44

In this article, IDEAL (Integrated Drilling Evaluation andLogging), GeoSteering tool, PowerPak, RAB (Resistivity-at-the-Bit), RWOB (Receiver, Weight on Bit and Torquetool), PowerPulse, CDR (Compensated Dual Resistivitytool), SFL (Spherically Focused Resistivity Log), AIT(Array Induction Imager Tool), CDN (Compensated Den-sity Neutron tool) and FMI (Fullbore Formation MicroIm-ager) are marks of Schlumberger. For help in preparation of this article, thanks to DavidAllen, Schlumberger Well Services, Sugar Land, Texas,USA; Philippe Faure, Dominic McCann, SamanthaMiller, Bernard Montaron and Kanai Pathak, Anadrill,Sugar Land, Texas, USA; Richard Rosthal, SchlumbergerLogging While Drilling, Sugar Land, Texas, USA; andDavid Hill, Schlumberger Well Services, New Orleans,Louisiana, USA.1. Betts P, Blount C, Broman B, Clark B, Hibbard L,

Louis A, Oosthoek P: “Acquiring and Interpreting Logsin Horizontal Wells,” Oilfield Review 2, no. 3 (July1990): 34-51.Logging While Drilling. Schlumberger Education Ser-vices: Houston, Texas, USA, 1992.

2. For a review on horizontal drilling methods:Burgess T and Van de Slijke P: “Horizontal DrillingComes of Age,” Oilfield Review 2, no. 3 (July 1990):22-33.

Steve BonnerTrevor BurgessBrian ClarkDave DeckerJacques OrbanBernhard PrevedelSugar Land, Texas, USA

Martin LülingRidgefield, Connecticut, USA

Jim WhiteAberdeen, Scotland

Measurements-while-drilling technology has moved down the drillstring to enlist the bit itself as a sensor. Drillers

time information about petrophysics and drilling mechanics without a lag between bit and sensors. This technical

ciency of directional drilling, enhance real-time formation evaluation, and ultimately create a more productive well.

Measurements at the Bit: A New Generation of MWD Tools

nA typical horizontal well plan. Geometric drilling refers todrilling along a fixed, predetermined trajectory, generally basedon offset data and a stratigraphic model. Decisions about steer-ing are based only on real-time information about bit directionand inclination. Geosteering refers to navigating the boreholeusing geologic information in real time. Geosteering is possiblewith logging-while-drilling sensors, which are integrated intodrill collars 40 to 100 ft [12 to 30 m] above the bit and steerablemotor. Geosteering becomes more efficient with measurementsat the bit.

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaa a a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaGeometric section

Geosteering section

Kick-offpoint

First build(5.5 ft /100 ft)

Second build(10 ft /100 ft)

Tangentsection

Horizontalentry point

Targettolerance

DRILLING

Conventional drilling of high-angle and hor-izontal wells is like piloting an airplane fromthe tail rather than the cockpit. Informationrequired to land the well in the target forma-tion is derived from sensors 50 ft [15 m] ormore behind the bit or at the surface.Because these measurements—about welltrajectory, drilling efficiency and formation

properties—are remote from the bit, crucialdrilling decisions are delayed and data mayrequire more complex interpretation. In par-ticular, course corrections are delayed bylag in measurements needed to make steer-ing decisions, resulting in less drainhole inthe pay zone. Also, maximum drilling effi-ciency requires information about mechani-

Oilfield Review

and geologists now have real-

progress promises to improve effi-

nTypical bottomhole assemblies for horizontal drilling. A rigid,or locked, assembly is used for drilling a vertical, tangent orstraight horizontal section. Rigidity increases with the number ofstabilizers. This type of assembly permits only gradual changesin the vertical angle of the well trajectory. A steerable assemblywith a downhole motor inside a bent housing can vary well tra-jectory vertically and to the left and right, and can changeangle more quickly than a locked assembly.

nHow well trajectory is changed. In rotary mode, both the bitand drillstring rotate and the bit cuts a straight path parallel tothe axis of the drillstring above the bent sub. In sliding mode,only the bit rotates and the hole follows the axis of the bent hous-ing below the bend.

