waste streams that arise from oil and gas produc-tion may be amenable to bioremediation: hydro-carbon-impacted soil and drilling waste.

During the last 100 years, some production facilities have experienced contaminated soils because of leaks or uncontrolled discharges of crude oil and other liquids. Natural weathering can significantly reduce the hydrocarbon con-centration in soil but does not eliminate it.

Although researchers have shown that heavily weathered, high–molecular weight hydrocar-bons are essentially nonbiodegradable, these same hydrocarbons can be rendered less detri-mental by treatment with a mixture of nutrients and cultured microbes.44 Currently, bioremedia-tion is usually the preferred method for dealing with crude oil–impacted soil.45 Because not all crude oils respond to bioremediation in the same way, engineers have developed predictive models to allow quick assessment of ex situ bio-remediation without resorting to time-consum-ing laboratory trials.

Drilling waste, a by-product of oilfield opera-tions, is mostly nonhazardous, although the vol-umes of such waste are significant for both marine and onshore operations. For example, a midsize operator in the Gulf of Mexico may routinely gen-erate 250 tonUS [227,000 kg] of waste monthly.46 Some operators dispose of water-base drilling wastes from marine operations directly to the ocean. Although harm to the ecosystem from this type of disposal has not been demonstrated, it remains a controversial practice.47

As in marine environments, onshore drilling generates a significant volume of waste. A 509-m [1,670-ft], 61/2-in. hole produces 21 m3 [130 bbl] of cuttings, and disposal of onshore cuttings pres-ents a different challenge from that of marine environments. Scientists are designing synthetic drilling muds that, when added to soil, enhance soil quality and stimulate more rapid bioremedia-tion.48 In addition, engineers have developed a standardized screening protocol for drill cut-tings. This protocol compares rates of bioreme-diation using greenhouse-scale models to simulate field conditions (next page). Scientists at M-I SWACO, a Schlumberger company, use results from the greenhouse simulations to pre-dict the length of time for treatment, final condi-tion of the material following treatment, the capability of the material to comply with environ-mental targets and the likelihood of technique effectiveness.

> AERO technology results. Data from the Stirrup Well 12-2 are plotted as water cut versus cumulative production from the well with approximate trend lines drawn for periods both before and after nutrient injection. When these trend lines are extrapolated to constant 95% water cut, they imply a 50,000- to 55,000-bbl [7,950- to 8,740-m3] oil production increase as a result of the treatment. (Adapted with permission from Glori Energy.)

Wat

er c

ut, %

Cumulative production, 1,000 bbl

95

85

75

75 100 125 225150 250175 275200

90

80

70

100

AERO nutrient start

Before AERO nutrient additionAfter AERO nutrient addition

Estimated increase50,000 to 55,000 bbl

44. Adams RH, Díaz-Ramírez IJ, Guzmán-Osorio FJ and Gutiérrez-Rojas M: “Biodegradation and Detoxification of Soil Contaminated with Heavily Weathered Hydrocarbons,” presented at the 13th Annual International Environmental Petroleum Conference, San Antonio, Texas, October 16–20, 2006.

45. Hoffman R, Bernier R, Smith S and McMillen S: “A Four-Step Biotreatability Protocol for Crude Oil Impacted Soil,” paper SPE 126982, presented at the SPE International Conference on Health, Safety and Environment in Oil and Gas Exploration and Production, Rio de Janeiro, April 12–14, 2010.

46. Louviere RJ and Reddoch JA: “Onsite Disposal of Rig-Generated Waste via Slurrification and Annular Injection,” paper SPE/IADC 25755, presented at the SPE/IADC Drilling Conference, Amsterdam, February 22–25, 1993.

47. Neff JM: “Composition, Environmental Fates and Biological Effects of Water Based Drilling Muds and Cuttings Discharged to the Marine Environment: A Synthesis and Annotated Bibliography.” Report prepared for the Petroleum Environmental Research Forum and API, January 2005, http://perf.org/pdf/APIPERFreport.pdf (accessed August 2, 2012).

48. Curtis GW, Growcock FB, Candler JE, Rabke SP and Getliff J: “Can Synthetic-Based Muds Be Designed to Enhance Soil Quality?,” paper AADE 01-NC-HO-11, presented at the AADE National Drilling Conference, Houston, March 27–29, 2001.

Clements K, Rabke S and Young S: “Development of a Standardized Screening Procedure for Bioremediation of Drill Cuttings,” presented at the 14th International Petroleum Environmental Conference, Houston, November 6–9, 2007.

49. Orwig J: “Scientists Grow Bacteria to Improve Oil Sands Remediation,” EARTH 57, no. 4 (April 2012):18.

50. Phan CM, Allen B, Peters LB, Le TN and Tade MO: “Can Water Float on Oil?,” Langmuir 28, no. 10 (March 13, 2012): 4609–4613.

Summer 2012 17

Microbe FrontiersThe ubiquity of microbe distribution on the planet ensures that scientists associated with the oil and gas industry have an abundance of oppor-tunities ahead of them. These opportunities include oil sands remediation and cleanup of ocean oil spills.

Production of hydrocarbons from Canadian oil sands has been successful in adding to the world’s sources of petroleum, but such hydrocarbon pro-duction is not without environmental cost. Tailings ponds, which must be fenced off to protect wild-life, are one consequence of oil sands production. Biologists and engineers have found that certain microbes thrive on potentially hazardous com-pounds in that environment.49 These scientists theorize that if the microbes could be cultured, identified and grown into biofilms, they could be

reintroduced to shorten the current 20- to 30-year compound breakdown time. Researchers are making progress; by simulating tailings pond con-ditions, they have reproduced 30% to 60% of the microbes in the sludge and expect to have pilot bioreactors running in a few years.

Drillers and producers in offshore operations must take significant precautions to avoid spills and must be prepared to deal with them if they occur. Use of dispersants remains controversial because the dispersants may have environmental impacts. Researchers in Australia, studying the physical chemistry of oil-water interactions, have reported a seemingly contradictory finding that may improve the odds in oil spill cleanup. These researchers found that, given certain values of interfacial tension, oil density and water droplet

volume, water droplets can float on an oil sur-face.50 Acceleration of aerobic biodegradation of spills is one application of this finding—small water droplets that float on the oil surface have more contact with airborne oxygen, thus acceler-ating the microbe-driven cleanup.

New analytical methods and scientists’ increased understanding of microbes have led to developments in controlling souring and corro-sion and improving oil recovery from mature wells. These advances are stimulating further work in the use of microbes for bioremediation in both onshore and offshore settings. Today, engi-neers are bringing the negative characteristics of microbes in the oil field under tighter control and are increasingly able to harness their positive aspects for improved hydrocarbon production and solutions to environmental concerns. —DA

> Bioremediation. Scientists at M-I SWACO in Houston use a greenhouse to study bioremediation rates by composting tub-sized samples of drill cuttings (right). These specialists have developed bioremediation protocols using 2.7- to 4.0-ft3 [0.08- to 0.1-m3] size samples of a drill-cutting mix containing sand, bentonite clay, an additional nonswelling silica clay and water, followed by coating with hydrocarbons at the 10 weight percent level. Typical soil amendments and nutrients are added to the resultant hydrocarbon-compost mix before it is allowed to sit for long periods under greenhouse conditions. During this extended period, constant conditions for the compost are maintained by introducing oxygen via periodic mixing and adding water and nutrients as required. Bioremediation as measured by total petroleum hydrocarbons is plotted for three hydrocarbon proxies (left). These data show that after 30 days, linear paraffins and mixed olefins have nearly completely dissipated, while diesel oil is significantly reduced but does not fall below about 1 weight percent. M-I SWACO uses this test to screen onsite remediation as well as to train field personnel to maintain optimal compost conditions.

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18 Oilfield Review

Drilling Automation

In pursuit of increased quality and profitability, many in the manufacturing industry

have found success in automating processes. The oil and gas industry is looking for

ways to replicate this strategy for drilling. Drilling automation may hold the key to

efficiently performing intricate and high-speed tasks and thus make complex wells

technically and economically feasible. When a drilling project involves large

numbers of wells drilled through well-documented lithologies and pressure regimes,

operators can capitalize on the repetitive nature of automated drilling to eliminate

costs associated with the performance variability typically exhibited from one well to

the next within a drilling program.

Walt Aldred Cambridge, England

Jacques Bourque Mike ManneringGatwick, England

Clinton Chapman Bertrand du CastelRandy Hansen Sugar Land, Texas, USA

Geoff Downton Richard HarmerStonehouse, England

Ian FalconerHouston, Texas

Fred FlorenceNational Oilwell VarcoCedar Park, Texas

Elizabeth Godinez ZuritaVillahermosa, Mexico

Claudio NietoPetróleos Mexicanos (PEMEX)Villahermosa, Mexico

Rob StauderHelmerich & Payne, Inc.Tulsa, Oklahoma, USA

Mario ZamoraM-I SWACOHouston, Texas

Oilfield Review Summer 2012: 24, no. 2. Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Jonathan Dunlop, Cambridge, England; Jean-Paul LeCann, Roissy-en-France, France; Eric Maidla, Houston; and Jose Luis Sanchez Flores, Sugar Land, Texas.Factory Drilling, PowerDrive, PowerV, ROPO and Slider are marks of Schlumberger.FBRM is a registered trademark of Mettler-Toledo Autochem, Inc.IntelliServ is a registered trademark of National Oilwell Varco.

Engineers have long viewed drilling as nearly equal parts art and science. Today, as autono-mous computer-controlled drilling operations—drilling automation—approach reality, the view of engineers is leaning decidedly toward science. The ultimate objective of drilling auto-mation, as with most upstream innovations, is to deliver financial benefits to the operator. Drilling automation seeks to accomplish this through pro-cess improvements, optimized rates of penetra-tion (ROPs), consistent hole quality and overall drilling performance, all of which allow operators to reach their objectives in the shortest time. Bringing together rig floor and downhole automa-tion also promises to improve environmental pro-tection and worker health and safety while helping operators to economically exploit reserves that are out of reach using today’s tech-nologies. As large numbers of upstream industry experts prepare to retire, automation may offer a way to codify best practices and knowledge and thereby preserve expertise.

On the manufacturing assembly line, automa-tion has become ubiquitous, typically taking the form of computer-guided robots performing repetitive tasks. The machines are tireless, pre-cise and do not suffer from the boredom or lapses in attention that their human counterparts do. They are able to attain a level of autonomy

because there are few decisions to make and there is little uncertainty or variability in their environment and tasks. This is the concept behind the Factory Drilling approach for field development in which a large number of wells—for which conditions are well-understood—are to be drilled and completed.

The drilling industry has lagged other indus-tries in adopting automation, but some advances have been made; high-end drilling units have been equipped with remotely operated iron roughnecks and pipe handling machines. However, while equipment mechanization repli-cates repetitive rig tasks on the drill floor and removes humans from potentially dangerous environments, it is not the same as drilling auto-mation. An automated drilling process provides operators with a way of accessing reservoirs at lower costs while safely and consistently outper-forming manual operations.

Automation of the drilling process requires a system that has the ability to deal with changing and uncertain environments. Fed directly by downhole and surface data, these systems must react to changes such as lithology in a manner that maintains optimal performance, thus increasing uptime and efficiency. Reduction of personnel on the rig floor and the system’s ability

Summer 2012 19Suummmerer 220101122 19191919

to perform some tasks remotely would be only by-products of this effort, not objectives.1 In prac-tice, automated systems will more likely leverage the knowledge and experience of rig personnel than do away with them.

The drilling culture is part of the reason for the upstream industry’s delay in adopting auto-mation. Drilling personnel often make opera-tional decisions based on their overall experience and knowledge of the local geology and drilling conditions. As a consequence, many are suspi-cious of systems that seem a threat to their skill set, require them to relinquish some portion of control of the drilling operation or move techni-cal limits away from traditionally conservative drilling practices.2 From an organizational point of view, the major components of an automated

system require close cooperation over long peri-ods of time, but the systems employed in the drill-ing process are often owned by a variety of companies and may have different drivers, mak-ing automated cooperation difficult.

The current challenge of creating an auto-mated drilling system that is capable of drilling a well or section autonomously lies in the many uncertainties associated with making a hole deep in the Earth. In manufacturing industries, dra-matic events encountered during the process are the exception, whereas in drilling, they are the rule. Downhole pressures, temperatures and rock characteristics often change rapidly as the bit progresses toward TD. Therefore, it is difficult to replicate an experienced driller’s response to any of the many possible scenarios.

1. Pink T, Bruce A, Kverneland H and Applewhite B: “Building an Automated Drilling System Where Surface Machines Are Controlled by Downhole and Surface Data to Optimize the Well Construction Process,” paper IADC/SPE 150973, presented at the IADC/SPE Drilling Conference and Exhibition, San Diego, California, USA, March 6–8, 2012.

2. The technical limit is the best possible drilling performance for a given set of parameters. It is an ideal standard, which requires a perfect set of conditions, tools and people.

Automating the drilling process hinges on not only availability and interoperability of com-puter-controlled machinery but also on informa-tion management: gathering the right information at the right time and coupling it with the experi-ence necessary to make optimal decisions. The industry has long used software that assists drill-ers in making decisions on the rig floor. These systems require human intervention to interpret

Summer 2012

20 Oilfield Review

data and carry out the appropriate actions, pro-viding drilling guidance rather than automation.

An automated drilling process requires a sys-tems engineering approach—a loop that inte-grates real-time downhole and surface data with predrill models. Adjusting to changing condi-tions, this system modifies operational settings, such as pump rates, hook load and rotary speed.3 In addition, an automated system updates the model using real-time data, essentially simulat-ing the decisions of an experienced driller adapt-ing to the results of imperfect predictions. The level of integration between surface and down-hole systems varies considerably and is limited by sensor availability near the bit and along the drillstring and by bandwidth to send measure-ments and commands to and from downhole. This means the character of drilling automation is likely to vary from well to well. However, results show that higher frequency data from more sensors improve operator ability to drill to the technical limit.

The path to drilling automation may be described in terms of three tiers. The first tier is a system that offers guidance to drillers, the sec-ond makes decisions with driller approval and the third moves toward an autonomous system in which the driller—who may be located off site—acts as the monitor, to intervene only when required (below).

The drilling industry has taken hesitant steps toward automation. Built and tested around 1980, the National Automated Drilling Machine was an early attempt to build an automated drill-ing rig.4 Because manufacturers could not over-come the failure of fragile sensors in a drilling environment, the machine was never commer-cialized. In the 1990s, many rigs were built with mechanized pipe handling equipment, and engi-neers developed closed loop control, using data gathered while drilling, to adjust rotary steerable drilling systems.

Only recently, driven by Norwegian operators and regulators concerned with safety and health issues, has the industry made a sustained effort toward drilling automation. In 2007, the SPE cre-ated a technical section devoted to drilling sys-tems automation; those involved in the section are working toward automation in all areas, including completion and production. This arti-cle examines the state of those ongoing efforts to bring to the industry a level of drilling automa-tion as a means to more efficient, safer and higher quality drilling operations in the future. Case studies from Mexico and the US illustrate various drilling automation applications.

Controlling the BrakeHistorically, in an imitation of manual drilling operations, automated drilling has centered on using the drilling line brake to control weight on bit (WOB). Autodrillers, which mimic human operators by using pneumatic controls to maintain constant WOB or constant ROP, have consistently outperformed humans when drilling conditions—formation geology, pressures and temperatures—are well-known and vary gradu-ally. However, autodrillers performed poorly when these conditions changed abruptly.5

The introduction of disk brakes gave rise to electronic autodrillers that used computer control algorithms to maintain a constant WOB or ROP.6 Improvements to autodrillers drove engineers to develop increasingly complex software that simplified control and adjusted drilling parameters in response to changing formation characteristics as the bit drilled ahead (next page).

Autodrillers are in the second tier of automa-tion because they rely on driller approval. Although dependent on local rig equipment auto-mation and mechanization, drilling automation seeks to build on those systems by integrating the drilling machine with downhole systems and mea-surements. The objectives are to improve and lower the cost of reservoir access and to outper-form manual operations safely and consistently.

Automating the drilling process is complex. Engineers at Schlumberger have segmented the process into manageable modules that may be used either independently or in combination to eventually deliver an intelligent system able to drill a hole section autonomously. The modules are the following:

� abnormal event detection and mitigation � shock and vibration monitoring and

mitigation

Integrating automation modules, which use downhole and surface information, with the rig control system requires drillers to exchange their role of overarching supervisor for that of a criti-cal component within a process. The integrated system must be designed so that the driller inter-acts with it intuitively and is in a position to take control of the rig at any time. To achieve this, the driller must understand what the automation sys-tem is doing as it handles its many tasks, and the

> The path to automation. Systems and industries move from manual to automated control systems in a predictable manner. Initially, in the first tier (bottom), the systems perform a limited analyze-and-advise function by suggesting an optimal course of action for the human operator to perform. In the second tier (middle), the semiautonomous automated system chooses the action and performs it, but only after receiving approval from the driller. In the third tier (top), the automated system is autonomous and informs the driller of its actions as it takes them.

Decides everything and acts autonomously.

Executes an action automatically and informs the driller only if it takes action.

Executes an action automatically and informs the driller only if asked.

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Offers a set of alternatives and narrows the selection.

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Summer 2012 21

driller must anticipate what the system is going to do next. Therefore, counter to preconceptions held in the industry, human involvement in drill-ing operations may be increased rather than decreased by automation.

Faster Engineers are applying these requisite computer control algorithms to various aspects of the drill-ing process; the algorithms fall in each of the

tiers on the path to full automation. Most pro-grams based on these algorithms act in an advi-sory capacity and require human intervention to initiate action. Others are, or are nearly, autono-mous systems, which take action without seeking permission from or notifying the driller and might be best described as supervised autonomy. One such algorithm helps optimize ROP and has been used in programs that have both advisory and full-control capacities.

Automated ROP optimization relies on the fact that while the bit is on bottom, the driller can control only three things: WOB, drillstring rotation speed in revolutions per minute (rpm) and mud flow rate. An automated ROP optimiza-tion system can therefore be created in which the set points of WOB and rpm are fed directly to the controls of the drilling rig.7 Building on this idea, engineers at Schlumberger developed the ROPO rate of penetration optimization module.

3. The driller adjusts the block position to keep the weight on bit within a desired range. The weight on bit is calculated as the difference between the measured hook load, which is a measure of the amount of pipe suspended below the block, and a datum taken by measuring hook load when off-bottom.

4. de Wardt JP and Rogers J: “Drilling Systems Automation—A Technology that Is at a Tipping Point,”

>Modern autodrillers. Whereas WOB was the only parameter considered by early autodrillers as input for controlling the drilling process, later autodrillers used multiple parameters. In this example of multiparameter autodriller output, the multicolor horizontal bar at the top indicates by color which parameter is controlling the brake at that point. The solid curves at the bottom represent parameter data and the dashed lines are the parameter set points. The horizontal black line across the middle of the graph shows the status of the autodriller. When the line is at the low value, the autodriller is off; the upper value signifies it is on. As the 90-ft (27-m) long stand is drilled through a fairly homogenous formation, the ROP function (red) controls when the autodriller is turned on and the bit is above bottom. When ROP reaches its set point, WOB and torque (dark blue and green, respectively) rise as the bit automatically finds bottom. Torque takes control as ROP and WOB level off. When torque is recognized as the limiting factor, the autodriller raises the torque limit and drilling continues on ΔP (light blue)—the standpipe pressure when drilling with a mud motor minus standpipe drilling pressure when just off bottom—through most of the stand, although ROP experiences brief intermittent control throughout the primary ΔP control period. Toward the end of the stand, WOB takes over as the bit encounters harder rock. (Adapted from Florence et al, reference 5.)

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paper IPTC 14717, presented at the International Petroleum Technology Conference, Bangkok, Thailand, February 7–9, 2012.

5. Florence F, Porche M, Thomas R and Fox R: “Multiparameter Autodrilling Capabilities Provide Drilling/Economic Benefits,” paper SPE/IADC 119965, presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, March 17–19, 2009.

6. For more on autodrillers: Aldred W, Belaskie J, Isangulov R, Crockett B, Edmondson B, Florence F and Srinivasan S: “Changing the Way We Drill,” Oilfield Review 17, no. 1 (Spring 2005): 42–49.

7. Dunlop J, Isangulov R, Aldred WD, Arismendi Sanchez H, Sanchez Flores JL, Alarcon Herdoiza J, Belaskie J and Luppens JC: “Increased Rate of Penetration Through Automation,” paper SPE/IADC 139897, presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, March 1–3, 2011.

