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58 Oilfield Review Real-Time LWD: Logging for Drilling For help in preparation of this article, thanks to Tom Bratton, Mark Fredette, Qiming Li and Iain Rezmer-Cooper, Sugar Land, Texas, USA; Jim Bristow, Gatwick, England; Jesse Cryer, Anchorage, Alaska, USA; Torger Skillingstad, Stavanger, Norway; Ian Tribe, Aberdeen, Scotland; and Doug Waters, Austin, Texas. ADN (Azimuthal Density Neutron tool), AIM (At-Bit Inclination Measurement tool), APWD (Annular Pressure While Drilling), ARC5 (Array Resistivity Compensated tool), CDN (Compensated Density Neutron tool), CDR (Compen- sated Dual Resistivity tool), Drill-Bit Seismic, DTOR (Downhole Torque-at-the Bit), DWOB (Downhole Weight- on-Bit), FMI (Fullbore Formation MicroImager), GeoSteering, GeoVISION, GeoVISION675, IDEAL (Integrated Drilling Third-generation logging-while- drilling tools are adding a new dimension to ongoing industry efforts targeting more efficient and cost-effective well construc- tion. Capability enhancements offer lower risk and more accu- rate well placement. As a result, real-time logging-for-drilling is fast becoming a reality. Pushed to keep pace with changing economics and rapid advances in drilling innovations, logging- while-drilling (LWD) technology has matured into its third generation in just over a decade (next page). The first tools, introduced in the late 1980s, provided basic directional and formation-evalua- tion measurements, and served as insurance logs in vertical and deviated wells. 1 At that time, the pri- mary applications were stratigraphic and structural correlation with nearby wells and basic formation evaluation. Logging while drilling ensured acquisi- tion of basic data needed to determine productivity and commerciality and mitigate drilling risk. As more and more reservoirs have been suc- cessfully exploited, the exploration and production (E&P) industry has undertaken development of more difficult and marginal reservoirs—smaller, thinner, fractured and of lower quality—which pre- viously had often been poorly rated and bypassed. Today, technically and economically challenging well designs that were rare or nonexistent only five years ago—deepwater, extended reach, horizontal and multilateral—are routinely utilized to maximize reservoir production and reserves. 2 To hit these smaller, tighter and harder-to-reach reservoir tar- gets, well construction evolved from geometrical designs to wells steered by geological information. The second phase in LWD development, throughout the mid-1990s, reflected this evolu- tion with the introduction of azimuthal measure- ments, borehole images, instrumented steerable motors and forward-modeling programs to achieve Saad Bargach Ian Falconer Carlos Maeso John Rasmus Sugar Land, Texas, USA Ted Bornemann Richard Plumb Houston, Texas Daniel Codazzi Kyel Hodenfield Clamart, France Gary Ford John Hartner Anadarko Petroleum Corp. Anchorage, Alaska, USA Bill Grether Petrotechnical Resources Alaska Anchorage, Alaska Hendrik Rohler RWE-DEA AG Hamburg, Germany Evaluation and Logging), IMPulse, INFORM (Integrated Forward Modeling), InterACT, InterACT Web Witness, ISONIC (IDEAL sonic-while-drilling tool), IWOB (Integrated Weight on Bit), KickAlert, M3, MACH-1 (Seismic Guided Drilling), MEL (Mechanical Efficiency Log), PERFORM, PERT (Pressure Evaluation in Real Time), Platform Express, PowerDrilling, PowerPulse, RAB (Resistivity-at-the-Bit tool), RWOB (Receiver, Weight on Bit and Torque tool), SHARP, Slim 1, SlimPulse, SPIN (Sticking Pipe Indicator program), UBI (Ultrasonic Borehole Imager), VIPER, VISION, VISION First Look, VISION475, VISION675 and VISION825 are marks of Schlumberger.
Page 1: Real-Time LWD: Logging for Drilling - slb.com/media/Files/resources/oilfield_review/ors00/... · Real-Time LWD: Logging for Drilling For help in preparation of this article, thanks

58 Oilfield Review

Real-Time LWD: Logging for Drilling

For help in preparation of this article, thanks to Tom Bratton,Mark Fredette, Qiming Li and Iain Rezmer-Cooper, SugarLand, Texas, USA; Jim Bristow, Gatwick, England; JesseCryer, Anchorage, Alaska, USA; Torger Skillingstad,Stavanger, Norway; Ian Tribe, Aberdeen, Scotland; andDoug Waters, Austin, Texas.ADN (Azimuthal Density Neutron tool), AIM (At-BitInclination Measurement tool), APWD (Annular PressureWhile Drilling), ARC5 (Array Resistivity Compensated tool),CDN (Compensated Density Neutron tool), CDR (Compen-sated Dual Resistivity tool), Drill-Bit Seismic, DTOR(Downhole Torque-at-the Bit), DWOB (Downhole Weight-on-Bit), FMI (Fullbore Formation MicroImager), GeoSteering,GeoVISION, GeoVISION675, IDEAL (Integrated Drilling

Third-generation logging-while-

drilling tools are adding a new

dimension to ongoing industry

efforts targeting more efficient

and cost-effective well construc-

tion. Capability enhancements

offer lower risk and more accu-

rate well placement. As a result,

real-time logging-for-drilling is

fast becoming a reality.

Pushed to keep pace with changing economics andrapid advances in drilling innovations, logging-while-drilling (LWD) technology has matured intoits third generation in just over a decade (nextpage). The first tools, introduced in the late 1980s,provided basic directional and formation-evalua-tion measurements, and served as insurance logsin vertical and deviated wells.1 At that time, the pri-mary applications were stratigraphic and structuralcorrelation with nearby wells and basic formationevaluation. Logging while drilling ensured acquisi-tion of basic data needed to determine productivityand commerciality and mitigate drilling risk.

As more and more reservoirs have been suc-cessfully exploited, the exploration and production(E&P) industry has undertaken development of

more difficult and marginal reservoirs—smaller,thinner, fractured and of lower quality—which pre-viously had often been poorly rated and bypassed.Today, technically and economically challengingwell designs that were rare or nonexistent only fiveyears ago—deepwater, extended reach, horizontaland multilateral—are routinely utilized to maximizereservoir production and reserves.2 To hit thesesmaller, tighter and harder-to-reach reservoir tar-gets, well construction evolved from geometricaldesigns to wells steered by geological information.

The second phase in LWD development,throughout the mid-1990s, reflected this evolu-tion with the introduction of azimuthal measure-ments, borehole images, instrumented steerablemotors and forward-modeling programs to achieve

Saad BargachIan FalconerCarlos MaesoJohn RasmusSugar Land, Texas, USA

Ted BornemannRichard PlumbHouston, Texas

Daniel CodazziKyel HodenfieldClamart, France

Gary FordJohn HartnerAnadarko Petroleum Corp.Anchorage, Alaska, USA

Bill GretherPetrotechnical Resources AlaskaAnchorage, Alaska

Hendrik RohlerRWE-DEA AGHamburg, Germany

Evaluation and Logging), IMPulse, INFORM (IntegratedForward Modeling), InterACT, InterACT Web Witness,ISONIC (IDEAL sonic-while-drilling tool), IWOB (IntegratedWeight on Bit), KickAlert, M3, MACH-1 (Seismic GuidedDrilling), MEL (Mechanical Efficiency Log), PERFORM, PERT(Pressure Evaluation in Real Time), Platform Express,PowerDrilling, PowerPulse, RAB (Resistivity-at-the-Bit tool),RWOB (Receiver, Weight on Bit and Torque tool), SHARP,Slim 1, SlimPulse, SPIN (Sticking Pipe Indicator program),UBI (Ultrasonic Borehole Imager), VIPER, VISION, VISIONFirst Look, VISION475, VISION675 and VISION825 are marksof Schlumberger.

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1. Allen D, Bergt D, Best D, Clark B, Falconer I, Hache J-M,Kienitz C, Lesage M, Rasmus J and Wraight P: “LoggingWhile Drilling,” Oilfield Review 1, no. 1 (April 1987): 4-17.Bonner S, Clark B, Holenka J, Voisin B, Dusang J,Hansen R, White J and Walsgrove T: “Logging WhileDrilling: A Three-Year Perspective,” Oilfield Review 4, no. 3 (July 1992): 4-21.