Locked Steerable

Locked assemblyRotary mode for vertical, tangentor horizontal sections

Steerable assemblyRotary or sliding modeaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaSliding mode

Rotary mode

Increased diameter due tooutward tilt of steerable motor (scale exaggerated)

cal power delivered to the bit, which isinferred from surface measurements,degrading its accuracy. And resistivity mea-surements from logging-while-drilling(LWD) sensors in drill collars are limited toformation resistivity less than 200 ohm-m.1

Despite these limitations, horizontal andhigh-angle drilling have proved successful,especially in simple geologic settings—uncomplicated layer-cake structure. Nearlyall these wells start vertically, with a con-ventional rotary bottomhole assembly (BHA)(previous page).2 The drillstring and bit arerotated from the surface either by a rotarytable on the derrick floor or a motor in thetraveling block, called a topdrive. Drillingthis way is called rotary mode. To kick offfrom vertical, the rotary assembly isreplaced with a steerable motor—usually apositive displacement motor, driven by mudflow, in a housing bent 1° to 3° (above,right ). When mud is flowing, the motorrotates the bit, but not the drillstring. Thistype of drilling is called sliding mode,because the drillstring slides along after thebit, which advances in the direction of thehousing below the bend (right). The largerthe angle of the bent housing, the sharperthe curvature of the trajectory. The directionin which the bit is pointing, called toolface,is measured and sent to surface by measure-ment-while-drilling (MWD) equipment forreal-time control of bit orientation. Mea-surements include azimuth, which is thecompass bearing of the bit, and inclination,which is the angle of the bit with respect to

45April/July 1993

vertical. Large changes in direction aremade by lifting off bottom and reorientingthe bent sub by rotating from surface. Smallchanges are made by varying weight on bit,which changes the reactive torque of themotor and hence toolface orientation.

Once sufficient inclination has been built,straight or tangent sections can be drilled inseveral ways. One is with a conventionalrotary, or “locked,” assembly, which is rigidenough to allow fast, straight drilling. Smalladjustments in inclination can be made byvarying weight on bit or rotary speed. Large

adjustments in inclination can be made withconventional rotary assemblies only bypulling out of the hole and varying the sizeand placement of stabilizers. Most horizon-tal sections, and some tangent sections, aredrilled with a steerable motor while rotatingthe drillstring from surface. In this mode, thesteerable motor behaves like a rotary BHA,maintaining both azimuth and inclination.

X800

X900

X000

X300

X400

X500

XX85

XX65

Bulk densityLW

D D

ata

True

ver

tical

dep

th, f

t

Rad (deep) resistivity Rps (shallow) resistivity

Horizontal distance, ft

Gas/oil contact

Oil /watercontact

Gamma ray in well path

Actual trajectory

ReservoirProposed geometric trajectory

Horizontal distance, ft

True

ver

tical

dep

th, f

t XX00

XX25

X700

X900

X100

X300

X500

X700

X900

nThe risk of steering geometrically with inadequate information about reservoir dip—less drainhole in the pay zone. This North Sea well was successfully drilled beyond hori-zontal, but the reservoir dipped more than expected. Only about 15% of the drainholewas in the pay zone.

nSteering along the top of the oil/water contact in the North Sea using logging-while-drilling measurements.

Cou

rtes

y of

Nor

sk H

ydro

However, the presence of the steerablemotor allows the driller to make course cor-rections without tripping the drillstring outof the hole. Generally, the driller tries tomake as much hole as possible using arotary assembly or a steerable motor inrotary mode. Rotation of the drillstringreduces the risk of getting stuck and allowsfaster drilling than in sliding mode.

Overcoming Limitations in Horizontal DrillingToday, the ability to drill horizontally isundisputed, and records for the longest hori-zontal section are broken nearly as soon asthey are set.3 Yet, the efficiency of drillingand steering horizontally is limited by thedistance between the bit and measurements.In drilling, for example, one way to defineefficiency is the ratio of time spent makinghole to the total rig time, including opera-tions such as trips or hole conditioning. Inthe horizontal section, steering efficiencycan be defined as the ratio of the length ofthe horizontal section in the pay zone to thetotal length of the horizontal section. Howdoes lag between measurements and the bitlimit these efficiencies?