22 Oilfield Review

The ROPO algorithm is based on a model of PDC bit–formation interaction and a data pro-cessing technique that detects changes in bit response. The PDC bit model assumes that bit-formation interaction is broken into three linear phases based on the depth of cut (below). During the first phase, when the bit is just starting to turn on bottom and before reaching critical depth, increasing WOB causes little increase in depth of cut and, consequently, low ROP. During the second phase, higher WOB results in an increased depth of cut. Phase three begins when this increased efficiency has led to the founder point—the time at which the fluid system is no longer able to adequately clean the face of the bit, and cutting efficiency is reduced.8

The ROPO module characterizes the bit response in real time and determines optimal val-ues of rpm and WOB—within a set of complex lim-its that includes WOB, torque, surface rpm, ROP and motor limits—to achieve maximum ROP.9

In 150,000 m [492,000 ft] drilled through a range of environments, wells drilled in the ROPO advisory mode have shown an average 32% ROP improvement compared with the ROP in offset wells drilled manually or with an autodriller sys-tem (above). When the ROPO algorithm was used in closed loop automation, or control mode, dur-ing which it sent commands directly to the rig control system, ROP improvements were even greater, with the control mode wells experienc-ing a 53.1% ROP gain over the ROP in wells drilled in advisory mode.10

For operators involved in multiple-well projects, saving rig time consistently, without sacrificing wellbore quality, is a strong incentive to improve ROP. In the Burgos basin in Mexico, PEMEX planned to drill 400 wells, many of which are in the Comitas field where the lithology is well known. Typical drilling trouble spots included an 81/2-in. section through mostly shale and a 61/8-in. section that is characterized by interbedded formations of shale and sand.

In their evaluations of the many wells already drilled in the Comitas field, engineers found that ROP averaged 23 m/h [75 ft/h] through the 81/2-in. section and 16.15 m/h [52.98 ft/h] through the 61/8-in. section. Both rates are well below the technical limit. Engineers determined that reducing drilling time by increasing ROP represented a singular opportunity to improve project economics.

Engineers first selected wells that appeared to be good candidates for ROPO applications and then gathered relevant offset well data. Wells were then drilled in ROPO mode and the results evaluated against offset well results. Two com-parisons were made with results from offset wells: rotating ROP and total ROP for the section. When the ROPO algorithm was used through the 81/2-in. section, the rotating ROP increased to 55.40 m/h [181.8 ft/h]. In the 61/8-in. section, ROPO use increased average ROP to 25.2 m/h [82.6 ft/h]. Time savings in the 81/2-in. and 61/8-in. sections were 37% and 39%, respectively.

SmootherIn high-angle wells, especially extended-reach wells with targets that may have a horizontal displacement of several miles from the surface location, some engineers view high ROP as a secondary objective to well path accuracy. To plan an accurate trajectory, the directional driller must locate the wellbore in three dimen-sions and precisely execute holds and turns. The objective is a trajectory that is the most efficient path to a distant target or one that keeps the wellbore within often narrow depth ranges to maximize formation exposure.

> Automated ROP algorithm. Depth of cut per revolution is estimated by dividing ROP by rpm so that real-time drilling data can be plotted in three dimensions of WOB, bit torque and depth of cut. WOB can be described as the sum of two components: friction and cutting. The drilling response of a PDC bit is modeled as three distinct operating regimes. During the first phase (blue), frictional and cutting components both increase during low WOB as interaction is dominated by friction at wear flats of the bit cutters. The second regime (tan) begins when WOB is beyond the critical point and friction is optimal, thus increasing WOB translates into pure cutting action. The third regime (green) occurs when the bit is past the founder point when cuttings are building up around the bit, causing cutting efficiency to decrease. As the bit drills into a new formation, the responses will change abruptly and the data points will fall on new lines.

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> ROPO algorithm advantage. When eight wells were drilled from the same pad, four using the ROPO module (blue) showed significantly faster drill rates on the final tangent section than those drilled conventionally (red). Furthermore, each of the ROPO wells exhibited consistent drilling time results. Time to drill the section in wells drilled without the ROPO technique varied from 6.8 to 8.3 days. In wells drilled with the ROPO approach, time to drill a section varied from 5.3 to 5.8 days. (Adapted from Chapman et al, reference 10.)

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Summer 2012 23

8. Detournay E, Richard T and Shepherd M: “Drilling Response of Drag Bits: Theory and Experiment,” International Journal of Rock Mechanics and Mining Sciences 45, no. 8 (December 2008): 1347–1360.

9. Though rpm and WOB are set by the system, they can also limit the system. For example, a PDC bit design may include maximum allowed WOB or rpm recommendations to prevent bit damage.

In directional drilling, certain processes have already been automated. For directional drilling with a bent housing downhole motor, engineers at PathFinder, a Schlumberger company, have developed the Slider automated surface rotation control system. The system is designed to increase drilling efficiency of a bent housing motor when in sliding mode by repetitively rotat-ing the drillpipe clockwise at surface, then coun-terclockwise without disturbing the toolface orientation of the BHA. The Slider system uses surface torque readings as feedback to an auto-mated system that controls the rocking move-ment of the drillstring to minimize the sliding

friction along the toolstring. At the same time, the system reduces the need to pull the bit off bottom to reset the toolface.

When using bent housing mud motors to change BHA direction, directional drillers must often halt drilling. The Slider control system, however, allows BHA directional change without halting drilling and as a consequence may enhance overall ROP, a secondary objective. For example, when engineers used the Slider system in the build section of a well in Wood County, Oklahoma, USA, they increased sliding ROP by 118% compared with results from manual opera-tions (below).

In contrast to mud motors, rotary steerable systems (RSSs) do not involve sliding sections so they generally deliver faster ROP and smoother wellbores. Additionally, because the drillstring rotates while drilling, hole cleaning is more efficient than when sliding.11 Therefore the well may be drilled with a lower pump pressure, which reduces the equivalent circu-lating density and reduces the threat of frac-turing the formation.12

For most rotary steerable systems, trans-mitting steering commands from surface to the RSS tool is accomplished using manually

>Marked ROP improvements. An operator used slide drilling in two sections of a well drilled in the Marcellus Shale. In the upper section, the well was drilled manually and had an average ROP of 5.8 ft/h. In the lower section, using the Slider system, ROP was raised to 16.1 ft/h (Track 1). WOB (gold) and hook load (purple) were essentially equal through both sections (Track 2). The Slider system kept topdrive torque (blue) low by adjusting rotary speed (red) through the lower sections (Track 3).

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10. Chapman CD, Sanchez Flores JL, De Leon Perez R and Yu H: “Automated Closed-Loop Drilling with ROP Optimization Algorithm Significantly Reduces Drilling Time and Improves Downhole Tool Reliability,” paper IADC/SPE 151736, presented at the IADC/SPE Drilling Conference, San Diego, California, March 6–8, 2012.

11. Melgares H, Grace W, Gonzalez F, Alric C, Palacio J and Akinniranye G: “Remote Automated Directional Drilling Through Rotary Steerable Systems,” paper SPE/IADC

119761, presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, March 17–19, 2009.

12. Equivalent circulating density, or ECD, is the effective density exerted by a circulating fluid against the formation. The ECD is calculated as: ECD = d + P/ (0.052*D), where d is the mud weight in pounds per gallon (lbm/galUS). P is the pressure drop in the annulus between depth D and surface (psi), and D is the true vertical depth (ft).

24 Oilfield Review

controlled timed variation in mud flow; the driller manipulates the mud pumps to change tool settings. By allowing the steering command to be sent directly to the mud pump controller via a digital signal, directional drillers are able to control the well trajectory remotely.

Many rotary steerable systems today are equipped with a degree of autonomy. For example,

hold inclination and azimuth commands, sent from the surface to the PowerDrive RSS, compel the BHA to maintain a constant course without further intervention from the surface. The PowerV vertical drilling system maintains a vertical tra-jectory, without human intervention, by sensing forces acting on the BHA that may cause it to devi-ate and then steering back to vertical.

Such a remote automated steering operation was performed in the 121/4-in. section of the Jacinto 1002 well located about 150 km [93 mi] from Villahermosa in southern Mexico. The only offset well, the Jacinto 1001, encountered very hard sands that caused low ROP. The formation in this section consists of intercalated zones with unconfined compressive strengths ranging from 41 to 83 MPa [6,000 to 12,000 psi], which cause high BHA vibrations and abnormal bit wear.

To address these challenges, drilling engi-neers used a directional drilling system that com-bined RSS tools with a mud motor power section. This system, which delivers more energy to the bit, mechanically decouples the bit from the drill-string, thus dampening vibrations above the motor because the drillstring rotates at a lower rpm than the bit and RSS. Engineers sent 21 automated downlinks to the RSS tool from a remotely located control center to build the curve, keeping the well tangent to the next casing point and drilling the 121/4-in. section with a sin-gle bit (above left).13

Schlumberger engineers are developing an automated trajectory control system that receives real-time survey data to characterize the steering behavior of a BHA. The system uses that real-time downhole information to create more-accurate projections and determine the appropriate steer-ing command to keep the drilling tool along the planned trajectory. Currently, the system is used in an advisory capacity, but an updated version in field tests will be able to act autonomously, issu-ing downlink commands to the tool to make it a fully automated trajectory control system.14

Changing or unexpected formation character-istics may cause bit or BHA dysfunction, requiring continuous adjustments to the WOB and rpm in response. Using surface measurements, an engi-neer may have difficulty recognizing a change or its cause at the time it is encountered. Usually, there is a significant time lag between the time an event occurs and when the driller recognizes it and takes the proper corrective action. Given the lag and the many factors influencing surface read-outs, it is not surprising when a driller makes an incorrect decision—one that is at best ineffectual and at worst detrimental.

A new automation array has the potential to overcome this shortcoming. The array consists of two elements: newly developed downhole sensors capable of high-frequency sampling and wired drillpipe capable of transmitting the resulting high volumes of data to the surface. By interpret-ing large volumes of data quickly, these auto-mated systems alert drillers in real time to

> Downlinking enhancement. Engineers used automated downlinking on the Jacinto 1002 well (blue) to drill a 121/4-in. section in 172 fewer hours than were required for the same section in the offset Jacinto 1001 well (red). The Jacinto 1002 required only one bit on a mud motor and RSS-equipped BHA compared with the need for four bits in the Jacinto 1001 well drilled using an RSS controlled conventionally by the directional driller. (Adapted from Melgares et al, reference 11).

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>Well construction fluids domain. Fluids whose characteristics must be maintained at critical levels during the drilling process are present in various environments. An automated drilling measurement system must be able to assess the condition of the fluids going into and out of the well and take necessary corrective actions to condition the fluids between each critical stage (arrows). (Adapted from Geehan et al, reference 16.)

Solids control Fluids treatment and pumping

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Summer 2012 25

threatening BHA phenomena such as stick-slip, whirl, axial shock and bit bounce.15

Wired drillpipe makes it possible to gather annular pressure and temperature measure-ments along the drillstring, which allows opera-tors to monitor the entire wellbore. Algorithms quickly condense these data and convert them into flags and control signals for the automation

system (above). Other algorithms sort the data, recognize an event and bypass the driller to initi-ate proper corrective actions if necessary.

Automatic Fluids MeasurementsOne of the most important factors influencing the success of drilling operations is the operator’s ability to maintain drilling fluids properties within

a prescribed range of values. Automation of the well construction fluids (WCF) domain addresses four major systems. In addition to the fluids, the WCF domain also encompasses flow conduits, tanks and process equipment. These four systems in turn fall into four areas: fluids treatment and pumping, downhole, solids control and waste management (previous page, bottom).16

13. Melgares et al, reference 11.14. Pirovolou D, Chapman CD, Chau M, Arismendi H,

Ahorukomeye M and Penaranda J: “Drilling Automation: An Automatic Trajectory Control System,” paper SPE 143899, presented at the SPE Digital Energy Conference and Exhibition, The Woodlands, Texas, USA, April 19–21, 2011.

> Automated drilling mechanics. High-frequency downhole measurements taken by a downhole sensor placed in the BHA can be processed to detect a drillstring state. This diagnostic information is sent uphole in real time and processed by an automated surface system that makes the appropriate modifications to the drilling parameters or to the procedures on surface. In this case, high levels of axial acceleration (top left) indicate the presence of bit bounce (top right), which can reduce drilling efficiency and potentially damage the bit cutting structure or components within the BHA. A spectral plot (center) identifies BHA and drillstring resonant frequencies and illustrates the energy present within the axial vibrations as a function of frequency. Red corresponds to high energy generated by vibrations while green indicates low energy has been generated. The higher the energy, the more damaging the vibrations are likely to be. The three intervals (bottom) correspond to different levels of risk. High-risk bit bounce (left) triggers a red light alarm on the surface. Normal drilling conditions, or low-risk drilling conditions (center), display as a green light on the surface to indicate it is safe to drill ahead. The presence of moderate risk of bit bounce presents a cautionary yellow light (right) to the driller.

4

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15. For more on these drilling phenomena: 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.

16. Geehan T and Zamora M: “Automation of Well-Construction Fluids Domain,” paper IADC/SPE 128903, presented at the IADC/SPE Drilling Conference and Exhibition, New Orleans, February 2–4, 2010.

26 Oilfield Review

The emergence of managed pressure drilling (MPD), in which engineers use a choke to regu-late backpressure on the well to preserve a con-stant bottomhole pressure (BHP), has been instrumental in the drive to automate the WCF domain.17 The set point for the choke is deter-mined using a hydraulic model. The hydraulic model is built and updated continuously during drilling operations using rig-supplied data such as flow rate, bit depth, rpm, torque and mud density, temperature and rheological parameters. Because fluids parameters are measured manually and because there is often a time lag between when a sample is collected and analyzed and when it is input into the model, the measurements may rep-resent a source of error in the model.18

Recently, two Norwegian operators asked M-I SWACO, a Schlumberger company, to develop automated drilling fluid sensors. In response, a team of M-I SWACO engineers, working with reg-ulators and supported by the operators, devel-oped several sensors, most of which were custom developed or adapted from other industries. Engineers for this fluids measurement automa-tion project began by determining that while most fluids measurement tasks could be executed

remotely, fluid analysis must be performed on site and monitored remotely. Engineers identi-fied existing sensors that allow fluids measure-ments to be accomplished remotely and determined which additional sensors required development.

Traditionally, engineers determine particle size distribution (PSD) using a series of sieves. Recently developed techniques rely instead on image analysis and require sample dilution in opaque fluids. One such technique uses an auto-mated FBRM focused beam reflectance measure-ment instrument. The sensor is installed directly in a 5-cm [2-in.] flow loop leading from the active flow pit or the flowline where it measures the PSD of the fluids entering the well or exiting the annulus at one-second intervals (above).19

Engineers designed an automated elemental analysis and solids content instrument to replace conventional retorting procedures and manual chemical titrations. The new analysis tool uses a 500-eV source and a sensor that can be moved along three axes and is capable of monitoring any element with an atomic weight greater than that of magnesium. It can also measure high- and low-gravity solids content. Analysis may be displayed in

existing graphical interfaces as concentrations of the various additives used in the fluid formulation.

To create an automated rheometer, the team focused on exploiting existing software and expanding instrument temperature range capa-bilities. To do so, they based the rheometer design on the Couette bob and sleeve API speci-fied layout and the 10-second and 10-minute gel strength measurements.20 The primary change to the standard equipment was an electronic load cell to replace the spring attached to the bob that measured torque. The load cell is designed to improve accuracy by reducing the effects of tem-perature on measurements.

The data from the automated rheometer are exported directly to software that updates flow and pressure simulations for comparison with real-time downhole data reported from the rig. The software also prepares and reports test data directly in wellsite information transfer standard markup language (WITSML) to be displayed on graphical user interfaces (GUIs).

An automated electrical stability (AES) instrument was built and designed for the project to change the high-frequency electrical stability test from a single-point to a trend analysis. Trends may then be displayed beside other measure-ments such as oil/water ratios and viscosity. Each test sequence includes seven measurements; the software excludes the extremes and the remain-ing five are averaged, recorded and displayed as a trend on a GUI. The AES meter includes real-time capacitance measurements of oil-base drilling flu-ids and is installed directly on the rig flowline. Engineers are thus able to identify instantaneous trends in water content variation.

17. For more on MPD: Elliott D, Montilva J, Francis P, Reitsma D, Shelton J and Roes V: “Managed Pressure Drilling Erases the Lines,” Oilfield Review 23, no. 1 (Spring 2011): 14–23.

18. Stock T, Ronaes E, Fossdal T and Bjerkaas J: “The Development and Successful Application of an Automated Real-Time Drilling Fluids Measurement System,” paper SPE 150439, presented at the SPE Intelligent Energy International, Utrecht, The Netherlands, March 27–29, 2012.

19. Stock et al, reference 18.20. Mud shear stress is measured after a mud has set

quiescently for a period of time. The times called for by the American Petroleum Institute procedure are for 10 seconds and 10 minutes, although measurements after 30 minutes or 16 hours may also be made.

21. Stock et al, reference 18.22. Sadlier A, Laing M and Shields J: “Data Aggregation and

Drilling Automation: Connecting the Interoperability Bridge between Acquisition, Monitoring, Evaluation, and Control,” paper IADC/SPE 151412, presented at the IADC/SPE Drilling Conference and Exhibition, San Diego, California, March 6–8, 2012.

23. Sadlier A and Laing M: “Interoperability: An Enabler for Drilling Automation and a Driver for Innovation,” paper SPE/IADC 140114, presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, March 1–3, 2011.

> Determining particle size distribution with FBRM focused beam reflectance measurement. During the drilling of a 121/4-in. section, engineers grouped particles by size to reflect materials added for formation strengthening. To test FBRM sensors, engineers equipped shakers with weak screens that were intended to fail quickly. When the first screen failed, at about 3:30 a.m., rig personnel observed a sharp increase in the concentration of coarse-size particles ranging from 185 to 1,002 μm (black, brown and blue). The installation of a new screen one hour later was followed by a decrease in the concentration of those coarse particles until that screen failed at about 10 a.m. The finer particles of 19 to 63 μm and 54 to 100 μm (green and red, respectively) showed steady increase in concentration over the entire period. (Adapted from Stock et al, reference 18.)

HighPa

rticl

e co

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370 to 632 μm

185 to 317 μm

542 to 1,002 μm 54 to 100 μm

19 to 63 μm

Summer 2012 27

Density measurements using dual real-time sensors present analytical trends and represent a significant change from standard API measure-ment techniques that use a conventional industry balance. Unlike the balance method, the new density sensor provides real-time updates of static and dynamic downhole pressures cor-rected for temperature variations.

Because the vibrating tube densitometer commonly used today is able to transfer temper-ature and density data from the sensors directly into the simulation software, engineers at M-I SWACO incorporated the densitometer into the project. As a consequence, data may be used in simulation software and shown on GUI displays located on rigs and in remote opera-tions centers.21

Interoperability: The Bridge to AutomationAs sensor and software capability expands and is further enabled by increased network capacity, the type and number of well construction tasks being moved from human control to machines continue to increase. New automation algorithms have provided substantial gains in reliability and tool performance, and operators wishing to take advantage of these algorithms will inevitably move the industry toward drilling automation. As part of that process, operators will also drive the creation of standards to facilitate deployment of these algorithms.

A fully automated drilling process depends ultimately on the ability of all the components to share information. This requires that many parts and processes sift, select and act upon an enor-mous amount of data autonomously and synchro-nously. LWD and mud logging illustrate why a data aggregator system that gathers and coordi-nates various data sources must be developed before true drilling automation will be possible. In most cases, LWD tools transmit their data to the surface via mud pulse, which must be then translated into usable data. This means the data are not available to the user in real time but in near real time. Similarly, drill cuttings used as a data source by mud logging systems are not avail-able until they are circulated to the surface, cap-tured and analyzed, which may be a matter of hours after they are created.22

To efficiently use these data to automatically and appropriately respond to the drilling situa-tion requires systemwide interoperability—the linking of people, tools, equipment and informa-tion at the right time and in the context of the drilling operation (above). Complete interopera-bility is fundamental to automation. Limited interoperability results in islands of automation that must be pulled together by humans to assure proper system interaction. Alternatively, custom solutions incorporated onto a select number of rigs are costly and also require human interven-tion. Rig contractors may offer a fast path to interoperability by providing remote control sys-tems, but this approach may also be hampered by

systems that are configured for specific rigs, con-tractors or rig types.

Improvements in the movement of and access to real-time data are also needed. Engineers are now working to apply to the drilling industry a uni-fied architecture standard, which offers a unified data access technology stack that combines the lessons learned in process control with the auto-mation used in aircraft, automobile, space and other industries. Engineers working on drilling automation are particularly interested in how these industries use existing standards, security configurations and certifications and real-time interoperability technologies to address redun-dancy and reliability. Of special interest for auto-mated drilling scenarios is how other industries have addressed the concepts of situational aware-ness, human interaction and planning and system contingencies in the face of unexpected events.

Drilling contractors, service companies, equipment manufacturers and operators use vari-ous standards for data portability. WITSML is used most commonly in the oil industry to standardize the interfaces between various well monitoring and control technologies and software programs.23 A new standard or extension of an existing stan-dard such as WITSML to describe rig and surface equipment is also needed but will require the combined efforts of operators, service companies, rig contractors and equipment suppliers.

For automation to occur on a wide scale, rig control standards must be applied industrywide. In addition to providing uniformity across all automated drilling units, contractor compliance with these standards will afford service providers a reliable platform upon which to integrate their solutions. Such a platform must allow a generic view of the rig from a programmatic standpoint. Once that is accomplished, conversion to specific rig platforms and specific rig contractor proto-cols will be necessary, requiring significant cus-tom coding and rig time to assure each application is correct. Though early adopters of automation will pay for its development internally, they will reap the financial benefits of automation early, and standardization will help reduce overall costs and engineering time. —RvF

> Information for action. Inputs required by a drilling automation system are at once related and distinct, making it difficult to consider which should be a priority. (Adapted from Sadlier et al, reference 22.)

