DRILLING

Measurements at the Bit: A New Generation of MWD Tools

Measurements-while-drilling technology has moved down the drillstring to enlist the bit itself as a sensor. Drillers time information about and drilling mechanics without a lag between bit and sensors. This technical ciency of , enhance real-time , and ultimately create a more productive well. a a a a a a a aa a a a a Steve Bonner a a a a aa aa a a a a Trevor Burgess a a Brian Clark aa a aa a a a a a a a aa a Dave Decker a Jacques Orban Kick-off aaa a a a a a a point Bernhard Prevedel a a First build aaa a a a a a a a a a a Sugar Land, Texas, USA a (5.5 ft /100 ft)

a a aa aa a Martin Lüling a a a G aa aa e a a Second build a aa a a aa a a a aa Ridgefield, Connecticut, USA o a a a a a m (10 ft /100 ft) e a a a a tr a Tangent aa a a a a a a a a a ic Jim White s section e c aaa a ti a a aa a a a a a Aberdeen, Scotland a a a o a a a a a a n a a Horizontala Target entry point tolerance a a a a a a aa aa a aa a a aaa a a a a a a a In this article, IDEAL (Integrated Drilling Evaluation and a aaa a aa a a a a a aa a a Logging), tool, PowerPak, RAB (Resistivity- a a a a a a a at-the-Bit), RWOB (Receiver, Weight on Bit and Torque a a a Geosteering section a a aa a a a tool), PowerPulse, CDR (Compensated Dual Resistivity a a a aaa a a a tool), SFL (Spherically Focused Resistivity Log), AIT (Array Induction Imager Tool), CDN (Compensated Den- a a aa a a a a a a a a a sity Neutron tool) and FMI (Fullbore Formation MicroIm- ager) are marks of . aaa a a aa For help in preparation of this article, thanks to David Allen, Schlumberger Well Services, Sugar Land, Texas, nA typical horizontal well plan. Geometric drilling refers to USA; Philippe Faure, Dominic McCann, Samantha drilling along a fixed, predetermined trajectory, generally based Miller, Bernard Montaron and Kanai Pathak, Anadrill, on offset data and a stratigraphic model. Decisions about steer- Sugar Land, Texas, USA; Richard Rosthal, Schlumberger ing are based only on real-time information about bit direction , Sugar Land, Texas, USA; and David Hill, Schlumberger Well Services, New Orleans, and inclination. Geosteering refers to navigating the borehole Louisiana, USA. using geologic information in real time. Geosteering is possible 1. Betts P, Blount C, Broman B, Clark B, Hibbard L, with logging-while-drilling sensors, which are integrated into Louis A, Oosthoek P: “Acquiring and Interpreting Logs drill collars 40 to 100 ft [12 to 30 m] above the bit and steerable in Horizontal Wells,” Oilfield Review 2, no. 3 (July motor. Geosteering becomes more efficient with measurements 1990): 34-51. at the bit. Logging While Drilling. Schlumberger Education Ser- vices: Houston, Texas, USA, 1992. Conventional drilling of high-angle and hor- properties—are remote from the bit, crucial 2. For a review on horizontal drilling methods: izontal wells is like piloting an airplane from drilling decisions are delayed and data may Burgess T and Van de Slijke P: “Horizontal Drilling the tail rather than the cockpit. Information require more complex interpretation. In par- Comes of Age,” Oilfield Review 2, no. 3 (July 1990): required to land the well in the target forma- ticular, course corrections are delayed by 22-33. tion is derived from sensors 50 ft [15 m] or lag in measurements needed to make steer- more behind the bit or at the surface. ing decisions, resulting in less drainhole in Because these measurements—about well the pay zone. Also, maximum drilling effi- trajectory, drilling efficiency and formation ciency requires information about mechani-