In drilling with a downhole motor inrotary mode, a key limitation on efficiencyis how much weight the driller can safelyapply to the steerable motor. As the drillerincreases weight, the motor produces moretorque, and power is torque times RPM. Themore power, the faster the rate of penetra-tion—up to a point. Excess weight may stalland eventually damage the motor, requiringan expensive trip for motor replacement.The goal is to apply as much power as pos-sible, but within the operational limit of themotor. Power is estimated conventionallyfrom surface measurements of mud flowand mud pressure. Motor RPM is roughlyproportional to mud flow. Torque is roughlyproportional to the increase in mud pressurewhen the bit is on bottom, compared to offbottom. Because of uncertainty in this esti-mation, a generous safety margin is main-

46

3. In the Norwegian North Sea, Statoil recently drilledan extended reach well with a horizontal section of24,000 ft [7000 m]. “Statoil Claims World Record inExtended Reach,” Oil & Gas Journal 91, no. 7 (Febru-ary 15, 1993): 31.

tained. This margin prevents the driller fromapplying optimal weight for a given forma-tion, which reduces penetration rate.

Perhaps the greatest limitation in conven-tional horizontal drilling is in steering effi-ciency. Wells are conventionally steered“geometrically”—along a path that has beenpredetermined based on nearby well dataand geologic assumptions. Steering is basedonly on bit direction and inclination data.Gamma ray and resistivity measurements, ifpresent, are made far from the bit and usedonly retrospectively. This technique is fine,as long as the target is thick, structurallysimple and well known. But it is less effec-tive when the target is thin, complex orinsufficiently known for planning the welltrajectory (top). And increasingly, withadvances in three-dimensional seismics,

operators are locating more intricate reser-voirs and drilling more complex wells.Challenges today include thin beds andcomplexly folded or faulted reservoirs.

In these settings, sensors in drill collarsallow replacement of basic geometric steer-ing with more efficient geologic steering, or“geosteering”—navigation of the bit usingreal-time information about rock and fluidproperties. A North Sea example shows howLWD sensors performed the dual purpose ofgeosteering and formation evaluation. Usingmostly resistivity measurements, the drillergeosteered a drainhole along the top of the

Oilfield Review

oil/water contact to avoid gas production(previous page, middle). Resistivity modelingfrom offset wells showed this contact shouldhave a resistivity of about 0.6 ohm-m. Whenthe value dropped, indicating water, the wellpath was turned up slightly; when resistivityincreased, the well path was droppedslightly. Although these measurementsenabled the driller to keep close to the payzone, the well strayed into the water for 100ft [30 m], between X900 and X000 ft. Thiswas due to lag between the bit and resistivitysensors. By the time the resistivity sensorsdetected the fluid change, the bit hadadvanced 50 ft. It took another 50 ft to steer

Depth and other surface

sensors

Detailed wellplan from drillingplanning center

Driller'sscreen

Safetyscreen Customer's

presentation

Wellsite Information System

Remotecommunications

CDN toolcompensated

density/neutron/Pe

PowerPulse tool10 bits/sec

MWD telemetryw

April/July 1993

nSurface and downhole components of the IGeoSteering tool, which is an instrumented sPowerPulse MWD telemetry tool and the RWOfor wireless telemetry of GeoSteering tool andmotor in a steerable assembly. Compatible dCDR Compensated Dual Resistivity tools. TheSystem, is its interactive nature. Users can cutations from depth to time and make annotamake interpretations and advise on drilling d

it back into the pay. Overall, 550 ft of this750-ft section of the drainhole [167 m of228 m] was in the pay zone—a respectable73% steering efficiency, and a markedimprovement over geometric steering.

In addition to reduced efficiency indrilling and geosteering, a third limitation ofconventional horizontal drilling is in forma-tion evaluation while drilling. Logging-while-drilling sensors reach the formationlong before wireline measurements, and sogenerally view it before wellbore degrada-tion, but some invasion has still occurred.Rapid invasion, called spurt, may mask trueresistivity in some formations. Also, LWDresistivity measurements by the CDR Com-pensated Dual Resistivity tool are limited toenvironments favoring induction-type set-tings—resistive mud (fresh or oil-base mud)and conductive rock.

