logging while drilling: a three-year perspective- disk...
TRANSCRIPT
MWD services
Short-normalresistivity
Gamma ray
Drillingmechanics
LWD•Compensated Dual Resistivity•Compensated Density Neutron
Direction&
Inclination
Real-time telemetry & recorded data
nThe relationship between MWD and LWD measurements. In this article, LWD is used to denote wireline-quality petrophysi-cal measurements made while drilling—resistivity, gamma ray,density and neutron porosities, calipers and photoelectric factor(Pe). LWD is a subset of MWD services, which also include sen-sors for drilling-related measurements, such as direction andinclination and equipment for data recording and telemetry.
4
Logging While Drilling: A Three-Year Perspective
Stephen BonnerBrian ClarkJacques HolenkaBernard VoisinSugar Land, Texas, USA
Jim DusangRandy HansenJim WhiteAberdeen, Scotland
Tom WalsgroveAmoco (UK) Exploration CompanyLondon, England
Logging while drilling (LWD) has been in commercial service since the late 1980s. Since then, the basic measurements
in hardware, processing and interpretation—some incremental, some monumental—has furthered understanding of the
FORMATION EVALUATION
Since the introduction of logging whiledrilling (LWD) in 1989, jobs in more than400 wells worldwide have propelled thetechnology through the first stage of matura-tion. Tools have improved, interpretationmethods can address more complex prob-lems, and challenges presented by highlydeviated and horizontal wells are beingovercome. Since 1989, worldwide expendi-tures for all measurement-while-drilling(MWD) services has more than doubled,from about $250 million in 1989 to a pro-jected $520 million in 1992.1
This article summarizes advances inSchlumberger’s LWD technology and appli-cations over the past three years (right ).Highlighted are tool technology, evolvingLWD applications and advances in dataprocessing and interpretation.
For help in preparation of this article, thanks to DaveBest, Keith Moriarty and Richard Rosthal, SchlumbergerLogging While Drilling, Sugar Land, Texas, USA; TrevorBurgess, Jean-Michel Hache, Marc Lesage, Bernard Mon-taron and Alan Starkey, Anadrill, Sugar Land, Texas,USA; Charles Flaum and Mike Gibbs, Etudes et Produc-tions Schlumberger, Montrouge, France; Ken Henry,Schlumberger International Coordination, Houston,Texas, USA; Martin Lüling, Schlumberger-Doll Research,Ridgefield, Connecticut, USA; Rod Nelson and FrankShray, Schlumberger Well Services, Houston, Texas, USA.
Oilfield Review
Tool TechnologyBasic LWD measurements—resistivity, neu-tron and density porosities and photoelec-tric factor—have not changed since theirintroduction (next page, below), but tooltechnology has undergone several refine-ments. These include a range of engineeringimprovements—from more robust sensordesign, to more secure mounting of connec-tors and integrated circuits. These improve-ments have led to increased tool durability.
Because the tools are contained in drillcollars, hardware takes up space inside thecollar, reducing the cross-sectional areaavailable for mud flow. This reduction inarea, and erosion of tool components by
sand and lost circulation material, meanmud flow rates are lower than in plain col-lars. However, demand for LWD measure-ments has increased in wells that requirehigher flow rates for effective hole cleaning.In response, the maximum mud flow rate forthe 61/2-in. tools was recently increasedfrom 450 to 600 gallons per minute [from28 liters/sec to 38 liters/sec]. This upgrademakes the tools practical in wells wheremud rate requirements might have pre-cluded them in the past. The upgrade wasaccomplished by redesigning internal toolparts to allocate more cross-sectional area
In this article, DWOB (Downhole Weight-on-Bit), M3(Measurement-while-drilling telemetry system), TLC(Tough Logging Conditions system), CDR (CompensatedDual Resistivity), CDN (Compensated Density Neutron)and EPT (Electromagnetic Propagation Tool) are marks ofSchlumberger.1. Modified from Hall GT: “Measurement While Drilling
Update,” First Boston Equity Research, July 31, 1991.In this report, MWD services include direction andinclination, porosity, resistivity and gamma ray mea-
nThe team that built the 8-inch CDN toolin Sugar Land, Texas, USA with (below)the 6 1/2-inch tool and its red, slide-on sta-bilizer, and (above) the 8-inch tool. Theblack plugs cover windows for the densitysource and gamma ray detectors. The 8-inch tool, because of its larger diameter,has the source and detector in the bladerather than in the tool body, which movesthem closer to the formation.
have remained the same, but evolution
best ways to use the measurements.
nMeasurementsand formationparameters fromCDR and CDN tools.
