1. Bloys B, Davis N, Smolen B, Bailey L, Houwen O, Reid P,Sherwood J, Fraser L and Hodder M: “Designing andManaging Drilling Fluid,” Oilfield Review 6, no. 2 (April1994): 33–43.

2 Oilfield Review

A Clear Picture in Oil-Base Muds

Philip Cheung Andrew HaymanRob Laronga Clamart, France

Greg CookThe GHK CompanyOklahoma City, Oklahoma, USA

Greg FlournoyOklahoma City, Oklahoma

Peter GoetzMel MarshallEl Paso Oil and Gas CanadaCalgary, Alberta, Canada

Steve HansenHouston, Texas, USA

Malcolm LambBingjian LiCalgary, Alberta

Mark LarsenShreveport, Louisiana, USA

Mark OrgrenAlliance Energy CorporationJones, Oklahoma

Jim ReddenM-I L.L.C. Drilling FluidsHouston, Texas

For help in preparation of this article, thanks to TedBornemann and Lindsay Fraser, Houston, Texas, USA; Amy Bunger and Robert Elphick, Denver, Colorado, USA;Mike Grace, Dallas, TX; Didier Largeau, Patrick Perrin, JayRussell and Patrick Vessereau, Clamart, France; StephenPrensky, Silver Spring, Maryland, USA; and John Rasmusand Don Williamson, Sugar Land, Texas.ADN (Azimuthal Density Neutron), ARI (AzimuthalResistivity Imager), BorDip (automatic dip computationsoftware), CMR (Combinable Magnetic Resonance), ECS(Elemental Capture Spectroscopy), ELAN (Elemental LogAnalysis), Formation MicroScanner, FMI (FullboreFormation MicroImager), GeoFrame (system software),GeoSteering (instrumented steerable positive displacementmotor), GVR (GeoVISION Resistivity sub), MDT (Modular

A new measurement device delivers high-quality borehole images in oil-base

and synthetic-base drilling fluids. This unique technology fills a gap in formation-

evaluation services and presents reservoir experts with a clear option to evaluate

wells and fields more thoroughly.

It is frustrating to be missing a single item orpiece of information that might provide the key toaccomplishing a task or solving a problem. Thatmissing piece of the puzzle may seem small andinsignificant, but often can make the differencebetween success and failure. Analogous tobuilding a puzzle, but certainly more complex, arecertain situations in hydrocarbon-reservoir char-acterization. Asset teams trying to build reservoirmodels often find that key information is missing.Geologists, geophysicists, petrophysicists andengineers may become frustrated when they areunable to extract the necessary detail from theirformation-evaluation program, making difficultdecisions more uncertain.

Today, microresistivity borehole-imaging toolsare a common source of geologic and reservoirknowledge. However, in oil-base and synthetic-

base drilling muds, a technical void prevented theindustry from fully evaluating reservoirs usingthese tools. To address this growing need, imag-ing in nonconductive muds became a top priorityof Schlumberger formation-evaluation researchand development (R&D) in 1997.

Complicated reservoirs require detailedformation evaluation that is achievable only with borehole-imaging tools. In fields worldwide,data from these tools are analyzed routinely, and reservoir experts have come to depend on the information that imaging provides. While microresistivity-imaging technology hasadvanced over the past 15 years to includeincreased borehole coverage, improved resolu-tion and more reliable measurement systems, theborehole environment in which these tools mustoperate also has changed.

Formation Dynamics Tester), OBDT (Oil-Base DipmeterTool), OBMI (Oil-Base MicroImager), OFA (Optical FluidAnalyzer), RAB (Resistivity-at-the-Bit), StrucView(GeoFrame structural cross section software) and UBI(Ultrasonic Borehole Imager) are marks of Schlumberger.SIGMADRIL and SIGMADRIL II are marks of M-I L.L.C.. ELIAS is amark of Bureau de Recherches Geologique et Minieres(BRGM) France. CAST and EMI are marks of Halliburton.CBIL and STAR are marks of Western Atlas.

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Winter 2001/2002 3

Advances in drilling-fluid technology have led to new and improved oil-base mud (OBM) and synthetic-base mud (SBM) formulations that are used in critical operations where costsand risks are high. This technological progressionhas decreased drilling risk and increased drillingefficiency, boosting the popularity of these mud systems.1

In many hydrocarbon basins, however, theevolution in drilling-fluid technology has compli-cated efforts to optimize logging programs andthereby obtain all the information needed toevaluate complex reservoirs. Nonconductive-borehole environments render conventional

microresistivity-imaging devices ineffective,limiting wireline options for high-resolutiongeological measurements to ultrasonic devicesand dipmeter tools. Unfortunately, the limitationsof these tools restrict their usefulness.

A new wireline imaging device allows expertsto see important details about reservoirs throughnonconductive muds. The new device, the OBMIOil-Base MicroImager tool, builds on provenmethods in resistivity logging and incorporates aunique imaging pad to deliver the industry’s firstcommercial microresistivity-imaging service forOBM- and SBM-filled boreholes.

In this article, we review factors leading tothis recent breakthrough in borehole imaging,which are a combination of the timing of industrytrends and the inventiveness and persistence of Schlumberger engineers, geologists andscientists. We explain how the new micro-resistivity tool operates in resistive-boreholeenvironments and discuss tool limitations andinterpretation considerations. Case historiesdemonstrate the usefulness of the new imagedata sets and interpretations, clarifying how thistool effectively provides crucial new informationin formation evaluation.

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OBM and SBM HistoryThroughout the last half century, oil-base drillingfluids and borehole-imaging techniques havedeveloped independently. The need for a morerobust imaging tool in nonconductive mud envi-ronments grew from the advantages andincreased use of such muds. Oil-base muds mayhave been used as early as the 1920s, muchearlier than the first borehole-imaging tools.2 Bythe next decade, the industry had begun to exper-iment more widely in the use of oil muds. In1934, crude oil was added to drilling mud toreduce pipe sticking in Oklahoma (left). The fol-lowing year, Humble Oil Company (nowExxonMobil) used oil in drilling mud to reduceshale sloughing and, in 1936, Shell Oil Companycreated a research program to develop an oil-base drilling fluid.3 Reports of faster drilling ratesattributed to the addition of oil to drilling mudssurfaced in 1937.

In 1950, OBMs were commercially availableand by the 1960s, oil-base emulsion, or invert-emulsion, muds were used in the Los Angelesbasin, California, USA.4 The high water contentof these muds—40% water emulsified in refinedoil—made them less flammable and less expen-sive than more concentrated OBMs. Throughoutthe 1970s, use of OBMs became more extensivebecause they improved control while drilling inreactive shales. The unprecedented stability ofoil muds allowed operators to push into extremedrilling environments—high-temperature, high-pressure and corrosive wellbores. For example,deep-gas drilling in the Canadian foothillsencountered thick shale sections under tremen-dous stress. Water-base mud (WBM) systemsreacted adversely with these shales, triggeringhole cavings, but OBMs maintained borehole sta-bility, allowing operators to advance the previoustechnical limits in this region.

Progress continued throughout the 1980s, asdrilling-fluid additives were developed to addressthe industry’s growing needs in increasinglydemanding conditions. Widespread concernabout the environmental impact of OBM spillsand discharge of drill cuttings offshore promptedthe introduction of low-toxicity mineral oils. Bythe late 1980s, the industry realized that therelease of even mineral oil-base cuttings couldhave long-lasting environmental impact, leadingto the first development of synthetic-base drillingfluids.5 The first two synthetic fluids, esters andpolyalphaolefins, were developed in 1990 and1991, respectively. Linear alphaolefins appearedin 1994 and internal olefins in 1996. Since thefirst use of synthetic-base drilling fluids in theearly 1990s, research has continued to focus onimproving nontoxic systems.

4 Oilfield Review

International Drilling Fluids (IDF) introduces the first 100% mineral oil-base mud on early Gulf of Mexico deepwater projects.

1987–

Environmental concerns prompt worldwide legislation restrictingthe use of oil-base muds.

1988–

The first synthetic, ester, is introduced.1990–

The second synthetic, polyalphaolefin, is introduced.1991–

Linear alphaolefin synthetic-base muds are developed.1994–

Internal olefin synthetic-base muds appear.1996–

M-I L.L.C. introduces SIGMADRIL drilling-fluid system, the first commercial conductive oil-base mud made to expandformation-evaluation options, including microresistivity imaging.

2000–

Ninety percent of North Sea wells use lower toxicity oil-basemuds in at least one interval.

1986–

Mineral oils are first introduced as a cleaner alternative todiesel oil in oil-base mud systems.

1983–

Diesel oil has become the dominant base for oil-base mudsystems.

1980–

Oil-base muds are used increasingly as a means to controlreactive shales.

1970–

Oil-emulsion drilling muds receive favorable reports.1950–

An oil-base emulsion drilling mud is used in the Los Angelesbasin, California.

1960–

Drilling crews receive training on the “Principles of Drilling Mud Control.”1945–

Commercial oil muds become available from Oil Base DrillingFluids Company.

1942–

Shell Oil Company uses oil-base drilling fluid.1938–

Faster drilling rates are reported after adding oil to drilling mud.1937–

Regular standards are published by the American Petroleum Institute (API).1938–

Regular standards for testing of drilling muds are studied.1936–

Shell Oil Company begins research to develop an oil-base drilling fluid.

1936–

Humble Oil and Refining Company (now ExxonMobil) uses oilto reduce shale heaving.

1935–

Damage caused by drilling muds is recognized in California, USA.1932–

Crude oil is added to drilling mud to reduce pipe sticking inOklahoma, USA.

1934–

Drilling mud is used to control pressure in Oklahoma, USA.1913–

Barite is first used to weight mud.1922–

Spindletop discovery is made in Texas.1901–

Mud-making clays are used with rotary drilling in Texas, USA.1890s–

Patent resembling rotary-rig design is issued. 1866–

Patent mentions the circulation of drilling fluid to lift cuttings.1860–

Circulation of water is proposed in a patent by Robert Beart.1844–1840

1860

1880

1900

1920

1940

1960

1980

2000

> Significant events in the development history of drilling fluids.

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Winter 2001/2002 5

This same decade also saw the dawn ofdeepwater drilling—prompted in the UnitedStates by the Deepwater Royalty Act of 1995.6 Asdrilling advanced into deeper waters, the indus-try confronted new operational and environmen-tal challenges. In some deepwater provinces,daily rig costs exceed $300,000 US, and totaldrilling costs eclipse $30 million for certainwells. Synthetic-base muds became crucial todrilling success because of their reduced envi-ronmental impact, decreased risks and improvedefficiency. The last ten years have revealed ashift from water-base to oil- and synthetic-basedrilling fluids in the Gulf of Mexico (below).

Borehole-Imaging HistoryWireline borehole-imaging techniques weredeveloped much later than the first OBMs. It wasnot until 1958 that photographic devices,deployed by Birdwell, were first used to get aglimpse of the rock within a wellbore (right).7

2. Lummus JL and Azar JJ: “Oil-Base Muds,” in DrillingFluids Optimization, A Practical Field Approach. Tulsa,Oklahoma, USA: PennWell Publishing Company (1986):200–229.

3. Gray R and Darley HC: “Development of Drilling FluidsTechnology,” in Composition and Properties of Oil WellDrilling Fluids, 4th ed. Houston, Texas, USA: GulfPublishing Company (1980): 63.