The solution to these problems—limitedefficiency in drilling and geosteering, andlimited capabilities of real-time formationevaluation—is relocation of drilling and log-ging measurements to the bit itself. This hasbeen achieved with the IDEAL IntegratedDrilling Evaluation and Logging system,which uses new logging and drilling mea-surement technologies to make real-timemeasurements at the bit (left and below).The system includes two new loggingdevices: the GeoSteering tool, an instru-mented steerable downhole motor, and theRAB Resistivity-At-the-Bit tool, an instru-

RWOB tooleight/ torque

CDR toolcompensateddual resistivity

Wireless telemetry

DEAL Integrated Drilling Evaluation and Loggteerable motor, the RAB Resistivity-At-the-Bit to

B Receiver, Weight on Bit and Torque tool for RAB data. The RAB tool can be run next to thownhole components include LWD tools, the C most significant advancement in the surfacestomize acquisition schemes and screen parations. Tasks such as data processing and integecisions.

mented stabilizer (next page). Measurementsinclude gamma ray, several types of resistiv-ity including a measurement at the bit, anddrilling data such as inclination, bit shocksand motor RPM.

The technical leap that allows measure-ments to be made at the bit and below thesteerable motor is a wireless telemetry sys-tem. This telemetry link sends data from sen-sors near the bit to the MWD tool up to 200ft [61 m] behind the bit, a path that bypassesthe intervening drilling tools, such as thesteerable motor. The PowerPulse MWD sys-tem recodes and then sends data to surfacein real time using mud-pulse telemetry at upto 10 bits per second. At surface, datarecording, interpretation and tool control areperformed by the Wellsite Information Sys-tem. Control data can be sent from the sur-face back downhole by varying mud pumpflow. This enables the operator to select froma predefined menu of data types, change thetelemetry rate and change how often dataare sent to surface, without pulling the toolsout of the hole. The operator can alsochange how often LWD and RAB data arestored in downhole memory (data from theGeoSteering tool are delivered only in realtime). The system provides the driller, geolo-gist and petrophysicist with information atthe earliest possible time to make real-timedecisions that minimize course corrections,improve drilling efficiency and allow real-time formation evaluation.

PowerPaksteerable motor

GeoSteeringtool

RABabove motor

Steerable

Rotary

RABtool

47

ing system. New downhole tools are theol, which is an instrumented stabilizer, thedownhole weight and torque on bit ande bit in a rotary assembly, or above theDN Compensated Density Neutron and

system, called the Wellsite Informationmeters, change scales, convert represen-ration are automated to free the user to

Logging at the Bit for Geosteering and PetrophysicsThe two new logging devices, the RAB tooland the GeoSteering tool, share many fea-tures in common but differ in importantrespects. The RAB tool provides real-timelog measurements for high-quality formationevaluation. It is run, like the CDR tool, in asteerable assembly behind the motor or in arotary drilling assembly immediately behindthe bit. The GeoSteering tool enables thedriller and geologist to make real-time cor-relation at the bit, detect hydrocarbons atthe bit and steer the borehole for increasedreservoir exposure (next page, below left).Both tools measure gamma ray, resistivityusing the bit as the electrode, and“azimuthal” resistivity—focused at a narrowangle along the borehole wall.4 The gammaray sensor on the GeoSteering tool isshielded on one side to provide anazimuthal reading.