44 Oilfield Review

Locked assembly

Rotary mode for vertical, tangent or horizontal sections

Steerable assembly Rotary or sliding mode

and geologists now have real- progress promises to improve effi-

Locked Steerable

cal power delivered to the bit, which is nTypical bottomhole assemblies for horizontal drilling. A rigid, inferred from surface measurements, or locked, assembly is used for drilling a vertical, tangent or degrading its accuracy. And resistivity mea- straight horizontal section. Rigidity increases with the number of stabilizers. This type of assembly permits only gradual changes surements from logging-while-drilling in the vertical angle of the well trajectory. A steerable assembly (LWD) sensors in drill collars are limited to with a downhole motor inside a bent housing can vary well tra- formation resistivity less than 200 ohm-m.1 jectory vertically and to the left and right, and can change Despite these limitations, horizontal and angle more quickly than a locked assembly. a a a a a a a a a high-angle drilling have proved successful, a especially in simple geologic settings— a aa a a a uncomplicated layer-cake structure. Nearly a aa a a aa a a a aa all these wells start vertically, with a con- a a a a a ventional rotary bottomhole assembly (BHA) aa a a a a a a a a (previous page).2 The drillstring and bit are a Sliding mode a aa a a a a a rotated from the surface either by a rotary a a a a a a a a a table on the derrick floor or a motor in the a a aa aa a aa a a traveling block, called a topdrive. Drilling a Rotary mode this way is called rotary mode. To kick off a aa a a a a a aa a a from vertical, the rotary assembly is a a a aa a a a replaced with a steerable motor—usually a a a a positive displacement motor, driven by mud Increased diameter due to a a aa a a a a a a a a a flow, in a housing bent 1° to 3° (above, outward tilt of steerable motor (scale exaggerated) aaa a a aa right). When mud is flowing, the motor rotates the bit, but not the drillstring. This nHow well trajectory is changed. In rotary mode, both the bit type of drilling is called sliding mode, and drillstring rotate and the bit cuts a straight path parallel to because the drillstring slides along after the the axis of the drillstring above the bent sub. In sliding mode, bit, which advances in the direction of the only the bit rotates and the hole follows the axis of the bent hous- housing below the bend (right). The larger ing below the bend. the angle of the bent housing, the sharper vertical. Large changes in direction are adjustments in inclination can be made with the curvature of the trajectory. The direction made by lifting off bottom and reorienting conventional rotary assemblies only by in which the bit is pointing, called toolface, the bent sub by rotating from surface. Small pulling out of the hole and varying the size is measured and sent to surface by measure- changes are made by varying weight on bit, and placement of stabilizers. Most horizon- ment-while-drilling (MWD) equipment for which changes the reactive torque of the tal sections, and some tangent sections, are real-time control of bit orientation. Mea- motor and hence toolface orientation. drilled with a steerable motor while rotating surements include azimuth, which is the Once sufficient inclination has been built, the drillstring from surface. In this mode, the compass bearing of the bit, and inclination, straight or tangent sections can be drilled in steerable motor behaves like a rotary BHA, which is the angle of the bit with respect to several ways. One is with a conventional maintaining both azimuth and inclination. rotary, or “locked,” assembly, which is rigid enough to allow fast, straight drilling. Small adjustments in inclination can be made by April/July 1993 varying weight on bit or rotary speed. Large 45 46 they areset. zontal sectionarebrokennearlyassoon undisputed, andrecordsforthelongesthori- Today, the Horizontal Drilling Limitationsin Overcoming faster drillingthaninslidingmode. reduces theriskofgettingstuckandallows rotary mode.Rotationofthedrillstring rotary assemblyorasteerablemotorin make asmuchholepossibleusinga of thehole.Generally, thedrillertriesto rections withouttrippingthedrillstringout motor allowsthedrillertomakecoursecor- However, thepresenceofsteerable mation, ageneroussafetymargin ismain- bottom. Becauseofuncertaintyinthisesti- when thebitisonbottom,comparedtooff proportional totheincreaseinmudpressure proportional tomudflow. Torque isroughly and mudpressure.MotorRPMisroughly from surfacemeasurementsofmudflow motor. Powerisestimatedconventionally sible, butwithintheoperationallimitof The goalistoapplyasmuchpowerpos- an expensivetripformotorreplacement. and eventuallydamagethemotor, requiring tion—up toapoint.Excessweightmaystall more power, thefasterrateofpenetra- torque, andpoweristorque timesRPM.The increases weight,themotorproducesmore apply tothesteerablemotor. Asthedriller is howmuchweightthedrillercansafely rotary mode,akeylimitationonefficiency limit theseefficiencies? does lagbetweenmeasurementsandthebit total lengthofthehorizontalsection.How the horizontalsectioninpayzoneto can bedefinedastheratiooflength the horizontalsection,steeringefficiency tions suchastripsorholeconditioning.In hole tothetotalrigtime,includingopera- efficiency istheratiooftimespentmaking In drilling,forexample,onewaytodefine distance betweenthebitandmeasurements. and steeringhorizontallyislimitedbythe 3. IntheNorwegianNorthSea,Statoilrecentlydrilled In drillingwithadownholemotorin ary 15,1993):31. Extended Reach,” 24,000 ft[7000m].“StatoilClaimsWorld Recordin an extendedreachwellwithahorizontalsectionof ability 3 Yet, the Oil & Gas Journal Journal Gas & Oil to drillhorizontallyis efficiency 91, no.7(Febru- of drilling trajectory ( insufficiently knownforplanningthewell tive whenthetarget isthin,complexor simple andwellknown.Butitislesseffec- as longthetarget isthick,structurally only retrospectively. Thistechniqueisfine, present, aremadefarfromthebitandused Gamma rayandresistivitymeasurements,if only onbitdirectionandinclinationdata. and geologicassumptions.Steeringisbased predetermined basedonnearbywelldata “geometrically”—along apaththathasbeen ciency. Wells areconventionallysteered tional horizontaldrillingisinsteeringeffi- tion, whichreducespenetrationrate. applying optimalweightforagivenforma- tained. Thismargin preventsthedrillerfrom n n advances inthree-dimensional seismics, drilling measurements. measurements. drilling hori- beyond drilled successfully was well Sea North This zone. pay the in drainhole less zontal, but the reservoir dipped more than expected. Only about 15% of the drainhole the of 15% about Only expected. than more dipped reservoir the but zontal, was in the pay zone. pay the in was Steering along the top of the oil/water contact in the North Sea using logging-while- using Sea North the in contact oil/water the of top the along Steering dip— reservoir about information inadequate with geometrically steering of risk The Perhaps thegreatestlimitationinconven- True vertical depth, ft True vertical depth, ft LWD Data XX85 XX65 XX25 XX00 X800 X700 R Bulk density top ad Gamma rayinwellpath (deep)resistivity ). Andincreasingly, with Gas/oil contact Gas/oil X900 Oil/water contact