4. Gray and Darley, reference 3: 62–70.5. Bloys et al, reference 1.6. Baud R, Peterson R, Doyle C and Richardson GE:

“Deepwater Gulf of Mexico: America’s EmergingFrontier,” US Department of the Interior, MineralManagement Service, OCS Report MMS 2000-022.(April 2000): 1–77.

7. For a comprehensive review of the evolution, methods,applications, limitations and guidelines of boreholeimaging: Prensky SE: “Advances in Borehole ImagingTechnology and Applications,” in Lovell MA, Williamson Gand Harvey PK (eds): Borehole Imaging: Applications andCase Histories, Geological Society Special PublicationNo. 159. London, England: Geological Society (1999): 1–43.

1960

1980

2000

1990

1970

Schlumberger introduces the first microresistivity-imaging tooldesigned for nonconductive mud.

Western Atlas introduces the STAR tool featuring six imagingarms combined with an acoustic-imaging device.

Halliburton introduces the EMI Electrical Micro Imaging service,a microresistvity imaging device featuring six arms that achieves 60% borehole coverage in a 77⁄8-in. hole.

Schlumberger introduces the RAB Resistivity-at-the-Bit LWD toolthat enables real-time borehole images.

Schlumberger introduces the ARI Azimuthal Resistivity Imagertool that employs a laterolog measurement.

Schlumberger introduces a microresistivity-imaging tool, the FMI Fullbore Formation MicroImager tool that doubles the boreholecoverage to 80% in a 77⁄8-in. borehole from that of the Formation MicroScanner tool by employing a flap-pad design.

Schlumberger introduces the UBI Ultrasonic Borehole Imagertool that also utilizes an ultrasonic, focused transducer and hasan increased tolerance for heavier muds.

Halliburton introduces the CAST borehole imaging service thatalso utilizes an ultrasonic, focused transducer.

BRGM develops the 2-in. diameter ELIAS tool that provides 100% borehole coverage in small boreholes.

Atlas introduces the CBIL borehole imaging service that utilizesdual ultrasonic, focused transducers.

Schlumberger introduces the second version of the Formation MicroScanner tool that has four imaging pads for improved borehole coverage.

Schlumberger introduces the first microresistivity-imaging tool,the Formation MicroScanner tool, with two imaging pads andtwo dipmeter pads.

Shell develops a 33⁄8-in. diameter, high-resolution borehole televiewer that features analog-to-raster conversion and digital reprocessing of images.

ARCO develops a 33⁄4-in. diameter, high-resolution borehole televiewer that features the digitization of the analog recordingand digital reprocessing of images.

Amoco develops a 33⁄8-in. diameter, high-resolution borehole televiewer that features analog-to-raster conversion and digital reprocessing of images.

Mobil develops an analog borehole televiewer that is 13⁄4 in.in diameter.

Mobil develops the first analog borehole televiewer that is33⁄8 in. in diameter.

Shell uses a black and white downhole television camera.

Birdwell employs borehole photography using a 16-mm lens.

2001–

1995–

1994–

1994–

1992–

1991–

1990–

1990–

1989–

1989–

1988–

1986–

1984–

1983–

1980–

1971–

1968–

1964–

1958–

> Significant events in the development of borehole imaging.

100

90

80

70

60

50

40

30

20

10

0

Use

of m

ud s

yste

ms

in th

e US

Gul

f of M

exic

o, %

WBM OBM SBM

199019952000

> Growth of the US Gulf of Mexico synthetic-base mud (SBM) market in the last decade. Syn-thetic-base muds have replaced WBM and OBMsystems in the US Gulf of Mexico after the use ofoil-base mud systems waned in the late 1980sand because of the increased deepwater activityin the mid-1990s.

50973schD3R1.p5.ps 2/6/02 7:12 PM Page 5

Later, in the 1960s, attempts to image the rockdownhole shifted toward the use of televisioncameras. A significant breakthrough occurred in1968, when Mobil developed the first high-frequency acoustic-imaging tool, the boreholeteleviewer. Unlike the optical devices beforethem, acoustic tools eliminated the need fortransparent borehole fluid—clear water, gas orair—and greatly expanded the range of bore-hole-imaging applications. Efforts launched inthe 1980s to make the data more usable resultedin improvements ranging from analog-to-digitalconversion and reprocessing capability to digitaltools with high-resolution, focused transducers—devices that function as both transmitter andreceiver. However, acoustic-imaging devices areextremely sensitive to tool eccentering, boreholerugosity and mud density, and often are insensi-tive to formation bedding.

In 1986, Schlumberger broke new groundwith the first microresistivity-imaging device, theFormation MicroScanner tool. This tool enabledgeologists to observe and analyze formation bed-ding, fractures and secondary porosity on animage workstation and in greater detail thanbefore. The initial tool included two imagingpads and two dipmeter pads, but could imageonly 20% of a 77⁄8-in. borehole in one pass; multi-ple logging passes were necessary to achievereasonable borehole coverage. In 1988, replacingthe two dipmeter pads with two more imagingpads doubled the coverage of the originalFormation MicroScanner tool.

The push for increased borehole coveragecontinued as operating companies wanted to seea larger percentage of the borehole in a singlepass, especially when imaging high-risk well-bores, heterogeneous or fractured reservoirs or in complex carbonate rocks. The FMI Fullbore

Formation MicroImager tool, equipped with fourimaging pads and four imaging flaps, againdoubled the coverage of a single logging pass in1991. The FMI tool achieved 80% coverage in a77⁄8-in. borehole (below left).

The quest for greater borehole coverage wasnot exclusive to Schlumberger. In 1989, Bureaude Recherches Geologique et Minieres (BRGM)developed the 2-in. diameter ELIAS, a 16-pad,microelectrical-imaging tool that achieved 100%borehole coverage in small boreholes. In the1990s, both Halliburton and Western Atlasachieved 60% coverage in a 77⁄8-in. borehole byemploying six-arm designs—the Halliburton EMIElectrical Micro Imaging tool in 1994 and theWestern Atlas STAR Simultaneous Acoustic andResistivity imager tool in 1995. In addition to themicroelectrical measurement, the Western Atlastool included an acoustic-imaging sensor.

Other acoustic-imaging tools were introducedprior to 1995, including the Halliburton CASTCircumferential Acoustic Scanning Tool and theSchlumberger UBI Ultrasonic Borehole Imagertool. These acoustic tools have resolution speci-fications similar to some of the microresistivitydevices, 100% borehole coverage and the poten-tial to operate in OBM. Despite tremendousadvancements, acoustic tools frequently do notassist in the analysis of formation bedding,which is critical to geologists trying to ascertainthe structural dip or stratigraphy of a reservoir.

Borehole-Imaging ApplicationsThe need to improve borehole-imaging capabili-ties in nonconductive muds came to the forefrontin the mid-1990s. At that time, microresistivity-imaging services were employed worldwide inboreholes filled with conductive water-basemuds. New geological and engineering appli-cations for these wireline tools evolved with the industry’s desire to more effectively find and exploit oil and gas reservoirs. The notableexception was wells drilled with OBM and SBMsystems (next page, top).

Microresistivity-imaging tools have becomeessential for geologists, helping them gaininsight into the complexities of reservoirs thatare stratigraphically controlled, structurally con-trolled or combinations of the two. At the largestspatial scale, borehole images help interpretersdefine the structural position of the reservoir andcharacterize features such as folds and faults.Geologists and geophysicists use formation dipand fault details to refine seismic interpretationsfor better understanding and mapping of thereservoir, more reliable reserve estimates andbetter development-well placement.

6 Oilfield Review

Imaging pads Imaging padsand flaps

62 sensors 64 sensors 192 sensors

Two-pad FormationMicroScanner tool

Four-pad FormationMicroScanner tool FMI tool

Two pads Four pads Four pads plus four flaps

> Increased borehole coverage over time. As more image data are acquiredfrom around the circumference of the borehole, a more comprehensive inter-pretation is possible. Schlumberger microresistivity-imaging devices haveprogressively added more sensors and pads to improve borehole coverage.

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Winter 2001/2002 7

Geologists assess vertical and lateral changesin the reservoir by identifying and characterizinglarge-scale depositional events and sequence-stratigraphic boundaries across fields. Usingmicroresistivity-image data from devices like theFMI tool, they also define and determine the ori-entation of smaller depositional features tounderstand stratigraphically-controlled reser-voirs.8 A close examination of bedding reveals thedepositional history in vertical successions of sediment types and grain sizes, helping toanswer questions about the reservoir’s origin (right). Was it deposited by the wind, in a fresh-water system, a marine system or in a combina-tion of environments? Was it deposited in deep orshallow water? In what direction was the deposi-tional system prograding? In what directionshould the reservoir thicken or thin? Answers toquestions like these help geologists determinethe potential size of the reservoir, the best drillinglocations and whether additional wells areneeded for efficient reservoir exploitation.

Frequently, there are reservoirs in which bothstratigraphic and structural elements trap hydro-carbons. A common practice is to remove ordelete the structural dip from the handpicked orcomputed dips to visualize the reservoir duringsedimentation.9 If the tectonic history of the

8. Depositional features observable on borehole imagesvary from current bedding to erosional surfaces and fill sequences.Serra O: “Information on Depositional SedimentaryEnvironments,” in Serra O: Sedimentary Environmentsfrom Wireline Logs, 2nd ed. Sugar Land, Texas, USA:Schlumberger Educational Services (August 1989): 119–233.

9. Structural dips are usually taken from a constant andcontinuous section of deep-marine shale or low-energybedding exhibiting planar laminations that weredeposited horizontally.

HighLowPerformance

Optical

Ultrasonic

Microresistivity

Stratigraphic Analysis

Optical

Ultrasonic

Microresistivity

Structural Analysis

Optical

Ultrasonic

Microresistivity

Fracture Characterization

Optical

Ultrasonic

Microresistivity

OBM/SBMWBMHeavyLightHeavyLight

ClearBrine

Air/Gas

Borehole Shape, Stability and Stress Analysis

Optical

Ultrasonic

Microresistivity

Horizontal-Well Applications

Optical

Ultrasonic

Microresistivity

OBM/SBMWBMHeavyLightHeavyLight

ClearBrine

Air/Gas

Petrophysical Analysis

OBM/SBMWBMHeavyLightHeavyLight

ClearBrine

Air/Gas

>Wireline borehole-imaging techniques, applications and operating environments. Different borehole-imaging techniques demonstrate various levels ofperformance depending on the application and the operating environment. Microresistivity devices offer a wide range of applications in WBMs, while ultrasonic devices represent the only option for borehole imaging in OBMs and SBMs. A performance gap in OBM- and SBM-imaging technology exists,most notably in heavy muds.