Resistivity at the bit is measured byattaching the GeoSteering or RAB tooldirectly to the bit and driving an alternatingelectric current down the collar, out throughthe bit and into the formation. The currentreturns to the drillpipe and drill collarsabove the transmitter. In water-base mud,returning current is conducted from the bitthrough the mud, into the formation andback to the BHA. In oil-base mud, which isan insulator, current returns through theinevitable but intermittent contact of thecollars and stabilizers with the boreholewall, leading to a qualitative indication ofresistivity. Formation resistivity is obtainedby measuring the amount of current flowinginto the formation from the bit, and normal-izing it to the transmitter voltage. Axial reso-lution is determined by the length of theBHA below the lowermost coil, includingthe bit.5 In the GeoSteering tool, resolutionof resistivity at the bit is about 6 ft [1.8 m];

Uppertransmitter

Azimuthalelectrodes

Ringelectrode

Lowertransmitter

PowerPak motor

Surface-adjustablebent housing

Inclination RPM,gravity toolface

3/4° fixedbent housing

Stabilizerand bearings

Transmitter forwireless telemetryand measurement

current

Gamma raydetector

Azimuthal resistivity(depth of investigation

12 in. or less )

Measurementantenna

nThe GeoSteeringand RAB tools. TheGeoSteering tool isan instrumentedsteerable motor,meaning it can beused in rotary orsliding mode. The RAB tool is aninstrumented stabilizer on arotary assembly.

48 Oilfield Review

in the RAB tool, resolution of resistivity atthe bit can be as fine as 2 ft [0.6 m].

Azimuthal resistivity is measured fromone or more button electrodes and, like theazimuthal gamma ray measurement, can beused to steer the bit. Both tools can be ori-ented in multiple directions to find thelocation of a lithologic or pore fluid bound-ary relative to the borehole—up, down, leftor right—and thereby steer the bit. In rotarymode, the borehole circumference can bescanned, providing an average resistivityand the ratio of the highest button readingto the lowest button reading for a given atime frame. If the ratio is close to 1, the for-mation is homogeneous. If it deviates from1 and jumps, a bed or pore fluid boundarywas crossed and stationary (azimuthal) log-ging can indicate the direction to theboundary. If it deviates from 1 and changesslowly, anisotropy may be present. TheGeoSteering tool has a single resistivity but-

ton within 5 ft [1.5 m] of the bit that pro-vides an axial resolution of a few inches; thenew RAB tool design has three buttons pro-viding three depths of investigation, 3, 6and 9 in., [7.6, 15 and 23 cm] for detectionand evaluation of invasion.6

In the RAB tool, a fourth depth of investi-gation, 12 in. [30 cm], is provided by a ringresistivity measurement 5 ft behind the bit(right). This measurement is focused to ahigh axial resolution by addition of a sec-ond transmitter near the bit (below, right).Ring resistivity is like azimuthal resistivity in

nPrinciple of ring resistivity measurement. The measurement current is forced into theformation by current flowing out the bottomhole assembly above and below the ring.

nComparison of geosteering efficiency for a conventionalMWD/steerable bottomhole assembly vs. one in which forma-tion evaluation measurements are made at the bit. This assumesthe systems can steer at 6° per 100 ft [30 m]. If the relative dipbetween the formation floor/roof and the drainhole is as small as3°, a conventional MWD system takes twice as long to reenterthe target formation as a system with measurements at the bit.

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaLost drainhole potential

Conventional steerable MWDsystem (sensors 50 ft behind bit)

50 ft

GeoSteeringtool

Pay zone

α

Lost

pot

entia

l dra

inag

e, ft

Relative dip, α deg

Lost production using

conventional steerable system

400

300

200

100

00 2 4 6 8 10

10

100

1000

10,000R

esis

tivity

, ohm

-m

Depth, ft

150100500

Unfocusedresistivity

10

100

1000

10,000

Res

istiv

ity, o

hm-m

Actively focusedring resistivity

Rt

Rt

Drillcollar

Insulation

Mud

To computer

Side view Top view

Currentmeter

49April/July 1993

4. The term “azimuthal” here descends from verticalwell terminology, in which the azimuth refers to acompass bearing with respect to the side of the bore-hole wall.

5. “Vertical” resolution does not apply in a horizontalwell and is instead called “axial,” describing resolu-tion with respect to the borehole axis.

6. Depth of investigation here means radial distancefrom the borehole wall into the formation.

nHow focusing improves axial resolution of RAB ringresistivity response in a modeled formation.

rotary mode, but the larger surface area ofthe ring compared to the button allowsgreater precision. The ring measurementcan detect beds thinner than 2 in. [5 cm].Neither azimuthal nor ring resistivity mea-surements function in oil-base mud becausethe mud acts as an insulator.