LWD ToolsCDR Tool
Parameter
Correlation
Rt
Rxo
Thin bedsInvasion
Shale volume
Porosity
Measurement/Computation
Dual resistivities (Rps and Rad)Gamma ray (total API)
Dual Resistivities
Natural gamma ray scintillationspectroscopy (Th, U, K)Computed gamma ray
Compensated neutron porosityCompensated spectral gamma-gamma density
Tool OD/Mud ratein./gal/min
61/2 / 60063/4 / 8008 / 85081/4 / 120091/2 / 1400
CDN Tool
Lithology Density-neutron crossplotPe
Ultrasonic caliper1
61/2 / 600
63/4 / 800 (under development)
8 / 850
Rugosity,detection offree gas
1. For 63/4- and 8-in. CDN.
to mud flow, and by increasing the tooldiameter. In 1991, the outside diameter ofthe CDR (Compensated Dual Resistivity)tool was increased from 61/2 and 8 in. to63/4 and 81/4 in., respectively. The 61/2-in.CDN (Compensated Density Neutron) toolwill be replaced in the near future by a 63/4-in. version. The 63/4-in. tools permit a maxi-mum mud flow rate of 800 gal/min [50liters/sec]; the 81/4-in. tool is rated to 1200gal/min [76 liters/sec].
The most fundamental change in thenuclear tool is detector design. The first gen-eration used a combination of 3helium (He)detectors, also used in wireline tools, andGeiger-Mueller detectors. Compared toGeiger-Mueller detectors, 3He detectors,have a broader dynamic range, do not needcorrection for spurious activation, are lessaffected by borehole salinity and have betterstatistics, permitting a higher rate of penetra-tion (ROP). But they were not thought to beas rugged as Geiger-Mueller detectors. Fieldexperience proved otherwise, and since1990 the CDN tool uses 3He detectors only.Older tools are being retrofitted.
The CDN tool has a 7.5-curie 241ameri-cium-beryllium neutron source and a 1.7-curie 137cesium density source, both con-nected to a source retrieval assembly. In thefirst version of the tool, the sources andretrieval head were connected with a flexi-ble steel cable. This has been replaced witha flexible titanium rod, giving more reliableretrieval and more accurate placement of
the sources. Also improved is the densitydetector shielding, which eliminates sensi-tivity to spurious signals from the mud.
The CDN tool uses a full-gauge stabilizerwith windows cut in the blades in front ofthe density source and gamma ray detectors(top). When the hole is in gauge, the blades
surements and charges for real-time data transmission.
wipe away mud from in front of the sensors,thereby minimizing borehole effects. Alocking mechanism is being retrofitted onthe stabilizer to increase its resistance toslippage under high torque and jarring. Newstabilizers with an integrated lock are underdesign and scheduled for release next year.A range of stabilizers, including undergaugesizes, has been added for use in horizontaland deviated holes.
6
A
B
in in7
12
17
22
12 22
Large Axis-Wireline
Large Axis-Ultrasonic
Small Axis-Wireline
Large Axis
Small Axis
Superpositionof Calipers
MWD UltrasonicCaliper
While DrillingSmall Axis-Ultrasonic
X300
X400
Dep
th, f
t
nComparison of LWD ultrasonic caliper madwireline caliper, made five days after drillingborehole has become larger with time due toAt zone B, the discrepancy between LWD anments is due to mudcake buildup in front of
A significant development in nucleartechnology was the introduction in 1991 ofthe 8-in. CDN tool, and, in the near future,of a 63/4-in. version. Other than being ableto operate in holes up to 123/4-in., the 8-in.tool has several features that distinguish itfrom the 61/2-in. tool. In the 8-in. tool, neu-tron and density detectors are both in stabi-lizer blades rather than in the tool body, asin the smaller tools. This design is preferred
in12 22
Large Axis
Small Axis
Wireline Four-ArmCaliper 5 Days
After Drilling
X3
X4
X5
X6
X7
ROP
150 0ft/hr
e while drilling and. At zone A, the sloughing shales.
d wireline measure-the permeable zone.
nA gas detection log mditions, using the ultrasics (next page). The ultblades of LWD tools. It rubber window of simi
in the larger tool because locating the detec-tors in the tool body would have placedthem too far from the formation and therebydegraded the measurement. The 8-inch toolalso includes an ultrasonic caliper (see“Unocal, Indonesia,” page 21).2 The 63/4-in.version will have new electronics toincrease the number of measurements perfoot by a factor of four and will also have anultrasonic caliper.