2. Allen F, Tooms P, Conran G, Lesso B and Van de Slijke P:“Extended-Reach Drilling: Breaking the 10-km Barrier,”Oilfield Review 9, no. 4 (Winter 1997): 32-47.Bosworth S, El-Sayed HS, Ismail G, Ohmer H, Sracke M,West C and Retnanto A: “Key Issues in MultilateralTechnology,” Oilfield Review 10, no. 4 (Winter 1998): 14-28.

3. Bonner S, Burgess T, Clark B, Decker D, Orban J,Prevedel B, Lüling M and White J: “Measurement at theBit: A New Generation of MWD Tools,” Oilfield Review 5,no. 2/3 (April/July 1993): 44-54.

Autumn 2000 59

accurate well placement through geosteering.3

Initially, real-time steering used rate of penetra-tion (ROP), then resistivity to “bounce” off sand-shale bed boundaries. Drillers now use real-timeazimuthal measurements, including boreholeimages, formation dips and density to find andstay within the reservoir sweet spot. Theseadvances have resulted in a higher percentage ofsuccessful wells, especially highly deviated,extended-reach and horizontal boreholes.4

Today, drilling efficiency, risk managementand accurate well placement are the keys to

lower exploration and development costs.Drilling efficiency means minimizing lost or non-productive time by avoiding problems such asdrillstring failure, stuck pipe and fluid influx orloss, and also managing the risks inherent in thedrilling process, such as wellbore instability.Mechanical earth models (MEM) are used tointegrate all available data.5 Logging for drillingprovides the data needed to define the geologicenvironment and drilling process and the real-time information essential for confirming orupdating the predicted MEM during drilling.

Inconsistencies between prediction and reality mayindicate the need for preventive or remedial action.

Accurate well placement means steeringwells to an optimal position in the target reser-voir to maximize production. At the same time,today’s economic constraints related to the highcost of reaching reservoirs often dictate that awell access multiple targets, typically over longhorizontal segments. Failure to correct rapidly forunforeseen variations in geology and structure,such as fault offset or changes in dip, can resultin a low-value deviated or horizontal hole.

2nd (1993 to 1996) 3rd (1997 to 2000)Generation

Service type

Surface control system

bits per second (bps)Maximum telemetry rate,


Primary application




1st (1988 to 1992)






Formation evaluation




Slim 1


Formation evaluation while drilling

Borehole-compensated resistivity

Dual-spacing resistivity

Density-neutron resistivity



Answer products




Maximum density

Quick look formation evaluation


Quantitative Resistivity Overlay



6 to 10


Geosteering-successfully in the reservoir

Formation evaluation






Azimuthal readings

Resistivity images

Array resistivity

Bit resistivity

Instrumented motor

Drill-Bit Seismic







Ultrasonic caliper

Answer products

Drillpipe washout


TR anticollision

PowerDrilling monitor

Bit cone lock

Smart alarms


Quadrant density

Correlation screen

GeoSteering screen



12 to 16

InterACT Web Witness

Real-time decisions for drilling efficiency and risk management

Geosteering to best part of reservoir




Improved accuracy

Wider range in hole size

Nonchemical source

Real-time images

Improved reliability

Seismic MWD

VISION475, 675, 825

ARC312, ARC900

Porosity Evaluation Tool


Answer products


Density images


VISION First Look

> Introduction history for logging-while-drilling (LWD) and measurements-while-drilling (MWD) technologies.

Bonner S, Fredette M, Lovell J, Montaron B, Rosthal R,Tabanou J, Wu P, Clark B, Mills R and Williams R:“Resistivity While Drilling—Images From the String,”Oilfield Review 8, no. 1 (Spring 1996): 4-19.Evans M, Best D, Holenka J, Kurkoski P and Sloan W:“Improved Formation Evaluation Using AzimuthalPorosity Data While Drilling,” paper SPE 30546, pre-sented at the SPE Annual Technical Conference andExhibition, Dallas, Texas, USA, October 22-25, 1995.Prilliman JD, Allen DF and Lehtonen LR: “Horizontal Well Placement and Petrophysical Evaluation UsingLWD,” paper SPE 30549, presented at the SPE AnnualTechnical Conference and Exhibition, Dallas, Texas, USA,October 22-25, 1995.

4. Rasmus J, Bornemann T, Farruggio G and Low S:“Optimizing Horizontal Laterals in a Heavy Oil ReservoirUsing LWD Azimuthal Measurements,” paper SPE 56697,presented at the SPE Annual Technical Conference andExhibition, Houston, Texas, USA, October 3-6, 1999.

5. Aldred W, Cook J, Bern P, Carpenter B, Hutchinson M,Lovell J, Rezmer-Cooper I and Leder PC: “Using DownholeAnnular Pressure Measurements to Improve Drilling Per-formance,” Oilfield Review 10, no. 4 (Winter 1998): 40-55.Aldred W, Plumb D, Bradford I, Cook J, Gholkar V,Cousins L, Minton R, Fuller J, Goraya S and Tucker D:“Managing Drilling Risk,” Oilfield Review 11, no. 2(Summer 1999): 2-19.Plumb R, Edwards S, Pidcock G, Lee D and Stacey B:“The Mechanical Earth Model Concept and ItsApplication to High-Risk Well Construction Projects,”paper IADC/SPE 59128, presented at the IADC/SPEDrilling Conference, New Orleans, Louisiana, USA,February 23-25, 2000.Rezmer-Cooper I, Bratton T and Krabbe H: “The Use of Resistivity-at-the-Bit Images and Annular PressureWhile Drilling in Preventing Drilling Problems,” paper IADC/SPE 59225, presented at the IADC/SPEDrilling Conference, New Orleans, Louisiana, USA,February 23-25, 2000.

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Near-bit inclination and azimuthal data, espe-cially borehole images, offer the best means forreaching the desired target with fewer correctionruns, less tortuosity, and more of the boreholewithin the reservoir. Current tools routinelyachieve absolute vertical depth tolerances of lessthan 2 m [6 ft] and relative depth tolerances ofless than 0.35 m [1 ft]. This allows wells not onlyto stay within narrow pay zones but also avoidcollisions with other wells draining the samezone.6 In total, enhanced well placement pro-duces safer, more efficient and more accuratedrilling, and more productive wells, resulting insignificant cost savings.

To accomplish these objectives, data must beavailable and delivered to decision-makers withinthe relevant time frame required for making oper-ational choices. “Relevant” real time may varyfrom seconds to 12 hours, depending on the typeof problem that is anticipated or has beenencountered, and the type and speed of responserequired. Rapid advances in communicationstechnology, particularly Internet-based solutions,

make possible in-time data delivery to assetteams anywhere in the world.7

Real-time LWD products now includeenhanced resistivity, porosity, acoustic transittime, borehole images, dips, annular pressure,leakoff and formation integrity tests.8 This articlediscusses recent advances in LWD technology,focusing on the application of real-time at-bitinclination data and images for enhanced wellplacement and drilling efficiency.

Enhancing Well PlacementContinuous inclination saves rig time by reducingthe need for stationary measurements. Combiningcontinuous wellbore surveys from the new AIMAt-Bit Inclination Measurement module withVISION modules optimizes drilling control andefficiency (above).9

Direct measurement of inclination changeduring slide drilling optimizes steering andresults in reduced tortuosity and minimal undula-tions in horizontal wells. Resulting reductions intorque and drag on the drillstring enable greaterrates of penetration and enhance the ability todrill extended-reach wells with longer lateralsections while reducing the chances of gettingstuck. AIM technology lowers costs by saving rig

60 Oilfield Review









89.516,700 16,800






Measured depth, ft

16,900 17,000 17,100 17,200 17,300 17,400 17,500 17,600 17,700

> Comparison of AIM At-Bit Inclination Measurement results (yellow) with conventionalMWD (red) and stationary (purple) surveys. The data are taken from a 61⁄8-in. horizontal welldrilled in the Austin Chalk. The stationary and MWD measurements track very well, whilethere is a slight difference between the MWD and AIM measurements. This difference,only 0.2° to 0.3°, results from the way bottomhole assembly (BHA) sag affects each tool.The difference between the two measurements decreases further when the stabilizerbuttons are in a retracted position (purple shaded area) and the BHA drops angle.