X900

X000

X100 Horizontal distance,ft Reservoir Actual trajectory Horizontal distance,ft geosteered adrainholealongthetopof mostly resistivitymeasurements,thedriller geosteering andformationevaluation.Using LWD sensorsperformedthedualpurposeof properties. ANorthSeaexampleshowshow real-time informationaboutrockandfluid “geosteering”—navigation ofthebitusing ing withmoreefficientgeologicsteering,or allow replacementofbasicgeometricsteer- complexly foldedorfaultedreservoirs. Challenges todayincludethinbedsand voirs anddrillingmorecomplexwells. operators arelocatingmoreintricatereser-

In thesesettings,sensorsindrillcollars X300 Proposed geometrictrajectory

X300

R X500 ps (shallow)resistivity

X400

Oilfield Review Oilfield X700

X500

X900

Courtesy of Norsk Hydro oil/water contact to avoid gas production it back into the pay. Overall, 550 ft of this mented stabilizer (next page). Measurements (previous page, middle). Resistivity modeling 750-ft section of the drainhole [167 m of include gamma ray, several types of resistiv- from offset wells showed this contact should 228 m] was in the pay zone—a respectable ity including a measurement at the bit, and have a resistivity of about 0.6 ohm-m. When 73% steering efficiency, and a marked drilling data such as inclination, bit shocks the value dropped, indicating water, the well improvement over geometric steering. and motor RPM. path was turned up slightly; when resistivity In addition to reduced efficiency in The technical leap that allows measure- increased, the well path was dropped drilling and geosteering, a third limitation of ments to be made at the bit and below the slightly. Although these measurements conventional horizontal drilling is in forma- steerable motor is a wireless telemetry sys- enabled the driller to keep close to the pay tion evaluation while drilling. Logging- tem. This telemetry link sends data from sen- zone, the well strayed into the water for 100 while-drilling sensors reach the formation sors near the bit to the MWD tool up to 200 ft [30 m], between X900 and X000 ft. This long before wireline measurements, and so ft [61 m] behind the bit, a path that bypasses was due to lag between the bit and resistivity generally view it before wellbore degrada- the intervening drilling tools, such as the sensors. By the time the resistivity sensors tion, but some invasion has still occurred. steerable motor. The PowerPulse MWD sys- detected the fluid change, the bit had Rapid invasion, called spurt, may mask true tem recodes and then sends data to surface advanced 50 ft. It took another 50 ft to steer resistivity in some formations. Also, LWD in real time using mud-pulse telemetry at up resistivity measurements by the CDR Com- to 10 bits per second. At surface, data pensated Dual Resistivity tool are limited to recording, interpretation and tool control are Wellsite Information System environments favoring induction-type set- performed by the Wellsite Information Sys- tings—resistive mud (fresh or oil-base mud) tem. Control data can be sent from the sur- Driller's Safety screen screen Customer's and conductive rock. face back downhole by varying mud pump presentation The solution to these problems—limited flow. This enables the operator to select from efficiency in drilling and geosteering, and a predefined menu of data types, change the limited capabilities of real-time formation telemetry rate and change how often data evaluation—is relocation of drilling and log- are sent to surface, without pulling the tools ging measurements to the bit itself. This has out of the hole. The operator can also Remote been achieved with the IDEAL Integrated change how often LWD and RAB data are communications Drilling Evaluation and Logging system, stored in downhole memory (data from the which uses new logging and drilling mea- GeoSteering tool are delivered only in real surement technologies to make real-time time). The system provides the driller, geolo- measurements at the bit (left and below). gist and petrophysicist with information at The system includes two new logging the earliest possible time to make real-time devices: the GeoSteering tool, an instru- decisions that minimize course corrections, mented steerable downhole motor, and the improve drilling efficiency and allow real- RAB Resistivity-At-the-Bit tool, an instru- time formation evaluation. Depth and Detailed well other surface plan from drilling sensors planning center

Wireless telemetry Steerable

GeoSteering tool CDN tool PowerPulse tool RWOB tool CDR tool PowerPak compensated 10 bits/sec weight/torque compensated steerable motor RAB density/neutron/Pe MWD telemetry dual resistivity above motor

RAB tool Rotary

nSurface and downhole components of the IDEAL Integrated Drilling Evaluation and Logging system. New downhole tools are the GeoSteering tool, which is an instrumented steerable motor, the RAB Resistivity-At-the-Bit tool, which is an instrumented stabilizer, the PowerPulse MWD telemetry tool and the RWOB Receiver, Weight on Bit and Torque tool for downhole weight and torque on bit and for wireless telemetry of GeoSteering tool and RAB data. The RAB tool can be run next to the bit in a rotary assembly, or above the motor in a steerable assembly. Compatible downhole components include LWD tools, the CDN Compensated Density Neutron and CDR Compensated Dual Resistivity tools. The most significant advancement in the surface system, called the Wellsite Information System, is its interactive nature. Users can customize acquisition schemes and screen parameters, change scales, convert represen- tations from depth to time and make annotations. Tasks such as data processing and integration are automated to free the user to make interpretations and advise on drilling decisions.