Drilling pressureRheologyHole cleaning

Hydraulic

DrillingAutomation

Formation pressureWellbore qualityFormation evaluation

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ControlSurface measurementsDownhole measurementsMaintenance

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Reduction ofnonproductive timeInvisible lost timemanagementData analyticsDownhole dynamics

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28 Oilfield Review

Seismic Detection of Subtle Faultsand Fractures

For decades, operators have relied on seismic images for illuminating the geometry

and location of major faults and folds to target their wells. Now, advances in process-

ing and visualization techniques are helping reveal information about the patterns of

small-scale faulting and fracturing that were beyond the detection capabilities of

previous techniques. Operators are using this new knowledge to drill and manage

their reservoirs with greater certainty.

Victor AarreDonatella AstrattiStavanger, Norway

Taha Nasser Ali Al DayyniSabry Lotfy MahmoudAbu Dhabi Company for Onshore Oil OperationsAbu Dhabi, UAE

Andrew B.S. ClarkPetroleum Development OmanMuscat, Sultanate of Oman

Michael J. StellasJack W. StringerSpectra Energy CorporationHouston, Texas, USA

Brian ToelleDenver, Colorado, USA

Ole V. VejbækGillian WhiteHess CorporationCopenhagen, Denmark

Oilfield Review Summer 2012: 24, no. 2. Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Art Bonett and Ismail Haggag, Abu Dhabi, UAE.FMI and PowerV are marks of Schlumberger.

Over the last decade, oil and gas companies have had increased success placing wells within pro-ductive zones—sweet spots—of fractured reser-voirs. These fracture zones often display subtle expressions in seismic data, but recent advances in seismic attributes and visualization tech-niques are helping geophysicists identify and characterize them. By combining these geophysi-cal results with geologic and engineering data, companies are reducing risk and increasing their drilling and production successes.

Optimal well placement requires the operator to factor the predominant trend of natural frac-tures into the selection of wellbore orientation. Production may be enhanced by intersecting mul-tiple fractures. Fractures may also redirect the path of injected fluids, thus limiting the fluids’ effi-cacy in contacting, sweeping and displacing hydro-carbons. In this case, production benefits must be balanced by offsetting inefficiencies caused by fracture systems. An operator’s objective is, there-fore, to maximize production from fractured reser-voirs while limiting the deleterious effects of those very same fractures.

Fractures tend to be aligned along preferred directions, or azimuths, and often cross strati-graphic layers. Fractures occur at many scales but most are smaller than the seismic wave-lengths typically used for surveys, and thus they are not visible in standard seismic displays. Although seismic methods may not be able to detect individual fractures, the measurable seis-mic response from the aggregate fracture system may indicate their presence. As an analogy, the human eye cannot see a single droplet of water from a kilometer away, but can see a collection of water droplets—a cloud—in the sky. The same applies to seismic methods and fractures. Accordingly, some of the most successful seismic fracture detection techniques rely on specialized processing designed to highlight seismic attri-butes that reveal faults and fracture systems.1

Historically, certain seismic methods have proved successful in detecting naturally frac-tured reservoirs. Such methods include the anal-ysis of shear-wave (S-wave) data, vertical seismic profiling, compressional- and shear-wave (P- and S-wave) anisotropy and waveform scattering.2

1. Seismic attributes are measurements, characteristics or properties derived from seismic data. Attributes can be measured at one instant in time or over a time window and may be measured on a single trace, a set of traces, a surface or a volume extracted from seismic data. Their calculation is useful because they help to extract patterns, relationships or features that may not be apparent otherwise. The derivation or calculation of seismic attributes usually involves data processing such as windowing, smoothing, averaging, filtering, calculating statistical measures, finding maxima and minima, performing differentiation and integration, analyzing polarity changes or conducting spectral or wavelet analysis.

2. A shear wave (S-wave) is an elastic wave that travels through a medium and vibrates perpendicular to its direction of travel. For more on shear waves: Caldwell J, Christie P, Engelmark F, McHugo S, Özdemir H,

Kristiansen P and MacLeod M: “Shear Waves Shine Brightly,” Oilfield Review 11, no. 1 (Spring 1999): 2–15.

Vertical seismic profiles (VSPs) include a variety of borehole seismic surveys. However, the defining VSP survey refers to measurements in a vertical well using a seismic source on the surface near the well transmitting to receivers distributed inside the well. For more on VSPs: Christie P, Dodds K, Ireson D, Johnston L, Rutherford J, Schaffner J and Smith N: “Borehole Seismic Data Sharpen the Reservoir Image,” Oilfield Review 7, no. 4 (Winter 1995): 18–31.

Seismic waveform scattering refers to the changing propagation direction of seismic waves resulting from heterogeneity and anisotropy of the medium. For more on waveform scattering: Revenaugh J: “Geologic Applications of Seismic Scattering,” Annual Review of Earth and Planetary Sciences 27 (May 1999): 55–73.

Summer 2012 2929Summer 2012

30 Oilfield Review

Studies have also indicated that spectral decom-position, typically used in stratigraphic analysis, may be used to locate subtle structural features that control the distribution of fractures within a reservoir.3

To identify the stratigraphic and structural fab-ric, texture or grain within the reservoir, state-of-the-art seismic methods focus on determining how seismic properties and attributes vary direction-ally. Such reservoir fabric affects the directional—anisotropic—properties of seismic signals.4 Seismic methods include techniques that scruti-nize the seismic signal for subtle variations in fre-quency and amplitude response with azimuth and dip. The orientation or grain of fibers in a piece of wood is analogous. Woodworkers use the wood grain to maximize strength, minimize splintering and enhance the beauty of the finished product.

With the exception of large-scale faults that the seismic interpreter can pick by hand, most structural lineaments are ignored as being too small and too numerous to be interpreted manu-ally. Moreover, it is not straightforward to account for the effects of these small features in reservoir models. Advanced seismic imaging and process-ing techniques and workflows have been devel-oped to assist geoscientists in this challenging interpretation task.

This article describes reservoir studies that incorporate seismic methods for characteriz-ing fracture systems. Case studies demonstrate how these methods inform operators as they make well placement and reservoir manage-ment decisions. An example from Pennsylvania, USA, describes the optimal placement of wells for an underground gas storage reservoir that has shear zones that control fracture orienta-tion and distribution. In a North Sea fractured chalk reservoir, advanced seismic attribute

analysis reveals details of a complex fault sys-tem. In a UAE giant carbonate field, fracture network modeling helps represent fractures that are too numerous to be picked by hand but are known to affect the movement and sweep of injected fluid.

Natural Fractures and Their DetectionRocks respond to stress in predictable ways, form-ing fractures, joints and faults (left).5 Fractures are rock failure planes that result from stress. Rocks experience stress during folding, faulting, burial, uplift, erosion and metamorphism. Additionally, in shale formations, endogenous fractures can form through dewatering and devolatilization during thermal maturation of hydrocarbons.

The stress field that formed these features may change significantly after their formation. Consequently, the structural configuration of faults and fractures indicates the paleostress condition that existed at the time of their for-mation but may not correspond to the current stress field.

Natural fractures are ubiquitous and occur in many forms: open, closed, healed or partially healed. They occur at all scales, from those asso-ciated with tectonic faults hundreds of kilome-ters long to cracks on the micrometer scale.

However, the importance of natural fractures in the subsurface has not been fully appreciated until recently. Historically, oil and gas wells have primarily been drilled vertically. Stress condi-tions in the subsurface often cause open natural fractures—the ones of interest for production—

> Principal stresses and the creation of fractures. The three principal compressive stresses—the maximum stress, σ1, the minimum stress, σ3, and the intermediate stress, σ2—may give rise to several types of fractures and dictate fracture movement (black arrows). The colored arrows are compressive stress directions and their size indicates relative magnitude.

σ1

σ1

σ3 σ3

σ2

Joint, ortension fracture

Conjugate faults,or shear fractures

3. Neves FA, Zahrani MS and Bremkamp SW: “Detection of Potential Fractures and Small Faults Using Seismic Attributes,” The Leading Edge 23, no. 9 (September 2004): 903–906.

4. Anisotropy is the variation of a physical property, such as P- or S-wave velocity, with the direction of its measurement. For a discussion of elastic anisotropy: Armstrong P, Ireson D, Chmela B, Dodds K, Esmeroy C, Miller D, Hornby B, Sayers C, Schoenberg M, Leaney S and Lynn H: “The Promise of Elastic Anisotropy,” Oilfield Review 6, no. 4 (October 1994): 36–47.

5. A fracture is any break in rock regardless of origin. A joint, or Mode I fracture, is a fracture formed by opening displacement, normal to the fracture plane, under tensile stress conditions. A fault is a fracture formed by shearing displacement, in the plane of the fracture, under shear stress conditions. Faults form under sliding (Mode II) or tearing (Mode III) conditions depending on whether the shear stress acts perpendicular or parallel to the fracture front.

Pollard DD and Aydin A: “Progress in Understanding Jointing over the Past Century,” Geological Society of America Bulletin 100, no. 8 (August 1988): 1181–1204.

Aydin A: “Fractures, Faults, and Hydrocarbon Entrapment, Migration and Flow,” Marine and Petroleum Geology 17, no. 7 (August 2000): 797–814.

6. Within the Earth, open natural fracture planes are parallel to the principal stress plane that contains the maximum and intermediate principal compressive stresses. This plane tends to be vertical because the vertical stress is often one of these principal stresses.

7. Fingered flow is the instability that arises at the interface between two immiscible fluids when one invades the other. The result of differences in fluid viscosity and mobility, fingered flow may occur during waterflooding when water infiltrates oil or during air sparging when air bubbles through water.

8. For more on fractured reservoirs: Bratton T, Canh DV, Que NV, Duc NV, Gillespie P, Hunt D, Li B, Marcinew R, Ray S, Montaron B, Nelson R, Schoderbek D and Sonneland L: “The Nature of Naturally Fractured Reservoirs,” Oilfield Review 18, no. 2 (Summer 2006): 4–23.

9. Dershowitz WS and Herda HH: “Interpretation of Fracture Spacing and Intensity,” in Tillerson JR and Wawersik WR (eds): Proceedings of the 33rd U.S. Symposium on Rock Mechanics. Rotterdam, The Netherlands: AA Balkema Publishers (1992): 757–766.

Crosta G: “Evaluating Rock Mass Geometry from Photographic Images,” Rock Mechanics and Rock Engineering 30, no. 1 (January 1997): 35–58.

10. Florez-Niño J-M, Aydin A, Mavko G, Antonellini M and Ayaviri A: “Fault and Fracture Systems in a Fold and Thrust Belt: An Example from Bolivia,” AAPG Bulletin 89, no. 4 (April 2005): 471–493.

11. Zahm CK and Hennings PH: “Complex Fracture Development Related to Stratigraphic Architecture: Challenges for Structural Deformation Prediction, Tensleep Sandstone at the Alcova Anticline, Wyoming,” AAPG Bulletin 93, no. 11 (November 2009): 1427–1446.

12. For more on seismic attributes: Chopra S and Marfurt KJ: “Seismic Attributes—A Historical Perspective,” Geophysics 70, no. 5 (September– October 2005): 3SO–28SO.

Chopra S and Marfurt KJ: “Emerging and Future Trends in Seismic Attributes,” The Leading Edge 27, no. 3 (March 2008): 298–318.

Chopra S and Marfurt K: “Gleaning Meaningful Information from Seismic Attributes,” First Break 26, no. 9 (September 2008): 43–53.

13. For more on elastic anisotropy: Armstrong et al, reference 4. Hardage B: “Measuring Fractures—Quality and

Quantity,” AAPG Explorer 32, no. 7 (July 2011): 26–27. Hardage B: “For Fractures, P + S = Maximum Efficiency,”

AAPG Explorer 32, no. 8 (August 2011): 32.14. For more on azimuthal seismic anisotropy analysis:

Barkved O, Bartman B, Compani B, Gaiser J, Van Dok R, Johns T, Kristiansen P, Probert T and Thompson M: “The Many Facets of Multicomponent Seismic Data,” Oilfield Review 16, no. 2 (Summer 2004): 42–56.

Grimm RE, Lynn HB, Bates CR, Phillips DR, Simon KM and Beckham WE: “Detection and Analysis of Naturally Fractured Gas Reservoirs: Multiazimuth Seismic Surveys in the Wind River Basin, Wyoming,” Geophysics 64, no. 4 (July–August 1999): 1277–1292.

Lynn HB, Campagna D, Simon KM and Beckham WE: “Relationship of P-Wave Seismic Attributes, Azimuthal Anisotropy, and Commercial Gas Pay in 3-D P-Wave Multiazimuth Data, Rulison Field, Piceance Basin, Colorado,” Geophysics 64, no. 4 (July–August 1999): 1293–1311.

Summer 2012 31

to be vertically oriented.6 Vertical wells rarely intersect these vertical fractures. However, in some types of reservoirs, such as tight sandstone and carbonate layers, shale gas, oil shale and coalbed methane plays, fracture systems provide the only permeability in the formation; achieving commercial production rates requires that the wellbore traverse fractures. Drilling wells to con-nect as many fractures as possible has become a principal objective, but the task must be per-formed carefully. Fractures are able to dominate permeability both positively and negatively. On the one hand, they provide the essential permea-bility to give tight reservoirs improved productiv-ity and recovery efficiency. On the other hand, fractures may harm productive reservoirs by cre-ating thief zones, and in enhanced oil recovery efforts, they may cause early breakthrough and reservoir flow instabilities—fingered flow.7

For both exploration and production of a hydrocarbon reservoir, operators need to charac-terize natural fracture systems to identify the best opportunities for placing wells and planning horizontal well trajectories. To characterize frac-tures, scientists require information about frac-ture orientation, aperture, porosity, permeability, density, size, location, stress anisotropy and

direction and fluid content.8 Orientation is quan-tified by the strike and dip of a fracture surface. Aperture, the perpendicular width of an open fracture, is a key parameter for determining frac-ture porosity and permeability, but its measure-ment is complicated by factors such as fracture wall roughness, infill by minerals and gouge, and continuity along fracture planes.

Density, or intensity, of fracturing is quanti-fied by measuring the number, length, width, area and volume of fractures in a prescribed length, area or volume of rock.9 Fracture density and size are influenced by lithology, rock proper-ties, bed thickness and the compressive or ten-sile strain imposed during tectonic deformation.10 In a tectonic setting, the distribution of fracture density and dimension ranges from many small fractures confined to individual beds, to fewer intermediate-scale fractures that cut across a few beds and sometimes to a few kilometer-scale tectonic faults that deform entire stratigraphic sequences (above left).11

The scale, displacement and aperture of most fractures are too small to be detected by surface seismic techniques alone. To delineate fractures and quantify their properties, geophysicists use attributes of seismic data derived from the elas-tic and geometric properties of fractured rocks.12

Attribute analyses take advantage of the volume averaged response from the fracture system to obtain quantitative and qualitative estimates of seismic properties within the reservoir rock vol-ume (above right).

Aligned natural fractures in a formation cause elastic anisotropy—the variation of elastic wave properties with direction—that, if present, may be observed in properly acquired and pro-cessed seismic data.13 Seismic attributes that vary with azimuth include velocity, reflection amplitude and S-wave birefringence, or splitting. Azimuthal variations of these properties are deduced from analysis of 3D surface and bore-hole seismic data and surveys that have been acquired in multiple azimuths.14

> Folds, faults and fractures along an anticline. In folded rocks, faults and fractures may be oriented parallel or perpendicular to the fold axis. Fractures form in response to stress; joints form by means of tensile stresses, and faults form by means of shear stresses. Further deformation causes fractures to extend and may change the direction of motion along fracture planes. Faults and fractures may be stratabound and confined to a single layer or become throughgoing—crossing all sedimentary sequences and spanning many formations. Their connectivity ranges from isolated individual fractures to widely spaced fracture swarms or corridors to fully interconnected fracture networks. Drilling horizontal wells parallel to the fold axis should ensure the greatest chance of intersecting fractures. (Adapted from Florez-Niño et al, reference 10.)

JointIntermediate faultsFold axis

Sheared joints,incipient faults

Throughgoingfault zones

> Computing attributes on a time surface in a 3D seismic volume. Geophysicists analyze the character of each seismic trace at a selected time slice surface (top, red) and assign a value. For example, each trace’s amplitude is mapped onto an amplitude attribute surface (middle). Higher amplitudes near the center of the 3D seismic volume plot as higher values in the center of the 2D amplitude time slice. Other attribute surfaces, such as frequency, are computed in the same way (bottom).

Seismic Data Cube

Amplitude Attribute

Frequency Attribute

Tim

e

Time slicex y

xy

xy

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32 Oilfield Review

In the case of velocity anisotropy caused by oriented natural fractures alone, P- and S-wave velocities are at their maximum in the direction parallel to the fractures and at their minimum in the direction perpendicular to the fracture trend. As the present-day stresses may not coincide with the paleostresses active at the time of frac-ture formation, this velocity anisotropy may be modified by the present-day maximum compres-sive stress, preferentially closing fractures per-pendicular to it and opening fractures parallel to it. The resultant velocity anisotropy is the super-position of the anisotropies caused by preexisting fractures and the present-day in situ stress field.

Rocks that contain natural fracture systems have been stressed and strained—compressed, elongated, bent and broken—which deforms their original shapes. The seismic attributes of variance, coherence, curvature and distance to flexures, folds and faults are all useful indicators of strain. Variance and coherence have a recipro-cal relationship; variance measures the differ-ences between seismic traces and coherence measures the similarities. Variance emphasizes the unpredictability of seismic horizons—their

edges and interruptions—while coherence emphasizes their predictability: their connected-ness and continuity.15 High variance and low coherence may indicate faults or fracture zones, clusters or swarms. Geologists use similar char-acteristics of seismic horizons for interpreting faults or fractures when analyzing a seismic data-set; via the graphical data display, geologists fol-low along a seismic horizon or surface until it ends, breaks or becomes displaced up, down or sideways to a different location.

The curvature attribute at points on a horizon can be a measure of structural strain.16 Areas in which curvature is high or tight may have been subjected to high strain to transform them into areas of flexure, folding, faulting or high fracture intensity. The attribute of distance to flexure, folding and faulting is a geometric strain indica-tor; fracture intensity is expected to increase with proximity to these structural elements.

Coherence and curvature provide comple-mentary structural information. Folded hori-zons are expected to display curvature but no disruption in coherence; conversely, faulted

horizons do show breaks in coherence. But this is not always the case. For example, if fault movement has been small relative to the seis-mic wavelength, the faulted horizon may appear to have high coherence.

Another sensitive attribute is derived from analysis of the frequency content of seismic sig-nals: Spectral decomposition, or time-to-fre-quency analysis, is a method for separating seismic signals into their frequency compo-nents.17 The spectral content of recorded seismic data depends on cumulative effects of the seis-mic properties and interfaces of rock strata encountered by the propagating signals. By iso-lating certain frequencies, interpreters may be able to extract subtle features. For example, higher frequency components contain informa-tion about shorter wavelength structural features hidden within a dominantly long wavelength sig-nal of the full-frequency seismic data. Scientists apply spectral decomposition for image enhance-ment—improving resolution, balancing fre-quency content or suppressing noise. They also use it for reservoir characterization—evaluating sequence stratigraphy and depositional features,

> Steckman Ridge gas storage field. The Appalachian Valley and Ridge Province arcs from south-central Pennsylvania to the northeast (black outline). Many NW–SE structural lineaments cut across the Appalachian axis (red dashed lines), some of which are unnamed. The western boundary of Bedford County (pink) approximately separates the smoother topography of the Allegheny Plateau to the west from the more rugged Appalachian Valley and Ridge topography to the east. [Topographic surface map adapted from the US National Oceanic and Atmospheric Administration National Geophysical Data Center, http://www.ngdc.noaa.gov/cgi-bin/mgg/topo/state2.pl?region=pa.jpg (accessed June 6, 2012).]

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estimating stratigraphic thickness and determin-ing fracture properties and fluid content. Spectral decomposition is a powerful tool for illu-minating subtle features such as shear faults that control the geometry of the fracture system but that are below the resolution of the full-frequency surface seismic data, as demonstrated in an Appalachian basin gas storage facility.