Vertical section, m





th, m

0 400








X56200 600 800

Top of window

Bottom of windowA




1000 1200

C Drilled using GeoSteering toolD Drilled using VISION475 and AIM tools

A, B Drilled without GeoSteering tool

> Vertical tolerances. A West African horizontal well projectrequired a depth tolerance of ±3 ft. Depth variation in the first twowells (A and B), drilled with a conventional steerable motor BHA,exceeded 6.5 ft and resulted in gas production. The average depthtolerance (± 2.2 ft) of three wells (C) drilled with the GeoSteeringinstrumented motor stayed within the goal. The final well (D) wasdrilled with an AIM tool on a steerable motor and achieved an aver-age vertical tolerance of less than 1 ft. Wells C and D were completedwithout gas production, and well D was completed three days aheadof schedule.

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Autumn 2000 61

time and improving drilling efficiency, andincreases productivity by maximizing pay-zonefootage and mitigating borehole undulations thatcan result in restricted oil flow.

A West African horizontal well project calledfor a target window that was only 4 m [13 ft] belowthe gas-oil contact and 12 m [39 ft] above anaquifer. One deviated and six horizontal wells weredrilled to create the horizontal drains. Maximumreservoir drainage required a tight vertical depthtolerance of ±1 m [±3 ft] to prevent water coningand gas production. In the first two wells, A and B,the operator used conventional steerable-motorbottomhole assemblies (BHA) and the verticaldepth variation exceeded 2 m [6.5 ft], resulting ingas production (previous page, bottom). The nextthree drainholes were drilled with the GeoSteeringtool, an instrumented motor with an inclinationsensor positioned 2.5 m [8 ft] behind the bit. Theaverage vertical tolerance improved to ± 0.7 m [± 2.2 ft]. The last well was landed in a 81⁄2-in. holefrom which a 6-in. lateral was drilled. A steerablemotor equipped with AIM capability was used, andthe average vertical tolerance achieved was ± 0.3 m[± 0.9 ft]. The drainhole section was completedthree days ahead of schedule because of reducedtortuosity and better BHA control. In the last fourwells, the use of near-bit sensors providing contin-uous directional control, together with steerablemotors, achieved the necessary depth tolerance toavoid gas production.10

Multidepth VisionThe VISION system represents the latest genera-tion of LWD multidepth measurements, includinginduction-type, or electromagnetic propagation,resistivity, azimuthal density-neutron, and con-ventional and azimuthal laterolog services (aboveright). The VISION propagation resistivity andazimuthal density-neutron tools, redesignedbased on the earlier RAB Resistivity-at-the-Bitand ADN Azimuthal Density Neutron tools, areequipped with increased downhole memory and

all-digital electronics that provide more accurateand reliable measurements equal in quality tothe wireline Platform Express system. Real-timeAPWD Annular Pressure While Drilling measure-ments contribute to improved steering perfor-mance, drilling efficiency and rig safety.11

Fullbore images for use in structural interpre-tation, geosteering, formation evaluation andborehole-failure analysis can be obtained with theVISION system in all mud conditions. In conductivemuds, GeoVISION azimuthal resistivity providesadditional imaging capability. Sixteen-channeldensity images and 56-channel resistivity imagesare available in real time or from memory data. Inhighly deviated or horizontal wells drilled with oil-base or synthetic muds, VISION tools often pro-vide the only option for borehole images. Forenhanced interpretation, both tools can be com-bined on the same BHA.

Initially introduced in a 43⁄4-in. tool collar size,VISION modules are now available for 63⁄4-in.BHAs. The VISION475 tool is designed for bore-

holes smaller than 61⁄4-in. diameter, while the newVISION675 tool is used for 8- to 97⁄8-in. holes.12 Theforthcoming VISION825 system is designed for121⁄4-in. boreholes. VISION services are combin-able with optional AIM measurements, GeoVISION,GeoSteering tool, IWOB (Integrated Weight onBit), ISONIC IDEAL sonic-while-drilling, and MVC(multiple axis vibration) services.

High-resolution azimuthal image logs areextremely valuable in highly deviated wells, butsometimes the deviation itself makes the mea-surement difficult to acquire. VISION azimuthaldensity-neutron (VADN) technology advances theazimuthal technology introduced with the previ-ous ADN tool.13 Density and Pe photoelectric fac-tor measurements with 6-in. vertical resolutionare now sampled in 16 azimuthal sectors for moredetailed imaging—compared with only fourquadrants in the older ADN tool—and simultane-ously in four quadrants for improved real-timegeosteering decisions and petrophysical analysis.The availability of quadrant data ensures that

VISION density neutron


VISION resistivity

IDEAL wellsiteinformation system GeoVISION

resistivityAIM At-Bit Inclination


GeoSteering tool(optional)



> Available VISION services. Multidepth propagation resistivity and azimuthal density-neutrondevices are available in 43⁄4-in. and 63⁄4-in. collar sizes, and multidepth at-bit and azimuthal laterologmeasurements are available in 63⁄4-in. collars. Both are combined with the PowerPulse MWDtelemetry module for uphole data transmission to the IDEAL Integrated Drilling Evaluation and Logging wellsite information system and real-time data communication and delivery viasatellite. The GeoVISION tool can also be combined with the GeoSteering tool instrumenteddownhole motor.

6. Pogson M, Hillock P, Edwards J and Nichol G: “ReservoirOptimization in Full-Field Development Using GeosteeringTechniques to Avoid Existing Production Completions,”paper SPE 56452, presented at the SPE Annual TechnicalConference and Exhibition, Houston, Texas, USA,October 3-6, 1999.Edwards J: “Geosteering Examples Using Modeling of 2-MHz Resistivity LWD in the Presence of Anisotropy,”Transactions of the SPWLA 41st Annual LoggingSymposium, Dallas, Texas, USA, June 5-7, 2000, paper NN.

7. Brown T, Burke T, Kletzky A, Haarstad I, Hensley J,Murchie S, Purdy C and Ramasamy A: “In-Time DataDelivery,” Oilfield Review 11, no. 4 (Winter 1999/2000): 34-55.

8. Aldred et al, reference 5.Rezmer-Cooper I, Rambow FHK, Arasteh M, HashemMN, Swanson B and Gzara K: Real-Time FormationIntegrity Tests Using Downhole Data,” paper IADC/SPE59123, presented at the IADC/SPE Drilling Conference,New Orleans, Louisiana, USA, February 23-25, 2000.

9. Varco M, Smith JE and Stone DM: “Inclination at the BitImproves Directional Precision for Slimhole HorizontalWells—Local Case Histories,” paper SPE 54593, pre-sented at the SPE Western Regional Meeting,Anchorage, Alaska, USA, May 26-28, 1999.

10. Skillingstad T: “At-Bit Inclination Measurements Improves Directional Drilling Efficiency and Control,”paper IADC/SPE 59194, presented at the IADC/SPEDrilling Conference, New Orleans, Louisiana, USA,February 23-25, 2000.

11. Aldred et al, reference 5.12. Bornemann E, Hodenfield K, Maggs D, Bourgeois T and

Bramlett K: “The Application and Accuracy of GeologicalInformation From a Logging-While-Drilling Density Tool,”Transactions of the SPWLA 39th Annual LoggingSymposium, Keystone, Colorado, USA, May 26-29,1998,paper L.Bourgeois TJ, Bramlett K, Craig P, Cannon D, HodenfieldK, Lovell J, Harkins R and Pigram I: “Pushing the Limitsof Formation Evaluation While Drilling,” Oilfield Review 10,no. 4 (Winter 1998): 29-39.

13. Bourgeois et al, reference 12.

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reliable density is obtained in highly deviatedboreholes. This is especially important whentools are run slick without stabilizers. Viewingthe density image or analyzing quadrant dataindicates which sectors are actually in contactwith the borehole, thus providing an accurate

In the case of enlarged wellbores, reliableand accurate data can be extracted manuallyfrom different sectors for different intervals.Furthermore, as long as the BHA rotates, theazimuthal sensors continue to acquire measure-ments for each sector. Because the tool can beeccentered within the borehole, these data mayrepresent varying amounts of mud and formation.Under these circumstances, density images stillprovide valuable information about borehole

geology, such as dips and concretions, and con-dition, such as spiraling.14 Although structuraldata, such as absolute image-derived dips andazimuth obtained from a slick tool are not reliable,relative changes will still be significant.