A

B

C

D

EF

G

H

I

1

2

3

4

89

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16

17

18

19 2022 25

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30

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36

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4041

23

2421

10

1112

13

5 67

34

35

263228

27 31

A. Glacial Environment1. Ice sheet 2. End moraine 3. Nunatak 4. Delta 5. Medial moraine 6. Icebergs 7. Glaciomarine

F. Fluvial Environment–Meandering System26. Channel 27. Chute 28. Concave bank 29. Convex bank 30. Oxbow lake 31. Cut bank 32. Point bar

G. Shallow Water–Carbonate Environment33. Reef 34. Fore reef 35. Back reef 36. Tidal channel

H. Deep-Sea Clastic Environment37. Submarine canyon 38. Turbidity currents 39. Abyssal fan

I. Deltaic Environment40. Actively prograding delta wedge 41. Abandoned wedge

E. Shallow Siliciclastic–Sea Environment18. Tidal flats 19. Flood tidal delta 20. Ebb tidal delta 21. Main tidal channel 22. Barrier beach complex23. Marsh 24. Lagoon 25. Barrier island

C. Alluvial Fan Environment14. Proximal 15. Mid-fan 16. Distal

D. Eolian Environment17. Beach ridge

B. Fluvial Environment–Braided System8. Levee 9. Marsh 10. Longitudinal bar 11. Transverse bar 12. Crevasse splay 13. Flood plain

> Depositional environments. Microresistivity devices help define specific environments and identifytheir unique features. Understanding the relationship between wellbore-scale bedforms and thelarger scale depositional environments is crucial when integrating the borehole-image interpretationinto the reservoir-modeling process.

50973schD3R1.p7.ps 2/6/02 7:12 PM Page 7

rocks includes multiple episodes of deformation,an involved reconstruction may be necessary todetermine the relative position of the reservoir atthe time of its deposition.

The superior vertical resolution of micro-resistivity-imaging tools helps petrophysicistsanswer difficult questions about porosity typeand distribution, sand-clay distributions and thecorrelation and orientation of both fullbore andsidewall cores. In some cases, borehole imagesprovide the details to resolve log-quality and loginterpretation issues, such as the presence ofdrilling-induced fractures or laminated sands. Inthin-bedded reservoirs, high-resolution boreholeimages enable petrophysicists and geologists todetermine the distribution of high-quality, pro-ductive sand, also known as sand-count analysis.Sand-count accuracy is limited by the resolutionof the measurement, but also is related to thethickness of the sand and shale layers. Thinnersand beds and shale laminations require higher

resolution measurements to fully account for theamount of sand. This microresistivity techniquehas significantly improved the industry’s ability to calculate total hydrocarbon reserves in thin-bedded reservoirs.

Borehole images give completion and reser-voir engineers an opportunity to observe effectsof in-situ stresses. Engineers frequently examineborehole breakout and mechanically-inducedfractures created by the drilling process to deter-mine stress directions (below). This analysisimproves completion design and effectiveness—for example, orienting perforations beforehydraulic fracturing.10

Induced fractures and borehole breakoutsalso indicate weak formation, potential lost-circulation zones and other wellbore-instabilityhazards that affect drilling and completion.Reservoir engineers model reservoir behaviormore accurately when they know natural frac-ture trends, hydraulic fracture direction or a

stratigraphic trend that may dictate a preferentialpermeability direction.11 Reservoir engineers alsoneed to know the structural details of a fieldbecause fluid contacts and reservoir compart-mentalization directly affect field development.

Formation dip from borehole images allowsthe determination of true bed thickness, which isa critical input for field development and plan-ning offset and kickoff wells.

Natural fractures commonly play a crucial rolein oil and gas reservoirs. They can be the primarychanneling mechanism allowing hydrocarbon orwater migration to a wellbore and can be detectedand characterized through borehole-imaging tech-niques. In many regions, microresistivity-imagingdevices are used to assess whether natural frac-tures are open, allowing fluid flow, or healed bymineralization, thereby restricting fluid flow.Schlumberger developed a quantitative method tocalculate the aperture or width of open fracturesfrom FMI or Formation MicroScanner data.12

8 Oilfield Review

Caliper 2 FMI Images

Orientation NorthCaliper 1

in. 166

in. 166

MDft

0 120 240 360

XX050

Density Porosityft3/ft3 00.15

Deep Inductionohm-m 200020

Photoelectric Factor100

degrees

Bed Boundaries True Dip

0 90

degrees

BorDip DIP MSDTrue Dip

0 90

XX055

XX060

Density tool affected bya dense nodule on theSE side of the borehole

Drilling-inducedfractures, NE–SW

Borehole breakout,SE–NW

Density tool affected byborehole breakout on theSE side of the borehole

Resistive Conductive

> Using FMI images to determine stress directions and to help explain log response. The drilling-inducedfractures are observed on the northeast and southwest side of the borehole and are oriented parallelto the maximum in-situ stress direction. The borehole-breakout direction confirms the stress directionand is oriented perpendicular to maximize in-situ stress direction. Frequently, borehole images providethe only means of determining why certain log responses occur. In this case, the density tool is respond-ing to a high-density nodule at XX051 ft and borehole breakout at XX059 ft. Both are located on thesoutheast side of the wellbore.

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Winter 2001/2002 9

Frequently, this fracture-aperture information iscomparable to production results and offers aneffective way to judge the productive potential ofa fractured reservoir.

At a smaller scale, microresistivity-imagingtools reveal rock textures and porosity types,helping to identify and correlate both clastic andcarbonate facies. These interpretations are mostreliable when integrated with fullbore-coreanalysis. Borehole-imaging services include thehighest resolution measurements that can bemade on wireline today and are used frequentlyin combination with other tools—such as theSchlumberger CMR Combinable MagneticResonance and ECS Elemental CaptureSpectroscopy tools and ELAN Elemental LogAnalysis software—to evaluate reservoir com-plexities (right).13 These complexities are chal-lenging, especially in porosity systems ofcarbonate reservoirs because of the extensivediagenetic changes that occur after deposition.

Their tremendous versatility has mademicroresistivity-imaging devices a fundamentalpart of detailed formation evaluation in conduc-tive borehole environments. Reservoir experts inmany disciplines use microresistivity boreholeimages to better understand the behavior of areservoir, from its largest to smallest scale, andfrom its distant past to its production future.

Borehole Imaging While DrillingA discussion of modern borehole-imaging tech-niques would be incomplete without mentioningthe impact of logging-while-drilling (LWD) imag-ing methods. Acquiring real-time image data hasmajor advantages when combined withGeoSteering motor and real-time borehole-sta-bility control. Timely access to informationimproves the quality of critical decisions madeduring drilling operations.

A great range of tool sizes and modulardesigns adds flexibility and reduces nonproduc-tive rig time, making LWD tool use widespreadtoday. LWD measurement sensors are placedclose to the bit, providing immediate informationto drillers and geologists. For example, in con-ductive muds, the RAB Resistivity-at-the-Bit toolallows operating companies to select casing andcoring points immediately. The GVR GeoVISIONResistivity sub measures an azimuthal resis-tivity using 1-in. button sensors integrated intothe tool collar. Borehole images are computed

10. Al-Qarni AO, Ault B, Heckman R, McClure S, Denoo S,Rowe W, Fairhurst D, Kaiser B, Logan D, McNally AC,Norville MA, Seim MR and Ramsey L: “From ReservoirSpecifics to Stimulation Solutions,” Oilfield Review 12,no. 4 (Winter 2000/2001): 42–60.

11. Anderson B, Bryant I, Lüling M, Spies B and Helbig K:“Oilfield Anisotropy: Its Origins and ElectricalCharacteristics,” Oilfield Review 6, no. 4 (October 1994): 48–56.Robertson D and Kuchuk F: “The Value of Variation,”Middle East Well Evaluation Review no. 18 (1997): 42–55.

12. This method requires the image data to be calibrated toa shallow-resistivity measurement. For a more detailed

m3/m3

m3/m3

Bound-FluidVolume

mMD

1355

1360

1365

1370

1375

1380

1385

1390

1395

Total PorosityProducedWater

0.5 0 msec0.3 3500 mD

Permeability FMI Image

1 1000 Resistive Conductive

m3/m3

Effective Porosity

0.5 0

1 0

mD

Minipermeameter

1 1000

mD1 1000

m3/m3

Vug %

0.5 0

0 120 240 360

m3/m3

CMR T2 Dist.

0 29

m3/m3

VolumetricAnalysis

0 1m3/m3 00.5

m3/m3 00.5

Hg Macroporosity

Core Permeability Core Permeability

Orientation North

CMR T2 Dist.

T2 Cutoff

0 29

Clay-Bound Water

Macroporosity

Mesoporosity

Microporosity

Irreducible Water

Clay

Bound Water

FMI Macroporosity

> A comprehensive analysis of a carbonate reservoir offshore western India. When FMI images arecombined with CMR, ECS, core data and an ELAN analysis, a more accurate description of carbonatereservoirs is the result. ECS data are the main input to produce a detailed lithology description and a bound-water fraction (Track 1). CMR data are used to distinguish irreducible from mobile water thatis associated with the smaller pore sizes (Track 2). Track 3 displays the T2 distributions from the CMRlog. Track 4 compares the ELAN-generated permeability (blue curve) with the measured core perme-abilities, both from core-plugs (light blue dots) and a 1-cm sampling of the core-slab using a miniper-meameter. The FMI data are used to assess the larger pore geometries. Track 5 shows a comparisonof macroporosity computed from the FMI data (shown in Track 6) and core methods, including coreplug mercury-injection and core slab vugular-porosity measurements.

review of this technique: Luthi S and Soulhaité P:“Fracture Apertures from Electrical Borehole Scans,”Geophysics 55, no. 7 (July 1990): 821–833.

13. Akbar M, Petricola M, Watfa M, Badri M, Charara M,Boyd A, Cassell B, Nurmi R, Delhomme J-P, Grace M,Kenyon B and Roestenburg J: “Classic InterpretationProblems: Evaluating Carbonates,” Oilfield Review 7,no. 1 (January 1995): 38–57.

Akbar M, Vissapragada B, Alghamdi A, Allen D, Herron M,Carnegie A, Dutta D, Olesen J-R, Chourasiya R, Logan D,Steif D, Netherwood R, Russel SD and Saxena K: “ASnapshot of Carbonate Reservoir Evaluation,” OilfieldReview 12, no. 4 (Winter 2000/2001): 20–41.

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and provide data on formation bedding and natu-ral fracturing (above). Real-time knowledge ofthe geology and the location of the bit withrespect to the reservoir allow precision steeringof the bit, useful in highly deviated and horizon-tal wells. Imaging the formation through trouble-some zones also gives drillers and engineers theopportunity to mitigate borehole-stability prob-lems by examining geomechanical data and iden-tifying failure modes.

Another LWD imaging device, the SchlumbergerADN Azimuthal Density Neutron tool, can beused in both conductive and nonconductive mudsand assists in the examination of thin beds, for-mation porosity, lithologic heterogeneity, unevenfiltrate invasion and fluid contacts. LWD imagingdevices have proven beneficial to drillers as theynegotiate complex drilling situations withincreasingly aggressive well plans.

100% Coverage?As oil- and synthetic-base drilling fluids devel-oped and their uses spread, technical barriers torunning microresistivity devices in these mudsappeared insurmountable. In these muds, aninsulating layer of resistive mud or mudcakeseparates the microresistivity electrodes fromthe formation wall, preventing the pads fromimaging the formation. The complexity of deep-water drilling brought new focus to joining these technologies.

Deepwater drilling operations require stable,environmentally friendly drilling-mud systems—demands addressed by synthetic-base mud sys-tems. Unable to image the formation usingmicroresistivity devices, companies were forcedto use alternative methods, including fullborecoring, acoustic-imaging devices and oil-basedipmeter tools to evaluate reservoirs. Thesealternative methods can increase costs and maystill result in missing, marginal or unusable data.