Oilfield Review
Mea
sure
d de
pth,
ft
LWD UltrasonicCaliper
While Drilling
00
00
00
00
00
Large Axisin Gas Indicator
0 750
8 18
gal/min
Flow In
0 25units
Baseline-no gas
Bit entersgas-
producingfracture
zone
Sensors pass
below gas-producing
zone
Gas-producing
fracture zones
ade while drilling in underbalance con-onic caliper (above), and caliper schemat-rasonic sensor is mounted in stabilizertransmits a pulse that passes through alar acoustic impedance to that of mud.
2. Orban JJ, Dennison MS, Jorion BM and Mayes JC:“New Ultrasonic Caliper for MWD Operations,”paper SPE/IADC 21947, presented at the SPE/IADCDrilling Conference, Amsterdam, The Netherlands,March 11-14, 1991.
3. Rewcastle SC and Burgess TM: “Downhole ShockMeasurements Increase Drilling Efficiency andImprove MWD Reliability,” paper IADC/SPE 23890,presented at the IADC/SPE Drilling Conference, NewOrleans, Louisiana, USA, February 18-21, 1992.
4. A g, for gravity, is a unit of force equal to the force ofgravity exerted on a body at rest. It is used to indicatethe force to which a body is subjected when acceler-ated. For example, 25g is 25 times the force exertedon the body as when it is at rest.
Two ultrasonic sensors are mounted 180°apart on stabilizer blades. The sensors func-tion in a pulse-echo mode that allows thedirect measurement of standoff, from whichshort and long axes of the borehole diame-ter are computed. The vertical resolution is1 in. [25 mm] and accuracy of the diametermeasurement is ± 0.1 in. [2.5 mm]. Thecaliper is used to correct the density andneutron porosity measurements for boreholeeffects and can be used as a borehole stabil-ity indicator (previous page, left). It can alsobe used for downhole detection of freegas—gas bubbles, not dissolved gas—through a combination of formation and“faceplate” echo signals (below and previ-ous page, right). The faceplate echo is mea-sured at the surface of the tool, at themud/window interface. It is affected by gascontent in mud, with echo amplitudeincreasing with gas content. The smallestamount of detectable gas is less than 3%volume of free gas. Real-time transmissionof this information can shorten the timeneeded to detect gas influxes while drilling.This can simplify kill operations.
Memory of the CDN and CDR tools wasdoubled to 1 megabyte in 1991, and withthe introduction of Anadrill’s second-genera-aaa
July 1992aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaa aaaaMWD
Ultras
LWD toolwith ultra-sonic sensorin stabilizer A
mpl
itude
When gas bubbles are present in the mud, thless than that of the mud. Much of the pulse athe mud/window interface. When no gas bubthrough the window with no reflection, and agenerating a formation echo of higher amplit
tion MWD/telemetry system in 1991, down-link to the tools can be established whilethey are in the hole. Previously, tool opera-tion—such as data sampling rate—had to bepreset at the surface and was not adjustableonce the tool was downhole. The downlinkcapability permits, for example, the operatorto use one CDR sample rate during drillingand switch to a higher rate while trippingout, or to turn sampling off in front of casing,thereby saving memory. The current genera-tion mud telemetry system permits transmis-sion of data at up to 3 bits/sec.
Another advance is the introduction of adownhole shock measurement transmittedto surface. This measurement enhancesselection of the bottomhole assembly (BHA)and drilling parameters, and may increasesurvival of MWD/LWD tools. Many failuresof MWD/LWD tools result from high shockand vibration produced during drilling. Lat-eral vibration contains the most energy anddoes the most damage to downhole tools,the drillstring and drill bits. Traditionally,engineers predicted a rough running drillingenvironment from surface torque measure-ment and modeling of drillstring dynamics.But this is not a direct shock measurementand therefore does not properly account for
aaaaaaaaaaaaaaaaaaaaaaMud/formationinterfaceMud/window
interface
Window echo
Window
Mud Formation
Firingpulse
Formationecho
Formationecho
Firingpulse
sonicensor
Mudinterfaceecho
Time after firing
Clean mud, no gas Mud with gas
e acoustic impedance of the window ismplitude is therefore lost on the echo atbles are present, the pulse passes
stronger pulse reaches the formation,ude than the faceplate echo.
all causes of vibration and for frictional lossbetween the surface and BHA. Now thedriller can see the downhole environment inreal time and adjust rotary speed, weight-on-bit and flow rate to eliminate or reduceshocks. The drilling engineer can also usethis information to design BHAs less proneto vibration.