For optimum drilling efficiency and accuracy,high-resolution resistivity images can revealsubtle stratigraphic features, formation beddingand near-borehole dip to enable drillers to keepboreholes parallel to bedding, thereby reducinguncertainty in geosteering. Resistivity imagesalso provide valuable information about fracturesand borehole failure that reflect the geomechan-ical state of the borehole. Recognizing and under-standing the modes and mechanisms of boreholefailure allow drillers to take remedial actions thatimprove drilling efficiency.

GeoVISION tools add important laterologresistivity measurements to the VISION systemfor 63⁄4-in. BHAs. Measurements include at-bitresistivity, high-resolution ring resistivity, and anoption for near-bit high-resolution, and multi-depth, azimuthal resistivity. GeoVISION technol-ogy is based on earlier RAB technology, but thenew design and technical improvements providemore accurate measurements in high-resistivityzones—even in the most conductive muds. Theresolution of GeoVISION recorded-mode imageshas improved by increasing the maximum scanrate from once every 10 to once every 5 seconds.Built-in, downhole processing, first introducedwith RAB measurements, allows real-time calcu-lation of structural dip. GeoVISION technologynow includes the transmission and viewing of56-sector azimuthal resistivity fullbore images in

When sufficient density contrast exists, for-mation heterogeneity, thin beds and large-scalestratigraphic features can be identified on densityimages, as well as on higher resolution GeoVISIONresistivity images.

Conventional image processing and analysis,including normalization, and dip-extraction tech-niques are applied to LWD density and resistivityimages. GeoVISION images have the highest LWDresolution, but this is still lower than wireline FMIFullbore Formation MicroImager resolution by a

be acquired only during drillstring rotation.Image quality is affected by a number of

factors that must be considered during imageinterpretation. The first is the relative location ofthe sensors used to make the images. Resistivityimages are generated from data obtained bynear-bit sensors, while density images are gen-erated from data obtained by sensors 60 to 130 ft[18 to 40 m] behind the bit. Features apparent on density images but not on resistivity imagesmay be drilling-induced and signal the need tomake corrections in the drilling process. Second,discrimination of structural and stratigraphicfeatures on density images requires a contrast in density greater than 0.1 g/cm3. Third, bore-hole shape and size and BHA position within thehole may prevent sensors from contacting theborehole wall, resulting in a lower quality image.Fourth, image resolution suffers when rotationspeed is low (less than 30 rpm) or the rate ofpenetration is high (greater than 200 ft/hr[61 m/hr]) since this affects the number of datapoints per foot.

62 Oilfield Review


drilling upstructure

RHOB image




Pe0 10

Bottom density1.95 2.95

Neutron0.45 -0.15


g/cm3Bottom density

Bulk volumes


Res. time-bitft0 10 ohm-m0 10

0 10hr




GR0 10API unit

Effective porosityClayLimestoneBound water

1.95 2.95

Phase-shift resisitivities0.2 2000ohm-m

ohm-m ft3/ft3

> VISION First Look field presentation. Track 1 contains true vertical depth (TVD) and theelapsed time between bit penetration and resistivity measurement. Track 2 presents gammaray (red) and Rwa (green fill). Track 3 presents relative bulk volumes of the lithologies, boundwater and effective porosity. Track 4 presents VISION resistivities (attenuation and phaseshift) and Track 5 VISION azimuthal density neutron (bottom density, neutron porosity andphotoelectric effect, Pe). Track 6 contains the density image. The green stripes representintervals where an image was not generated. Dips obtained from the chevron patterns indicatethe well is drilling up structure. Vertical image resolution is dominated by the resolution ofthe far detector, 6 in. for density and 2 in. for Pe. Discrimination of bed boundaries, as shownhere, requires an image contrast greater than 0.2 g/cm3. Images identify that the drill bit isdrilling up structure and approaching a boundary far before it is evident on geosteering withresistivity or gamma ray. Azimuthal data and images provide wellbore orientation relative tobedding planes that is vital to accurate and efficient geosteering.

14. Maeso C, Sudakiewicz N and Leighton P: “FormationEvaluation From Logging-While-Drilling Data in a 6.5 InchHorizontal Well—A North Sea Case Study,” Transactionsof the SPWLA 40th Annual Logging Symposium, Oslo,Norway, May 30-June 3,1999, paper K.

real time (next page, left).

factor of five (next page, right). LWD images can

density measurement (above).

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Autumn 2000 63

Geosteering for Increased ProductionDefining geologic structure while drilling is oftencrucial to accurate geosteering. Structural dipscomputed in real time or “relevant” real time—using images created from memory dataretrieved during bit runs—from VISION systemsare used to update the INFORM IntegratedForward Modeling model. This reduces uncer-tainty in the structural model and helps improveinterpretation. The results are more efficientdrilling and lower cost to reach the desired targetor to stay within the pay zone. Detailed post-drilling dip interpretations using density andresistivity images are valuable for updating geo-logic maps and planning subsequent well trajec-tories. Dip determination from density images issimilar to the process used by traditionalmicroresistivity interpretation.

The complex geology of the Cook Inlet, Alaska,USA, presents many technical challenges fordrilling and evaluation. Targets include tight,steeply dipping anticlinal structures. Successfuldrilling and completion require the acquisition ofprecise structural and stratigraphic dips to updatepredrilling seismic models and to geosteer wellsfor optimal placement. In one recent well, the

>GeoVISION real-time log presentation for a RWE-DEA horizontal gas-storagewell in Germany. Track 1 shows borehole drift and azimuth (tadpoles) andazimuthal gamma ray (up, red and down, green). Track 2 contains apparent(triangles, right side) and true (circles, left side) dips computed in real time.Track 3 presents GeoVISION resistivity curves: ring (black), bit (red) and deepbutton up (purple, dotted) and down (purple, dashed). Track 4 contains thereal-time image generated from the 56-sector deep-button resistivity. Theimage shows the wellbore paralleling a thin bed. The green stripe representsan interval where the image was not generated, due to lack of tool rotation.

Image resolution, relative pixel size



> Comparison of the relative pixel size of logging-while-drilling (LWD) and wireline (WL) imagingtools in a 6-in. borehole. Each pixel representsthe area of the borehole wall resolved. Key:VISION azimuthal density neutron (LWD), 16sectors; GeoVISION (LWD), 56 sectors; UBIUltrasonic Borehole Imager (WL); FMI FullboreFormation MicroImager (WL).

RABgammaray, up,







ray, down,real-time


Dip azimuth

True dip: Bedto north




50 150

50 -10 90150



AzimuthPath 1

0 100

Dip azimuth

Ring resistivity

2 200

Deep bottom up

2 200

Apparent dip:Bed to top

of holedeg

0 100

Deep bottom down

2 ohm-m




Bit resistivity Conductive


Resistive2 ohm-m 200

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Anadarko Petroleum Corporation Lone Creek No. 1,wireline FMI dips were acquired in the upper por-tion of the well, but drilling difficulties preventedFMI logging in the lower and reservoir portions. Ameasurements-after-drilling pass with an LWDBHA acquired GeoVISION images over a zone pre-viously logged with the FMI tool. Comparison ofwireline- and LWD-derived dips in the overlap zonedemonstrated that GeoVISION images could pro-vide accurate dip measurements sufficient forgeosteering wells (left). As drilling progressed,steeper dips and a tighter fold geometry than pre-dicted by the predrilling data were encountered,and GeoVISION dips allowed the well to besteered close to the anticlinal crest to adequatelytest the structure.15

Image-derived dips are available in real time orcan be handpicked off images generated frommemory during bit runs (below left). In contrast toconventional dipmeter processing, which is mostaccurate when bedding planes are nearly normalto the borehole, real-time dip determination ismost accurate when bedding planes are nearlyparallel to the borehole.16 At high relative angles,beds normally too thin—less than 6 in. [15 cm]—to be quantitatively resolved by the VISION den-sity measurement will have an apparent thicknessthat allows them to be resolved. For example, atan apparent dip of 85°, a 1-in. [2.5-cm] thick layerhas an apparent thickness of 1 ft [30 cm].Handpicking dips using a workstation helps toremove low-quality dips and supplement intervalswhere automated dips are not computed, therebyemphasizing subtle trends that may otherwise bemasked (next page).