April/July 1993 47 Logging at the Bit for Geosteering Resistivity at the bit is measured by in the RAB tool, resolution of resistivity at and Petrophysics attaching the GeoSteering or RAB tool the bit can be as fine as 2 ft [0.6 m]. The two new logging devices, the RAB tool directly to the bit and driving an alternating Azimuthal resistivity is measured from and the GeoSteering tool, share many fea- electric current down the collar, out through one or more button electrodes and, like the tures in common but differ in important the bit and into the formation. The current azimuthal gamma ray measurement, can be respects. The RAB tool provides real-time returns to the drillpipe and drill collars used to steer the bit. Both tools can be ori- log measurements for high-quality formation above the transmitter. In water-base mud, ented in multiple directions to find the evaluation. It is run, like the CDR tool, in a returning current is conducted from the bit location of a lithologic or pore fluid bound- steerable assembly behind the motor or in a through the mud, into the formation and ary relative to the borehole—up, down, left rotary drilling assembly immediately behind back to the BHA. In oil-base mud, which is or right—and thereby steer the bit. In rotary the bit. The GeoSteering tool enables the an insulator, current returns through the mode, the borehole circumference can be driller and geologist to make real-time cor- inevitable but intermittent contact of the scanned, providing an average resistivity relation at the bit, detect hydrocarbons at collars and stabilizers with the borehole and the ratio of the highest button reading the bit and steer the borehole for increased wall, leading to a qualitative indication of to the lowest button reading for a given a reservoir exposure (next page, below left). resistivity. Formation resistivity is obtained time frame. If the ratio is close to 1, the for- Both tools measure gamma ray, resistivity by measuring the amount of current flowing mation is homogeneous. If it deviates from using the bit as the electrode, and into the formation from the bit, and normal- 1 and jumps, a bed or pore fluid boundary “azimuthal” resistivity—focused at a narrow izing it to the transmitter voltage. Axial reso- was crossed and stationary (azimuthal) log- angle along the borehole wall.4 The gamma lution is determined by the length of the ging can indicate the direction to the ray sensor on the GeoSteering tool is BHA below the lowermost coil, including boundary. If it deviates from 1 and changes shielded on one side to provide an the bit.5 In the GeoSteering tool, resolution slowly, anisotropy may be present. The azimuthal reading. of resistivity at the bit is about 6 ft [1.8 m]; GeoSteering tool has a single resistivity but-

Upper nThe GeoSteering transmitter PowerPak motor and RAB tools. The GeoSteering tool is an instrumented Azimuthal steerable motor, electrodes meaning it can be used in rotary or sliding mode. The RAB tool is an instrumented stabilizer on a rotary assembly. Surface-adjustable Ring bent housing electrode Transmitter for wireless telemetry and measurement current Inclination RPM, gravity toolface Gamma ray detector

Azimuthal resistivity 3/4° fixed (depth of investigation bent housing 12 in. or less) Lower transmitter Stabilizer Measurement and bearings antenna

48 Oilfield Review

ton within 5 ft [1.5 m] of the bit that pro- Side view Top view vides an axial resolution of a few inches; the new RAB tool design has three buttons pro- viding three depths of investigation, 3, 6 and 9 in., [7.6, 15 and 23 cm] for detection and evaluation of invasion.6 Current In the RAB tool, a fourth depth of investi- meter gation, 12 in. [30 cm], is provided by a ring Drill resistivity measurement 5 ft behind the bit collar (right). This measurement is focused to a Mud high axial resolution by addition of a sec- Insulation ond transmitter near the bit (below, right). To computer Ring resistivity is like azimuthal resistivity in

4. The term “azimuthal” here descends from vertical well terminology, in which the azimuth refers to a compass bearing with respect to the side of the bore- hole wall. 5. “Vertical” resolution does not apply in a horizontal nPrinciple of ring resistivity measurement. The measurement current is forced into the well and is instead called “axial,” describing resolu- formation by current flowing out the bottomhole assembly above and below the ring. tion with respect to the borehole axis. 6. Depth of investigation here means radial distance from the borehole wall into the formation. a a a a a a a a a a aa a aa a a 10,000 a a a a a aa aaaa a a a a a a aa a a a a a

Lost drainhole potential 1000 a aaa a a a a Unfocused Rt aa a a a a a aa a a a a a a a a a Conventional steerable MWD resistivity system (sensors 50 ft behind bit) aa a a a aa a a 100 α 50 ft Resistivity, ohm-m Resistivity, aa a a a a a a a a a a a a aa a a a a a 10 a a a a aa a a a a a a GeoSteering aaa a a aa tool Pay zone 10,000 400

Rt 300 1000 Actively focused 200 ring resistivity Lost production using conventional steerable system 100 100 Resistivity, ohm-m Resistivity, Lost potential drainage, ft 0 024 6 810 10 Relative dip, α deg nComparison of geosteering efficiency for a conventional MWD/steerable bottomhole assembly vs. one in which forma- 0 50 100 150 tion evaluation measurements are made at the bit. This assumes Depth, ft the systems can steer at 6° per 100 ft [30 m]. If the relative dip between the formation floor/roof and the drainhole is as small as nHow focusing improves axial resolution of RAB ring 3°, a conventional MWD system takes twice as long to reenter resistivity response in a modeled formation. the target formation as a system with measurements at the bit.