Intersecting Fractures with Horizontal WellsThe Steckman Ridge field is a joint venture between New Jersey Resources (NJR) Steckman Ridge Storage Company and Spectra Energy Corporation, together known as the partnership. The facility is operated by Spectra Energy as a mul-ticycle underground gas storage (UGS) facility, regulated by the US Federal Energy Regulatory Commission (FERC). The field is in the Valley and Ridge Province of the Appalachian basin in Bedford County, Pennsylvania, USA (previous page). The reservoir is in the Devonian-age Oriskany Formation, which at reservoir depths is a fractured quartzite. It is a Type 1 fractured reser-voir, in which fractures provide the primary poros-ity and permeability.18

Steckman Ridge LP acquired the depleted gas field in 2004; the field had yielded 12.5 Bcf [354 million m3] of gas cumulatively from five vertical wells. Production from the individual wells varied considerably, leading the partner-ship experts to suspect that a fracture network, rather than matrix properties, was controlling porosity and permeability. The company received approval from FERC in 2008 to convert the field to a gas storage facility, with an operating capac-ity of 17.7 Bcf [501 million m3], comprising 12 Bcf [340 million m3] of working gas and 5.7 Bcf [161 million m3] of cushion gas, with a maximum delivery rate capability of 300 MMcf/d [8.5 mil-lion m3/d] and maximum injection rate of 227 MMcf/d [6.43 million m3/d].19 The original plan called for converting the five existing production

wells to storage wells and drilling a substantial number of new vertical storage wells. Each well was designed for a 50- to 70-year life span.

Steckman Ridge field contains three anticli-nal structures that formed along the leading edge

of thrust faults (below).20 The original operator, Pennsylvania General Energy Company (PGE), had acquired 3D surface seismic data and FMI fullbore formation microimager logs in two of the production wells. To prepare for conversion to

15. Bahorich M and Farmer S: “3-D Seismic Discontinuity for Faults and Stratigraphic Features: The Coherence Cube,” The Leading Edge 14, no. 10 (October 1995): 1053–1058.

Caldwell J, Chowdhury A, van Bemmel P, Engelmark F, Sonneland L and Neidell NS: “Exploring for Stratigraphic Traps,” Oilfield Review 9, no. 4 (Winter 1997): 48–61.

16. Curvature describes how bent a 2D curve or 3D surface is at a point. At a point on a 2D curve, the curvature is the reciprocal of the radius of the largest circle capable of touching the point with tangent contact. The curvature, or the amount of bending, increases as the radius of the circle decreases because of their reciprocal relation. This concept can be extended to 3D surfaces. Many curves may be defined through a point on a surface by cutting the surface with planes through the point.

> Top of the Oriskany Formation at Steckman Ridge. Three anticlines, A, B and C, at the leading edge of thrust faults (red lines) formed primarily during the Allegheny (Permian) orogeny, although earlier Taconic (Ordovician) and Acadian (Devonian) orogenies also affected the basement and the sedimentary cover of the region. Five vertical wells, Clark 1663, Clark 1664, Clark 1665, Stup 1557 and Quarles 1709, depleted the original gas reservoir.

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Common types of 3D curvature are the maximum, minimum, strike and dip curvatures. For more on curvature: Roberts A: “Curvature Attributes and Their Application to 3D Interpreted Horizons,” First Break 19, no. 2 (February 2001): 85–100.

17. Partyka G, Gridley J and Lopez J: “Interpretational Applications of Spectral Decomposition in Reservoir Characterization,” The Leading Edge 18, no. 3 (March 1999): 353–360.

Castagna JP and Sun S: “Comparison of Spectral Decomposition Methods,” First Break 24, no. 3 (March 2006): 75–79.

18. There are four principal fractured reservoir types based on the importance of fractures in providing reservoir porosity and permeability. For a more detailed discussion of fractured reservoir types: Bratton et al, reference 8.

19. “Steckman Ridge LP—Order Issuing Certificates,” US Federal Energy Regulatory Commission, Docket No. CP08-15-000 (June 5, 2008), http://www.ferc.gov/eventcalendar/Files/20080605185040-CP08-15-000.pdf (accessed July 14, 2012).

For more on underground gas storage: Bary A, Crotogino F, Prevedel B, Berger H, Brown K, Frantz J, Sawyer W, Henzell M, Mohmeyer K-U, Ren N-K, Stiles K and Xiong H: “Storing Natural Gas Underground,” Oilfield Review 14, no. 2 (Summer 2002): 2–17.

20. Scanlin MA and Engelder T: “The Basement Versus the No-Basement Hypotheses for Folding Within the Appalachian Plateau Detachment Sheet,” American Journal of Science 303, no. 6 (June 2003): 519–563.

34 Oilfield Review

> Initial seismic attributes. Maps of seismic attributes—reflection amplitude (left), distance to faults (center) and curvature (right)—show the large-scale trends consistent with the NNE strike of the Appalachian fold-and-thrust structures of the Oriskany Formation in the Steckman Ridge field.

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> Exposures of natural fractures in the Steckman Ridge vicinity. Fractures in an Oriskany quartzite quarry (left) in West Virginia, USA, located about 60 mi [100 km] southeast of Steckman Ridge field, occur in two main fracture sets that strike to the northwest. The quarry wall faces northwest and the red and green lines point to fracture planes that strike 330° and 290°, respectively. In a view from the SSE, fractures exposed in a pipeline ditch (right) near Anticline C are oriented at 350°. FMI data (not shown) from the SR17 well on Anticline C showed the same 350°orientation for open fractures.

NW-trending fracture planes that strike 290°

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Summer 2012 35

gas storage operations, the partnership and Schlumberger consulting geophysicists reexam-ined these datasets and conducted field studies.

Initial examination of seismic attributes—reflection amplitude, curvature and distance to faults—revealed large-scale trends consistent with the NNE strike of the thrust-and-fold struc-tures that formed the valley and ridge topography in the region (previous page, top). In contrast, the field studies revealed a NW orientation of fractures in pipeline ditches, outcrops and creek bottom incisions through topographic ridges (previous page, bottom). These observations cor-roborated FMI interpretations of WNW- to NNW-oriented natural fractures and the NW orientation of the present-day maximum horizontal stress deduced from the direction of drilling-induced fractures (right). Further more, regional satellite imagery, gravity and magnetic studies indicated

NW-oriented cross-strike structural discontinui-ties (CSDs) or lineaments (above).21 Results from these studies suggested that natural fractures may be exerting significant control on the poros-ity and permeability in the field as well as on the gross structures of the Steckman Ridge anti-clines. If so, evidence of the NW-oriented fracture system should have been visible in the seismic attributes extracted from the seismic data. Therefore, the 3D seismic data were reexamined using advanced fracture detection analyses to identify and map the more subtle effects of the open fracture systems.

Spectral analysis of the seismic data indicated that the frequency content of the seismic wavelet was fairly consistent, ranging from 25 to 75 Hz at the well locations. However, the shape of the seis-mic wavelet along the top of the Oriskany horizon varied from location to location across the field.22

> Fracture characterization. An FMI tool was used to detect fractures in the Clark 1663 well. These fracture trends were plotted in a rose diagram and helped geoscientists see the predominant NW–SE trend of the fractures. They also showed that most fractures in this well were open or partially open and their directions corresponded to the direction of a set of faults.

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> Cross-strike structural discontinuities (CSDs) on a magnetic anomaly map. Interpretation of a portion of the North American magnetic anomaly map shows northwest to southeast CSDs (dashed red lines) crossing the Appalachian basin. There is a clear break in the magnetic field anomaly in southwest Pennsylvania along the Washington County CSD that is interpreted to be a shear zone related to the NW–SE fractures in the Steckman Ridge field, which is in Bedford County (black outline). [Magnetic anomaly map adapted from the US Geological Survey (Bankey et al, reference 21).]

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21. For more on jointing in the Appalachian basin: Engelder T, Lash GG and Uzcátegui RS: “Joint Sets That Enhance Production from Middle and Upper Devonian Gas Shales of the Appalachian Basin,” AAPG Bulletin 93, no. 7 (July 2009): 857–889.

Bankey V, Cuevas A, Daniels D, Finn CA, Hernandez I, Hill P, Kucks R, Miles W, Pilkington M, Roberts C, Roest W, Rystrom V, Shearer S, Snyder S, Sweeney R, Velez J, Phillips JD and Ravat D: “Digital Data Grids

for the Magnetic Anomaly Map of North America,” Reston, Virginia, USA: US Geological Survey, Open-File Report 02-414, 2002.

22. For a tutorial on seismic wavelets: Henry SG: “Catch the (Seismic) Wavelet,” AAPG Explorer 18, no. 3 (March 1997): 36–38.

Henry SG: “Zero Phase Can Aid Interpretation,” AAPG Explorer 18, no. 4 (April 1997): 66–69.

36 Oilfield Review

This variability did not affect large-scale structural interpretation but would affect stratigraphic inter-pretation and the search for small-scale features.

Scientists performed spectral decomposi-tion on the 3D seismic data volume and exam-ined selected frequency volumes, which revealed subtle structures within the data (left). They extracted the 30-Hz isofrequency volume through spectral decomposition, iso-lated the top of the Oriskany horizon as a vol-ume slab—bounded 12 ms above and below the horizon pick—and then, using time slices, sliced through this 24-ms thick subvolume. They saw clear evidence of NW-trending shear zones cutting across the NNE strike of the anticline axes (next page, top). These shear zones were the only structural features discovered with the same orientation as that of the fracture system observed in both the local outcrops and the FMI data from the nearby Clark 1663 vertical well-bore.23 The scientists determined that these shear zones were the structural features con-trolling the highly permeable fracture system believed to hold the actual storage capacity for the field’s gas.

Schlumberger geoscientists designed a dual-porosity discrete fracture network (DFN) model to help with designing well trajectories, to update with data from the drilling program and to use for production modeling of gas storage and retrieval (next page, bottom). Input for the model included the shear zones and fracture sets mapped from seismic interpretation, frac-ture aperture, fracture fill, dip angle and dip azimuth from FMI images and fracture conduc-tivity from resistivity logs; high electrical con-ductivity spikes on the resistivity logs correlated with more open and, presumably, more hydrauli-cally conductive fractures.24

The data revealed two fracture sets within the field. One fracture set ran west to east in the southern portion of the field, and the other ran NW–SE. Moving north across the field, both frac-ture trends rotated clockwise. Scientists theorize that this rotation is associated with the rotation of the stress field away from the NW-trending shear zones.

> Spectral decomposition. Spectral decomposition of a seismic wavelet (top left), which contains a wide range of frequencies, separates it into many single-frequency traces (top right). The spectral decomposition process proceeds from left to right, and spectral summation—the reverse process of spectral decomposition—proceeds from right to left. In spectral decomposition of a volume of 3D full-frequency seismic data (bottom), bandpass filtering produces volumes that contain data of narrow frequency ranges.

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23. Strike-slip displacement or motion refers to the movement of the other side of the strike-slip fault relative to the reference side—the side on which one is standing, facing the fault. The motion is right lateral when the other side of the fault moves to the right and left lateral when other side moves to the left.

24. For procedures of DFN model development: Souche L, Astratti D, Aarre V, Clerc N, Clark A, Al Dayyni TNA and Mahmoud SL: “A Dual Representation of Multiscale Fracture Network Modelling: Application to a Giant UAE Carbonate Field,” First Break 30, no. 5 (May 2012): 43–52.

Summer 2012 37

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, Isofrequency amplitude of the top of the Oriskany Formation. A seismic time slice map at 746-ms two-way traveltime through the 30-Hz isofrequency volume, after spectral decomposition, is centered on the top of the Oriskany Formation within Anticline A. Amplitude variations highlight right and left lateral strike-slip offsets through the anticline. An example is the NW–SE right lateral offset (dashed red line) cutting the large blue amplitude area. To the southwest, left lateral offsets of the same blue amplitude area parallel the dashed red line. These NW–SE offsets are consistent with NW–SE structural lineaments mapped throughout Pennsylvania. They are interpreted to be cross-strike shear zones that control the gas storage and flow regime of the Steckman Ridge reservoir.

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> Discrete fracture network modeling. A discrete fracture network (DFN) model was constructed for the Oriskany reservoir, which was divided vertically into five zones. The model incorporated results of seismic and log interpre-tations. Results from Zone 5 show, from left to right, the fracture dip, fracture azimuth, matrix porosity and traces of the 27,367 fractures. A fracture trace is a curve formed by the intersection of a fracture crossing a horizon surface. The radial pole plot (bottom right) summarizes the dips and dip directions of the modeled fracture planes, which dip 45° to 90° in the southwest to northeast directions. A pole is a line perpendicular to a fracture plane; a fracture that has a strike azimuth of 135° and dip angle of 75° to the NE plots as a point at direction azimuth 45°—reading clockwise around the plot—and inclination 75°—reading from the center toward the edge—on a pole plot.

38 Oilfield Review

Spectra Energy well planners working for the partnership used this model to design horizontal wells along NE to SW trajectories to maximize interception of the NW- to SE-oriented cross-strike fracture systems (left). Wells SR10 and SR14, the first and second wells drilled into these seismically defined features, were drilled into Anticlines A and C, respectively. Well plan-ners intended to drill 1,000-ft [305-m] horizon-tal sections for both wells. However, the drillers encountered large open fracture systems imme-diately upon entering the reservoir. In the two horizontal sections, after drilling only 130 ft [40 m] and 172 ft [53 m], respectively, drillers lost circulation in the open fracture system, which forced them to suspend operations. Having encountered good zones for gas injec-tion, the operators deemed these wells suitable for gas storage. Both wells were barefoot open-hole completions with casing set 50 ft [15 m] into the top of the reservoir to ensure isolation of the storage unit.

The remaining wells were completed in con-junction with updates to the DFN model; the pro-cess consisted of drilling a well to TD, running an FMI log, updating the DFN model and drilling the next well. For example, fractures interpreted in the FMI log run in Well SR21 were used to update the model before drilling the next well (left). In addition, the drillers used the DFN model for geo-steering all these horizontal wells.

Because of the complicated geologic struc-ture in the field area, steering the wells was a challenge. Engineers obtained sonic and density logs at critical points during drilling to create synthetic seismic traces for correlation with actual seismic traces. They used these prelimi-nary well-to-seismic ties to compare the then-current drilling location with the drilling target that had been planned from the seismic data. This geophysically guided borehole placement methodology helped engineers adjust the well trajectories. Schlumberger engineers executed the well plans using Schlumberger directional drilling tools. The PowerV rotary steerable verti-cal drilling system was used to keep the hole straight to the kickoff point, and directional drill-ers helped steer the wellbore to the intended cas-ing, landing and final lateral TD targets.

The partnership considered this gas storage conversion successful. Through careful analysis, integration and interpretation of geologic, geo-physical and engineering data, the team identi-fied and confirmed the controlling fracture system within the reservoir. The original plan was to drill all new vertical wells to achieve the designed injection and withdrawal capability

> Planning horizontal wells to intersect open fractures. Some studies suggest that vertical wells have only a slight chance of intersecting vertical fractures. At the Steckman Ridge field, engineers planned to drill horizontal wells parallel to the anticline axis and through the cross-axis shear and fracture zones identified from analyses of seismic, geologic and surface mapping data.

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> Controls on fracture density. The horizontal section of Well SR21 (purple line) was drilled parallel to the axis of Anticline B and intersected fractures (brown disks) as interpreted from FMI images. Fracture density increased as the well crossed a shear fault (dashed red line). The blue lines represent NNE-oriented faults mapped during the initial seismic interpretation effort. The contours (black) and colors indicate depth to the top of the Oriskany Formation.

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Summer 2012 39

of 227 and 300 MMcf/d of gas, respectively. The partnership has currently installed com-pressor capacity for injecting 150 MMcf/d [4.2 million m3/d] of gas. To date, the original five vertical production wells have been reentered and recompleted with varying degrees of success, and the partnership has drilled and completed substantially fewer wells than originally planned. The newly drilled wells were highly successful horizontal wells. The well performance indicates rates near the target levels for withdrawal. The partnership is evaluating whether further hori-zontal wells may be required, but the potential to inject and withdraw gas at or near the design rates, with significantly fewer horizontal wells than originally planned, will result in substantial cost savings.

To convert the Steckman Ridge field to an underground gas storage facility, engineers made use of attributes from seismic data to identify subtle cross-strike shear zones and associated fracture systems. In the North Sea, geoscientists are using advanced seismic attribute analysis for detailed mapping of fault networks that provide additional reservoir production capacity.

Detailed Mapping of Fault NetworksThe South Arne field is in the Danish sector of the North Sea, about 250 km [155 mi] WNW of Esbjerg, Denmark. Hess has operated the field since 1994; its partners are DONG Energy A/S and Danoil Exploration A/S. The reservoir is in chalks of the Late Cretaceous Tor and overlying Early Paleogene Ekofisk formations, situated on an elongated structure that trends NW–SE.25

Oil production began in 1999 from horizontal wells that were drilled parallel to the structural axis. Production is supported by water injection from horizontal wells drilled parallel to and inter-laced with the production wells. To aid production, both well types underwent fracture stimulation pro-grams using either acid to erode the induced frac-ture surface or proppant to keep fracture channels open. The induced fractures have vertical fracture planes oriented NW–SE, parallel to the anticline structure. The well pattern and stimulation pro-gram promoted homogeneous sweep across the res-ervoir.26 After a few years, production data indicated that reservoir fluids were not flowing as projected, and the reservoir sweep was becoming more heterogeneous.

Consequently in 2005, Hess and Schlumberger commenced a time-lapse seismic program to investigate flow patterns indicated in the pro-duction data and to compare them with patterns inferred from interpretation of time-lapse seis-mic data. Time-lapse seismic interpretation

compares one or more recent surveys against a reference survey to uncover production-related changes within the surveyed reservoir volume. Time-lapse seismic surveys help operators mon-itor a reservoir, map pathways and barriers to fluid movement and understand reservoir phe-nomena such as compaction from changes in the distribution of reservoir fluid content.27 For the South Arne field, a preproduction 3D seis-mic survey acquired in 1995 served as the refer-ence survey. A 3D survey acquired in 2005 served as the monitor survey.

A key result of the time-lapse seismic analysis was a strong indication that faults were affecting reservoir flow. These faults were providing addi-tional flow capacity parallel to their strike while impeding the flow perpendicular to their strike (above). Engineers have incorporated this aniso-tropic flow behavior into reservoir simulation models; predictions of reservoir flow have

25. Mackertich DS and Goulding DRG: “Exploration and Appraisal of the South Arne Field, Danish North Sea,” in Fleet AJ and Boldy SAR (eds): Petroleum Geology of Northwestern Europe—Proceedings of the 5th Petroleum Geology Conference. London: Geological Society (1999): 959–974.

26. Herwanger JV, Schiøtt CR, Frederiksen R, If F, Vejbæk OV, Wold R, Hansen HJ, Palmer E and Koutsabeloulis N: “Applying Time-Lapse Seismic Methods to Reservoir Management and Field Development Planning at South Arne, Danish North Sea,” in Vining BA and Pickering SC (eds): Petroleum Geology: From Mature Basins to New Frontiers—Proceedings of the 7th Petroleum Geology Conference. London: Geological Society (2010): 523–535.

27. For more on time-lapse seismic analyses: Pedersen L, Ryan S, Sayers C, Sonneland L and Veire HH: “Seismic Snapshots for Reservoir Monitoring,” Oilfield Review 8, no. 4 (Winter 1996): 32–43.

Aronsen HA, Osdal B, Dahl T, Eiken O, Goto R, Khazanehdari J, Pickering S and Smith P: “Time Will Tell: New Insights from Time-Lapse Seismic Data,” Oilfield Review 16, no. 2 (Summer 2004): 6–15.

, South Arne time-lapse amplitude difference map. The time-lapse amplitude difference map (left) shows changes in seismic amplitude along the top of the Tor horizon between 1995 and 2005. NW–SE faults (green) dominate the structure. Blue colors indicate a decrease in reflection strength and red to yellow indicates an increase. Geoscientists interpret the reflection amplitude increase and decrease to signal, respectively, compaction and dilation of the formation pore volume. The distribution of changes in reflection strength results from fault-controlled flow and circulation of reservoir fluids during oil production that was supported by water injection. The fault orientations promoted structural crest collapse and compaction (orange and yellow, top right) and preferential flow of and pressure support from fluids and dilation toward the flanks of the structure (blue, bottom right).

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40 Oilfield Review

improved, providing closer agreement between estimated pressures and actual pressures mea-sured in appraisal wells drilled for field extension to the north.28 Since that study, Hess and Schlumberger have continued to collaborate to improve imaging of the fault pattern within the South Arne field.29

A promising approach for revealing fault pat-terns follows a workflow that identifies three independent attributes of seismic dip, combines them into an aggregate attribute and then uses edge enhancement processing to enhance fault zones (above). The independent attributes—chaos, curvature and variance—describe the structural uncertainty, structure and amplitude sensitivity of fault dips interpreted from seismic data. Although dip is difficult to estimate cor-rectly, geophysicists used global constraints to estimate dip reliably and consistently.30

The chaos attribute results from the struc-tural uncertainty or variability of the seismic dip and azimuth estimates. It measures the chaotic or disordered quality from statistical analysis of local seismic responses—abruptly changing sig-nals are chaotic, but smoothly varying signals are not—thus helping identify faults and fractures, which cause disruptions in the seismic volume.31 Chaos is an independent attribute because it does not vary with seismic amplitude or dip ori-entation, meaning that the chaos value will be

the same whether in a low- or high-amplitude or dipping or flat region of the 3D seismic volume.

The second attribute, the curvature attribute, describes the lateral structural variation in dip. Large values of curvature highlight abrupt changes in dip and are common indicators of fractures and faults.32

The third attribute, amplitude variance, is a seismic attribute of the coherence family. Amplitude variance reveals the lack of continuity in the signal, which is useful for identifying faults as well as stratigraphic features.