64 Oilfield Review

0U R B L U




Dip,degrees0 90

U R B L UDip,

degrees 90

> GeoVISION handpicked dips (left) agree with automatically determined dips(right).


Dip, degrees0 90

Dip, degrees0 90








> Comparison of LWD GeoVISION resistivity image (left) with wireline FMI image(right). Although the LWD image resolution is considerably less than its wirelineequivalent, the primary geological features are readily apparent and can be usedfor ascertaining stratigraphic and structural dips. Comparison of handpicked dips(left) with FMI image and dips (right) shows excellent agreement.

15. Ford G, Hartner J, Grether B, Waters D and Cryer J:“Dip Interpretation from Resistivity at Bit Images (RAB) Provides a New and Efficient Method for Evalu-ating Structurally Complex Areas in the Cook Inlet,Alaska,” paper SPE 54611, presented at the SPEWestern Region Annual Meeting, Anchorage, Alaska,USA, May 26-28, 1999.

16. Rosthal RA, Bornemann ET, Ezell JR and Schwalbach JR:“Real-Time Formation Dip From a Logging-While-DrillingTool,” paper SPE 38647, presented at the SPE AnnualTechnical Conference and Exhibition, San Antonio,Texas, USA, October 5-8, 1997.

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Autumn 2000 65

In eastern Venezuela, an operator is using lat-eral drainholes to develop the Faja, a shallow,heavy-oil reservoir. The reservoir comprisesstacked, high-permeability, well-sorted, unconsol-idated channel sands that are typically 20 to 40 ft[6 to 12 m] thick. These stacked channel sands arediscontinuous sand bodies separated by silty lam-inations, creating a complex and challenging envi-ronment for lateral drilling and optimal wellplacement. GeoVISION azimuthal measurementsare used to differentiate between nonproductive

laminated siltstones, homogeneous pay sandsand mudstone reservoir boundaries. These mea-surements also provide the relative orientation of these geological features with respect to thewell trajectory, allowing stratigraphic features to be recognized and their influence on produc-tion studied.

A series of lateral wellbores averaging4000 ft [1220 m] in length was drilled from verti-cal stratigraphic wells. Three-dimensional (3D)

seismic data were used to predict the most likelyposition of the channel sands away from the vertical wells. Reservoir studies indicate thatresistivity of the best pay sands exceeds500 ohm-m, while resistivity of the layered, non-productive silts is generally less than 50 ohm-m.The percent of total measured-depth footagewithin the higher resistivity range is used to gaugethe well’s success. To date, an average of morethan 75% of the sections drilled are in pay sand.

> Revealing subtle trends. Structural trend is difficult to see in GeoVISION real-timedips (right) but is readily apparent in the handpicked data (left). Real-time imageswould greatly enhance this drilling program but were not available at that time.









0 Dip, degreesDip, degrees 90 0 90

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Measurements and images from another well demonstrate how azimuthal measurementscan be used for proper well placement (top). Theseparation of the azimuthal and bit resistivitiesshows the borehole approaching, then droppingaway from a low-resistivity layer along the top of the wellbore. This is more readily seen in the resistivity image. The low-resistivity layer,the dark color along the left and right sides,

represents the top of the borehole. Resistivityincreases from 3530 to 3560 ft, indicating thatthe wellbore is going in the correct direction toregain its position in the high-resistivity sand.

A 3D view of the same azimuthal image pre-sents the wellbore with respect to local geology(above). A 50-ft [15-m] measured depth interval isshown for the 81⁄2-in. diameter borehole. Lithologyboundaries, shown by the green lines, are used tocompute the true dip of the layers. This presenta-tion shows the wellbore coming up through

a transition from high-resistivity sand (light colorsat the bottom of the wellbore on the left) to a low-resistivity, nonreservoir layer (dark colors at thetop of the wellbore on the right).

In this case, the use of conventional, nonaz-imuthal measurements alone would have resultedin an incorrect interpretation. If the omnidirec-tional bit-resistivity measurement is used forgeosteering, the 40 ohm-m reading between

66 Oilfield Review

3500 ft 2550 ft

, Three-dimensional view of a GeoVISIONimage. This presentation shows the wellboreapproaching a low-resistivity layer along the topof the wellbore. The borehole cylinder is 81⁄2-in.diameter, and the measured depth interval shownis 3500 ft (left) to 2550 ft (right). The green linesrepresent lithology boundaries and have beendrawn to compute true formation dip.



ROP5ft/hr2000 0


deg0 360 ohm-m0.2 2000


GeoVISION deep resisitivityHorizontal scale: 1:13Orientation top of hole

Linear scaling

North marker curve GeoVISIONohm-m

Deep image















GeoVISION deep bottom up

GeoVISION deep bottom down

High res down

High res up

2060 2030ftDEVIdeg


0.2 2000ohm-m

0.2 2000ohm-m


GR upAPI0 100

API0 100GR down







, GeoVISION azimuthal measurements show thewellbore approaching, then dropping away froma low-resistivity layer along the top of the well-bore. Track 1 contains azimuthal gamma ray(solid purple, up, dashed green, down) and depthtrack (ft, MD). Track 2 shows rate of penetration(dashed black), rotation speed (pink), TVD (dashedpurple), and annotation indicating inclination andazimuth. Track 3 is the normalized deep-buttonresistivity image with brighter colors indicatinghigher resistivity. The bottom of the hole is shownin the center of the image and the top of the holeat the two edges. Track 4 shows azimuthal resis-tivity (dashed blue, down; solid black, up) and bit resistivity (dashed black). The color shadingbetween curves indicates the direction of thetarget sand: yellow, when measurements indi-cate the sand is below the tool and green, whenthe sand is above. Here, the yellow shadingindicates the wellbore trajectory needs to bedropped to steer back into the higher resistivitypay sand.


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Autumn 2000 67

3545 ft and 3560 ft suggests that the wellbore isin a low-resistivity, nonproductive silt layer. Incontrast, the azimuthal data, particularly in thestructurally oriented image, indicate that only afew inches of the low-resistivity layer have beenpenetrated.17 Azimuthal measurements combinedwith true dip provide the correct interpretation.

Geologic information derived from boreholeimages can influence real-time decisions for opti-mizing well placement and completion. A North

Sea subhorizontal production well was originallypredicted to penetrate two reservoir sectionswithin separate west- to northwest-tilted faultblocks. Structural dips manually picked onimages generated from VISION density data con-firmed that the actual structure was quite differ-ent and more complex (above). In fact, the welltrajectory crossed two fault zones orientedapproximately NE to SW. These faults definedthree fault blocks containing three different

Structural dip 13° / 332° NNW





30- to 40-ftwide faultdrag zone

No obvious angularunconformity at Base B

UC @ top H

UC @ top H

13° to 35° / 330° NNW


15° / 331° NNW



VISION densitystatic image





Measureddepth, ft





X550 ft

X950 ft





ps fr

om A

DN im













0 ft





ps in


e D





g in


or fa





p di

ps to



t dra



g to






ne H


t pla



its o

f fau

lt ro




0 ft




ce fe






D vs

. MD




n in








Measureddepth, ft

Stratigraphy A B C D E ED F G H B D E F G H




























Very minor angularunconformity at Base B


Dips fromVISION images

True dipmagnitude Co













10 ftX1450



sity m






r uni

t E



sity r




Structural geologic interpretation for a NorthSea production well based on VISION azimuthaldata, images and derived dips (top). Track 1contains the stratigraphic column. Track 2presents a graphic representation of the stratig-raphy using gamma ray (GR) and density images.Resistivity (P34H, Track 3), density and porositydata (TNPH, ROBB, Track 4) are also shown. Dip magnitude and azimuth derived from densityimages are presented in Tracks 5 and 6. Thegeologic interpretation based on these data is presented in Tracks 7 and 8. The lower figurepresents the gamma ray log, density image,measured dips, density and neutron porosity for an expanded interval.

17. Rasmus et al, reference 4.


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reservoir sections. The dominant structural atti-tude of these reservoirs is 13 to 35° NNW.Bedding drag and fault-damaged zones adja-cent to the fault affected the reservoir intervals.A low-angle unconformity is present at the baseof stratigraphic marker B.