April/July 1993 49 nComparison of rotary mode, but the larger surface area of RAB GeoSteering Functionality RAB and GeoSteer- Tool Tool the ring compared to the button allows ing tool specifica- greater precision. The ring measurement Resistivity at the bit tions (top) and can detect beds thinner than 2 in. [5 cm]. applications • Rotary BHA (bottom). Although Neither azimuthal nor ring resistivity mea- (replacing the near-bit stabilizer) surements function in oil-base mud because both tools have many features in the mud acts as an insulator. • Motor BHA (run below the motor) common, they Although they are not laterolog measure- differ in certain ments, azimuthal and ring resistivities work Resistivity operates in oil-base mud Qualitative respects. The RAB tool can be run at best in laterolog-type settings—conductive Quantitative laterolog-type R t the bit in rotary (salty) mud and/or resistive formations. They Gamma ray mode for formation complement the resistivity measurement of evaluation. The the CDR tool, which is optimized for induc- Azimuthal gamma ray GeoSteering tool, tion-type environments. Capabilities of the Real-time data an instrumented GeoSteering and RAB tools show how their steerable motor, Wireless telemetry provides measure- applications differ (right). ments for correla- Single-axis inclination tion, hydrocarbon Surface Control for Measurements Triaxial inclination identification and at the Bit drilling mechanics Downhole memory data. Determining Because the GeoSteering tool is an instru- the optimal choice Combinable with CDR /CDN tools mented steerable motor, it enables the of tools (bottom) driller to steer the bit on a geometric or geo- Three-button array —CDR, RAB, GeoSteering tool logic path through the pay zone. The Qualitative single-button resistivity driller’s window into the bit is the Wellsite or some combina- tion—requires Information System, which includes a dis- evaluating the play for checking and revising the structural information and stratigraphic model, and updating the Resistivity Environment needed and the drilling trajectory (next page, top). This borehole environ- Laterolog Induction ment. Here, only screen is intended mainly for real-time man- Conditions Conditions three resistivity agement of horizontal drilling. In this exam- environments Water-base Oil-base ple, steering was guided by the logging- Salt mud are shown. while-drilling CDR measurement 70 ft [21 mud mud However, many wells encounter m] behind the bit, but the screen functions Routine Short normal more than one the same way with GeoSteering tool data. correlation environment. Input for this display is the simulated true CDR tool GeoSteering resistivity (Rt) profile (A) built by the com- Reconnaissance GeoSteering GeoSteering or pany geologist and log analyst using offset logging tool tool RAB tool log data to model the earth vertically below (qualitative) the well. While the well is drilled, this Rt Critical CDR tool profile and the actual well trajectory are decisions input to a program that models CDR log GeoSteering 7 Geosteering CDR tool CDR tool response at various relative dips (B). Com- or RAB tool

parison of the curves in (B) and the logs Applications Logging measured in real time (C) indicates how RAB tool CDR tool CDR tool while drilling close the model is to reality—both modeled Logging and measured logs advance across the RAB tool CDR tool CDR tool screen during drilling. Misalignment of after drilling modeled and measured responses means Preinvasion Petrophysics RAB tool CDR tool CDR tool the dip must be changed, or structure logging

GeoSteering and CDR tools may be run together. RAB and CDR tools may be run together.