The three independent attributes—chaos, curvature and variance—are combined into an aggregate seismic attribute using a weighted summation of the independent inputs; weighting equalizes each of the contributions so that they affect the aggregate output attribute similarly. This combined attribute volume undergoes edge enhancement processing using “ant tracking” to bring out the fault planes and suppress other nonstructural features.33 The resulting seismic volume—a fault cube—provides a detailed description of the fault network associated with the fractures that control reservoir production (next page). These details are important inputs into fractured reservoir simulation and geome-chanical earth models, which engineers use for predicting reservoir properties and their evolu-tion with production.

Fracture Network Modeling at Multiple ScalesIdeally, reservoir models should include all that is known about the geology, rock and fluid proper-ties and production history of a reservoir. Faults and fractures deserve special treatment because they represent discontinuities in the rocks. Changes in properties near faults and fractures are as important as changes in properties near stratigraphic surfaces and horizons—bedding, sequence and unconformity boundaries. Lithology may be displaced slightly or drastically across faults, while porosity and permeability may change in their vicinity. Faults and fractures may affect fluid flow regimes by acting as preferential channels for flow when they are open or as obsta-cles to flow when sealed.

Using seismic data to detect a fault and frac-ture network, a geoscientist team from Abu Dhabi Company for Onshore Oil Operations (ADCO), the operator, and Schlumberger con-ducted a study of a giant carbonate field south-east of Abu Dhabi, UAE, to determine how best to capture the details of the network, which was suspected of affecting reservoir production.34 The objective was to represent the seismic lineaments in reservoir models as completely and efficiently as possible within the restrictions set by the com-puting environment.

Production comes from the Lower Cretaceous Thamama Formation. The structure is a broad, gentle anticline elongated in the northeast direc-tion and crossed by four fracture sets identified both in wells and 3D seismic data. The main shear fracture set has a WNW–ESE orientation, right lateral strike-slip displacement, and en ech-elon regular spacing of 3 to 4 km [2 to 2.5 mi].35 Data show that the set may be related to the reac-tivation of Precambrian basement strike-slip faults. The second set is oriented NW–SE and interpreted to be the right lateral synthetic Riedel shear set associated with the main set.36 The third set is oriented N–S and interpreted to be the left lateral antithetic Riedel shear set. A fourth minor set, oriented NNW–SSE, consists of extension relay fractures that propagated between fractures in the main WNW–ESE shear fracture set.

The dataset for this study included 3D prestack time-migrated (PSTM) seismic data that were converted from time to depth over the reservoir, a comprehensive well log dataset of 55 image logs and 18 production logs from horizon-tal and vertical wells and a 3D static model of the reservoir based on the ADCO asset team’s inter-pretation of the geology, stratigraphy, lithology and rock and fluid properties from well log, core, petrophysical and fluid analyses.

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Variance

Dip estimator Dip volume

> Globally consistent dip estimation for fault and fracture mapping. The workflow starts with seismic data input (top left, purple) into a dip estimator (top, blue). Comparison against dip constraints (center, yellow) determines convergence. The result is a dip volume (top right, green) along with the three dip attributes (center right, green) used for fault and fracture identification. The dip attributes undergo a weighted summation and edge detection to yield an estimated volume of potential faults and fractures (bottom, right to left). Geologists, geophysicists and well log analysts screen and validate (bottom left, orange) these faults and fractures as real or as other geologic features or seismic artifacts.

Summer 2012 41

> Faults and fractures from dip mapping. These images are grayscale shaded relief maps of the two-way traveltime surface at the top of the Ekofisk Formation; in the bottom right corner of each image, the green arrow points north. A view from the southeast of the two-way traveltime surface (top left) shows the NW–SE trending structure of the South Arne field, with a vertical seismic section in the background. The other views are from the north and are seismic results superimposed on the two-way traveltime surface. Reflection amplitude (top right) depends on the rock contrast across the surface; the blue amplitude shows the negative reflection polarity caused by a decrease in the seismic impedance at the top of the Ekofisk Formation, which has lower seismic impedance than the shales immediately overlying it. The structural dips (bottom left) that result from dip estimation show the dip at every point on the surface and are independent of reflection strength. The gray scale indicates dip magnitude and direction and ranges from white to black; white indicates dips toward the west and black indicates dips toward the east. Ant tracking edge detection and enhancement processing of the dips accentuates the traces of faults and fractures (yellow and orange, bottom right) that cut across the surface.

Top of the Ekofisk Formation: Time Surface Top of the Ekofisk Formation: Amplitudes

Top of the Ekofisk Formation: Dips Top of the Ekofisk Formation: Ant Tracking

28. Herwanger et al, reference 26.29. Aarre V and Astratti D: “Seismic Attributes for Fault

Mapping—The Triple Combo,” presented at the Petroleum Exploration Society of Great Britain Geophysics Seminar on Amplitudes and Attributes; Uses and Abuses, London, June 15–16, 2011.

30. Aarre V: “Globally Consistent Dip Estimation,” Expanded Abstracts, 80th SEG Annual Meeting, Denver (October 15–17, 2010): 1387–1391.

31. Randen T, Monsen E, Signer C, Abrahamsen A, Hansen JO, Sæter T, Schlaf J and Sønneland L: “Three-Dimensional Texture Attributes for Seismic Data

Analysis,” Expanded Abstracts, 70th SEG Annual Meeting, Calgary (August 6–11, 2000): 668–671.

32. Roberts, reference 16.33. For more on the patented ant tracking procedure:

Pedersen SI, Randen T, Sønneland L and Steen Ø: “Automatic Fault Extraction Using Artificial Ants,” Expanded Abstracts, 72nd SEG Annual Meeting, Salt Lake City, Utah, USA (October 6–11, 2002): 512–515.

Pedersen SI: “Image Feature Extraction,” US Patent No. 8,055,026 (November 8, 2011).

34. Souche et al, reference 24.

35. En echelon is a stepped or shingled arrangement of similar objects, either to the right or left of the reference object.

36. Riedel shear structures are secondary structures that form in shear zones. They include two conjugate sets of en echelon slip surfaces. The synthetic set has the same sense of displacement as the primary shear and is inclined at a low angle to the primary direction of relative motion. The antithetic set has the opposite sense of displacement as the primary shear and is at a high angle to it.

42 Oilfield Review

> Evaluation of seismic estimates of faults and fractures. Faults (cyan) were interpreted in vertical sections (top left) and in depth slices (bottom left) close to well trajectories—in this case Well E (yellow). These seismically identified faults were the result of dip estimation and ant tracking and were compared with faults picked by hand from seismic data (red lines) and faults and fractures interpreted from FMI image logs (orange and red disks along Well E). Faults and fractures interpreted on the image logs from Well E are plotted on a radial pole plot stereonet (top right) and well log section (bottom right) for more detailed comparison with other borehole measurements and seismic data. The blue and green rectangles in Track 1 of the well log section show intervals where water (blue) and oil (green) entries into the well were detected during production log testing and interpreted as associated with faults crossing the horizontal well. Track 2 shows intervals where faults were identified through ant track processing of seismic data; the gray rectangles mark where Well E crosses faults. The dip tadpoles in Track 3 indicate the depth and orientation of fractures observed in the FMI image log: The tadpole color indicates fracture classification; the circle plots at the depth and dip of the fracture and the tail gives the fracture dip azimuth. Track 4 (light green) shows the grid cell boundaries crossed by the representation of Well E in the 3D model of the fracture system in the reservoir. (Adapted from Souche et al, reference 24.)

0°

30°

60°

90°

120°

150°

180°

X,250

Gamma Ray AntsTracking

Dip CellGrids

MD,ft

X,500

00 140gAPI 90deg

X,750

Y,000

210°

240°

270°

300°

330° 90°

70°

50°

30°

10°

50× vertical exaggeration

Vertical SectionPole Plot from Well E

Well Section from Well E

Fault

Fractures and Faults

Resistive fractureHairline fracture

Possible fault

Well E

Depth Slice

Well E

Hand-picked fault

+

0

–

Ampl

itude

+

0

–

Ampl

itude

Fault

Summer 2012 43

To extract fault and fracture information from the 3D PSTM seismic data, the workflow followed a procedure similar to that used for the South Arne field; the interpretation team fol-lowed up by comparing the seismic results with image logs. They accomplished this task using seismic cross sections along well trajectories and seismic depth slice maps within the reser-voir interval or along the horizontal sections of horizontal wells. Seismic lineaments were retained in the fault cube if they showed close agreement with image log interpretation (previ-ous page). The remaining lineaments were screened further to categorize them as sedi-mentary boundaries or as artifacts from seismic data acquisition and processing.

The team incorporated the verified fault cube into the 3D reservoir model. Including and representing so many elements with enough detail to be faithful to the reservoir geology and meaningful to reservoir engineers—while keep-ing model computations manageable—were the challenges. To address these challenges, the team chose a hybrid model using multiscale rep-resentation.37 The large fractures, thought to con-trol the flow of injected fluids in this reservoir,

were modeled explicitly using a discrete fracture network (DFN). The small fractures, believed to augment the matrix permeability, were repre-sented statistically using an implicit fracture model (IFM). The size threshold between large and small fractures was grid-size dependent: The large fractures provided connectivity within the cells and the small fractures contributed to the cell properties. DFN and IFM models may be combined and scaled up for dynamic reservoir simulation purposes (above). The primary out-come of the hybrid model is that a single model accounts for the predominant effects from large fractures and the contributions from smaller fractures. The hybrid model also results in a con-siderable speedup in computation time, which is reduced from hours to minutes, making it possi-ble to test several reservoir development sce-narios and their production outcomes efficiently and quickly.

Seeing Fractures in the FutureTo ensure successful reservoir development and production, engineers must have an accurate geo-logic understanding of natural fractures and faults. Analysis of seismic data is fundamental to this process, and seismic attributes play a crucial role in helping interpreters identify subtle fea-tures. Also vital is integration of seismic results with large-scale geologic trends, log data, outcrop studies and real-time drilling results.

Knowledge of natural fracture systems and their orientations, dimensions and physical prop-erties allows operators to plan well trajectories to intersect these sweet spots in reservoirs con-trolled by fracture porosity and permeability—or to avoid them if necessary. And although most fractures are too small to be sensed individually by seismic waves, sets and networks of fractures can have a collective impact on seismic response.

New capabilities for high-fidelity seismic data acquisition, greater data storage and faster com-puting spur the quest for even more-accurate geo-logic maps and models to support and sustain decisions about developing reservoirs, drilling wells and planning surface support facilities and infrastructure. Completing this quest will require new and innovative ways to design seismic attri-butes for better identification and characteriza-tion of fractures in reservoirs. —RCNH

> Hybrid model of a natural fracture system. The hybrid model combines a discrete fracture network (DFN) for large fractures (left) and an implicit fracture model (IFM) for small fractures (center) into a single coherent framework (right). Upscaling the model enables efficient testing of reservoir development plans and their production outcomes. Each color in the DFN plot represents a distinct DFN set. The model covers an area of 33 km2 [13 mi2]. (Adapted from Souche et al, reference 24.)

Large Fractures: Discrete Fracture Network

Perm

eabi

lity

Low

High

Upscaling to Effective Fracture Properties for Simulation PurposesSmall Fractures: Implicit Fracture Model

Inte

nsity

Low

High

37. Souche L, Kherroubi J, Rotschi M and Quental S: “A Dual Representation for Multiscale Fracture Characterization and Modeling,” Search and Discovery Article 50244 (December 2009), http://www.searchanddiscovery.com/documents/2009/50244souche/ndx_souche.pdf (accessed July 15, 2012).

Lee SH, Lough MF and Jensen CL: “Hierarchical Modeling of Flow in Naturally Fractured Formations with Multiple Length Scales,” Water Resources Research 37, no. 3 (March 2001): 443–455.

44 Oilfield Review

Logging Through the Bit

Increasing use of horizontal drilling has spurred E&P companies to look for more

cost-effective ways to log their wells. To meet this need, an innovative logging

service has been developed. Operators are now capitalizing on a unique conveyance

method that uses small-diameter tools to obtain formation evaluation data in highly

deviated or extended-reach wells.

James AivalisTony MeszarosRobert PorterRick ReischmanRobin RidleyPeter WellsThruBit LLCHouston, Texas, USA

Benjamin W. CrouchOsage Resources, LLCHutchinson, Kansas, USA

Taylor L. ReidOasis Petroleum, Inc.Houston, Texas

Gary A. SimpsonForest Oil CorporationHouston, Texas

Oilfield Review Summer 2012: 24, no. 2.Copyright © 2012 Schlumberger.For help in preparation of this article, thanks to Martin Isaacs and Rick von Flatern, Houston; and Tony Smithson, Northport, Alabama, USA.Geo-Frac, Mangrove, Portal, SureLog and ThruBit are marksof Schlumberger.

Advances in drilling and completion technology are helping E&P companies open and develop new plays previously deemed uneconomic. In many of these plays, operators are turning to horizontal drilling and hydraulic stimulation to increase wellbore exposure to productive forma-tions. However, horizontal or high-angle wells can be difficult to evaluate. Often, these wells cannot be logged on wireline without specialized convey-ance equipment, which frequently results in added expense and operational delays. An unfor-tunate consequence is that some operators forgo the acquisition of petrophysical data entirely.

In high-angle wells, the combined effects of borehole trajectory and geology hamper an oper-ator’s ability to acquire the data needed to assess a reservoir and develop a stimulation program to enhance payout. To meet the challenges of high-angle wells, the industry has steadily refined technology for acquiring openhole logs. Logging while drilling (LWD), tractor conveyance and various pipe-conveyed logging techniques are just a few of the options currently available.1

Nevertheless, there are costs—in the form of tool rentals or rig time—associated with these alter-native methods.

In the unconventional plays of North America, such costs may adversely impact development strategies. A major factor in field development economics is the cost of drilling and completing each horizontal well. It is therefore common in some unconventional plays for operators to limit use of logging suites.2

Often, gamma ray logs obtained by measure-ment-while-drilling (MWD) tools are used during geosteering to determine stratigraphic position. For some wells, the MWD gamma ray log may pro-vide the sole petrophysical input for designing perforating and formation fracturing programs. Although the gamma ray log may help geologists identify target zones through correlations with offset well logs, gamma ray measurements alone are not sufficient to characterize reservoir prop-erties that impact production. Measuring lateral and vertical variations in lithology, mineralogy, grain size, porosity, permeability and fluid content in complex unconventional reservoirs requires a suite of logging tools.

The capability to identify changes in reser-voir rock, which petrophysical logs provide, can significantly affect a well’s completion program and its economics. This is particularly relevant for unconventional plays or other tight forma-tions, in which fracture treatments must be divided into several stages to stimulate a pay zone that extends thousands of feet along a hori-zontal wellbore. By excluding some zones, while selectively perforating and stimulating the inter-vals most likely to be productive, operators may reduce the number of stages required to opti-mally fracture a reservoir. Decreasing the num-ber and length of stages conserves water, sand and other resources, thereby reducing expenses and the overall impact of well stimulation.

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

2. Pitcher J and Buller D: “Shale Assets: Applying the Right Technology for Improving Results,” Search and Discovery Article 40883, adapted from an oral presentation at AAPG International Conference and Exhibition, Milan, Italy, October 23–26, 2011.

Summer 2012 45Summer 2012 45

46 Oilfield Review

A unique, cost-effective logging system has been developed to help operators obtain valuable formation data in high-angle wellbores. The sys-tem, developed by ThruBit LLC, uses mud pump pressure to deliver small-diameter logging tools down the center of the drillstring and out through a specialized bit to log the open borehole beyond. Traveling through this drillpipe conduit to TD, the tools are pumped through the bit opening where they can survey the formation as the drill-pipe is tripped out of the hole. Schlumberger acquired ThruBit LLC in 2011.

This article provides an overview of the equip-ment and deployment system that make the ThruBit logging technique possible. Datasets obtained with this system help demonstrate its quality and usefulness.

Logging EssentialsThe concept of logging through the bit centers on two requirements: logging tools that are small enough to pass through the drillstring and a bit designed to permit their passage into the open borehole. The ThruBit logging system uses spe-cially designed logging tools that combine small diameters with high-pressure, high-temperature capabilities. At 21/8-in. diameter, all tools in the SureLog suite are small enough to pass through the center of most drillpipe, jars, collars and bits (above). Each tool can withstand temperatures to 300°F [150°C] and pressures up to 15,000 psi [103 MPa]. These tools can be run in combination

to obtain a full suite of measurements during a single logging run.

The SureLog telemetry, memory and gamma ray device is run as the topmost logging tool to provide communications and memory functional-ity for the entire logging string. The gamma ray detector measures naturally occurring gamma rays in the formation to provide a qualitative evaluation of clay content. A multiaxis acceler-ometer in the tool monitors downhole tool orien-tation, motion and vibration. The tool also measures borehole inclination and temperature.

The array induction tool has five median depths of investigation and three vertical resolu-tions. In some configurations, a combinable spon-taneous potential (SP) tool is run immediately below the induction tool. The SP measurement gives a qualitative indication of formation shali-ness and permeability and can be used to deter-mine equivalent formation water resistivity. A mud resistivity sensor is built in for array induc-tion corrections and analysis of borehole fluids.

The SureLog neutron tool operates in both openhole and cased hole environments. It uses a californium [Cf] source to obtain thermal neu-tron porosity measurements. In addition to bore-hole temperature and pressure corrections, the neutron porosity measurement may be corrected for environmental factors such as hole size, mud type, mud weight, mudcake thickness, salinity and tool standoff.

The density tool measures formation bulk den-sity (ρb), photoelectric factor (Pe) and borehole size. The raw measurement processing includes a correction algorithm that preserves overall den-sity accuracy across a wide range of borehole sizes, mud types and mud weights. The tool’s scin-tillation detectors are housed in an articulated pad for better contact with the formation to improve overall measurement quality in deviated and rugose holes (next page, top left). The density tool uses a single-arm caliper to measure hole size and to press the tool against the formation.

The SureLog waveform sonic tool has a mono-pole transmitter and a six-receiver array. Waveforms recorded at each of the six receivers are subsequently processed using a slowness-time coherence technique to obtain compres-sional (Vp) and shear (Vs) velocities. Monopole shear velocity can be determined from the sonic measurement in formations whose compres-sional and shear velocities are faster than the acoustic velocity in mud (Vmud).

The Portal PDC bit is designed to allow log-ging tools to pass through the end of the drill-string without requiring removal of the bit. This bit is hollow at the center, with a 21/2-in. [63.5-mm] opening at its crown—the center of the bit face (next page, top right). The bit design is adaptable to almost any PDC bit model rang-ing in size from 57/8 in. to 121/4 in. in diameter. The bits are manufactured in a variety of blade and cutter configurations to accommodate drilling and lithology requirements.

> SureLog tool specifications. Any of these tools may be combined to permit operators to run a triple- or quad-combo logging string. All tool diameters are small enough to run in 4-in. holes.

Measurements

Diameter

Length

Temperature

Pressure

Logging Speed

Vertical Resolution

Depth of Investigation

Hole Size

Gamma ray,borehole temperature,tool acceleration

2 1/8 in.

74 in. [188 cm]

300°F [150°C]

15,000 psi [103 MPa]

1,800 ft/h [550 m/h]

12 in. to 24 in.[30 cm to 61 cm]

12 in. [30 cm]

4 in. to 14 in.

Induction resistivity,spontaneous potential,mud resistivity

2 1/8 in.

185 in. [470 cm]

300°F [150°C]

15,000 psi [103 MPa]

3,600 ft/h [1,100 m/h]

1 in., 2 in. and 4 in.[3 cm, 5 cm and 10 cm]

10 in., 20 in., 30 in., 60 in. and 90 in.[25 cm, 51 cm, 76 cm, 152 cm and 228 cm]

4 in. to 14 in.

Bulk density,photoelectric factor,hole size

2 1/8 in.

128 in. [325 cm]

300°F [150°C]

15,000 psi [103 MPa]

1,800 ft/h [550 m/h]

9 in. to 12 in.[23 cm to 30 cm]

12 in. [30 cm]

4 in. to 16 in.

Shear and compressionalvelocity

2 1/8 in.

144 in. [366 cm]

300°F [150°C]

15,000 psi [103 MPa]

3,600 ft/h [1,100 m/h]

6 in. to 24 in.[15 cm to 61 cm]

3 in. [7 cm]

4 in. to 14 in.

Neutron porosity

2 1/8 in.

74 in. [188 cm]

300°F [150°C]

15,000 psi [103 MPa]

1,800 ft/h [550 m/h]

12 in. to 15 in.[30 cm to 38 cm]

10 in. [25 cm]

4 in. to 16 in.

Telemetry, Memory,Gamma Ray Tool

Induction Tool Neutron Tool Density Tool Sonic Tool

Summer 2012 47

A hangoff sub, positioned above the Portal bit, enables the logging sensors to extend immedi-ately beneath the bit when logging in memory mode. In this mode, the wireline is detached from the toolstring and retrieved to the surface. Batteries power the tools, and the log data are stored in onboard memory. The hangoff sub pre-cisely positions the logging tools as they extend through the opening in the bit. This sub restricts

the movement of a no-go collar located near the top of the logging toolstring. The sub prevents the no-go collar from traveling farther downhole while permitting the logging sensors to protrude into open hole, just beyond the bit face.