Dip information was integrated with otherLWD petrophysical measurements and formationtops correlated with nearby wells. The resultinggeologic cross section contained more detail andhigher reliability than seismic information com-bined with only well tops, and provides an excel-lent representation of the reservoir. VISIONdensity images confirmed three separate reser-voirs, rather than two, as originally predicted.

Prejob modeling and planning reduce drillinguncertainty through evaluation of expected LWDresponse. VISION azimuthal data and imagesallow predrilling structural and petrophysicalreservoir models to be updated in real time duringdrilling. Real-time interpretation, based onobserved changes in the reservoir, enables cor-rective geosteering action to adjust the boreholetrajectory for optimized well placement andimproved well productivity.

In a southern North Sea gas developmentwell, geosteering based on predictive real-timemodeling has successfully reduced uncertainty inwell positioning.18 The primary concerns related todrilling this horizontal well were uncertainties instructural relief, the relatively thin, 70-ft [21-m]

reservoir and the indistinct petrophysical charac-ter of the reservoir unit. These conditions mightlead to uncertainty of the wellbore position in thereservoir and thus increase the risk of drilling outof the top or bottom of the reservoir in the 2500-ft[762-m] horizontal section. The well landed within6 in. vertically of the desired horizon. After drilling1500 ft [457 m] of the horizontal section, slidingbecame difficult, and a bit trip was made to con-vert to a rotary drilling assembly. At this point,uncertainty in the bit position also had increased,and several possible structural scenarios weregenerated with INFORM forward modeling duringthe bit trip (above and next page).

68 Oilfield Review

18. Bristow JF: “Real-Time Formation Evaluation for OptimalDecision Making While Drilling—Examples From theSouthern North Sea,” Transactions of the SPWLA 41stAnnual Logging Symposium, Dallas, Texas, USA, June 5-7,2000, paper L.

> GeoSteering screen correlation. In Scenario 1, the reservoir formations are dipping at -2.7° andthe well trajectory is below the reservoir and headed into Carboniferous rocks.

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Autumn 2000 69

In the model for Scenario 2, the reservoir dip is 0.75° and thewell is approaching the top of the reservoir.

In the model for Scenario 3,formation dip is -1° with the wellessentially parallel to bedding. A variation in dip as small as 3.5°,between Models 2 and 3, couldhave resulted in the well exitingthe reservoir.



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During this same bit trip, density imageswere generated from memory data, and dip inter-pretation was conducted by the office-basedasset team (left).

Image-derived dip information establishedthe correct structural model and provided theoperator with an unequivocal interpretation ofthe relative position of the well in the formationprior to resumption of drilling. Once the positionwas known, the decision was made to steerdown to penetrate the lower portion of thereservoir and ensure drainage from these lowerlayers (next page).

The density images also yielded importantfacies-related information. The reservoir is pre-dominantly a fluvial sequence containing duneapron and dune slip-face facies. The dune slip-face facies, characterized by 20 to 30° dips evi-dent at 4275 to 4350 ft, usually provides the bestpermeability. The southwest dip direction indi-cates a paleotransport direction consistent withother field data.

Drilling Efficiency Through Integrated SolutionsDownhole drilling mechanics processes are toocomplex to be characterized by any single mea-surement. Experience shows that combiningdownhole measurements results in a synergythat allows better understanding of how thedrilling process can affect the borehole and influ-ence LWD measurements.

LWD borehole images, especially higher res-olution resistivity images, provide a means todirectly evaluate downhole geological facies,

70 Oilfield Review



Bed parallel







Up sequence













Bed parallel

Up sequence





High dip

Dune slip face

U R B L UDepth, ft

> VISION presentation used to locate bit position in the reservoir during a bitrun. Track 1 contains the density image with interpreted dip superimposed(green sinusoids). Track 2 contains the dip interpretation. Track 3 containsgamma ray (green), average density (black) and neutron (dotted) data. Track 4contains the resistivity curves. Structural dip is 1° southeast at 3850 ft, andborehole direction is 89 to 90° toward the east.

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Autumn 2000 71

structure and borehole failure, such as fracturesand breakouts. The addition of real-time imagesto conventional LWD data can dramatically andsignificantly alter log interpretation and helpselect the best remedial operations to optimizedrilling operations.

The drilling process causes the wellbore toundergo changes with time. Drilling-inducedchanges range from formation invasion tomechanical failure of the borehole wall, such asfractures and sloughing. During drilling, it is

important to distinguish natural features fromthose induced by the drilling process so that thedrilling program can be modified to minimize itsimpact and ensure accurate petrophysical evalu-ation. Borehole images are essential for diagnos-ing drilling-induced changes.

With only conventional LWD data or a singlelogging pass, these changes may go unnoticed.Time-lapse data, obtained during drilling orwashdown, are particularly important in monitor-ing dynamic processes affecting the borehole.

In many sand-shale environments, separationof deep- and shallow-reading resistivity curvesoccurs because of conductive invasion and is anindication of formation permeability. However,curve separation also may result from resistivityanisotropy with high apparent formation dip,close proximity of tight streaks, permeability vari-ations in carbonate reservoirs, or formation frac-turing by heavy mud or high equivalentcirculating density (ECD). In the latter case, curveseparation may serve as an early indicator that

> GeoSteering screen correlation model showing the final structural model based on density image-derived dips. The previous density image is shown in its relative position along the well trajectory.

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an unanticipated problem is occurring in thereservoir (above).

The GeoVISION tool uses three button sensorsto provide azimuthal resistivity measurementswith different depths of investigation. These datatypically are used for invasion analysis in forma-tion evaluation. However, borehole images gen-erated for each depth of investigation canprovide additional information regarding theinfluence of drilling on the borehole and on petro-physical measurements (left). In this case, theshallow resistivity is strongly affected by theconductive mud that fills features near the bore-hole wall. Unlike natural features, induced fea-tures may seem to disappear with increasingdepth of investigation.

72 Oilfield Review




d de








> GeoVISION borehole images generated from 56-sector resistivitydata measured by the shallow- (Track 1), medium- (Track 2), and deep-reading buttons (Track 3). The borehole breakouts (dark color) seen inthe shallow image (Track 1) appear to gradually disappear in the medium-and deep-reading images. Shallow, near-borehole features like theseare commonly drilling-induced rather than naturally occurring.






R B L R B 2 ohm-m 200

Drilling imageMD1:140 ft

Washdown image Resistivity overlay


> GeoVISION time-lapse data illustrating how invasion and the increase of borehole failures (breakouts)with time affect LWD resistivity measurements (right). Washdown images were acquired two days afterthe drilling pass. Resistivity curve separation occurs at two intervals—between X080 and X090 ft, andX100 and X110 ft—where the images show conductive invasion.

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Autumn 2000 73

Misidentifying zones as permeable or over-looking tight streaks can lead to overly optimisticpredictions of productivity, while failure to recog-nize formation breakdown can result in costlyremedial operations. Real-time resistivity anddensity images provide the additional informa-tion necessary for making correct interpretations.

In this example, borehole breakouts filled withconductive mud caused curve separation (above). Real-time annular pressure providesadditional information that further indicateswhether breakouts are natural or drilling-induced.

Annular-pressure-while-drilling data can helpcalibrate formation strength and stress parame-ters. Integrating resistivity images with APWDmeasurements allows geologists and engineers

to study dynamic processes, like cuttings buildupand the evolution of the geomechanical conditionof the borehole. These data can help distinquishnot only drilling-induced changes—along withdepth, azimuth and extent of failure—but alsothe mechanism of borehole failure. The recogni-tion of drilling-induced fractures and knowledgeof their influence on logging measurementsgreatly improves geological and petrophysicalinterpretation. Furthermore, correct diagnosis isessential to identifying problems and implement-ing proper remedial actions needed to optimizethe drilling operation. In many extended-reachand horizontal wells with a narrow marginbetween pore pressure and fracture gradient,such as in deep water, borehole instability is

unavoidable. In these cases, drilling optimizationfocuses on monitoring and managing, that is min-imizing, instability through mud weight and circu-lation pressure.

The recognition of drilling-induced fracturesin a horizontal well leads to decisions to reducetripping speeds to ensure that swab and surgepressures are kept to a minimum and that correcthole-cleaning procedures are utilized to preventunmanageable formation breakdown.