Although they are not laterolog measure-ments, azimuthal and ring resistivities workbest in laterolog-type settings—conductive(salty) mud and/or resistive formations. Theycomplement the resistivity measurement ofthe CDR tool, which is optimized for induc-tion-type environments. Capabilities of theGeoSteering and RAB tools show how theirapplications differ (right).

Surface Control for Measurements at the BitBecause the GeoSteering tool is an instru-mented steerable motor, it enables thedriller to steer the bit on a geometric or geo-logic path through the pay zone. Thedriller’s window into the bit is the WellsiteInformation System, which includes a dis-play for checking and revising the structuraland stratigraphic model, and updating thedrilling trajectory (next page, top ). Thisscreen is intended mainly for real-time man-agement of horizontal drilling. In this exam-ple, steering was guided by the logging-while-drilling CDR measurement 70 ft [21m] behind the bit, but the screen functionsthe same way with GeoSteering tool data.Input for this display is the simulated trueresistivity (Rt) profile (A) built by the com-pany geologist and log analyst using offsetlog data to model the earth vertically belowthe well. While the well is drilled, this Rtprofile and the actual well trajectory areinput to a program that models CDR logresponse at various relative dips (B).7 Com-parison of the curves in (B) and the logsmeasured in real time (C) indicates howclose the model is to reality—both modeledand measured logs advance across thescreen during drilling. Misalignment ofmodeled and measured responses meansthe dip must be changed, or structure

50 Oilfield Review

Reconnaissancelogging

Qualitative

Resistivity at the bit

• Rotary BHA (replacing the near-bit stabilizer)

• Motor BHA (run below the motor)

Resistivity operates in oil-base mud

Quantitative laterolog-type Rt

Gamma ray

Azimuthal gamma ray

Real-time data

Wireless telemetry

Single-axis inclination

Triaxial inclination

Downhole memory

Combinable with CDR /CDN tools

Three-button array

Qualitative single-button resistivity

RABTool

GeoSteeringToolFunctionality

Resistivity Environment

LaterologConditions

Induction Conditions

Salt mud Water-basemud

Oil-basemud

Geo

log

yP

etro

phy

sics

Ap

plic

atio

ns

GeoSteeringor

RAB tool

CDR toolGeoSteering

tool(qualitative)

Geosteering GeoSteeringor RAB tool CDR tool CDR tool

Loggingwhile drilling RAB tool CDR tool CDR tool

Loggingafter drilling

Preinvasionlogging

RAB tool CDR tool CDR tool

CDR tool CDR toolRAB tool

Routine correlation

Criticaldecisions

GeoSteering and CDR tools may be run together.

RAB and CDR tools may be run together.

CDR tool

Short normal

GeoSteeringtool

nComparison ofRAB and GeoSteer-ing tool specifica-tions (top) andapplications (bottom). Althoughboth tools havemany features incommon, they differ in certainrespects. The RABtool can be run atthe bit in rotarymode for formationevaluation. TheGeoSteering tool,an instrumentedsteerable motor,provides measure-ments for correla-tion, hydrocarbonidentification anddrilling mechanicsdata. Determiningthe optimal choiceof tools (bottom)—CDR, RAB,GeoSteering tool or some combina-tion—requiresevaluating the informationneeded and theborehole environ-ment. Here, onlythree resistivityenvironments are shown. However, manywells encountermore than oneenvironment.

moved up or down. Changes in the geo-logic model result in automatic changes tothe modeled logs. In this way, the modelcan be iteratively modified until it matchesthe real-time data, indicating the correctmodel for depth and dip of the structure. Inthe measured logs, Hres means horizontalresistivity, a computed value that includesinclination data to compensate for theeffects of dipping, anisotropic beds.8 Inplace of resistivity mode, modeling mayalso be done based on gamma ray with for-mation strength, neutron-density responseor RAB measurements.