ThruBit surface pressure equipment is designed to control the well in the event of an unexpected surge in pressure. This equipment allows the driller to rotate and reciprocate the drillstring and to circulate while deploying log-ging tools.3 A float valve may also be installed in the bottomhole assembly (BHA) to provide an added measure of well control. This flapper-style float valve allows logging tools and ancil-lary equipment to pass through the valve in both directions.4

Downhole DeploymentThe ThruBit deployment system uses the Portal bit to ream and condition the wellbore in prepa-ration for logging. Once the BHA has reached log-ging depth, the drilling crew trips the BHA out of the hole to install a Portal bit and hangoff sub. As the Portal bit and hangoff sub are tripped back into the hole, the driller uses the Portal bit to ream past ledges and tight spots encountered on the way to TD. Once the wellbore is conditioned for logging, the driller positions the bit just above the base of the lowest interval to be logged,

leaving only enough open hole for the logging sensors to extend beyond the bit.

With the Portal bit at target depth, the logging crew inserts the SureLog toolstring into the drill-pipe, installs pressure control equipment and low-ers the SureLog suite of tools on wireline. The wireline connection allows the ThruBit logging engineer to create a downlog and monitor tool-string functionality from the moment the logging tools leave the surface until they are switched to memory mode. The drillpipe protects the logging tools and wireline as they are lowered downhole.

At the point where wellbore inclination pre-vents gravitational descent, the rig’s mud pumps are engaged to pump the tools to the end of the drillstring. The drillpipe provides a smooth bore to ensure that the small-diameter tools deploy to the bit face. Pump pressure and mud flow force the logging sensors out through the opening in the Portal bit. The tools stop once the no-go

3. In some wells, the ability to circulate during logging may prove helpful in reducing borehole temperature when the bottomhole temperature approaches the tool’s temperature rating.

4. Reischman RL and Porter RC: “An Innovative New System for Obtaining Open Hole Logs in Difficult Wells,” paper AADE-11-NTCE-67, presented at the AADE National Technical Conference and Exhibition, Houston, April 12–14, 2011.

> SureLog density tool. Scintillation detectors, housed in a pad that articulates from the main tool, measure both formation bulk density and photoelectric factor. The tool uses a single-arm caliper to increase overall pad contact with the formation while it measures borehole size.

Caliper

Densitypad

> Portal bit. This specialized bit is engineered to meet drilling requirements for a variety of rock types. The main feature of this PDC bit (side view, left) is a central hole (top view, right) to permit passage of the slim-diameter logging string. (Figure courtesy of Smith Bits, a Schlumberger company.)

48 Oilfield Review

device near the top of the toolstring reaches the hangoff sub.

The logging engineer performs a final check of toolstring functionality before opening the caliper on the density tool. Accelerometers inside the tool verify that the density skid is oriented against the low side of the hole. The logging engi-neer then signals the toolstring to release the wireline. The wireline and the upper part of a

dropoff and retrieval assembly are reeled back to the surface and removed from the drillstring. This leaves a fishing neck exposed at the upper end of the logging tools to permit ready retrieval of the tools and the density and neutron sources through the drillpipe at any time—eliminating the need to trip pipe.

Operating in memory mode, the logging tools survey the formation and record the data as the

drillpipe is tripped out of the well. After the zone of interest has been logged, the logging crew can lower a retrieval tool on wireline to retract the logging tools back through the Portal bit and drillpipe. With the toolstring retrieved to the surface, the driller is free to resume normal oper-ations in preparation for the next phase of well activity (above). Alternatively, the tools can simply be tripped to the surface with the pipe.

> ThruBit logging sequence. A Portal bit is used to ream to TD to prepare the hole for logging (1). The driller pulls the bit off bottom, leaving enough room to accommodate the SureLog suite of logging tools. The logging toolstring is pumped through the drillpipe (2). With tools positioned beneath the bit, the ThruBit logging engineer verifies tool function, then disconnects the wireline and draws the cable back to the surface (3). As the drilling crew trips pipe out of the hole, the logging tools survey and record formation data (4). Logging is complete when the tools are pulled up into the casing (5). With the bit and tools inside the casing, the logging crew lowers the retrieval tool on wireline, latches the tools and retrieves them to the surface (6). Once the logging tools are recovered from the drillstring, the driller is free to ream to the bottom or resume other operations in preparation for the next phase of drilling (7).

1

2

3

4

5

6

7

Summer 2012 49

However, early retrieval permits the data to be downloaded, verified and transmitted while the pipe is still being pulled out of the hole— providing more time for the operator to plan com-pletion operations.

This deployment system can positively impact a logging operation. The rig time spent on acquiring logs is reduced because deploy-ment and acquisition can take place during the conditioning trip. Because they are not deployed until the bit is in position near TD, the tools receive less exposure to shocks, vibrations and high temperatures. Risk is minimized because the tools are retrievable and the system provides the driller with full well control capability. Thus,

if well conditions deteriorate, and the drillpipe becomes stuck, the logging tools and the density and neutron sources can be retrieved prior to activating jars or implementing other stuck pipe procedures. With the logging string laid out on the catwalk, the driller may jar the drillstring without fear of damaging the tools.

The flexibility of this system is opening the way for its use in other challenging logging situations.

Field ApplicationsThe geometry of extended-reach wells makes them inherently difficult to log. Unconventional plays, commonly exploited through horizontal wells, have created a demand for specialized

conveyance techniques. As the number of plays proliferated across the US, they provided a proving ground for ThruBit logging technology. The use of this technology has since expanded to other unconventional plays where high-angle wells make logs difficult to obtain.

In North Dakota, USA, Oasis Petroleum, Inc. utilized the ThruBit logging system to evaluate a Bakken Shale well drilled to 20,766 ft [6,330 m] MD with a 10,000-ft [3,050-m] lateral section. The well had a 29.5°/100-ft [29.5°/30-m] radius of curvature and was deviated up to 91° from the vertical (below). Oasis used a Portal bit during the reaming run to prepare the hole for log-ging prior to running production liner. The

> Logging an extended-reach well. Oasis Petroleum used the ThruBit system to log a well drilled in the Bakken formation. The 20,766-ft well, with a 10,000-ft lateral section, was deviated up to 91°. The hangoff assembly, battery and retrieval tool (inset) enable logs to be recorded in memory mode as pipe was tripped from the well. The tools can be retrieved at any time after the wireline is released. (Adapted from Reischman and Porter, reference 4.)

Drillstring

Intermediate casing

Drilled radius,29.5°/100 ft

BHA SureLog logging string

Wired dropoffand retrieval tool

No-go collar Induction arraytool

Telemetry, memory,gamma ray tool

Densitytool

Caliper

Drillpipe Hangoff sub Portal bit

Batteries Neutrontool

Total length: 63.7 ft [19.4 m]

50 Oilfield Review

ThruBit system enabled the driller to maintain circulation as logging tools were deployed around the curve and through the extended lateral sec-tion. The SureLog suite of logging tools safely passed through the drillpipe and out the bit to acquire formation evaluation data as the pipe was tripped out of the well. In a single logging run, Oasis geoscientists obtained the petrophysical data they needed to evaluate the Bakken section.

In Barber County, Kansas, USA, Osage Resources, LLC sought to optimize perforation placement and length of fracture stages in a horizontal well drilled in the Mississippi Lime play. This play, initially discovered and exploited through vertical drilling, is being revitalized through horizontal wells and multistage frac-ture stimulation treatments. The Mississippi Lime is highly variable, consisting of limestone, dolomite and siliceous deposits of tripolite, chert and spiculite. To properly evaluate the well, Osage needed more than an MWD gamma ray log.

The ThruBit logging crew made up a SureLog quad-combo toolstring, consisting of gamma ray, caliper, resistivity, neutron, density and sonic tools. This toolstring was pumped down through 4-in. drillpipe, and the logs were recorded in memory mode as drillpipe was tripped out of the hole. Once the logging tools reached casing, they were retrieved to the surface by wireline. With the 61/8-in. Portal bit still downhole, the driller was able to ream back to TD for a final cleanup trip in preparation for a subsequent casing run.

The log data revealed significant lithological changes along the length of the lateral wellbore (next page). This information prompted Osage engineers to reassess their initial stimulation strategy and shift focus toward treating the toe of the wellbore, where better reservoir condi-tions were found. Sonic data were used to com-pute a brittleness curve. This curve provided a basis for dividing the stimulation into separate intervals according to rock type, which helped the operator optimize stage lengths, pad sizes and perforation clusters. Sonic waveform data indicated where the formation was naturally fractured along the wellbore, which helped Osage engineers design a hydraulic fracturing program that minimized the risk of early screen-out during stimulation. They added another frac-turing stage to the plan and successfully completed the revised stimulation program. The well is producing significantly better than other Mississippi Lime wells in the area.

South Texas, USA, has seen a resurgence in drilling as oil and gas companies pursue new unconventional plays. In Gonzales County, Forest Oil Corporation has drilled several wells to develop the Cretaceous Eagle Ford play. To exploit a rather narrow oil window, the company drills high-angle wells that target a 20 ft [6 m] thick sweet spot within an 80- to 110-ft [24- to 34-m] reservoir section. These wells are typically drilled to around 12,000 ft [3,660 m] MD, and are deviated between 87° and 92° with lateral sec-tions of about 5,500 ft [1,675 m] through the Eagle Ford.

Working from 3D seismic data obtained over the lease area, Forest geoscientists have identified a number of locations within the Eagle Ford to develop further. These locations were drilled with input from an MWD gamma ray tool for geosteering. Once drilled, early wells were stimu-lated using a geometric approach: divide the lateral section into 300-ft [90-m] stages, then per-forate and fracture, pumping 240,000 lbm [109,000 kg] of sand into each stage. To execute this strat-egy, Forest engineers used the “plug and perf” method, in which a bridge plug is set between frac-ture stages to isolate perforation clusters.

After completing several of these wells, Forest petrophysicists and engineers had acquired enough data to evaluate production in the Eagle Ford. The engineers noted that, although several wells had been drilled and com-pleted in a similar manner, production varied widely once the wells were brought on stream. Some wells were producing significant volumes of high-salinity water, not common to either the Eagle Ford or the adjacent Austin Chalk forma-tion above. This water was attributed to the Buda or the Edwards Limestone and indicated that the hydraulic fractures had penetrated below the Eagle Ford, providing a water migration pathway to underlying formations.

Forest Oil engineers and geoscientists mounted a study to determine why some wells stood out—either as good or bad producers—and to fine-tune their drilling and completion strategies in this formation. Their investigations sought to achieve the following outcomes:

-tal wells

-ture initiation

formations

Central to their study was the capability to acquire and analyze log data from the horizontal wellbores; thus, they carefully weighed the con-veyance options. Forest had concerns with slick-line retrievability of MWD components, needed for geosteering, in the event that LWD tools were used to evaluate the formation; other pipe- conveyed methods for logging consumed extra rig time. Needing to evaluate the producing zones, Forest used ThruBit logging to obtain a suite of logs in horizontal wells slated for an upcoming drilling campaign.

As these wells were drilled, the driller made a series of short trips to clean out cuttings beds from the horizontal section. Once the hole was conditioned, the driller tripped the directional BHA out of the well and ran back in the hole with a Portal bit and hangoff sub, reaming past any tight spots on the way to TD. The SureLog quad-combo logging suite was then pumped through the drillpipe to TD on wireline. The logging tools were pumped out through the Portal bit. Once the logging engineer verified toolstring operabil-ity, the tools were released from the wireline, which was reeled back to the surface. The logging tools recorded formation data in memory mode as the drillpipe was pulled out of the hole. After it reached the casing shoe, the toolstring was retrieved on wireline and the data were down-loaded. If needed, the driller could then make another conditioning trip back to TD before lay-ing down pipe for a casing run. By combining the logging run with a conditioning trip, the operator saved more than 24 hours of rig time when com-pared with the time needed for conventional pipe-conveyed methods.

Forest Oil petrophysicists used sonic and den-sity data to derive rock properties such as Young’s modulus and Poisson’s ratio. Shear-wave anisot-ropy from the SureLog sonic tool enabled Forest geophysicists to compare attributes of natural fractures in the wellbore with those seen in 3D seismic data. This information was instrumental in mapping new exploration targets and provid-ing a better understanding of the seismic attri-butes needed to evaluate their extensive acreage position for future drillsite selection.

Forest was able to capitalize on a more selective approach to fracturing. The mechani-cal properties data processed from the SureLog suite proved crucial for grouping hydraulic fracturing stages by highlighting rock of similar

Summer 2012 51

> Evaluating a lateral wellbore in the Mississippi Lime Formation. After running a SureLog quad-combo logging string in a horizontal well, Osage Resources engineers determined that formation properties varied considerably throughout the length of this horizontal interval. Porosity (Track 3) varies from 4% to 16%. The sonic waveform and shear semblance curves indicate natural fractures (Track 4, yellow) through some intervals. A brittleness calculation (Track 5), which is used to produce a quicklook curve related to the stress profile, also shows contrasts in brittleness. Based on these curves, along with elevated resistivities (Track 2), Osage Resources was able to select optimal zones for hydraulic stimulation (Track 4, yellow).

Caliper

in.

Depth,

ft166

10-in. Induction

ohm.m 2,0000.2

Crossover

Gamma Ray

Correlation Depth Resistivity Porosity Sonic Data Brittleness

gAPI 2000

Shear Wave Semblance

–11

highlow

Brittleness

1000

20-in. Induction

ohm.m %2,0000.2

Photoelectric Factor

200

30-in. Induction

ohm.m 2,0000.2

Density PorositySonic Waveform Amplitude

% –1030

60-in. Induction

ohm.m 2,0000.2

Neutron Porosity

% –1030

90-in. Induction

ohm.m 2,0000.2

Density Correction

g/cm3 0.25– 0.75

Possible Fractures More Brittle

X,050

X,100

X,150

52 Oilfield Review

> Forest Oil log montage. This Eagle Ford formation evaluation interpretation combines ThruBit data with cuttings analysis and computed rock properties to determine the optimal placement of fracture stages in a South Texas well. Although gas spikes (Track 5, green) are seen throughout this interval, the sweet spot in this horizontal well extends from about W,700 to Z,400 ft measured depth. Onsite geochemical analysis of wellbore cuttings obtained through this interval shows a marked increase in total organic carbon, or TOC, (Track 2, black dots) and S2—hydrocarbons generated by thermal breakdown of kerogens (Track 2, purple curve), key indicators of source rock quality. Sonic data (Track 7) show a clear change in the elastic properties of the formation in this zone. While the P-wave maintains a constant slowness (solid black) throughout the interval, the S-wave splits into two distinct arrivals. The spread between the fast (dashed black curve) and slow (black dotted) S-wave slownesses is an indicator of anisotropy, possibly attributed to fractures. Using all of the data together, Forest Oil elected to divide the stimulation program into 19 stages. After the stimulation treatment, tracer logs (Track 6) helped verify that modifications to the stimulation program created more complex fractures throughout each stage, opening more rock face to production. This optimized completion strategy resulted in increases in production relative to surrounding wells that had used simple geometric fracture treatments.

Stage 1

Stage 3

Stage 4

Stage 6

Stage 7

Stage 9

Stage 12

Stage 13

Stage 15

Stage 16

Stage 18

Stage 19

Stage 10

Stage 2

Stage 5

Stage 8

Stage 11

Stage 14

Stage 17

U,000

V,000

W,000

X,000

Y,000

Z,000

MeasuredDepth,

ftTVD

Stagesft U,200V,200

Shear Slownessμs/ft 40440

Compressional Slownessμs/ft 40140

Neutron Porosity% –1545

TVDft U,200V,200

highlow

Mud Log Total Gas 5000

Shear Wave Semblance 0.51

TVDft U,200V,200

highlow

Strontium TracergAPI 2,0000

Scandium TracergAPI 2,0000

Iridium Tracer

Fast Shear Slowness

Compressional SlownessgAPI 2,0000

Sonic Waveform Amplitude

Slow Shear Slownessμs/ft %24040

μs/ft 24040TVD

Brittleness 1000

ft U,200V,200

μs/ft 24040

Semblance

TVD

Cuttings Lithology Depth Fracture Sonic Data Sonic Waveform Mechanical PropertiesTracersResistivity, S2, TOC Density, Neutron, Sonic

ft U,200V,200

Cuttings: S2mg/g 250

Total Organic Carbon 100

Total Organic Carbon 100

S2mg/g

%

%

250

TVDft U,200V,200

Bulk Densityg/cm3 2.951.95

10-in. Inductionohm.m 2,0000.2

30-in. Inductionohm.m 2,0000.2

90-in. Inductionohm.m 2,0000.2

Porosity

Total Organic Carbon

Pyrite

Carbonate

Quartz

Total Clays

Summer 2012 53

properties (previous page). This information was used in 3D fracture design programs to opti-mize and confine the fractures to the Eagle Ford and overlying productive Austin Chalk forma-tions. Based on these log data, the company now plans 220-ft [67-m] fracture stages and has saved on stimulation costs by reducing the vol-ume of sand pumped into each stage by one-third. Wells stimulated in this manner are producing significantly better than those frac-tured using the previous geometric approach, and none have produced the high-salinity water associated with deeper formations. Overall, Forest Oil has reduced completion cost per stage by about 60% while increasing the number of stages per lateral section. Also, oil production averaged over a 30-day period has doubled in comparison with the output of earlier wells.

Evaluation ToolsTo increase wellbore exposure to unconventional reservoirs, operators usually need to drill horizon-tal wells. These formations generally exhibit high natural gamma ray activity, so gamma ray logs are useful for distinguishing lithologies. Although effective as correlation tools, gamma ray measure-ments are not sufficient for distinguishing produc-tive from nonproductive zones, much less for designing stimulation programs.5

Rather than relying on a geometric approach to developing these wells, operators who run a comprehensive suite of logs across the target

zone can base their completion programs on res-ervoir quality and geomechanical properties. With this information, operators can selectively target the best zones to stimulate, while elimi-nating unproductive zones from their completion program. Compressional and shear velocity mea-surements from the SureLog multireceiver mono-pole sonic tool provide input for the ThruBit Geo-Frac analysis program to compute rock prop-erties, Poisson’s ratio, static Young’s modulus and minimum horizontal stress gradient. The stress data and indicators of reservoir quality, such as clay content and porosity, are useful in selecting optimal completion zones for hydraulic stimula-tion. Using the Geo-Frac analysis, the operator can identify zones along the lateral that are most likely to be productive (above).

Data from the Geo-Frac program may also be imported into Mangrove stimulation modeling software, which was developed by Schlumberger to address unconventional hydraulic fracture design. The Mangrove system generates a score based on reservoir quality and completion quality to rank the intervals of similar rock properties along a wellbore. Those intervals that score high in reservoir quality and completion quality are prime candidates for hydraulic fracture stimula-tion. This evaluation facilitates selection of loca-tions for optimal completion stages and perforation clusters.

Portal of OpportunityHigh-angle and extended-reach wells have been central to the development of new plays in tight res-ervoirs and organic-rich source rocks. To increase wellbore exposure to productive zones in these

plays, many operators drill horizontal wells; but drilling is only part of the story—well stimulation is another key to unlocking resources from formations previously deemed unproducible. Hydraulic frac-turing is typically required to stimulate these tight formations, and a number of advanced programs have been developed to help operators optimize the fracturing process for each well. All of these pro-grams rely on petrophysical data.

Well logs are vital for identifying intervals likely to benefit most from stimulation. Operators who use this data-driven approach to selecting fracture intervals are able to reduce the amount of sand, water and horsepower expended. Without log data, they might be left with no choice but to stimulate the entire length of horizontal section—with little regard to reservoir and completion quality.

The ThruBit conveyance system helps E&P companies obtain valuable formation data along the entire length of the wellbore. It provides a cost-effective and operationally efficient alterna-tive to standard wireline conveyance or LWD log-ging while saving trip time. With a Portal bit conditioning the hole before the slim-diameter logging tools are run, the ThruBit system can acquire petrophysical data in the challenging, high-deviation and extended-reach wellbores that are common to unconventional plays. Using the drillstring as a protective conduit for the logging tools and wireline, this system reduces tool expo-sure to the openhole environment. ThruBit logging increases the likelihood of acquiring quality reser-voir log data on the first attempt, particularly when hole conditions threaten the success of con-ventional conveyance methods. If the bit can reach the target, so can the logging tools. —MV

> Geo-Frac evaluation of a horizontal well in the Bakken formation. SureLog compressional and shear sonic data (Tracks 4 and 5) are used to compute Poisson’s ratio (Track 6, red). Young’s modulus (Track 6, green), is derived from sonic and bulk density data. The brittleness curve (Track 7), which is estimated from Young’s modulus and Poisson’s ratio, indicates how easily the rock will fracture under hydraulic pressure. The fracture gradient (Track 8) may be used as an indicator of stress, showing contrasts along the length of the lateral with lower stresses (red and white) and higher stresses (blue). Used in conjunction with the other data presented, the brittleness and fracture gradient curves help operators determine intervals best suited for initiating fractures (Track 7, red).