A North Sea operator was drilling a horizontalwell in chalk in search of natural fractures. In thiscase, as in many wells, successful drillingrequired that the pressure exerted by the drillingfluid stay within a tight mud-weight window



U R BResistivity imageShallow resistivity

2 2000L U

Deep resistivity

2 2000




> Separation of the deep (purple, Track 2) and shallow (green, Track 2) resistivity curves inthis highly deviated well occurs only in the sand intervals and not the shales (GR, Track 1),implying normal conductive invasion. GeoVISION images of this interval (Track 3) tell adifferent story. Bedding in the sand at X750 suggests that curve separation here is due toinvasion. However, in the lower sands, conductive mud filling the apparent breakouts isresponsible for the curve separation. Azimuthal information provided by the image shows the breakouts are along the top and bottom of the borehole. In a horizontal well, the bottomquadrant density is generally assumed to be the most reliable. However, the breakoutsshown in these images indicate that bottom density would be adversely affected andshould not be used. The availability of image data prevented an incorrect interpretation.

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defined by the pressure limits for wellbore stabil-ity: the upper limit being the formation fracturegradient and the lower limit, the formation porepressure (above). Increasing water depth reducesthe margin between the mud weight required tobalance formation pore pressures to avoid well-bore collapse and the mud weight that will resultin formation breakdown.

GeoVISION resistivity images made in thehorizontal portion of the well show a relativelycontinuous vertical fracture running for approxi-mately 1100 ft [335 m] (right).

Normally, the image data presented on a logare the data recorded the first time the sensorpasses a depth. However, time-lapse data arealso available, showing changes in the sameinterval as a function of time (next page). Thedeep-button sensor was positioned 53 ft [16 m]above the bit. The gray curve superimposed onthe image shows the depth of the deep-buttonsensor as a function of time. The green curve isthe ECD that was computed from a downholepressure measurement in the annulus.

74 Oilfield Review





-ft in





d de






> Rotated GeoVISION images in the horizontal section. The deep-buttonimage (left) shows a relatively continuous vertical fracture running fromthe top to the bottom, approximately 1100 ft. The fracture appears faintbecause of the compressed depth scale. A shorter, 200-ft interval (right)shows a more pronounced feature.





13 3/8

11 3/4

9 5/8

7 5/8

Overburden gradient, lbm/gal10.00 17.00

Resistivity pore-pressure estimate, lbm/gal10.00 17.00

ECD, lbm/gal10.00 17.00

Seismic pore-pressure estimate, lbm/gal10.00 17.00

A typical pressure window for adeepwater well. The overburden pres-sure (purple) is the fracture gradientand defines the upper limit of the pres-sure window. The predrill seismic pore-pressure estimate (black) defines thepressure window lower limit. The close-ness of the two curves indicates a tightpressure window. The actual, resistivity-derived pore pressure is shown in red.The actual mud-weight profile plottedas APWD-derived ECD is shown in blue.Overall, the drilling program succeededin staying within the narrow pressurewindow. However, at two depths wheremud weight dropped below the lowerpressure limit, the well took kicks.


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Autumn 2000 75

During the first 13⁄4 hours of this timesequence, the well was drilled from X1933 ft toX2017 ft (horizontal white line) and imaged fromX1880 ft to X1964 ft. The drilling image wasacquired within an hour of the bit penetrating theformation and shows a faint axial fracture. Duringthe next six hours, the BHA was raised and low-ered numerous times to help clean out the drillcuttings. At about eight hours, drilling continued,and the interval drilled seven hours earlier (X1965to X2017 ft) was finally imaged while drilling. Adramatic change was noted in the later imagethat shows a wide induced fracture in addition tothe sought-after natural fractures, which appearas low-angle sinusoids. This difference is explainedby analysis of the drilling records.

Memory data recorded between 13⁄4 and 8 hours, while the pipe was being worked, wereused to extract the center image. This time-lapseimage clearly shows that a fracture was enlargedsoon after drilling. Although the image acquired

between 73⁄4 and 83⁄4 hours was generated whiledrilling, the borehole interval between X1964 andX2040 ft was open six hours longer than thatabove and below these depths.

The downhole annular pressure was recordedduring a bit run, and the ECD was derived fromthat measurement. There was a distinct buildupin ECD during the drilling of the top interval.During the period the pipe was being worked toclear debris, the ECD varied between 13.5 and15.5 lbm/gal [1.62 and 1.86 g/cm3], and the highestreading occurred approximately 11⁄2 hours afterdrilling was stopped. Severe losses occurred inthis interval every time the flow rate increasedabove a certain level.

Cuttings removal is a major problem in thedrilling of horizontal wells. However, in fields likethis one where the tolerance between pore andfracture gradient pressures is small, high flowrates and surge pressures that occurred duringhole-cleaning operations led to high ECD and,ultimately, to hydraulic fractures.

Without the ECD information provided byAPWD measurements, interpretations based onborehole images alone might have indicated theneed to increase mud weight to handle theapparent borehole breakouts seen in the image.This would have been the incorrect response.The addition of the time-lapse pressure profileprovided the evidence (spiking of the ECD) that,in fact, it was the drilling process itself thatinduced the borehole failure.

This combination of information providesguidance to drillers about where, when and howto improve processes to avoid damaging theborehole. LWD measurements show how geol-ogy, geophysics and drilling process cometogether to make the correct interpretation. TheGeoVISION image shows not only the geologicenvironment, but also the consequences of thedrilling process.















0 2 4Elapsed time, hr



d de



6 8 10




> Time-lapse GeoVISION resistivity images with the elapsed time (gray) and mud-weight (ECD, green)curves superimposed. On the left is shown the position of the GeoVISION sensors relative to the bit. Thefirst image (A) was made as the bit drilled to X2017 ft (white line) and shows a faint axial fracture. At thatTD, the BHA was worked for 6 hours to clean out cuttings. An image made from memory data acquiredduring this period (B) shows a wide induced fracture. Images of the lower interval (C) acquired afterdrilling resumed, approximately 7 hours after the first images, show a dramatic change in the boreholefor the interval where the BHA was worked, compared to the newly drilled interval below. Spikes in theECD curve during the period the pipe was worked demonstrate that the borehole failure shown in theapparent borehole breakout in (B) and (C) is actually induced borehole failure caused by high ECD.

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Images and GeomechanicsThe state of stress around the wellbore has a directinfluence on drilling efficiency and wellbore stabil-ity. Recognizing borehole failure and instability andunderstanding how and why failure occurs are vitalto successful drilling.19 Proper management of bore-hole stability minimizes nonproductive time and iscentral to drilling optimization.

Borehole failure results from stresses aroundthe borehole. The Earth’s far-field stresses (maxi-mum horizontal, minimum horizontal and vertical)are converted into wellbore stresses (radial, axialand tangential) at the borehole wall (below).

When these stresses exceed the formationstrength, irreversible shear and tensile deforma-tions occur in the near-wellbore formation. Themud weight is used to control borehole stresses.

Most geological forces acting on the boreholeare compressive and produce shear failure. Otherstructural forces act to pull rock grains apart,resulting in tensile failure. Shear failure is initi-ated by two orthogonal stresses with differentmagnitudes, whereas tensile failure is initiatedby a single tensile stress. Shear and tensile fail-ure mechanisms can, and most often do, actindependently. Understanding the relationshipbetween stresses affecting the borehole pro-vides information about formation strength,information that is especially important fordrilling highly deviated and horizontal boreholes.

Many failure mechanisms have specific asso-ciated fracture signatures that are apparent onborehole images, and each failure mode has aunique pressure regime of high or low mud weightor ECD. GeoVISION images, coupled with VISIONAPWD measurements, allow immediate, real-timeidentification of potential failure modes and pro-vide early warning of borehole stability problems(above). Based on a diagnosis of the associatedissues, the driller can take appropriate remedialactions for managing borehole instability.