Resolution of both GeoSteering tool andRAB resistivity measurements is sufficient forhydrocarbon detection and lithologic corre-lation (below). The multiple depths of inves-tigation and high resolution of the focusedRAB measurements also provide formation

nComparison of wireline induction andGeoSteering tool bit and button resistivi-ties for a Gulf of Mexico well. Separationof the bit and button curves is due to thedifferent physical nature of the measure-ments and different locations of the sensors. Bit resistivity is from currentinjected directly from the bit whereas button resistivity is an azimuthal lat-erolog-style measurement made about 5 ft [1.5 m] above the bit.

In zones A1 and A2, bit resistivity isable to fully resolve Rt in the thick bed,except for the thinnest streak, resolvedonly by the SFL Spherically Focused Resis-tivity Log. Invasion doesn’t appear toaffect the measurement. Button resistivity,however, flattens out at X624 to X629 ftbecause drilling was stopped at the bot-tom of A1, increasing the time betweendrilling and logging from 5 minutes to 18 minutes. The flat response is from inva-sion masking Rt . At zone B, fast drillingthrough quick resistivity changes spreadsout sample points of the GeoSteeringmeasurement. It missed the peak at X664 ft because sample points fell oneither side of the highest value.

51April/July 1993

7. 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): 13-15.

8. For effects of anisotropy:Tittman J: “Formation Anisotropy: Reckoning With itsEffects,” Oilfield Review 2, no. 1 (January 1990): 16-23.

X600

X700

A1

A2

B

Dep

th, f

t

500 0

0 150 0.2 20 0.2 20GAPI

ft/hr

Ohm-m Ohm-m

GeoSteering ROP

GeoSteering GR

Gamma Ray

Medium Induction

Spherically FocusedResistivity Log

Deep Induction

Button Resistivity

Bit Resistivity

A

B

C

D

nGeosteering through a North Sea pay zone using the GeoSteering screen to guide the drill bit.

0.2

2000

Res

istiv

ity, o

hm-m

RAB ringafter drilling

RAB ringwhile drilling

AIT

Water sand Rmf > Rw

1500 1550 1600

Distance, ft

Res

istiv

ity, o

hm-m

100

0.2

Laminated wet sands

570 580 590 600

Distance, ft

AIT

MicroSFL

RAB ringafter drilling

RAB ringwhile drilling

nComparison of RAB ring resistivity measurements, after andwhile drilling, with wireline logs. In the water sand, the RABmeasurement shows higher resolution than the AIT Array Induc-tion Imager tool. In the laminated wet sands example, RAB logsmade after drilling and while drilling anticorrelate, showingpreferential invasion.

nComparison of RAB andFMI Fullbore FormationMicroImager logs in anOklahoma, USA well,showing good agreementon features as thin as 1 in.[2.5 cm].

52 Oilfield Review

FMI Images GammaRay RAB Data

Dep

th, f

t

1050

1060

1070

1080

1090

Ring resistivity

Bit resistivity

nThe GeoSteering Station Logging screen(top) is used by the directional drillermainly for foot-by-foot steering of a hori-zontal well, and (bottom) a schematic ofgamma ray response in a station loggingpolar plot, looking up and down whencrossing a sand/shale boundary. Direc-tional reading of log values at pointsaround the borehole circumference tellswhether the bit has penetrated the roof orfloor of the pay zone, or a fluid or lithol-ogy boundary. Logs in this display are“button” (BTN) resistivity, measured by abutton a few feet above the bit; gravitytoolface (GTF)—bit orientation withrespect to the top of the hole—andgamma ray (GR) a few feet above the bit.The circular plot shows resistivity (red)and gamma ray (green) values vs. tool-face, in which 0 is the top of the hole. The origin is a resistivity or gamma rayvalue of zero. In this example, each inter-val is 50 API units for gamma ray, 20ohm-m for resistivity. The two measure-ments are 180° apart because the sensorslie on opposite sides of the tool. Eachpoint represents a measurement at agiven toolface and time. A sudden rise orfall along a certain toolface helps thedriller recognize not only the presence ofa boundary, but also its direction relativeto toolface. The largest dot shows themost recent value, which corresponds tothe endpoint on the log. As many as 20dots can be shown. The update can takeplace as often as every sample point,with the oldest data point dropping out ateach update.aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaSand

Shale

Sensorlooking upHigh GRsees mostlyshale

Sensorlooking downLow GRsees mostlysand

evaluation-quality information (previouspage, top). Applications include promptlocation of coring and casing points, andmonitoring of invasion by logging afterdrilling (previous page, bottom).