Caliperin.

Depth,ft155

Gamma RaygAPI 1500

Brittleness 1000 %

Fracture Gradient 10 psi/ft

60-in. Induction ResistivityCompressional

Slowness

CompressionalSemblance

ohm.m μs/ft200 2400.2 0

highlow90-in. Induction Resistivityohm.m 2000.2

Static Young’s Modulus 100

Poisson’s Ratio 10

psi × 106

Photoelectric Factor

200

Density Porosity% –1030

Neutron Porosity% –1030

Density Correctiong/cm3 0.25– 0.75

Shear Slowness

ShearSemblance

μs/ft 2400

highlow

More Brittle Fracture Gradient

X,250

5. Kok J, Moon B, Han SY, Tollefsen E, Baihly J and Malpani R: “The Significance of Accurate Well Placement in the Shale Gas Plays,” paper SPE 138438, presented at the SPE Tight Gas Completions Conference, San Antonio, Texas, USA, November 2–3, 2010.

Victor Aarre, based in Stavanger, is the Geophysics Advisor for the Schlumberger Information Solutions Norway Technology Center, where he works closely with the Petrel* engineering, commercialization and portfolio teams. Since joining Schlumberger in 1995, he has worked in various research and engineering positions. His research focuses on improved reservoir characterization and interpretation technologies for faults and fractures. Victor holds an MSc degree in computer science from the University of Bergen, Norway.

James Aivalis, now retired, was most recently General Manager of ThruBit Logging Solutions in Houston and has more than 30 years of experience in the oilfield services industry. Prior to the Schlumberger acquisi-tion of ThruBit LLC, a Schlumberger company, he was CEO, president and a member of the board of directors for ThruBit LLC. Before joining ThruBit, he was a man-aging director at TenarisConnection, with responsibil-ity for the company’s Premium Connections product line and related services for oil country tubular goods. He began his career with Schlumberger in 1981 as a wireline field engineer and later held line manage-ment and staff positions within various Schlumberger business segments both in the US and internationally. Jim, who holds multiple patents, received a BSc degree in ocean engineering from Florida Institute of Technology, Melbourne, USA.

Taha Nasser Ali Al Dayyni is a Senior Reservoir Geologist for the Abu Dhabi Company for Onshore Oil Operations (ADCO) in Abu Dhabi, UAE. Currently, he is responsible for developing a giant oil field for ADCO. Taha is a member of SPE and the Emirates Society of Geoscience.

Walt Aldred is Research Director and Scientific Advisor for Drilling at the Schlumberger Cambridge Research Center in England. Previously he worked in the North Sea and West Africa as a mud logger, moni-toring real-time drilling operations and evaluating pore pressure and geology. Since the early 1980s when he began working for Schlumberger, he has worked on the development of real-time drilling monitoring and evaluation of new drilling systems, including the early development of geosteering. He worked in engineering development and in marketing in Houston and has had a number of field assignments, including setting up and running the Port Harcourt Drilling Engineering Center in Nigeria. He is a founding member of the SPE Drilling Systems Automation Technical Section. Walt holds a joint BSc degree (Hons) in chemistry and geol-ogy from Durham University, England.

Donatella Astratti is a Research Geologist Advisor for Schlumberger Stavanger Research with more than 25 years of experience in integrated studies as an inter-pretation geophysicist and modeler. She joined ENI S.p.A. in Italy in 1985 and worked as part of field devel-opment asset teams in Italy and Nigeria. In 1997, she joined the Western Geophysical 4D & Reservoir Characterization R&D group and worked on North Sea and Middle East projects. For the last 15 years with Schlumberger, her primary focus has been the applica-tion of research and novel technologies to the charac-terization and modeling of Middle East carbonates and

naturally fractured reservoirs, maximizing the use of 3D seismic data. Donatella earned an MSc degree in geology from the University of Bologna, Italy. She is a member of the European Association of Geoscientists & Engineers (EAGE), the AAPG, SPE, SEG and SPWLA and is the 2012–2013 chair of the EAGE Oil and Gas Geoscience Division committee.

Zdenko Augustinovic works for DONG E&P in Hoersholm, Denmark. He is a Senior Chemical Engineer, specializing in corrosion and integrity man-agement. Zdenko attained a BSc degree in chemistry from the Technical University of Denmark, Copenhagen.

Øystein Birketveit is a Product Line Manager and Discipline Leader in Production Technologies for M-I SWACO, a Schlumberger company, in Bergen, Norway. For the past 14 years, he has specialized in the field of corrosion. Prior to joining M-I SWACO, Øystein worked for Statoil and for Det Norske Veritas. He received his MSc degree in materials and electro-chemistry from the Norwegian University of Science and Technology, Trondheim.

Jacques Bourque is the Schlumberger Vice President of Technology in Gatwick, England. He has 32 years of industry experience, mainly in drilling engineering and operations in Europe and Africa, North and South America and the Far East. His experience ranges from high-volume drilling operations to deep HPHT wells. His current focus is the automation of the drilling pro-cess. Jacques has a BS degree in civil engineering from the Université de Moncton, New Brunswick, Canada.

Clinton Chapman is the Drilling Automation Program Architect for Schlumberger in Sugar Land, Texas, USA. There he has spent the past 15 years in various roles related to the creation of software to support drilling engineering and real-time drilling data. He serves as Deputy Chair of the SPE Drilling Systems Automation Technical Section and holds a PhD degree in aerospace engineering from Texas A&M University, College Station.

Andrew Clark is a Principal Development Geologist with Shell International, seconded since 2011 to Petroleum Development Oman (PDO) in Muscat, Sultanate of Oman. His 30-year career in the oil industry also includes positions with Premier Oil plc, Woodside Energy and ADCO. He received an MSc degree in geology from The University of Auckland, New Zealand.

Kayli Clements is the Manager of Environmental Treatment Services in the M-I SWACO Environmental Affairs Department in Houston. She provides global support for onshore waste management issues through greenhouse research, technical knowledge and cus-tomer involvement. Her areas of concentration are in beneficial reuse of drill cuttings, water recycling and development of ecotoxicity tests to qualify fluids and additives for onshore drilling. She has been an advisor on oilfield bioremediation projects in several countries and has extensive regulatory knowledge and design experience on land disposal and treatment of drilling residuals. Kayli, who has worked for M-I SWACO since 2006, earned a BS degree in biological engineering from Louisiana State University, Baton Rouge, USA.

Benjamin W. Crouch is the Cofounder, Executive Vice President and Chief Operating Officer of Osage Resources, LLC. He has 18 years of industry experi-ence and started his career as a research geologist at Kansas State University, Manhattan, USA, then worked briefly as a geologist for the state of Kansas before he moved to Petroglyph Energy, Inc. in Boise, Idaho, USA. There he worked as manager of geology and opera-tions, overseeing projects in Colorado, Texas and Utah, USA. He gained experience in both conventional and unconventional exploration and development plays before forming Osage Resources. Ben has presented papers on carbonate and siliciclastic reservoirs, is a member of AAPG and SPE and is a Registered Professional Geologist in Kansas. He obtained a bache-lor’s degree from the University of West Georgia, Carrollton, USA, and a master’s degree from Kansas State University, both in geology.

Geoff Downton, based in Stonehouse, England, is Senior Drilling Advisor to the Schlumberger Drilling Group president and a Schlumberger Fellow. He began his career in England in 1976 as a systems engineer with Sperry Gyroscopes, now known as British Aerospace. While at British Aerospace, he advanced from senior principal engineer to chief projects officer, working on strapdown inertial navigation systems, optical tracking systems, vertical references and gyro sensor development. In 1989, he joined the nuclear industry as a research officer, and nine years later he joined Camco (later acquired by Schlumberger) as engineering manager for the PowerDrive* rotary steer-able system; he has remained active in guiding direc-tional drilling technology. Geoff holds a BSc degree (Hons) in mechanical engineering from the University of Birmingham, an MSc degree in control systems engi-neering from City University, London, and a PhD degree in cybernetics from Brunel University, Uxbridge, all in England.

Bertrand du Castel is a Schlumberger Fellow whose focus is on using neuroscience for human-centered drilling automation. He is coauthor of Computer Theology: Intelligent Design of the Worldwide Web (Midori Press, 2008) and has publications in artificial intelligence, linguistics, logic and computer engineer-ing as well as drilling, earth modeling and geothermal technology. Bertrand, who is based in Sugar Land, Texas, received a PhD degree in computer science from the University of Paris and an engineer diploma from École Polytechnique, France.

Ian Falconer joined Schlumberger as a field engi-neer in 1981. Currently based in Houston, he is the Marketing and Technology Manager for the Schlumberger Drilling Group. He has worked pre-dominantly in the directional drilling and LWD busi-ness line in various operations, marketing and engineering roles. Previously, Ian was the marketing manager for Integrated Project Management ser-vices, vice president of marketing for Schlumberger Oilfield Services in the Middle East and Asia and vice president of industry affairs and global account director responsible for managing the Shell global account. Ian has a BSc degree (Hons) in geology from Cardiff University, Wales.

Contributors

54 Oilfield Review

Fred Florence, based in Cedar Park, Texas, joined National Oilwell Varco in 1996 and currently is a mem-ber of the Corporate Engineering team as Product Champion for Automation and Drilling Optimization. Prior to joining National Oilwell Varco, he worked for Sedco-Forex, now Transocean, where he held various positions in engineering and operations. Fred obtained a BS degree in electrical engineering from Southern Methodist University, University Park, Texas, as well as an MA degree in international management and an MBA degree in marketing from The University of Texas at Dallas.

Mike Freeman is a Scientific Advisor for M-I SWACO in Houston. He works with industry clients and organi-zations and serves as a technology champion, working on projects as diverse as improving ROP when drilling carbonates and real-time chemical analysis of drilling fluids. Mike began his career in 1985 with Exxon as a research chemist and joined M-I Drilling Fluids in 1993. During his career, he has published numerous industry papers.

Elizabeth Godinez Zurita, based in Villahermosa, Mexico, is a Well Engineer for Schlumberger; she is currently working in Rio de Janeiro, where she offers operations support on a project with OGX Petróleo e Gás Participações SA. Her responsibilities include fol-lowing up and supporting real-time operations and monitoring drilling parameters. She began her career with the company in 2008 as a field engineer trainee in Mexico. Elizabeth received a BS degree in civil engi-neering from the Universidad del Valle de México, Mexico City.

Santosh Gopi, who is a Business Development Manager for M-I SWACO Production Technologies, joined the company in 2008. Before that, he worked on joint projects for Henkel Oilfield Chemicals and Antico Chimie, now Scomi Anticor SA, in Nigeria, where he received training on production chemical formulation and application and on bioremediation projects. Santosh has more than 18 years of experience in the industry and holds a postgraduate diploma in petro-leum engineering from the Azerbaijan Institute of Petroleum and Chemistry, Baku.

Randy Hansen has been Schlumberger Drilling Automation Program Manager in Sugar Land, Texas, since 2010. His main responsibility is to achieve drill-ing optimization through automation that uses down-hole and subsurface data to control drilling parameters to achieve consistent best-in-class perfor-mance. He began his career with the company more than 30 years ago as a general field engineer in south Texas and has since held positions across several con-tinents and Schlumberger businses segments. Randy earned a BS degree in physics from The University of Kansas, Lawrence.

Richard Harmer is the Drilling Performance Product Champion for Schlumberger Drilling & Measurements in Stonehouse, England. His role focuses on marketing and leading the development of products related to drilling mechanics and dynamics and ROP optimiza-tion. In his prior position, he was an engineer on drill-ing, planning and execution for the worldwide InTouchSupport.com* online support and knowledge

management system. Richard has 11 years of experi-ence with Schlumberger and started as an MWD and LWD engineer in Alaska, USA. He received an MS degree in mechanical engineering from Loughborough University, Leicestershire, England.

Thomas Ishoey is Chief Technology Officer of Glori Energy, Inc. Previously, he was vice president for sub-surface hydrocarbons at Synthetic Genomics, Inc. in La Jolla, California, USA. Thomas, who specializes in applied microbiology and biotechnology research and development, has pioneered the use of micromanipula-tion of microbial-size cells for whole genome amplifi-cation and genomic analysis and applied the technology for the discovery of uncultured microbes from environments as diverse as subsurface environ-ments, marine sediments, soil, bioreactors and human biopsies. His experience also includes design, con-struction and operation of bioreactors using anaerobic microbes and applying these methods for quantitative studies of anaerobic metabolism. He has served as a visiting researcher at the University of California, Los Angeles, and has an MS degree in chemical engi-neering and a doctoral degree in biotechnology, both from the Technical University of Denmark, Copenhagen.

Graham Jackson is a Senior Staff Engineer with Husky Energy Inc., in Calgary, where he has worked for nine years. Prior to joining Husky, Graham worked for Dome Petroleum, Amoco, Crestar Energy and Newport Petroleum, all in Calgary. He is a member of the Association of Professional Engineers and Geoscientists of Alberta, the Association of Professional Engineers and Geoscientists of Saskatchewan and the SPE. Graham holds a diploma in reservoir technology from the Southern Alberta Institute of Technology, Calgary, and a BS degree in petroleum engineering from the Montana College of Mineral Science and Technology, Butte, USA.

Gregory Kubala, Chemistry Métier Manager for Schlumberger Pressure Pumping and Chemistry, began his career with Schlumberger in 1982. During the last 30 years, he has been involved in the develop-ment of more than 65 chemical products in various roles within R&D, engineering, manufacturing and sus-taining. He has also served in environmental manage-ment and personnel positions. As métier manager, he works within the technical community to identify new technologies for product development, increase the competencies within the technical community and improve the product development process. Gregory earned BS and PhD degrees in chemistry from the University of Rochester, New York, USA, and Texas A&M University, College Station, respectively. He has published 18 papers and has been named inventor or coinventor on 25 patents.

Jan Larsen is a Senior Production Chemist at Maersk Oil in Copenhagen, where he has worked since 1983. His areas of focus are reservoir souring, chemical treat-ment concepts for combating H2S production, modeling of H2S production, H2S scavenging and microbiologically influenced corrosion and the implementation of molecu-lar techniques for improved microbial monitoring of souring and corrosion. Jan received a master of science degree in chemistry from the Technical University of Denmark, Copenhagen.

Sabry Lotfy Mahmoud, a Senior Geophysicist for ADCO in Abu Dhabi, UAE, is responsible for developing a giant oil field in the UAE. He has multidisciplinary oil industry experience in seismic data processing, geosci-ence data management, IT and application support, seismic interpretation and reservoir characterization. He worked for the E&P division of the Gulf of Suez Petroleum Company in Cairo for the first 10 years of his career. Sabry has a BSc degree from Cairo University and MSc and PhD degrees from Al-Azhar University, Cairo, all in geophysics. He is a member of SPE and the Emirates Society of Geoscience.

Mike Mannering, based in Gatwick, England, is the Schlumberger President of Rig Management. He has 38 years of industry experience, mainly in drilling engi-neering, well operations and drilling contracting in Europe, North and West Africa, the Middle East and the Far East. His current focus is fit-for-purpose advanced technology drilling rigs and automation of the drilling process. Mike obtained a BS degree in mechanical engineering from the University of Southampton, England.

Brian W.G. Marcotte is President and CEO of Titan Oil Recovery, Inc., a service provider specializing in microbiologically enhanced oil recovery. Prior to join-ing Titan, he held technical and executive positions at Unocal Corporation, where he served as president of Unocal Netherlands, Unocal Indonesia and Unocal Thailand. He is a Registered Petroleum Engineer in Alaska, and was recognized as a 2005 distinguished member of the SPE. Brian earned a BS degree in petroleum engineering from the University of Southern California, Los Angeles, and pursued graduate studies in engineering management at the University of Alaska Anchorage.

Tony Meszaros is the Business Manager for ThruBit LLC in Houston. He also serves as Vice President for the ThruBit LLC board of directors. Tony began his career with Schlumberger Wireline as a field engineer in 1995 and has since been a sales engineer, opera-tions and integration manager, a champion for person-nel management development and a general field engineer. Before assuming his current position, he was the global perforating business development manager at the Schlumberger Reservoir Completions Technology Center in Rosharon, Texas. Tony holds a BSc degree in civil engineering from the South Dakota School of Mines and Technology, Rapid City, USA.

Claudio Nieto is the Burgos field Asset Manager for Petróleos Mexicanos (PEMEX). He is based in Villahermosa, Mexico.

Robert Porter joined ThruBit LLC in 2006 as Operations Manager; he is based in Houston. He previ-ously worked for Halliburton in operations in West Africa and for the manufacturing and technology group in Houston. He has 14 years of experience in the oil industry and was initially involved in the design and commercialization of ThruBit logging equipment and techniques. He has a degree (Hons) in mechanical engineering from the Royal Military College of Science, Shrivenham, Oxfordshire, England.

Summer 2012 55

Ole V. Vejbæk is Geophysical Advisor at Hess Corporation in Copenhagen, Denmark. Before joining Hess, where he has worked for four years, he was a senior researcher and research professor at the Geological Survey of Denmark and Greenland. Ole earned a PhD degree in geoscience from Københavns Universitet in Copenhagen, Denmark.

Peter Wells, based in Houston, was the first employee of ThruBit LLC. In his role as ThruBit Senior Vice President of Engineering and Manufacturing, he put in place the development team that created the SureLog* suite of logging tools and oversaw their manufacture and support. Prior to joining ThruBit, he was a director of a privately held oil and gas data ser-vices company and has held various positions with Schlumberger, including engineering manager in the downhole tool development center, operations man-ager and field engineer. He received an MA degree in engineering science from Merton College, University of Oxford, England, and a master of science degree in petroleum engineering from Heriot-Watt University, Edinburgh, Scotland.

Gillian White is a Geoscience Team Lead at Hess Corporation in Copenhagen, Denmark, where she has worked for four years. Gillian’s career spans 20 years in the oil industry working in exploration, development and production geoscience in north-west Europe. Before working for Hess in Denmark, she worked for Shell Expro and for Hess in London. Gillian holds a BSc degree in geology from Newcastle University, Newcastle-Upon-Tyne, England. She also has an MSc degree from the University of Reading, England, and a PhD degree from Keele University, England, both in sedimentology.

Mario Zamora, based in Houston, is the Applied Engineering Manager for M-I SWACO, a position he has held since 1987. He began his career in 1967 as a drilling engineer with Shell, where he worked for four years. Mario attained a BS degree in mechanical engi-neering from The University of Texas at Austin.

spectroscopy tools. Gary is a member of the SPWLA, AAPG and SPE.

Torben Lund Skovhus has worked as a consultant in the oil and gas industry for the last 10 years and cur-rently works at the Danish Technological Institute (DTI) as a Team Leader for DTI Oil & Gas in Aarhus, Denmark. He chairs the Technical and Scientific Committee of the International Symposium on Applied Microbiology and Molecular Biology in Oil Systems and is a member of the SPE, the National Association of Corrosion Engineers and the microbi-ology committee at the Energy Institute, London. Torben is the author of several scientific and techni-cal articles and is the coeditor of Applied Microbiology and Molecular Biology in Oilfield Systems (Springer, 2011). He earned a PhD degree in molecular microbiology from Aarhus University.

Rob Stauder has worked for Helmerich & Payne, Inc. for 28 years and is currently Senior Vice President and Chief Engineer. Based in Tulsa, he has held a vari-ety of field and engineering positions with the com-pany, including roughneck, driller, drilling engineer, project engineer, project manager, operations man-ager and manager of deepwater engineering. Rob has a BS degree in petroleum engineering from The University of Oklahoma, Norman.

Michael J. Stellas, a Senior Technical Advisor at Spectra Energy Corporation in Houston, is responsible for all aspects of subsurface work in preparing depleted hydrocarbon reservoirs for gas storage. He is a petroleum geologist with 36 years of E&P experi-ence in locations around the world. He has additional experience in business development, integrated exploration software systems, data management, inte-grated field development projects and natural gas storage systems. Michael obtained a BS degree in geology from the University of Tennessee, Knoxville, USA, and an MS degree in geology from Rutgers University, Newark, New Jersey, USA.

Jack W. Stringer, based in Houston, is the Storage Design Manager for Spectra Energy Corporation, where is he responsible for subsurface designs of all new storage projects in the US, including both reser-voir and salt projects. His group is also responsible for storage project drilling and completion efforts. He has 36 years of experience in engineering and construc-tion, working with both liquid and gas storage. Jack received his BS degree in civil engineering from Texas A&I University in Kingsville, USA.

Egil Sunde has worked in the oil industry for 31 years, 27 of which were with Statoil. During that time, he held a variety of technical positions and is currently a Specialist in Reservoir Technology in Stavanger. Egil holds an MS degree in marine microbiology from the University of Bergen, Norway.

Brian Toelle is a Schlumberger Geosciences and Petroleum Engineering Advisor on exploration and geophysics. Based in Denver, he is responsible for project management, is a lecturer and has consulted on projects worldwide. He has more than 31 years of experience in the industry, specializing in the use of geologic and geophysical methods. He joined Schlumberger in 1997 and has spent the majority of his career with the company in consulting services, managing a geoscience team in Pittsburgh, Pennsylvania, USA. Brian is completing his PhD degree in applied geophysics from West Virginia University, Morgantown, USA.