Fullbore coring is time-consuming and expen-sive, and can significantly complicate drillingoperations. High rig costs compound the effectsin deepwater operations. Often, operators mini-mize the length of cored intervals, and partialcore recovery is common. In highly fracturedintervals, poor recovery and jammed core barrelsare routine. When coring is successful, it is anexcellent way to examine the reservoir rock’spetrophysical and mineralogical properties.However, fullbore cores are rarely oriented andtherefore have limited use for structural andstratigraphic dip determination.

High-frequency acoustic-imaging deviceshave been used successfully for natural fractureidentification, borehole geometry informationand in-situ stress analysis. Traveltime and amplitude are the key measurements derivedfrom a high-frequency acoustic pulse fired from atransducer, reflected off the borehole wall andthen received back at the transducer.14 Traveltimeand amplitude measurements are affected bydrilling-fluid density and solids content, boreholesize and tool eccentering.

Acoustic images are dominated by surfacetexture and rugosity effects, allowing observa-tion of open fractures and vugs, breakouts anddrilling-related features. Different textures oracoustic impedances can indicate bed bound-aries. Formation bedding is most readily observ-able in smooth boreholes and hard rocks.

Today, the most common source of dip infor-mation in OBM- and SBM-filled boreholes is fromoil-base dipmeter tools. The OBDT Oil-BaseDipmeter Tool sonde, for example, uses fourmicroinduction sensors to measure variations information conductivity. Ideally, dipmeter process-ing provides computed dips for quick deter-mination of structural dip and for locating andorienting significant structural events. OBDTprocessing often does not provide a sufficientnumber of accurate dips because the boreholeenvironment adversely affects the measurement.Usually, visual examination and interpretation ofthe OBDT data are necessary to manually extractdip information from OBM-drilled wellbores inthe Gulf of Mexico.

The practice of displacing OBMs and SBMswith conductive water-base muds prior to loggingfor microresistivity images has been used withlimited success. However, because changingmuds increases the risk of borehole instability,other solutions were required.

10 Oilfield Review

1 in

.

FMI Image RAB Image

> RAB images compared with FMI images. RAB images (right) identifyformation bedding needed for the determination of structural dip. The FMIimage (left) delineates the very fine bedding as well as fine fracturing (topof image).

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Winter 2001/2002 11

Seeing Through the Resistive DarknessThe capacity of a microresistivity-imaging deviceto electrically image features on a borehole wallis analogous to the ability of the eye to see. Tofunction, the human eye needs some minimumtransparency in the surrounding medium for lightto reach it from an object. To operate effectively,microresistivity-imaging tools require some mini-mum conductivity—measured in siemens permeter (S/m)—in the surrounding medium so thatcurrent can flow in and out of the imaging sen-sors. In nonconductive boreholes, attempting toimage using standard microresistivity devices ismuch like trying to see through darkened glass.Just as reduced light transmittance obscuresvision, low conductivity makes microresistivityimaging difficult.

A typical water-base mud is one million timesmore conductive than an average OBM—10 S/mversus 10 microsiemens per meter (µS/m),respectively—making the task of measuringmicroresistivity in oil-base drilling fluids a daunt-ing challenge.

Just as advances in optical technology providelight amplification in diminished light to enablenight vision, the solution to the OBM challengealso required a novel approach. Schlumberger sci-entists and engineers developed an innovativetechnique based on the proven principles of resis-tivity logging, producing the OBMI Oil-BaseMicroImager tool.

The new tool employs the four-terminalmethod for measuring resistivity. On each of thetool’s four imaging pads, an alternating current, I,is injected into the formation between twocurrent-injector electrodes located above andbelow five pairs of small button sensors. A poten-tial difference, δV, is measured between the but-ton sensors in each pair. For each pair of sensorbuttons, a flushed-zone resistivity, Rxo, is derivedfrom the measured δV, a known I and the geo-metrical factor, k, and can be described by theequation Rxo= k(δV/I) (left).

In nonconductive muds, the electrical-contactpoints between the imaging pads—specificallythe current electrodes and button sensors—andthe borehole wall are points of high impedance.This contact impedance originates at the thin lay-ers of highly resistive mud and mudcake betweenthe pad and the formation. What starts out as a

potential difference of hundreds of volts at theinjector electrode diminishes to only a fraction ofa millivolt at the button sensors. Making thissubtle measurement while simultaneously gen-erating the required high voltages proved to be a difficult technical obstacle. The OBMI tool-development team successfully designed andimplemented a unique imaging pad and associ-ated electronics to clear this hurdle.

High-quality images are now acquired innonconductive muds over a wide range of Rxo

values—0.2 to over 10,000 ohm-m—when thestandoff between the formation and the imagingpads remains within certain bounds.15 Mathe-matical modeling, laboratory experiments andthe OBMI tool field test helped define the tool’ssensitivity to standoff (above). Sensitivity tostandoff increases as Rxo decreases and secon-darily as the resistivity of the mud, Rm, increases.In a typical nonconductive mud, for example,

Button-sensorpairs

Current-injectorelectrode

Current-injectorelectrode

IδV

I

Rxo

Rxo = k(δV/I).k = geometrical factor ~ 10 m.

8 cm

37 c

m

> Schematic diagram of the OBMI pad againstthe borehole wall in side-view (left) and in front-view (right). An alternating current, I, is injectedinto the formation between two current-injectorelectrodes located above and below five pairs of small button sensors. A potential difference,δV, is measured between the button sensors in each pair. For each pair of sensor buttons, a flushed-zone resistivity, Rxo, is derived from themeasured δV, a known I and the tool geometri-cal factor, k, and can be described in the equa-tion Rxo=k(δV/I).

100,000

Form

atio

n re

sist

ivity

, ohm

-m

Pad standoff, in.

0.10 1

Noise

Noise

Noise

Limit of Rxo measurement

Working zone

Best practic

es, future development

Logging speed

> OBMI tool operating envelope. The approximate OBMI operating envelopeis described in terms of flushed-zone resistivity (Rxo) and standoff at the pad.At resistivities below 1 ohm-m, the measured signal is always small andtherefore susceptible to noise, which may be reduced by logging in a slowermode (900 ft/hr or 1800 ft/hr [274 m/hr or 549 m/hr]). Pad standoff also dimin-ishes the signal while simultaneously introducing systematic noise that cannotbe helped by slower logging. The limit of accuracy for the Rxo measurement isfound over 10,000 ohm-m, though the images are still useful for structuralinterpretation in this range. Ongoing engineering development and the applicationof a set of best practices during logging and drilling operations aim toincrease the performance in marginal conditions.

14. The Schlumberger UBI tool operates on two frequen-cies: 250 kHz or 500 kHz. The lower frequency of 250 kHzhas greater penetration through heavy muds, a lowerresolution, and is used for imaging in heavy muds.

15. Standoff is defined as the distance between the externalsurface of a logging-tool sensor and the borehole wall.

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where Rxo equals 10 ohm-m, a standoff of 0.5 in.[1.3 cm] may start to degrade image quality, butif Rxo is less than 1 ohm-m, degradation mayoccur at a standoff of 0.25 in. [0.64 cm].16

Excessive pad standoff from rugose hole or poor pad contact appears on the images as areasof high resistivity and is displayed as white.Anomalous readings from too much standoff are detected by the tool’s software and indicatedon a log-quality display presented with theimages (above).

The five button-sensor pairs on each of thefour OBMI pads yield five pixels per imaging pad.The pixel size is equal to the spacing betweenbutton sensors in each pair, in this case, a 0.4-in.by 0.4-in. [1.0-cm2] pixel. The vertical resolutionof the tool is 1.2 in. [3.0 cm] and is defined as thethinnest bed whose thickness can be measured.The OBMI tool responds to beds and featuressmaller than 1.2 in. but cannot accurately deter-mine their thickness (next page). The 1.2-in. ver-tical resolution of the OBMI tool falls betweenthat of the FMI tool and that of the RAB tool res-olution.17 The OBMI tool, however, is the onlymicroresistivity-imaging device available fornonconductive muds.

The new tool also provides high-resolutionquantitative Rxo data with a maximum error of20% in zones greater than 10 in. [25 cm] thickand where Rxo ranges from 1 ohm-m to 10,000ohm-m. Beyond this resistivity range, the imagescan still be useful in showing the correct geome-try and relative contrast of objects, but the resis-tivity measurement becomes less reliable.18

At sharp bed boundaries, OBMI results cansuffer from shoulder-bed effects and distor-tions—as do laterologs and conventionalmicroresistivity imagers, but for reasons arisingfrom different measurement principles.19 Theseverity of the distortion depends on the bedthickness, resistivity contrast between theimaged thin bed and the shoulder beds and onwhether the thin bed is more resistive or moreconductive than the shoulder beds. In the case ofa 1.2-in. thin bed surrounded by two equivalentshoulder beds, a low thin-bed to shoulder-bedresistivity contrast of 3:1 or 1:3 produces an Rxo

of good quality. At higher thin-bed to shoulder-bed resistivity contrasts—10:1 and above—distortions are observed, affecting the measuredRxo for both the thin bed and the shoulder beds.These effects occur up to 10 in. away from thethin bed because the injector-electrode spacingis 10 in. Where the thin bed is conductive and theshoulder beds are resistive, the higher contrasts

generate less distortion than where the thin bedis more resistive than the shoulder beds (nextpage). Even though distortion can affect the mea-sured thickness of thin beds and introduce smallerrors into thin-bed analysis, the OBMI tool has emerged as the most accurate wirelinemethod to calculate a total sand count in non-conductive muds.

A Matter of InterpretationThe OBMI tool produces the image resolutionneeded for detailed structural analysis. Large- tomedium-scale stratigraphic analysis is also pos-sible, characterizing thicker, more continuousbedding packages that represent deposition in avariety of environments.20 However, the tool’sability to provide the detail required to fully inter-pret small features on or near the borehole walldepends on the size of the object. For example, aconcretion imaged by an OBMI tool would haveto be at least 1.2 in. in diameter for an accuratesize assessment.21 Smaller features, such as finebedding and small-scale ripple laminations mightbe undetected.22

The OBMI tool sees fractures and allows theirorientation to be determined. However, becausethe measurement is taken in nonconductivemuds, several factors affect fracture analysis. As

12 Oilfield Review

High-ResolutionZ-Axis

Accelerometer Caliper 1m/s29 11 in.6 16

Deviationdegrees0 100

Gamma RayAPI0 150

Caliper 2in.6 16

Pad A Impedancekohm0 1000

Pad B Impedancekohm0 1000

Pad C Impedancekohm0 1000

Pad D Impedancekohm0 1000

OBMI Button #3 Pad Aohm-m0.1 10,000

OBMI Button #9 Pad Bohm-m0.1 10,000

OBMI Button #3 Pad Cohm-m0.1 10,000

OBMI Button #3 Pad Dohm-m0.1 10,000

OBMI Pad Pressurepercent–20 130

Relative Bearingdegrees–40 360

LQC Image

OKPoor Signal

SaturationLift-Off

OBMI Image

849

850

851

> OBMI log quality control. The OBMI log quality-control (LQC) display identifies intervals where the data may be compromised. From left to right: In thedepth track, the accelerometer curve shows tool sticking. In Track 1, the caliper curve shows hole rugosity, and the pad-pressure curve indicates the log-ging engineer should reduce tool sticking by lowering pad pressure or improve pad contact by increasing pad pressure. In Track 2, the injector impedanceindicates pad standoff from all four pads. In Track 3, a color-coded LQC shading is shown for each pad. Green coding indicates the proper amount of stand-off, yellow coding for a small amount of standoff, resulting in a poor signal, and red coding for excessive standoff present or pad lift-off. Track 4 presentsthe resistivity from one button on each pad, and Track 5 displays the OBMI image.