Applications of the tools are linked withinterpretation packages in the Wellsite Infor-mation System. Geosteering, for example, isfurther enhanced by the merger of lithologydata with directional drilling data. Conven-tionally, the driller uses a display that

April/July 1993

reports only bit tool face—up, down, left orright. It tells nothing directly about lithologyor pore fluids. The IDEAL drilling systemincludes a display of resistivity and gammaray by tool face (above). This shows thedriller not only where the bit is pointing, butalso whether it has penetrated a boundarybetween formations or pore fluids. It allowsthe driller to instantly confirm entry into thepay zone or promptly redirect the bit backinto the target formation.

53

Optimal downholetorque for thegiven flow rate

Motor stalls

P = Standpipe pressureQ = Flow rate, pumpsN = TorqueM = RPM

Real-time field dataLab data on dynamometer

500

400

300

200

100

0400 500 600 700 800

Mec

hani

cal p

ower

, NXM

Hydraulic power, P X Q

nPower curve for a downhole motor. Inthis example, the driller ran the motorconventionally, using surface measure-ments to derive mechanical power. Thepenetration rate was 40 to 60% of whatcould have been achieved by runninghigher up the curve. Use of downholemeasurements of torque and motor RPMallows the driller to work closer to theoptimum point on the curve, and obtain ahigher rate of penetration.

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Improving Drilling EfficiencyThe most significant advancement forimproved drilling efficiency is downholemeasurement of RPM, provided by theGeoSteering Tool. Together with downholemeasurements of weight and torque fromthe RWOB tool, these measurements allowthe driller to operate the motor near thepeak of the power curve (right ). Higherpower to the bit means faster penetration.

A near-bit measurement of downholeshock—from bit bouncing or pipe slappingthe borehole wall—provides the driller withmore accurate information about optimaldrilling speed and weight on bit. This trans-lates into longer bit life, fewer bit trips andless shock-related damage to the wellboreand drillstring.

Other improvements for drilling efficiencyare an array of alarms in the Wellsite Infor-mation System. These alarms are displayedin front of the driller on a color monitor andaddress situations that account for mostdrilling difficulties, such as stuck pipe, kicks,washouts and bit damage. These events ortheir precursors are flagged with alarms thatalert the driller not only about potentialdrilling trouble, but also about conditionsthat could threaten rig safety. The alarms arebased on integrated interpretations usingsurface and downhole data.

Another improvement of the surface sys-tem is better depth control, critical forproper steering and evaluation of a horizon-tal drainhole. Improvement in depth accu-racy comes mainly from sampling draw-works rotation and hook load at highfrequency. The drawworks is a drum thatspools and unspools cable that moves thetraveling block up and down to lift andlower the drillstring. Drawworks rotation isrelated to depth added or subtracted. Hookload is needed to determine when the pipeis “in slips”—clamps that hold the drillstringwhen it is not supported by the hook on thetraveling block. Hook load is at a minimumwhen pipe is in slips. Drawworks samplingduring that period is not counted because

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the pipe is stationary. The higher samplingfrequency reduces error introduced duringrapid travel of the drillstring, when samplepoints become less dense. Improved soft-ware logic lets the system know automati-cally the precise times that pipe goes in orout of slips. This saves having to make peri-odic recalibration to driller’s depth, which isbased on a tally of pipe sections and thelength of each section. These and otherimprovements keep the Wellsite InformationSystem depth readings within an average of0.1% of driller’s depth.

Drilling with at-the-bit measurements isstill in its infancy, but promises to make thedriller’s job more quantitative, improvingdrilling and steering efficiency. Petrophysi-cal measurements near the bit draw closerto the uninvaded formation. On the horizonis the real-time merging of geosteering datawith seismic data and reservoir models. Thiswill permit update of field maps as the wellis drilled, finally integrating the data basesof exploration and development. —LS, JK

Oilfield Review