50 Oilfield Review moved up or down. Changes in the geo- logic model result in automatic changes to the modeled logs. In this way, the model can be iteratively modified until it matches the real-time data, indicating the correct C model for depth and dip of the structure. In the measured logs, Hres means horizontal resistivity, a computed value that includes inclination data to compensate for the effects of dipping, anisotropic beds.8 In place of resistivity mode, modeling may B also be done based on gamma ray with for- mation strength, neutron-density response or RAB measurements. Resolution of both GeoSteering tool and RAB resistivity measurements is sufficient for hydrocarbon detection and lithologic corre- A D lation (below). The multiple depths of inves- tigation and high resolution of the focused RAB measurements also provide formation

7. Bonner S, Clark B, Holenka J, Voisin B, Dusang J, Hansen R, White J and Walsgrove T: “Logging While Drilling: A Three-Year Perspective,” Oilfield Review 4, no. 3 (July 1992): 13-15. 8. For effects of anisotropy: Tittman J: “Formation Anisotropy: Reckoning With its Effects,” Oilfield Review 2, no. 1 (January 1990): nGeosteering through a North Sea pay zone using the GeoSteering screen to guide 16-23. the drill bit.

nComparison of wireline induction and GeoSteering ROP Medium Induction GeoSteering tool bit and button resistivi- 500ft/hr 0 ties for a well. Separation of the bit and button curves is due to the GeoSteering GR Spherically Focused Button Resistivity Resistivity Log different physical nature of the measure- ments and different locations of the Depth, ft Gamma Ray Deep Induction Bit Resistivity sensors. Bit resistivity is from current injected directly from the bit whereas 0GAPI 150 0.2Ohm-m 20 0.2 Ohm-m 20 button resistivity is an azimuthal lat- erolog-style measurement made about 5 ft [1.5 m] above the bit. X600 In zones A1 and A2, bit resistivity is able to fully resolve Rt in the thick bed, except for the thinnest streak, resolved only by the SFL Spherically Focused Resis- tivity Log. Invasion doesn’t appear to affect the measurement. Button resistivity, A however, flattens out at X624 to X629 ft 1 because drilling was stopped at the bot- A2 tom of A1, increasing the time between drilling and logging from 5 minutes to 18 minutes. The flat response is from inva- sion masking Rt . At zone B, fast drilling through quick resistivity changes spreads out sample points of the GeoSteering measurement. It missed the peak at B X664 ft because sample points fell on either side of the highest value.

X700

April/July 1993 51 nComparison of RAB and FMI Images Gamma Ray RAB Data FMI Fullbore Formation MicroImager logs in an Oklahoma, USA well,

Depth, ft showing good agreement on features as thin as 1 in. 1050 Ring resistivity [2.5 cm].

1060

1070

1080 Bit resistivity

1090

2000 100

Water sand Rmf > Rw Laminated wet sands

RAB ring after drilling MicroSFL

AIT Resistivity, ohm-m Resistivity, AIT RAB ring while drilling RAB ring after drilling Resistivity, ohm-m Resistivity, 0.2 1500 1550 1600 Distance, ft

nComparison of RAB ring resistivity measurements, after and RAB ring while drilling, with wireline logs. In the water sand, the RAB while drilling measurement shows higher resolution than the AIT Array Induc- tion Imager tool. In the laminated wet sands example, RAB logs made after drilling and while drilling anticorrelate, showing 0.2 preferential invasion. 570 580 590 600 Distance, ft

52 Oilfield Review

nThe GeoSteering Station Logging screen (top) is used by the directional driller

mainly for foot-by-foot steering of a hori- zontal well, and (bottom) a schematic of gamma ray response in a station logging polar plot, looking up and down when crossing a sand/shale boundary. Direc- tional reading of log values at points around the borehole circumference tells whether the bit has penetrated the roof or floor of the pay zone, or a fluid or lithol- ogy boundary. Logs in this display are “button” (BTN) resistivity, measured by a button a few feet above the bit; gravity toolface (GTF)—bit orientation with respect to the top of the hole—and gamma 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 ray value of zero. In this example, each inter- val is 50 API units for gamma ray, 20 ohm-m for resistivity. The two measure- ments are 180° apart because the sensors lie on opposite sides of the tool. Each point represents a measurement at a given toolface and time. A sudden rise or fall along a certain toolface helps the driller recognize not only the presence of a boundary, but also its direction relative to toolface. The largest dot shows the most recent value, which corresponds to Sensor the endpoint on the log. As many as 20 looking up dots can be shown. The update can take High GR sees mostly place as often as every sample point, shale with the oldest data point dropping out at each update.