50973schD3R1.p12.ps 2/6/02 7:12 PM Page 12

Winter 2001/2002 13

with other microresistivity-imaging devices, theOBMI resistivity measurements are displayed asan image using lighter colors for higher resistivi-ties and darker colors for lower resistivities. Inconductive muds, an open, mud-filled fracture isconductive and appears dark while a healed frac-ture, more commonly filled with resistive mineralthan conductive minerals, would appear light.However, an open fracture filled with nonconduc-tive mud is resistive and appears white, makingit difficult to differentiate open fractures from

healed fractures. Although less common, frac-tures that appear dark on OBMI images indicatethat conductive minerals—clays or pyrite forexample—are present. Those fractures havebeen interpreted as inactive and lacking fluidflow. Additionally, standard microresistivity-imaging devices in conductive borehole fluidsdetect conductive fractures in resistive forma-tions without difficulty. The opposite is true whenimaging with the OBMI tool in nonconductivefluids, where fractures, both natural and induced,are identified more readily in conductive forma-tions like shale.

Wells targeting the fractured carbonate reser-voirs in the deep Anadarko basin of Oklahoma,USA, penetrate a harsh environment for acquiringeven the most basic log data. Oil-base muds, usedfor the added drilling efficiency, made this loca-tion especially inhospitable for attempts to imagethe formation. The OBMI tool was run in a Huntonand Sycamore Limestone well to determine struc-tural dip and identify structural features andnatural fractures. An extensively fractured inter-val was identified in the Hunton section and theorientations of the main fracture trends weredetermined. Because both open and mineralizedfractures are resistive in OBMs and SBMs, othermethods, including other log data, helped inter-pret the Hunton fractures to be calcite-filled.

16. Cheung P, Pittman D, Hayman A, Laronga R, Vessereau P,Ounadjela A, Desport O, Hansen S, Kear R, Lamb M,Borbas T and Wendt B: “Field Test Results of a New Oil-Base Mud Formation Imager Tool,” Transactions of theSPWLA 42nd Annual Logging Symposium, Houston,Texas, USA, June 17-20, 2001, paper XX.

17. Cannon D and Kienitz C: “Interpretation of AsymmetricallyInvaded Formations with Azimuthal and Radial LWDData,” Transactions of the SPWLA 40th Annual LoggingSymposium, Oslo, Norway, May 30-June 3, 1999, paper G.Cryer J, Ford G, Grether B, Hartner J and Waters D: “DipInterpretation from Resistivity at Bit Images (RAB) Providesa New and Efficient Method for Evaluating StructurallyComplex Areas in the Cook Inlet, Alaska,” paper SPE 54611,presented at the 1999 SPE Western Regional Meeting,Anchorage, Alaska, USA, May 26-28, 1999.Bonner S, Bagersh A, Clark B, Dajee G, Dennison M, Hall JS, Jundt J, Lovell J, Rosthal R and Allen D: “A NewGeneration of Electrode Resistivity Measurements forFormation Evaluation While Drilling,” Transactions of the SPWLA 35th Annual Logging Symposium, Tulsa,Oklahoma, USA, June19-22, 1994, paper OO.

18. Cheung et al, reference 16.19. A shoulder bed is a formation layer above or below the

layer being measured by a logging tool. The term is usedin resistivity logging to describe the layers above andbelow a reservoir. The term is more commonly used forvertical wells, and is derived from the typical picture of resistivity-log response across a reservoir—a high-resistivity reservoir (the head) with two low-resistivityshales above and below (the shoulders). The term alsomay be used in horizontal wells, although in that contextthe term surrounding bed is more common. The termadjacent bed is used in both cases.

20. For a general overview of sedimentary environments:Serra, reference 8.For a more detailed examination of sedimentaryenvironments: Scholle PA and Spearing D: SandstoneDepositional Environments. Tulsa, Oklahoma, USA: TheAmerican Association of Petroleum Geologists, 1982.

21. A concretion is a compact mass of mineral matter,usually spherical or disk-shaped and embedded in a host rock of a different composition. Concretions formby precipitation of mineral matter (commonly a carbon-ate mineral such as calcite, but sometimes an iron oxideor hydroxide, such as goethite, or an amorphous ormicrocrystalline form of silica) about a nucleus such asa leaf or a piece of shell or bone. Concretions range insize from a few centimeters up to 3 m [9.8 ft] in diameter.They form during diagenesis of a deposit, usually shortlyafter the enclosing sediment has been buried.

22. Ripple laminations are undulations on the sedimentsurface produced as wind or water moves across anddeposits sand.

101

100

Mea

sure

d re

sist

ivity

, ohm

-m

10-1

-10 -8 -6 -4 -2 0

Response to a 1.2-inch Bed—Rt Background = 1 ohm-m

Response to a 1.2-inch Bed—Rt Background = 10 ohm-m

Distance, in.2 4 6 8 10

101

100

Mea

sure

d re

sist

ivity

, ohm

-m

10-1

-10 -8 -6 -4 -2 0Distance, in.

2 4 6 8 10

Rthin-bed = 3 ohm-mRthin-bed = 10 ohm-mRthin-bed = 30 ohm-m

Rthin-bed = 3 ohm-mRthin-bed = 1 ohm-mRthin-bed = 0.3 ohm-m

> Modeled response of the OBMI tool across a 1.2-in. thin bed. The OBMI tool response is shown forthree different thin-bed resistivities when the shoulder-bed resistivity is 1 ohm-m (top). The bottomgraph shows the OBMI tool response for three different thin-bed resistivities when the shoulder-bedresistivity is 10 ohm-m. The graphs show some distortion in the OBMI tool response away from the thinbed. These shoulder-bed effects can be observed at a distance equal to the injector-electrode spac-ing, or 10 in. away from the thin bed.

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A short distance uphole, a normal fault, notobserved on seismic images, also was identifiedand oriented and displayed a change of dip acrossthe fault plane (below).

The OBMI tool injects currents into the for-mation that flow roughly parallel to the borehole.Voltage differences measured in this directionthen allow the formation resistivity to be deter-mined. Theoretically, if bed boundaries or frac-tures are oriented parallel to the borehole, thevoltage drop in the direction of the borehole

would be the same irrespective of the formationresistivity. Consequently, beds or fractures thatmaintain a high angle of dip relative to the bore-hole may be undetectable or difficult to observe.In practice, however, the new tool has had littledifficulty imaging both fractures and beddingwith apparent dips of up to 80 degrees relative tothe borehole.

Fracture aperture, on the other hand, is notas easy to quantify. The vast majority of frac-tures observed downhole have apertures signifi-

cantly less than the OBMI tool pixel width. Forthis reason, the fracture aperture cannot beobserved directly. A method for the quantitativeanalysis of fracture aperture, similar to that inconductive muds using FMI and FormationMicroScanner data, has not been developedusing OBMI data.

As more OBMI images become available, spe-cial interpretation challenges associated withOBMs become apparent. For example, the dehy-dration of shales by OBMs and SBMs leads to the

14 Oilfield Review

Normal fault

Heavily fractured

Gamma RayAPI0 200

Caliper 2in.4 14

degrees

TadpolesBorehole Drift

Orientation North

0 120 240 360

MDft

XX770

XX780

XX820

OBMI Static Image

Conductive Resistive

0 20

Caliper 1in.4 14

Orientation North

Fault, Orientation North

0 120 240 360

OBMI Dynamic Image

Conductive Resistive 0 deg 90

Resistive Fracture, Orientation North

Bed Boundary, Orientation North

Fault True DipResistive Fracture True DipBed Boundary True Dip

> Natural fractures as seen by the OBMI tool. The OBMI tool clearly identifies and provides orienta-tions of the natural fractures in this deep Anadarko basin well. The image on the left is the staticallyprocessed image to demonstrate gross changes across the section. The image on the right is thedynamically processed image to view small features within the section. Resistive fractures are moredifficult to detect in the resistive Hunton Limestone. A normal fault was also identified uphole.

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Winter 2001/2002 15

fracturing or parting of shale laminations. Thesecracks are invaded by nonconductive mud so theyappear as bright events on the OBMI images(above). Unlike stress-induced fractures, fracturescaused by the dehydration of clay—most notablysmectite—occur in high-density groupings andobscure the formation bedding on the imagesaround the entire circumference of the wellbore.This can make geological interpretation of theimage data extremely difficult. A dipmeter log runacross such intervals might yield good quality butvery misleading dips because of the presence ofdehydration fractures.

These fractures have been noted on core andmay explain the separation commonly observedbetween the shallow and deep induction logs.Until now, it has been difficult to know whetherthese fractures were on the borehole wallbecause they have not affected acoustic logs. Forthis reason, dehydration fractures are likely to beshallow and fine, and when filled with a very resis-tive fluid, become detectable by resistivity devices.

When operators cannot forego the use ofSBM or OBM but still require a high-resolutionimaging service, like the FMI tool, an alternativedrilling fluid is available. The SIGMADRIL conductiveOBM system, designed by M-I L.L.C., provides theadvantages of oil-base fluids and the electricalproperties of conductive mud systems. Small-scale stratigraphic analysis, quantitative fractureanalysis and other formation-evaluation tech-niques restricted to conductive boreholes are nowpossible with the use of this new mud (see “AnOil-Base Mud Designed for Imaging,” page 16).

Imaging in Deepwater Wells Given the immense cost of drilling, completingand producing wells at great ocean depths, theimportance of making the right decision and get-ting it right the first time is unprecedented.Production testing and drillstem testing carryenvironmental risk and tremendous expense inthe deepwater environment, making these prac-

tices undesirable. Operators want to maximizetheir initial look at the reservoir while minimizingtheir exposure to risk. The need for timely high-quality formation-evaluation data and accurateinterpretations has never been greater than intoday’s deepwater operations.

The majority of wells in deepwater opera-tions, including the US Gulf of Mexico and deep-water basins off the west coast of Africa, aredrilled using synthetic-base muds, severely limit-ing the available options for borehole imaging.The OBMI tool has been used extensively inthese areas, demonstrating significant applica-tions to help geologists and engineers assessdeepwater reservoirs.

More than half of the oil production in the USGulf of Mexico now comes from deepwater pro-jects. That figure is expected to rise to two-thirds, or nearly 2 million B/D [318,000 m3/d], bythe end of 2005.23 Deepwater subsalt prospectshave generated tremendous interest. Commonly,subsalt reservoirs are hard to detect and definethrough seismic imaging because much of theseismic energy is lost at the salt boundaries anddoes not penetrate and image subsalt strata.24

Salt also disperses seismic energy, making seis-mic imaging more difficult when assumingstraight raypath models.

The OBMI tool allows deepwater geologiststo pinpoint structural details and identify impor-tant features like faults and upturned beds,bringing more clarity to these complex sectionswhere traditional seismic imaging can beambiguous. Deepwater exploration targets in theGulf of Mexico feature complex structures andfaulting below salt in the folded strata of theUpper Jurassic through Miocene section. UsingOBMI images, a deepwater operator confirmedthe presence of a normal fault that was notdetected previously in seismic images. The faultrepresented a significant structural feature with500 ft [150 m] of throw. Faults like this hampersubsequent development efforts during thedrilling of lateral production wells and canreduce the total recoverable reserves if the reser-voir is highly compartmentalized. The improvedstructural picture derived from the OBMI inter-pretations can then be put into models used inseismic reprocessing, helping to define the reser-voir extent and the future development strategy.