The application of geomechanical modelsthat incorporate image and pressure data has adirect and immediate impact on drilling optimiza-tion and completion. Results from these models

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σh σH





> The relationship of far-field stresses to well-bore stresses. A Cartesian coordinate system isused to describe the far-field stresses: one stressis vertical, σv, and the two orthogonal stresses arehorizontal. If the magnitudes of the two horizontalstresses are different, and they usually are, theyare termed the minimum, σh, and the maximum,σH, horizontal stresses. The direction of eitherhorizontal stress completes the total descriptionof the far-field stresses. In a vertical well, thewellbore stresses are described by a cylindricalcoordinate system. Here, one stress is radial, σr,and the two orthogonal stresses are axial, σa,and tangential, σt. The axial stress is directedalong the axis of the borehole, whereas the tan-gential stress is directed around the circumfer-ence of the wellbore. The tangential stress isalso called the hoop stress because of thisgeometry. The radial stress is caused by thepressure of the mud and is controlled by thedriller. The axial and tangential stresses are controlled by the far-field stresses.

Shear failureMud weight low

Tensile failureMud weight high



Stress direction


>Mud-weight variation impact on shear and tensile failures. A vertical well drilled intoa basin with unbalanced horizontal stresses relates shear and tensile failure to differ-ences in circulating mud weight. The maximum horizontal stress is about 20% greaterthan the minimum horizontal stress. Wide breakouts are visible in the upper section ofthe GeoVISION image (left). A vertical fracture is offset from the wide breakout by 90°.Tensile fractures are visible in the lower section. Variation in the mud weight from astatic 9.5 lbm/gal to a circulating value that reached 12.5 lbm/gal caused both shearand tensile failures to occur with the same bit.

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ADN density imageHorizontal scale: 1:11.0Orientation top of hole

Histogram equalized overuser-selected depth interval



R BImage orientation


Low High

ROBU (density top)

g/cm3 2.951.95

ROBL (density left)

g/cm3 2.951.95

ROBR (density right)

g/cm3 2.951.95

ROBB (density bottom)

g/cm3 2.951.95


API 1000


cycles/sec 010


in. 166

DCAL (density caliper)

in. 7.75-2.25


ft/hr 0600


Rotation, bit depth

Rotation, ADN depth


cycles/sec 100

> Density image in a near-horizontal well in unconsolidated sandstones. Darker color repre-sents higher density. The uniform dark color through interval X512 to X542 ft in the image (Track 2)indicates good borehole contact and the caliper (Track 4) shows an in-gauge hole where thedrillstring was sliding for steering purposes. Enlarged borehole occurs where the drillstring wasrotating (Track 4). Where the ROP is low (Track 4), the borehole was further enlarged due to jet-ting of drilling fluid. Note that the bottom quadrant density is good through the majority of thesection, except at X502 to X513 ft, where the BHA climbs the right side of the borehole.

19. Bratton T, Bornemann T, Li Q, Plumb D, Rasmus J andKrabbe H: “Logging-While-Drilling Images for Geome-chanical Geological and Petrophysical Interpretations,”Transactions of the SPWLA 40th Annual Logging Sympo-sium, Oslo, Norway, May 30-June 3,1999, paper JJJ.

Autumn 2000 77

can be used to provide recommendations forremedial strategies that might not otherwisehave been considered. By validating strength andstress profiles, model results may be used to planfuture wellbores. The ability to distinguish naturalfeatures and formation properties from commondrilling-induced artifacts improves both petro-physical and geological interpretations. Recognitionof natural fractures, a source of potential fluidinflux, can be important in the management ofdrilling risk and safety hazards.

Recognizing and Preventing ProblemsInformation obtained from density images canresult in remedial action to minimize and preventborehole damage. Borehole enlargement mayresult from the drilling process: too fast, toomuch weight on bit, or too high a circulatingpressure. The VISION density measurement isextremely sensitive to the tool standoff thatincreases with borehole enlargement. Toolstandoff is easy to recognize on density images:dark color indicates high density and good bore-hole contact, light color indicates the presence oflower density mud.

An operator drilled through a massive, poorlyconsolidated sandstone reservoir. The densityimage shows low-density standoff (light color)extending from the top of the hole past the rightand left side of the hole in the intervals X480 toX512 ft and X542 to X562 ft (right).

The density variations, both radially and verti-cally, are the result of the drilling process. The low-density features reflect borehole enlargement thatwas produced by a bent steering sub during BHArotation. During BHA sliding, the borehole is closerto gauge, the density image quality is good aroundthe complete borehole interval from X512 to X542 ft,and all four density curves stack. Furthermore, den-sity variations within the intervals of BHA rotationare directly related to the rate of penetration. Inthese poorly consolidated sandstones, slow ratesof penetration result in high rates of boreholewashout from X492 to X502 ft. These images indi-cate that increasing the rate of penetration andoperating in sliding mode would improve boreholequality and drilling efficiency.

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The information derived from these imagesalso benefited the petrophysical interpretation.Generally, the bottom-quadrant density providesthe best density value in highly deviated and hor-izontal wells because gravity causes the BHA torest on the bottom of the borehole. Occasionally,the tool may climb to the side of the borehole,such as when the smaller diameter VISION475tool is run slick. In these instances, the bottomdensity measurement may not have the lowestdelta Rho, and a different quadrant density ismost representative. An example of this phe-nomenon occurs in the interval X502 to X513 ftwhere the BHA climbs the right side of the bore-hole and the right bulk density measurement isthe best value.

Cyclic density is often an indication of athreaded borehole (right). A recent North Sea wellshows a spiral borehole that developed throughmovement of the BHA during the first bit run.Drilling engineers were alerted to the problemand added a near-bit stabilizer to the BHA withthe next bit run. This action prevented the spiral-ing and resulted in a smooth borehole. Thisimage was generated from the memory dataplayed back during the bit run, and the interpre-tation and correction action were taken in time tosuccessfully drill the next interval. Recognizingdrilling-induced features on images allows cor-rections in the drilling process that lower costthrough more efficient drilling.

Real-Time ImagesThe examples presented in this article, with oneexception, used images generated from down-hole memory data. Retrieval of stored downholedata requires pulling the BHA during or betweenbit trips. Interrupting the drilling for data retrievaland interpretation may result in added rig timeand higher well costs. Recently introduced data-compression techniques now make real-timetransmission of VISION azimuthal density andGeoVISION resistivity images possible.

Resolution of GeoVISION real-time images isthe same as that for the earlier RAB recorded-mode images. A compressed data frame consistsof sixteen 10-sec time scans that each have 56-channel azimuthal scans. Data are com-pressed in both the azimuthal and time dimen-sions by a ratio of 50:1. The high compressionrate means that a relatively low bandwidth,approximately 1.5 bits per second (bps), isrequired for transmitting real-time image data.This figure is well within the capabilities of the PowerPulse MWD tool that achieves anuphole data rate that is commonly 6 bps andreaches 12 bps under favorable conditions. Thesedata rates, combined with VISION downhole

preprocessing of data, including data compres-sion, mean that an operator can obtain real-timeimages in addition to other real-time dataneeded for geosteering decisions.

In this article, we’ve discussed how real-timeazimuthal measurements can significantly enhancewell placement and drilling efficiency—and, inthe process, reduce E&P costs. Geologic informa-tion and structural dips derived from boreholeimages remove much of the guesswork in

geosteering, and thereby improve the successrate of extended-reach and horizontal wells.Information on borehole condition provided byimages during drilling allows monitoring ofdrilling operations in real time. VISION azimuthalmeasurements are just one element of the newgeneration of LWD technology that is transform-ing while-drilling measurements into Logging-for-Drilling. Integration of these images with otherreal-time measurements provides an effectivemeans for enhancing drilling efficiency. —SP

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Low Highg/cm3


VISION densityHorizontal scale 1:11.0Orientation top of holeHistogram equalized

Image orientationR B L UU

MD1:200 ft

API0 150

Gamma ray Bulk density down (ROBB)g/cm3

Bulk density right (ROBR)g/cm3

Bulk density left (ROBL)g/cm3

Bulk density up (ROBU)ft3/ft3

Neutron porosity (TNPH)




> Example of a VISION density image showing borehole damage. The parallelbright features between 11,030 and 12,010 ft MD represent hole spiraling. Havingthis information available in real time can result in changes in the BHA to preventsubsequent hole damage. At the next bit run, a near-bit stabilizer was added,and the image below 12,010 ft MD clearly shows the change in borehole condi-tion, from spiral to smooth hole. Note the cyclical pattern of the quadrant densitycurves (ROBU, ROBL, ROBR, ROBB) and the neutron-porosity curve (TNPH) inthe interval of spiral hole.