Taylor L. Reid, who is based in Houston, has served as Director, Executive Vice President and Chief Operating Officer of Oasis Petroleum, Inc. since the inception of the company in March 2007. He has 25 years of experience in the oil and gas industry. Previously, he was the asset manager for Permian and Panhandle operations with ConocoPhillips. Prior to joining ConocoPhillips, he served as general manager Latin America and Asia operations and general man-ager of corporate acquisitions and divestitures with Burlington Resources in Houston. Taylor received a BSc degree in petroleum engineering from Stanford University in California.

Rick Reischman, based in Houston, provides Technical Sales Support and is a Petrophysical Advisor for ThruBit LLC. His work experience includes 32 years with Schlumberger in various assignments, including wireline, petrophysics, image analysis and sales. Rick has a BS degree in mechani-cal engineering from The University of Texas at Austin. His professional affiliations include the SPE, SPWLA and AAPG.

Robin Ridley is the Sales and Marketing Manager for ThruBit LLC in Houston. Before this, he was a business development manager for the company. Previously, Robin worked at Halliburton as a senior account leader. He has 35 years of experience in the industry and earned a BSc degree in behavioral sci-ences from Sam Houston State University, Huntsville, Texas, USA.

Jan Scheie is a Senior Field Services Coordinator at the M-I SWACO Technical Operations and Services Center in Stavanger, Norway, where he serves custom-ers in Scandinavia. He has also been an account man-ager for production technologies, an international sales manager and an area manager for production chemicals in Stavanger. He has worked for M-I SWACO in market development for the eastern hemisphere, as technical manager in the Middle East and CIS, as sales manager in South Asia and as principal engineer for developing sales strategy in mainland Europe. Jan holds an MSc degree in chemical engineering from the Norwegian University of Science and Technology, Trondheim, and an MBA degree from the Thunderbird School of Global Management, Glendale, Arizona, USA. He is a member of TEKNA, the Norwegian Society of Graduate Technical and Scientific Professionals; the SPE; and the National Association of Corrosion Engineers.

Gary A. Simpson serves as Senior Petrophysical Advisor for Forest Oil Corporation in Houston. He works with asset teams that are currently focused on development projects in the Eagle Ford Shale forma-tion. He has also worked for Shell and ConocoPhillips on conventional, unconventional and tight gas reser-voirs. Previously, he worked in the oilfield service sec-tor holding positions with Halliburton, Computalog Inc., now part of Weatherford International, and Perf-O-Log, Inc., now part of Schlumberger. During his 33-year career, he has been a global product cham-pion for pulsed neutron tools and has worked in field engineering, sales, interpretation development, petro-physics and technical marketing. He has written more than 20 technical papers and articles, primarily related to the development of interpretation methods and logging techniques for measurements made with pulsed neutron, carbon oxygen and gamma ray

56 Oilfield Review

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

Contents:

Written by a leader in modern applied mathematics,

is a unified and well-organized synthesis of the physical ideas and mathematical techniques behind the multiscale approach to understanding physical phenomena. . . .

reflects its author’s breadth of experience and interest in physics, mathematical analysis, and scientific computation. It is ambitious in scope and in its insistence on taking seriously all stages in multiscale modeling, from fundamental physical models to efficient computational algorithms by way of rigorous mathematical analy-sis. I am not aware of any other work that covers all those topics with equal attention and rigor.

I do have a quibble with this book. It seems to have been produced cheaply using standard LaTeX macros and fonts; even the cover design is undistinguished.

Nevertheless, is uniquely

suitable for advanced graduate students and researchers who want to survey the field’s full range of physi-cal ideas, mathematical techniques, and computational algorithms.

Physics Today

Dr. Trudy Wassenaar, author and curator of the Virtual Museum of Bacteria . . . sees her book as an antidote for bacterial bad news, and the dosage is [many] pages of bacte-rial wonderment. Within the pages, she celebrates bacterial diversity, and quite humorously explains how bacteria feast on other species, move, and reproduce. . . . [The book is] written in a unique and comical voice. Some jargon is unavoidable, but the concepts are well illustrated, and a glossary is provided. . . . Bacteria are fascinating little creatures that are deserving of the stories contained within

. The reader’s viewpoint may very well change after hearing them.

New York Journal of

Books

Principles of Multiscale ModelingWeinan ECambridge University Press32 Avenue of the AmericasNew York, New York 10013 USA2011. 488 pages. US$ 75.00

This book offers a unified treatment of multiscale modeling, which provides a framework for constructing mathemati-cal and computational models by examining the connection between models at different scales. The author focuses on the two most prevalent applications of multiscale modeling: capturing macroscale behavior and resolving local events. The book also examines specific problems with multiple time scales.

Bacteria: The Benign, the Bad, and the BeautifulTrudy M. WassenaarJohn Wiley & Sons, Inc.111 River StreetHoboken, New Jersey 07030 USA2012. 232 pages. US$ 39.95

This comprehensive guide to the life and behavior of bacteria looks at the origins and evolution of bacteria and the ways that bacteria have shaped the world. The author describes bacteria found in the human body as well as those found in environmental extremes, from arctic ice to hydrocarbon reserves. Also included are numerous illustra-tions and color plates.

Contents:

Summer 2012 57

NEW BOOKS Coming in Oilfield Review

Plate Tectonics in Exploration. In the last decade, explorationists have had success finding oil and gas in rifted margin and transform margin fault systems. The rifted margin play has been important for the presalt discoveries off the coast of South America, and the application of plate tectonics theory allowed explora-tionists to apply the concept offshore southern Africa. Operators have also been successful in the trans-form margin, upper Cretaceous turbi-dite-fan play in West Africa and within the last few years, using the principles of plate tectonics, have extended the play to the Guyanas in South America. This article will describe how explorationists use plate tectonics to explore rifted mar-gin and transform margin systems.

Carbon Capture and Storage. The United Nations Intergovernmental Panel on Climate Change proposes to limit global temperature change by preventing greenhouse gases from entering the atmosphere. One strat-egy in that objective is the process of carbon capture and storage, which removes CO2 from emissions created by the burning of hydrocarbons. This article looks at the role of upstream expertise in this process and how it is being applied today in projects in the midcontinental US.

Thermal Rock Properties. Enhanced recovery techniques using thermal stimulation account for more than half of worldwide oil produc-tion. Project economics can hinge on accurately predicting this additional production using reservoir simula-tion, which in turn requires accurate knowledge of the thermal properties of reservoir fluids and rocks. Thermal properties of reservoir rocks, how-ever, are rarely measured. This arti-cle reviews rock thermal property measurements and describes an effi-cient new optical technique for obtaining them.

Oilfield Review

Fluid Mechanics, Heat Transfer, and Mass Transfer: Chemical Engineering PracticeK.S.N. RajuJohn Wiley & Sons, Inc.111 River StreetHoboken, New Jersey 07030 USA2011. 768 pages. US$ 158.00ISBN: 978-0-470-63774-6

This text presents the three core areas of chemical engineering. Raju empha-sizes practice rather than theory and uses a question and answer format to bridge theory to practice. The book, which offers analysis on all facets of chemical engineering, is intended for both students and practitioners.

Contents:

Fluid Mechanics Basics; Fluid Flow; Piping, Seals, and Valves; Flow Measurement; Pumps, Ejectors, Blowers, and Compressors; Mixing; Two-Phase Flow Systems

Dimensionless Numbers, Temperature Measurement, and Conduction Heat Transfer; Convective Heat Transfer Basics; Shell and Tube Heat Exchangers; Heat Transfer Equipment Involving Phase Transfer; Refrigeration, Heat Pumps, Heat Tracing, Coiled and Jacketed Vessels, Steam Traps, and Immersion Heaters; Compact Heat Exchangers, Regenerators, and Recuperators; Radiant Heat Transfer and Fired Heaters

Mass Transfer Basics; Mass Transfer Equipment; Absorption, Distillation, and Extraction; Crystallization, Air-Water Operations, Drying, Adsorption, Membrane Separations, and Other Mass Transfer Processes

This work is a useful reference for practicing and consulting engineers in mechanical, chemical, pharmaceu-tical, and environmental engineering and other related fields. Raju . . . developed the book using an inquisi-tive, idiosyncratic question-and-answer style. . . . [T]he author implements a unique bullet format to

describe hundreds of devices and types of equipment. . . . [I]n no way can this book replace classical textbooks on fundamental fluid mechanics, chemical thermodynam-ics, and heat and mass transfer. However, it definitely offers a helpful way for engineering students . . . to obtain quick familiarity with equip-ment and devices that are central to a wide range of engineering applica-tions. . . . [The author provides] a lucid, thorough approach to the subject. Recommended.

Choice 49, no. 2

Volcanoes of the World, Third EditionLee Siebert, Tom Simkin and Paul KimberlyUniversity of California Press 2120 Berkeley WayBerkeley, California 94704 USA2011. 568 pages. US$ 75.00 ISBN: 978-0-520-26877-7

The third edition of this resource documents 10,000 years of volcanic activity and includes new studies and assessments of the geologic ages of many volcanoes and the thousands of volcanic eruptions that have taken place since the book’s last edition in the mid-1990s. This edition includes new photographs, new data on rock types of each volcano and data on human population near volcanoes.

Contents:

Introduction; Data Table Summaries; Volcano Data; Eruption Data; Historical Record: Trends and Cautions

. . . this work covers four decades of data gathering by the Smithsonian’s Global Volcanism Program. . . . It documents Holocene volcanic activity across the globe, and with this edition expands into the Pleistocene. . . . Much of the book’s data can be found on the GVP Web site. . . . The Web site is more interac-tive and includes video and many more images, while the book provides more narrative about volcanism in general and appears to include more detailed information about the socio-economic impact of specific events. Together, the two resources make an excellent team. Highly recommended.

Choice

The Story of Earth: The First 4.5 Billion Years, from Stardust to Living PlanetRobert M. HazenViking, a division of Penguin Group (USA) Inc.375 Hudson StreetNew York, New York 10014 USA2012. 320 pages. US$ 27.95ISBN: 978-0-670-02355-4

Taking the view of an astrobiologist, historian, naturalist and futurist, Robert M. Hazen explains, through changes at an atomic level, the shifts in the Earth’s makeup during its 4.5-billion-year existence. He presents a theory of coevolution to describe reactions between organic molecules and rock crystals, which, he posits, may have generated the Earth’s first organisms. The author also tells the story of the men and women behind the earth sciences described in the book. He then ventures into the far future of the planet.

Contents:

Cramming billions of years of geological evolution into a single book is a daunting challenge, but it’s one that Hazen, a geophysicist, has risen to splendidly.

Science News

. . . Hazen and colleagues at the Carnegie Institution’s Geophysical Laboratory (with support from NASA) have succeeded in simulating condi-tions that would have existed on Earth as early as 4.5 billion years ago, while producing biomolecules that are today the building blocks of life. The author situates this latest experimen-tal evidence in a series of discoveries about the earth’s geological evolu-tion, sparked by analysis of moon rocks brought back by Apollo astro-nauts. A report of a fascinating new theory on the Earth’s origins written in a sparkling style with many per-sonal touches.

Kirkus Reviews

58

> Basic two-plug primary cementing operation. After a well interval has been drilled to the desired depth, the drillpipe is removed and a casing string is lowered to the bottom of the borehole (top). The bottom of the casing string is usually fitted with a protective shoe, and centralizers keep the casing centered in the wellbore. Engineers pump chemical washes and spacer fluids down the casing interior, thereby displacing drilling fluid (middle left). They next insert a bottom plug, followed by a volume of cement slurry that is sufficient to fill the annulus (middle right). Continued pumping of cement slurry forces drilling fluid out of the casing interior, up the annulus and out of the wellbore. When the bottom plug lands at the bottom of the casing string, a membrane in the plug ruptures, opening a pathway for the cement slurry to enter the annulus. Engineers insert a top plug after the cement slurry, and the top plug is then followed by a displacement fluid (bottom left). Pumping the displacement fluid forces the top plug downward until it lands on the bottom plug, thereby isolating the casing interior and annulus and filling the annulus with cement slurry (bottom right).

Displacement

Displacementfluid

Chemical wash

Bottom plug

Cement slurry

Spacer fluid

Top plug

Circulating Drilling Fluid

Pumping Wash, Spacer and Cement Slurry

Displacement Completed Job

Drilling fluid

Casing string

Annulus

Shoe

Centralizers

Summer 2012 59

DEFINING CEMENTING

Well Cementing Fundamentals

Oilfield Review Summer 2012: 24, no. 2. Copyright © 2012 Schlumberger.

Erik B. NelsonContributing Editor

Well cementing consists of two principal operations—primary cementing and remedial cementing. Primary cementing is the process of placing a cement sheath in the annulus between the casing and the formation. Remedial cementing occurs after primary cementing, when engineers inject cements into strategic well locations for various purposes, including well repair and well abandonment.

Primary cementing is a critical procedure in the well construction pro-cess. The cement sheath provides a hydraulic seal that establishes zonal iso-lation, preventing fluid communication between producing zones in the borehole and blocking the escape of fluids to the surface. The cement sheath also anchors and supports the casing string and protects the steel casing against corrosion by formation fluids. Failure to achieve these objectives may severely limit the well’s ability to reach its full producing potential.

Most primary cementing operations employ a two-plug cement placement method (right). After drilling through an interval to a desired depth, a crew removes the drillpipe, leaving the borehole filled with drilling fluid. The crew then lowers a casing string to the bottom of the borehole. The bottom end of the casing string is protected by a guide shoe or float shoe. Both shoes are tapered, commonly bullet-nosed devices that guide the casing toward the cen-ter of the hole to minimize contact with rough edges or washouts during installation. The guide shoe differs from the float shoe in that the former lacks a check valve. The check valve can prevent reverse flow, or U-tubing, of fluids from the annulus into the casing. Centralizers are placed along critical casing sections to help prevent the casing from sticking while it is lowered into the well. In addition, centralizers keep the casing in the center of the borehole to help ensure placement of a uniform cement sheath in the annulus between the casing and the borehole wall.

As the casing is lowered into the well, the casing interior may fill with drilling fluid. The objectives of the primary cementing operation are to remove drilling fluid from the casing interior and borehole, place a cement slurry in the annulus and fill the casing interior with a displacement fluid such as drill-ing fluid, brine or water.

Cement slurries and drilling fluids are usually chemically incompatible. Commingling them may result in a thickened or gelled mass at the interface that would be difficult to remove from the wellbore, possibly preventing place-ment of a uniform cement sheath throughout the annulus. Therefore, engi-neers employ chemical and physical means to maintain fluid separation. Chemical washes and spacer fluids may be pumped after the drilling fluid and before the cement slurry. These fluids have the added benefit of cleaning the casing and formation surfaces, which helps achieve good cement bonding.

Wiper plugs are elastomeric devices that provide a physical barrier between fluids pumped inside the casing. A bottom plug separates the cement slurry from the drilling fluid, and a top plug separates the cement slurry from the displacement fluid. The bottom plug has a membrane that ruptures when it lands at the bottom of the casing string, creating a pathway through which the cement slurry may flow into the annulus. The top plug does not have a membrane; therefore, when it lands on top of the bottom plug, hydraulic communication is severed between the casing interior and the annulus. After the cementing operation, engineers wait for the cement

to cure, set and develop strength—known as waiting on cement (WOC). After the WOC period, usually less than 24 hours, additional drilling, perfo-rating or other operations may commence.

Oilfield Review60

DEFINING CEMENTING

Well construction typically consists of installing several casing strings,each requiring a primary cementing operation (right). As the well deepens, the diameter of each casing string is usually smaller than the preceding one.

Nearly all well cementing operations use portland cement, which consists mainly of anhydrous calcium silicate and calcium aluminate compounds that hydrate when added to water. The hydration products, principally calcium sili-cate hydrates, provide the strength and low permeability required to achieve zonal isolation.

The conditions to which portland cements are exposed in a well differ significantly from those encountered at ambient surface conditions associ-ated with buildings, roads and bridges. Well cements must perform over a wide temperature range—from below freezing in permafrost zones to tem-peratures exceeding 400°C [752°F] in geothermal wells. Consequently, cement manufacturers produce special versions of portland cement for use in wells. In addition, more than 100 cement additives are available to adjust cement performance, allowing engineers to customize a cement formulation for a particular well environment. The principal objective is to formulate a cement that is pumpable for a time sufficient for placement in the annulus, develops strength within a few hours after placement and remains durable throughout the well’s lifetime.

Additives may be classified according to the functions they perform. Accelerators reduce the cement setting time and increase the rate of com-pressive strength development. Retarders delay the setting time and extend the time during which a cement slurry is pumpable. Extenders lower the cement slurry density, reduce the amount of cement per unit volume of set product, or both. Weighting agents increase the density of the cement. Fluid loss control agents control leakage of water from the cement slurry into porous formations, thereby preserving the designed cement slurry properties. Lost circulation control agents limit flow of the entire cement slurry out of the wellbore into weak, cracked or vugular formations and help ensure that the cement slurry is able to fill the entire annular space. Dispersants reduce the viscosity of the cement slurry, which allows a lower pumping pressure during placement. Specialty additives include antifoam agents, fibers and flexible particles. Cement additives are an active domain of research and development, and the industry regularly introduces new and improved products.

After a cementing operation has been performed and the cement has set, engineers frequently perform tests to confirm that the cement sheath integ-rity and performance meet the intended design criteria. Cement evaluation techniques include hydraulic testing and various well logging methods.

Pressure testing is the most common hydraulic testing method; engineers typically conduct such tests after every surface- or intermediate-casing cement job. Engineers first perform a casing pressure test to verify the mechanical integrity of the tubular string and then drill out the casing shoe. Next, they perform a pressure integrity test by increasing the internal casing pressure until it exceeds the pressure that will be applied during the next drilling phase. If no leakage is detected, the cement seal is deemed successful.

Engineers may choose from several well logging techniques to evaluate the quality of the cement behind casing. The logging crew lowers measuring devices into the well and plots the acquired data versus depth. Temperature logs help locate the top of the cement column in the annulus. Cement hydra-tion is an exothermic process that raises the temperature of the surrounding environment. Data from acoustic and ultrasonic logging tools help engineers analyze the cement/casing and cement/formation interfaces. These tools pro-vide information about the quality of the cement sheath and how well the cement adheres, or bonds, to the casing and to the formation.

The cement bond log presents the reflected amplitude of an acoustic signal transmitted by a logging tool inside the casing. The cement-casing bond integrity is directly proportional to the attenuation of the reflected signal. Another acoustic log presents the waveforms of the reflected signals detected by the logging tool receiver and provides qualitative insights con-cerning the casing, the cement sheath and the formation. Ultrasonic logging tools transmit a short ultrasonic pulse, causing the casing to resonate. The tool measures the resonant echoes; when solid cement is behind the casing, the echo amplitudes are attenuated. When there is fluid behind the casing, the echoes have high amplitudes.

When logging operations indicate that the cement job is defective, either in the form of poor cement bonding or communication between zones, a remedial cementing technique known as squeeze cementing may be performed to estab-lish zonal isolation. Engineers perforate the casing at the defective interval and force, or squeeze, cement slurry through the perforations and into the annulus to fill the voids. In addition, squeeze cementing may be an effective technique for repairing casing leaks caused by a corroded or split casing.

When a well has reached the end of its productive life, operators usually abandon the well by performing plug cementing. Engineers fill the casing interior with cement at various depths, thereby preventing interzonal com-munication and fluid migration into underground freshwater sources. The ultimate objective is to restore the natural integrity of the formations that were disrupted by drilling.

Well cementing technology is more than 100 years old; however, chemists and engineers continue to introduce new formulations, materials and tech-nology to meet the constantly changing needs of the energy industry. For example, the durability of zonal isolation, during and after a well’s productive life, is a major research and development topic. Modern cement systems may contain flexible particles and fibers that allow set cement to withstand severe mechanical stresses. Advanced self-healing cement systems contain “smart” materials that, upon cement-sheath failure, swell and reestablish zonal isola-tion when contacted by either aqueous or hydrocarbon formation fluids. The ultimate goals of these cementing technologies are to withstand the rigors of well operations and other disruptions that may occur over time and maintain zonal isolation indefinitely.

> Typical casing program. The large-diameter conductor casing protects shallow formations from contamination by drilling fluid and helps prevent washouts involving unconsolidated topsoils and sediments. Surface casing, the second string, has a smaller diameter, maintains borehole integrity and prevents contamination of shallow groundwater by hydrocarbons, subterranean brines and drilling fluids. The intermediate casing isolates hydrocarbon-bearing, abnormally pressured, fractured and lost circulation zones, providing well control as engineers drill deeper. Multiple strings of intermediate casing may be required to reach the target producing zone. The production casing, or liner, is the last and smallest tubular element in the well. It isolates the zones above and within the production zone and withstands all of the anticipated loads throughout the well’s life.

Conductor casing

Surface casingCement

Intermediatecasing

Production liner