23. Lyle D: “Deepwater Production Surges Higher,” Hart’sE&P 74, no. 8 (August 2001): 90.

24. Farmer P, Miller D, Pieprzak A, Rutledge J and Woods R:“Exploring the Subsalt,” Oilfield Review 8, no. 1 (Spring1996): 50–64.

X880

Gamma Ray20 120 OBMI Static Image OBMI Dynamic Image

X881

X882

X883

X884

X885

X886

X887

A090ohm-m0.2 20

A060ohm-m0.2 20

A020ohm-m0.2 20

A010Resistivity

ohm-m0.2 20

A030ohm-m0.2 20

Caliper 26 16

Caliper 1

TadpoleBorehole Drift

in.

API

in.6 16

degrees0 40

Depth,ft

PhotoelectricFactor

0 10 0 degrees 10

DensityPorosityft3/ft30.6 0

NeutronPorosity

Bed BoundaryTrue Dip

Dehydration FracturesTrue Dip

ft3/ft30.6 0

Formationbedding

Dehydrationfractures

> Dehydration fractures in shale on OBMI images. Dehydration fractures (sinusoids interpreted in theOBMI Dynamic Images Track) can mask formation bedding, making it difficult to automatically com-pute dips. In shales, the complexities of computing dips in SBMs and OBMs is readily apparent fromOBMI images, underscoring the importance of having the option to handpick dips from clearer images.

(continued on page 18)

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16 Oilfield Review

Oil-base mud systems were developed toimprove drilling performance relative to theirwater-base counterparts. With their associatedhigher rates of penetration and enhanced wellbore stability, shale inhibition and lubricity,oil-base drilling fluids often are the only viabletechnical and economic option for demandingapplications such as extended-reach, deepwaterand high-temperature, high-pressure wells.

Engineers and geoscientists often use micro-resistivity imaging to understand reservoir char-acteristics and to evaluate the productivecapacity of a field. Historically, water-basedrilling fluids were the only choice for acquiringhigh-quality formation-imaging logs usingmicroresistivity techniques. The low resistivity of the mud, filter cake and filtrate of conductivewater-base drilling fluids permits the return of a strong electrical-signal response from theformation, thereby generating logs of the highestclarity. On the other hand, the oil-wet fluid, filtercake and filtrate in conventional invert-emulsionfluids—water in an oil-continuous phase—create a resistive barrier that blocks electricalcurrent, making image quality inadequate.

In response to that dilemma, M-I L.L.C. andSchlumberger embarked on a five-year researchprogram that led to the joint development of the SIGMADRIL conductive oil-base drilling fluidsystem. SIGMADRIL mud employs an electricallyconductive continuous phase that produces con-ductive mud, filter cake and filtrate. The resultis a fluid delivering oil-base performance char-acteristics with the formation logging quality of a water-base drilling fluid. The conductiveborehole environment produced by this newmud yields high-quality microresistivity imagesnormally associated with water-base mudsystems. Extensive testing at a Schlumbergertest well in Meaux, France helped produce amud system ideally suited for FMI FullboreFormation MicroImager tool operations (left)(left).

An Oil-Base Mud Designed for Imaging

Low resistivity

Gravel layers

FMI toolBorehole

Low resistivity

High resistivity

Metal pipe

PVCbarrier

Brine water OBM SIGMADRIL fluid

>> Test borehole in Meaux, France. A 10-m [32.8-ft] long, 8-in. diameter hole constructed at 60° deviationwas used to test the FMI tool response in three different borehole fluids, including brine water, OBM andSIGMADRIL conductive oil-base mud. To simulate formation layers, five layers of cement of different resistivi-ties were used. The top and bottom layers were composed of high-resistivity construction concrete. Threemiddle cement layers were comprised of one high-resistivity center layer surrounded by two low-resistivitylayers. Additionally, 5-cm [2-in.] layers of higher resistivity gravel were placed at the bases of the upperlow-resistivity layer and the middle high-resistivity layer. The OBM prevented the acquisition of usableimages by the FMI tool. The test showed that the SIGMADRIL mud produced high-quality images thatidentified both the thin resistive gravel layers and also subtle breaks observed both in the center of theresistive layer and in the center of the lower conductive layer, marking where those layers were laid in twodifferent stages.

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Winter 2001/2002 17

1 ft

FMI Static Image FMI Dynamic Image

Small fault

>> FMI images in SIGMADRIL conductive oil-base mud. The FMI images fromthis Norwegian North Sea well demonstrate the quality and detail of imagesin SIGMADRIL mud. In this case, the FMI data indicate a small fault and thin beds.

The system features a proprietary andpatented chemical package that makes the con-tinuous oil phase conductive without destabiliz-ing the emulsion. The system is formulated forminimum filtration by incorporating a uniquefiltration-control package that contains a non-aqueous soluble polymeric additive and a liquidester additive. The properties of SIGMADRIL

drilling fluid are identical to those of a typicaloil- or synthetic-base system, except for itselectrical conductivity that permits the use of certain resistivity devices.

The system was first deployed in a highlydeviated well in the Norwegian sector of theNorth Sea where the primary objective was toacquire detailed geologic data, including struc-tural and sedimentary dip and information onfaults and fractures. The FMI tool was selectedas the only device capable of delivering therequired resolution and borehole coverageresults with minimal risk to data quality. Thetargeted section, however, contained highlyreactive shales that made drilling with a water-base fluid system extremely risky, possiblyresulting in loss of the well.

The operator displaced the original mudsystem with SIGMADRIL fluid in the targeted 81⁄2-in. diameter section and used it to drill a total depth of 15,599 ft [4755 m]. SIGMADRIL

mud proved to be a stable and easily maintainedfluid system that behaved like any high-qualityoil-base drilling fluid. The troublesome shaleswere drilled with no fluid-related downtime. The interval was drilled trouble-free, 41⁄2 daysahead of schedule, resulting in a savings of US $1.5 million.

The quality of the formation imaging anddetailed geologic interpretation was as good as, and in some instances better than, thatachieved with water-base drilling fluids (right)(right). High-quality, interpretable images wereobtained in formations with resistivity as low as2 ohm-m. The resolution quality allowed theoperator to define the reservoir clearly, reducingthe cost of future development. Similar resultswere recorded in a second Norwegian North Sea well.

resistivity-imaging devices, such as the GVRGeoVISION Resistivity sub. In the initial andongoing SIGMADRIL II mud field trial, the qualityof the GVR images was excellent and the wellexperienced no mud-related drilling problems.

Presently, M-I L.L.C. is conducting a field trialfor the second version of the oil-base system.The SIGMADRIL II conductive oil-base mud isdesigned to be 50% more conductive than itspredecessor, further enhancing microresistivity-image quality while opening the door for LWD

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Just as earlier microresistivity-imagingdevices revolutionized stratigraphic analysis inconductive WBMs, the OBMI tool allows deep-water operators to examine stratigraphicfeatures and internal bedding in nonconduc-tive muds. OBMI images assess laminatedsequences, bedding character and abruptchanges in sedimentation. In one deepwaterwell, a Gulf of Mexico operator ran the OBMI tooland identified a basal-scour surface that wasconfirmed by fullbore core (above).

In deepwater operations, the cost of produc-tion systems exceeds the cost of drilling wells inthe field. The selection and design of these pro-duction systems depend largely on the produced-fluid behavior. Wax and asphaltene solids that

form during production and cause flow problemsmust be minimized. Fluid samples, collecteddownhole by wireline fluid-sampling tools, likethe MDT Modular Formation Dynamics Testertool, are analyzed to determine fluid properties.However, when the samples are more than 10% contaminated by SBM or OBM filtrate,extracting critical information about production-fluid properties becomes more difficult and putsat risk effective flow assurance.25

Images from the OBMI tool have been used inthe selection of MDT fluid-sampling depths tominimize the percentage of SBM and OBM fil-trate contamination in the samples. In the deep-water sands of the Gulf of Mexico, nonoptimalMDT tool placement can occur when selectingfluid-sampling depths using standard logs. Withits 1.2-in. resolution, the OBMI tool can identify

the location and nature of bed boundaries—sharp versus gradational—better than standardlogs, facilitating optimal sample-depth determi-nation. Combining the knowledge of bed contactsfrom the OBMI tool and producibility indicatorsfrom the CMR tool, higher permeability sands

18 Oilfield Review

25. Andrews J, Beck G, Castelijns K, Chen A, Fadness F,Irvine-Fortescue J, Williams S, Cribbs M, Hashem M,Jamaluddin A, Kurkjian A, Sass B, Mullins OC, Rylander Eand Van Dusen A: “Quantifying Contamination UsingColor of Crude and Condensate,” Oilfield Review 13, no. 3 (Autumn 2001): 24–43.Cuvillier G, Edwards S, Johnson G, Plumb D, Sayers C,Denyer G, Mendonça JE, Theuveny B and Vise C:“Solving Deepwater Well-Construction Problems,”Oilfield Review 12, no. 1 (Spring 2000): 2–17.Christie A, Kishino A, Cromb J, Hensley R, Kent E, McBeath B,Stewart H, Vidal A and Koot L: “Subsea Solutions,” OilfieldReview 11, no. 4 (Winter 1999/2000): 2–19.

26. Cheung et al, reference 16.

OBMI Static Image

ConductiveCore ImageMDft Resistive

XX002

XX001

XX000

Scour surface oncore photo

Scour surface onOBMI image

Gamma Ray20 API 120

Caliper 26 16

Caliper 1

TadpoleBorehole Drift

in.

in.6 16

degrees0 40

A090ohm-m0.2 200

A060ohm-m0.2 200

A020ohm-m0.2 200

A010Resistivity

ohm-m0.2 200

A030ohm-m0.2 200

DensityPorosity

ft3/ft30.6 0

ft3/ft30.6 0

NeutronPorosity

> OBMI images of a basal-scour surface. OBMI images from an early field-test tool identified this abrupt erosional surface (arrows) in this deepwaterwell. The scour surface was confirmed by an examination of the core. Thecore photograph is shown in Track 3.

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Winter 2001/2002 19

can be sampled closer to sharp bed boundaries,thereby reducing spherical-flow effects to theMDT probe.

Improved positioning of the MDT tool usingOBMI and CMR logs, along with longer pumpouttimes and use of the OFA Optical Fluid Analyzermodule, has helped one operator reduce samplecontamination levels from 10 to 20% to less than5% (below). These reduced contamination levelsimprove fluid-property characterization and helpensure the optimal design of deepwater produc-tion and treatment facilities.

Images, Cores and DipsRecent experience in the US Gulf of Mexico hasshown the OBMI tool measurement to be robust.The new tool delivers high-quality results whencompared with fullbore cores and provides moreaccurate sand-count numbers for reserve esti-mates compared to standard logs. Because it isan imaging tool, the OBMI tool provides more pre-cise structural and stratigraphic dips comparedwith those obtained with previous methods.

OBMI images eliminate much of the ambiguity ofdip interpretations from processed dipmeter datain nonconductive mud-filled boreholes.