Shale a a a a a a a a a a a a a a a a Sand a a a aa aa a a a a a a a aaa a a aaa

Sensor looking down Low GR sees mostly sand

evaluation-quality information (previous reports only bit tool face—up, down, left or page, top). Applications include prompt right. It tells nothing directly about lithology location of coring and casing points, and or pore fluids. The IDEAL drilling system monitoring of invasion by logging after includes a display of resistivity and gamma drilling (previous page, bottom). ray by tool face (above). This shows the Applications of the tools are linked with driller not only where the bit is pointing, but interpretation packages in the Wellsite Infor- also whether it has penetrated a boundary mation System. Geosteering, for example, is between formations or pore fluids. It allows further enhanced by the merger of lithology the driller to instantly confirm entry into the data with directional drilling data. Conven- pay zone or promptly redirect the bit back tionally, the driller uses a display that into the target formation.

April/July 1993 53 Improving Drilling Efficiency 500 The most significant advancement for improved drilling efficiency is downhole Optimal downhole measurement of RPM, provided by the torque for the 400 given flow rate GeoSteering Tool. Together with downhole Motor stalls measurements of weight and torque from the RWOB tool, these measurements allow M the driller to operate the motor near the X peak of the power curve (right). Higher 300 power to the bit means faster penetration. A near-bit measurement of downhole shock—from bit bouncing or pipe slapping the borehole wall—provides the driller with 200 P = Standpipe pressure

more accurate information about optimal N Mechanical power, Q = Flow rate, pumps drilling speed and weight on bit. This trans- N = Torque lates into longer bit life, fewer bit trips and M = RPM less shock-related damage to the wellbore 100 and drillstring. Real-time field data Other improvements for drilling efficiency Lab data on dynamometer are an array of alarms in the Wellsite Infor-

mation System. These alarms are displayed 0 Courtesy of AGIP in front of the driller on a color monitor and 400 500 600 700 800 address situations that account for most Hydraulic power, P X Q drilling difficulties, such as stuck pipe, kicks, washouts and bit damage. These events or nPower curve for a downhole motor. In their precursors are flagged with alarms that this example, the driller ran the motor alert the driller not only about potential conventionally, using surface measure- ments to derive mechanical power. The drilling trouble, but also about conditions penetration rate was 40 to 60% of what that could threaten rig safety. The alarms are could have been achieved by running based on integrated interpretations using higher up the curve. Use of downhole surface and downhole data. measurements of torque and motor RPM allows the driller to work closer to the Another improvement of the surface sys- optimum point on the curve, and obtain a tem is better depth control, critical for higher rate of penetration. proper steering and evaluation of a horizon- tal drainhole. Improvement in depth accu- the pipe is stationary. The higher sampling racy comes mainly from sampling draw- frequency reduces error introduced during works rotation and hook load at high rapid travel of the drillstring, when sample frequency. The drawworks is a drum that points become less dense. Improved soft- spools and unspools cable that moves the ware logic lets the system know automati- traveling block up and down to lift and cally the precise times that pipe goes in or lower the drillstring. Drawworks rotation is out of slips. This saves having to make peri- related to depth added or subtracted. Hook odic recalibration to driller’s depth, which is load is needed to determine when the pipe based on a tally of pipe sections and the is “in slips”—clamps that hold the drillstring length of each section. These and other when it is not supported by the hook on the improvements keep the Wellsite Information traveling block. Hook load is at a minimum System depth readings within an average of when pipe is in slips. Drawworks sampling 0.1% of driller’s depth. during that period is not counted because Drilling with at-the-bit measurements is still in its infancy, but promises to make the driller’s job more quantitative, improving drilling and steering efficiency. Petrophysi- cal measurements near the bit draw closer to the uninvaded formation. On the horizon is the real-time merging of geosteering data with seismic data and reservoir models. This will permit update of field maps as the well is drilled, finally integrating the data bases of exploration and development. —LS, JK

54 Oilfield Review