In the Gulf of Mexico, operators have suc-cessfully used OBMI images and resistivitymeasurements to characterize uncored intervalsand to refine net-to-gross sand figures.26 Fullborecores and images were acquired across a sectionof Pleistocene-age sands to assess the level ofdetail provided by the OBMI tool. The correlationwas excellent, and beds as thin as 0.5 in. [1.3 cm]

Borehole Drift MDft

X070

X080

X090

X100

X110

X120

X130

degrees 100

Gamma RayAPI 12020

A090OBMI Static Image

Straight Image

ohm-m 20 Resistive0.2 ConductiveGamma Ray

API Depth, ft12020

Deep Resistivity

ohm-m 200.2

Caliper 1

in. 166

Neutron Porosity

Vol/Vol 00.6

Density Porosity

Vol/Vol 00.6

Caliper 2

in. 166

Density Porosityft3/ft3 00.6

ft3/ft3 00.6Neutron Porosity

Crossover

A060ohm-m 200.2

A030ohm-m 200.2

A020ohm-m 200.2

A010Resistivity

ohm-m 200.2

Caliper 2in. 166

Caliper 1in. 166

0 120 240 360

MDT Fluid-Sampling Results:

OBMI-aided MDT fluid sampleDepth = X097.0 ftPumpout time = 69.7 minPumpout volume = 16.88 galSBM contamination = 4.4%

MDT fluid sampleDepth = X108.1 ftPumpout time = 77.0 minPumpout volume = 11.28 galSBM contamination = 17.7%

X100

> Fine-tuning MDT sampling depths. The OBMI images allow the differentiation of bed-boundary types for MDT sample-point selection. This improves thechances that higher quality rock will be sampled, thereby increasing the volume of the fluid samples and reducing the contamination of fluid samples. Thelower MDT sample depth (red diamonds), X108.1 ft, was selected without the aid of the OBMI tool and suffered from a large percentage of SBM contam-ination. The upper sample depth (green diamonds), X097.0 ft, was selected from the OBMI images (Track 4) and was taken between laminations. It produceda larger, cleaner sample in less time than when the OBMI images were not used. Close proximity to the low-permeability laminations reduces spherical-flow effects, allowing quicker withdrawal of formation fluids from beyond the filtrate-invasion zone. MDT sample-contamination results have improved dramatically since new techniques and procedures have been introduced.

50973schD3R1.p19.ps 2/6/02 7:13 PM Page 19

were identified (above). At a depth of XX84 ft,thin beds can be observed both on the core andon the OBMI image. The core clearly shows shalebetween the sand stringers. The OBMI tool, lim-ited to a resolution of 1.2 in., suggests the shaleis silty. This introduces small errors in the net-sand calculation that become more significant asthe thin-bedded nature of the reservoir increases.In the Pleistocene sands of the Gulf of Mexico,the OBMI resistivity was used in combinationwith sidewall core data to improve the accuracyof the net-sand count. The calculated net-sandincrease was 50 ft [15 m] greater than conven-tional log analysis indicated.

Operating companies requiring structuralanalysis across thick sections of strata usuallybenefit from automatic dip computations. Thismethod provides a quick structural picture sothat critical decisions can be made rapidly.However, in nonconductive muds, dipmeter datamust often be processed and interpreted byhand, taking too much time to provide timelyanswers to critical decisions.

With identical processing parameters, struc-tural dips were computed from both OBDT dataand OBMI data acquired across the samePleistocene sand interval in a Gulf of Mexico well.

A single button per pad was used in the OBDT pro-cessing, while three buttons per pad were used toprocess the OBMI data. The geologist received tentimes more usable dip information from the OBMItool than from the OBDT tool, and dip magnitudesand dip directions varied greatly from those of theOBDT tool in some sections. Comparison of theOBDT data and the OBMI images clearly demon-strates how the dip correlations differ betweenthe two devices (next page). The computed sinu-soid traces displayed on each image demonstratethe advantages of having the superior clarity ofthe OBMI images. Improved borehole images leadto more accurate dip computations and more rig-orous structural interpretations.

20 Oilfield Review

XX82

MDft Core ImageConductive

OBMI Image

Resistive

Sand

XX83

XX84

XX85

XX86 262.87 48.69

263.24 48.87

263.70 49.18

264.10 49.34

264.30 49.47

A090ohm-m0.2 20

Density Porosityft3/ft30.6 0

Neutron Porosityft3/ft30.6 0

Gamma RayAPI20 120

Caliper 1in.6 16

Caliper 2in.6 16

A010ohm-m0.2 20

OBMI Resistivityohm-m0.2 20

Shale or Wet Sand

Silt

CumulativeSand

CumulativeSilt

> Imaging thin beds in nonconductive muds. OBMI images (Track 4) compare favorably to core (Track5) and improve total sand-count estimates (Tracks 6 and 7) in nonconductive muds. Beds as thin as 0.5 in. [1.3 cm] can be identified but their thickness cannot be quantified until they reach 1.2 in. [3.0 cm],for example at XX84.0 ft. Additionally, planar and nonplanar bed boundaries can be identified, such asthe nonplanar bed boundary at XX83.4 ft, on both the core and the OBMI image.

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Winter 2001/2002 21

0 90degrees

20 120APIGamma Ray

ft

X570

X575

X580

X950

X955

X960

MDTadpoles

Borehole Drift

6 16in.Caliper 2

6 16in.Caliper 1

0.2 20ohm-m 0 90degrees

OBDT True Dip

0 90degrees

OBMI True Dip

AO90

0.2 0 120 240 36020ohm-mAO10

0.2 20ohm-mOBMI Resistivity

Resistive ConductiveOBDT

OBDTOrientation North

Orientation North0 120 240 360

Resistive ConductiveOBMI

Orientation North

OBMIOrientation North

> Computed dips from OBDT and OBMI data. The upper section shows that, in some cases, OBDTcomputed dips are comparable to OBMI computed dips (Track 4). The lower section reveals significantdifferences. The OBDT data and the OBMI images demonstrate the considerable difference in claritybetween the two data sets. Clarity is critical when handpicking dip sinusoids during the interpretationof the data.

50973schD3R1.p21.ps 2/6/02 7:13 PM Page 21

Complex StructuresCertain geologic provinces have experiencedintense folding, faulting and uplifting throughouttheir tectonic history. Extensive thrust faultingalong orogenic belts has created viable hydro-carbon traps, attracting operating companieslooking to exploit these challenging reservoirs.

Companies operating in these fold-and-thrustbelts often depend on nonconductive-mudsystems to successfully drill exploratory- anddevelopment-well programs. In these structuralsettings, sloughing shales are especially trouble-some during the drilling process, so every effortis made to minimize the shale-instability prob-lems. OBMs and SBMs have successfullyaddressed those problems.

The use of nonconductive muds has madedefining structure with conventional borehole-imaging and dipmeter tools a difficult task, and itis in these complicated tectonic settings that aclear picture is needed most. Critical to the suc-cess of these prospects is the understanding ofstructural geometries and features that are oftensteeply dipping, small and complicated andtherefore a hindrance to the production of inter-pretable surface-seismic images. Adding to thiscomplexity are deep subthrust reservoirs thatlack a clear seismic response. The OBMI tool hasmade a positive impact in these areas by helpingcompanies define and refine near-wellbore struc-tural geometries. The new information from theOBMI tool is applied to geological models,improving the structural control and reducing theexploration risk of these prospects.

The OBMI tool has been used extensively bycompanies operating in the Canadian Foothills ofAlberta, Canada. The Foothills are a part of thelarger fold-and-thrust belt extending along theRocky Mountains. Horizontal compression hasdeformed the sedimentary rock layers so thatthrust sheets actually ride over each other, stack-ing to form complex and repeating or imbricatethrust-duplex geometries (next page, top).27 Two-dimensional (2D) and three-dimensional (3D)seismic images are an important source of sub-surface information, but the mountainous terrainoften complicates the data-acquisition process.Additionally, seismic images of deep, intenselyfaulted and folded structures must be reinforcedwith the detailed structural knowledge thatcomes from accurate formation dip and fault datafound at the wellbore. In WBMs, this would notbe an issue, but this region requires the use ofOBMs to mitigate problems associated withshale instability. For these reasons, the OBMItool has become an essential part of formation-evaluation programs in the Canadian Foothills.

22 Oilfield Review

2500

2000

1500

Primary wellbore

Major thrust fault

1000

Depth,m

> StrucView plot of the upper section of the primary wellbore. The OBMI data(left) were instrumental in the identification of the major thrust fault at 2800 m.Wellbore trajectory and formation dips were plotted on a cross-sectionalview (right).

22.ps 03/26/2002 08:01 PM Page 22

Winter 2001/2002 23

El Paso Oil and Gas Canada Incorporated, inconjunction with Suncor Energy, has targeted thefractured Turner Valley formation carbonate rocksin the northern portion of the Alberta foothills.Initially, a primary well was drilled vertically withOBM and logged with the OBMI tool in both theupper and lower sections. An upper OBMI log-ging pass produced formation dips and identifiedthe presence of a major thrust fault at 2800 m[9186 ft]. The formation bedding was thoroughlyexamined using the OBMI tool, and the dips wereused to generate a cross section in StrucViewGeoFrame structural cross section software (previous page). This StrucView interpretationwas generated across the upper portion of theprimary wellbore and was in good agreementwith the surface-seismic images.

Drilling was suspended temporarily to run theOBMI tool at 3582 m [11,750 ft] and again at3665 m [12,020 ft] because formation tops werecoming in 150 m below the predicted tops. Usingthe new dip information and sonic data, El Pasowas able to correctly tie the log data to the 3Dseismic image by moving the seismic data fivetraces in the up-dip direction.

High-confidence dip data from directly abovethe Turner Valley reservoir indicated that the pri-mary well actually missed the structural crestand was not in an ideal position to initiate thehorizontal well through the reservoir. Commonly,fractured reservoirs maintain optimal productiv-ity along the crest of these structures due to thepresence of open tensional fractures. The OBMIdata and the corrected seismic images wereinstrumental in the design of a sidetrack well,from which a more effective horizontal well couldbe drilled along the crest of the structure.

Across the upper section of the sidetrackwell, the UBI tool was run in place of the OBMItool because the OBMI tool was unavailable for that logging run. Sufficient dip informationwas acquired during this run to confirm El Paso’screstal position on the structure. These datawere combined with those from the OBMI tool to construct another StrucView cross section,incorporating both the primary and sidetrackwellbores (right).

27. Mitra S: “Duplex Structures and Imbricate ThrustSystems: Geometry, Structural Position, and HydrocarbonPotential,” The American Association of PetroleumGeologists Bulletin 70, no. 9 (September 1986): 1087–1112.

1

1

1

2

2

2

3

3

3

Lower detachment

Upper detachment

Floorthrust

Imbri

cate

Roof thrust

1

2

3

> Evolution of a fold-and-thrust system. The formation of fold-and-thrust duplexes results in complexstructures, high dips and repeated sections. The labels 1, 2 and 3 represent both the theoreticalsequence timing and physical location of the thrust faults that form a duplex. The uppermost fault isoldest and the lowermost fault is youngest.

3000

Major thrust fault

Major thrust fault

Secondarythrust fault

Sidetrackwellbore

Turner Valleyformation

Primary wellbore

Depth,m

3500

> StrucView plot of the lower section of the primary and sidetrack wellbores. The OBMI data (left)identified the presence of the upper major thrust fault and confirmed the presence of the secondarythrust fault. The lowest thrust fault was below the well total depths and was identified from seismicimages. The interpreted OBMI data sets show increasing dip into the major thrust fault below, withthe steepest dips occurring near the major thrust fault (sidetrack well). With all available information,the sidetrack well was drilled into the crest and was in optimal position from which to drill the hori-zontal production well.

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The close proximity between the upper por-tion of the sidetrack well and the primary wellallowed comparison between UBI images andOBMI images. Both the UBI tool from the upperportion of the sidetrack and the OBMI devicefrom the primary wellbore adjacent to the side-track identified natural fracturing. The UBIimages showed the fractures were open but pro-vided less information on formation bedding,while the OBMI images revealed abundant detailon bedding (left).

After examining all structural dip data incombination with the corrected seismic images,El Paso now was confident about proceedingwith the horizontal production well. After inter-mediate casing was run, a 675-m [2215-ft]horizontal leg was drilled and successfully com-pleted in highly fractured sections of the TurnerValley formation.

In another part of the Canadian Foothills, theOBMI tool helped an operating company gaininsight about a complicated and repeating fold-and-thrust structure, enhancing the outlook forthe field. Drilled with OBM, wells in this play typ-ically penetrate two occurrences of Cretaceoussandstone reservoirs. The upper occurrence of thesand is productive when naturally fractured fromfolding and faulting processes that haveenhanced the zone’s permeability. The lower sandoccurrence is less likely to produce because thelower thrusts have undergone less displacementand deformation, resulting in less permeabilityand porosity enhancement from natural fractures.

Accurate dips across these stacked thrustsheets clarify the true thickness of the sands andalso the position of both the sands and the faultsseparating them. This information allows the geol-ogist to determine if the entire repeated section ispresent from which a sidetrack well design, riskand economics can be reasonably assessed.Dipmeters have rarely provided this critical infor-mation in the Canadian Foothills (left).

The initial geologic model for the lower sandoccurrence featured a simple overthrust scenariowith minimal drag and reduced dip roughly equalto regional dip. Seismic images successfullycharacterized the low-dip strata but becameunclear near the faults and folds. Below theupper fault, the overturned limb exhibits high for-mation dips and intense fracturing, precludingaccurate interpretation of dipmeter and seismicdata. Without a coherent picture, the secondsand was assumed to be continuous, moderatelydipping below the upper fault, and of poor reser-voir quality.

24 Oilfield Review

OBMI ImagesHandpicked Dips

UBI Images

3204

3205

3206

3207

3208

Depth,m 0 degrees 90

Bedding

Fractures

> OBMI images compared with UBI images. OBMI images (Track 1) provide a detailed picture of forma-tion bedding (arrows). The UBI images (Track 3) identify some bedding and indicate that the naturalfractures are open.

X220

OBMI Dynamic ImageOBMI Static

Image

TadpoleBorehole Drift Depth,

m

X221

X222

X200

X400

degrees0 90

mmCaliper 2

125 375

mmCaliper 1

125 375

APIGamma Ray

0 150

TadpoleBorehole Drift

degrees0 90

mmCaliper 2

125 375

mmCaliper 1

125 375

APIGamma Ray

OBMI StaticImage

OBMI Handpicked DipsDepth,m 0 90degrees

Mean-Square Dip0 90degrees

0 150

> Fault zone in the Canadian Foothills. A thrust fault runs through the upper sand occurrence at X221 m(left) and is responsible for the repeated section at X200 m (right). En-echelon faulting is observed atX320 m. The OBMI images allow the handpicking of dips (Track 3) that are more accurate than thecomputed dips from dipmeter data (Track 4) and more clearly identify the faults in the section.

24.ps 03/26/2002 08:01 PM Page 24

Winter 2001/2002 25

From work done with OBMI images, the oper-ating company and Schlumberger recognized thata major fold extended to the upper thrust faultand that the second sand, now overturned, con-stituted a new production target (right). Unlikesecond-sand occurrences in typical wells, thehighly fractured Cretaceous sand within the over-turned limb makes an excellent reservoir,increasing field production and reserves esti-mates. The geologic model used in explorationand development has fundamentally changedfrom a simple overthrust structure to a compli-cated but more accurate model that involves aninitial folding event followed by thrust-fault fail-ure and associated faulting.

The Potato Hills field in the Arkoma basin ofOklahoma, USA exemplifies how thrust faulting,folding and fracturing combine to create anextremely prolific field. Owned by The GHKCompany, the three-year-old field has produced a cumulative 92 Bcf [2.6 billion m3] of gas from 34 wells. While the majority of this gas has beenproduced from the Pennsylvanian Ratcliff sand inthe Jackfork Group, another deeper horizon, theOrdovician Bigfork chert, is now of great interest.The OBMI tool was instrumental in defining thenear-wellbore structure in the Bigfork chert andsurrounding formations in Potato Hills field. Oil-base muds are used in drilling the OuachitaMountain portion of the Arkoma basin becauseof the unstable shales present throughout thesection. These shales, the Stanley, MissouriMountain and Polk Creek—overlying theBigfork—and the Womble shale—underneaththe Bigfork—have been stressed by the exten-sive thrust faulting and folding that took placeduring the Ouachita orogeny.

Knowledge of the local structural complexi-ties in the field is extremely important for properoffset-well placement and for understanding theproduction behavior of wells. This information isoften not provided by the existing 2D seismicimages. In one particular well, the OBMI results,combined with conventional logs and aStrucView interpretation, helped define an over-turned fold in the Bigfork chert section (right).

Sand position in previous interpretation

Thrust fault

2 1First

occurrence

Secondoccurrence

Sand position incurrent interpretation

> Structural scenario depicting two models and the resulting theoretical wellpaths. After primary folding from compression, major thrust faulting is initiated.A subsequent secondary, or en-echelon, fault occurs, furthering the complexityof the model. Sample Wellbore path 1 (red) represents the previous geologicmodel while sample Wellbore path 2 (green) represents the new model.

10,500

Raw data

Reference: true Cross section width: 10 in.Cross section color: black Data used for

cross section

Similar foldcylindrical

APDip = 3.0APAzi = 69.0CSDir = 342

11,000

0Depth,

ft 90 Cross Section

Wellbore

0 90

> StrucView cross section of the upper limb of an overturned fold in Potato Hills field. The OBMIhandpicked dips (Track 1) were input to the StrucView application and allowed visualization of thisstructure. The GHK Company now believes this reservoir is more extensive and less compartmental-ized than previously thought.

50973schD3R1.p25.ps 2/6/02 7:13 PM Page 25

The clearer picture of the structural geometry hasdemonstrated to GHK that the reservoir is moreextensive and less compartmentalized than waspreviously believed.

In the past, GHK used other methods toextract structural information from wells in thisplay with only moderate success. For example,conventional dipmeters have not producedrepeatable dip information. Dips computed fromdifferent companies’ wireline tools were signifi-cantly different in the same wellbore intervallogged twice.

Ultrasonic-imaging tools used in the PotatoHills field also have yielded disappointingresults. These acoustic devices delivered fair-quality images of natural fractures but gener-ated only low-quality dip information, becauseof the ultrasonic tools’ relative insensitivity toformation bedding.

Unlike dipmeter tools, the OBMI tool providedthe data quality necessary for GHK to identifyand differentiate lithology boundaries, faults,fractures and bedding planes (above). The staticOBMI image helped in locating lithology changesand faults, while the dynamic image was used to

calculate orientations of fractures, beddingplanes and faults.28 The ability to see the key fea-tures on the OBMI images allowed GHK to useonly the meaningful data in their analyses, andprovided the confidence to incorporate thosedata into their geologic and reservoir models.

26 Oilfield Review

Conductive Resistive

0 360120 240

OBMI ImageMD ft

2835

2840

Gamma Ray

API0 150

degrees

Fault, True Dip

0 90

Orientation Top of Hole

Conductive Resistive

0 360120 240

OBMI Image

Orientation Top of Hole

Caliper 2

Borehole Drift

in.5 15

degrees0 50

Caliper 1

in.5 15 degrees

Bed Boundary, True Dip

0 90

Minor reverse fault

> Using OBMI images to characterize a fault in Potato Hills field. Two passeswith the OBMI tool produced excellent borehole coverage and clearly pin-pointed this minor reverse fault (arrow) located uphole from the main reservoirs.

28. In static image processing, colors are assigned to resis-tivity values across an entire data set, enabling the inter-preter to observe gross changes across large intervals.In dynamic image processing, colors are reassigned at fixed intervals, normally one or two feet. Dynamic, or highlight, processing creates maximum contrast onthe images, allowing the observation of fine details suchas crossbedding.

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Winter 2001/2002 27

Imagine the FutureAs information on hydrocarbon reservoirsbecomes increasingly detailed, the industry hasdeveloped ways to harness improved measure-ments and convert them to knowledge for moreprofitable and less risky exploitation of assets.Although the physical obstacles to imagingreservoirs through nonconductive mud systemstemporarily placed the numerous benefits ofborehole imaging beyond the reach of reservoirexperts, that is no longer the case.

Throughout the development and field testingof the OBMI tool, data quality improved continu-ally with every design change. The image qualitytoday is making possible intensive structuralanalyses, and the tool now is being used in anever-expanding array of stratigraphic applica-tions. As experience with OBMI data grows,geologists and engineers will develop even moreapplications to answer key questions about theirreservoirs. The OBMI tool has effectively placedborehole imaging onto the OBM and SBM forma-tion-evaluation palette (above). Combining OBMI

information with existing knowledge and othernew and emerging technologies will help compa-nies find the missing pieces to complete a clearreservoir picture—a picture worth framing, evenwhen imaged through oil-base muds. —MG

Wire

line

LWD

UBI

FMI

OBDT

OBMI

RAB

ADN

Stratigraphic Feature Characterization

Wire

line

LWD

UBI

FMI

OBDT

OBMI

RAB

ADN

WBMLight Heavy

OBM/SBMLight Heavy

Thin-Bed Analysis

Wire

line

LWD

UBI

FMI

OBDT

OBMI

RAB

ADN

Structural Feature Characterization

Wire

line

LWD

UBI

FMI

OBDT

OBMI

RAB

ADN

Fracture Characterization

Wire

line

LWD

UBI

FMI

OBDT

OBMI

RAB

ADN

Core Orientation

Wire

line

LWD

UBI

FMI

OBDT

OBMI

RAB

ADN

WBMLight Heavy

OBM/SBMLight Heavy

Borehole Shape, Stability and Stress Analysis

Wire

line

LWD

UBI

FMI

OBDT

OBMI

RAB

ADN

Porosity and Dual-Porosity AnalysesW

irelin

eLW

D

UBI

FMI

OBDT

OBMI

RAB

ADN

WBMLight Heavy

OBM/SBMLight Heavy

Lithofacies Analysis

Wire

line

LWD

UBI

FMI

OBDT

OBMI

RAB

ADN

Horizontal Well and GeoSteering Applications

HighLowPerformance

> Filling the borehole-imaging gap in nonconductive mud-filled boreholes. At 1.2-in. resolution, the OBMI tool permits the examination of stratigraphic beddingand features, improves the accuracy of sand-count analyses and the capacity to identify small structural features, even in heavy SBMs and OBMs. Acoustic-imaging devices, like the UBI tool, are important in nonconductive muds because they allow detailed examination of borehole shape, stress-related featuresand natural fractures. Their effectiveness diminishes when mud weights increase. LWD imaging tools maintain their importance in horizontal or highly devi-ated wells, especially when real-time answers are required for geosteering operations. However, RAB images cannot be acquired in nonconductive muds.

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