Anadrill’s downhole measurement ofshock is made by an accelerometer near thetelemetry electronics, 20 to 50 ft [6 to 15 m]above the bit.3 At a given time interval, typi-cally 60 seconds, the cumulative number ofshocks exceeding 25g4 is reported to thesurface (next page). This 25-g value is con-sidered the optimal limit for alerting thedriller to possible mechanical failure.
7
aa
5. Allen D, Auzerais F, Dussan E, Goode P, Ramakrish-nan TS, Schwartz L, Wilkinson D, Fordham E, Ham-mond P, Williams R: “Invasion Revisited,” OilfieldReview 3, no. 3 (July 1991): 10-23.
6. Shray F: “LWD Detects Changes in Formation Param-eters Over Time,” Petroleum Engineer International64, 4 (April 1992): 24-32.
LWD/Wireline ComparisonsIn the three years since LWD technologybecame available, the industry has foundfive main applications for these tools:•Insurance logging, in case the well is lost,
can’t be logged with wireline tools or willyield poor-quality wireline logs.
•Logging before invasion, which mayreveal hydrocarbon zones that might bemissed by wireline time.5 In some high-permeability formations, borehole fluiddisplaces hydrocarbon from the near-wellbore rock, making the well look like adry hole by the time of wireline logging.This effect may be more common in hori-zontal than vertical wells because thedrainhole is exposed to full hydrostaticmud pressure for the long period requiredto drill the lateral section.
•Geosteering and enhancement of drillingefficiency (discussed below).
•Savings in rig time in settings requiring theTLC (Tough Logging Conditions) systemand offshore.
•Multiple pass logging. Comparison logsmade at different times can help distin-guish pay from water zones, locate fluidcontacts and identify true formation resis-tivity and density.6
Tom Walsgrove of Amoco UK, who isresponsible for introducing new technologyto the company’s North Sea operations, hasdone a cost-benefit analysis of LWD vs.wireline logging that has wide application.He finds that LWD has a clear cost advan-tage when well deviation is 60° or more. Atthis deviation, triple combo wireline toolsrequire conveyance by drillpipe with theTLC system. But LWD can be beneficial inother settings that are not so easily identi-fied. It is for this gray area that Walsgrovehas developed general criteria to helpchoose between wireline and LWD forbasic formation evaluation.He has found LWD cost-effective when:•Rig cost is high. Rig cost high enough to
make LWD attractive exists almost entirelyoffshore and where time-consuming TLClogging would be required. Most of theadditional expense of a TLC operation is inrig costs, which run about $5000/hour inthe North Sea. Amoco is looking toMWD/LWD as a means to cut this cost.Use of LWD may also accelerate selectionof coring and casing points and perfora-tion intervals, which can contribute to sav-ings in rig time.
•Water-base muds are used. These typicallyyield poorer borehole conditions by wire-line time than oil-base mud (OBM). Wire-line tools may therefore be difficult to get
200
300
Start of 171/2-in.hole
400
95 RPM
120 RPM
Run
#1
Run
#2
ROP
SWOB
Surface Torque
Downhole Shock
RPM
sec-1kNm
m/hr
1000 kg20
75 0
0 0 20 0
50 150
150Average
Maximum
Minimum
340
368
Dep
th, m
nRelationship between shock levels measured downhole, and rotary speed in a NorthSea well. Shock increases with increasing rotary speed and as stabilizers pass changesin borehole diameter. In run #2, a pendulum assembly—with stablilizers only high inthe BHA in order to drop hole angle—was run with low weight-on-bit to control holeangle. This resulted in greater vibration of the BHA and failure of the MWD transmis-sion. High shocks below 340 meters corresponded to the stabilizers passing from the 24-in. rathole to the 17 1/2-in. hole. At this point, surface torque also increased, indicatingincreased drag from the stabilizers. Rotary speed was reduced at about 347 m inresponse to the shock levels, and 95 rpm maintained minimum shock. At 368 m, thedriller, constrained to maintain verticality, increased rotary speed to 120 rpm andshocks rose to 120 sec -1.
8 Oilfield Review
7. The intergovernment treaty organization that governsdumping in the North Sea, the Paris Commission, isexpected to pass a ruling that 1% to 2% oil on cut-tings is not a significant environmental hazard. Thiswill then be ratified by the Commission ministers andcome into force in January 1994. This would representthe minimum standard to be enforced by signatorycountries.
nWhat can happen when CDR resistivity is not transmitted in real time. CDR data wereacquired in memory mode only, since the data stream to the surface was confined todrilling optimization information. In this case, the memory logs (gamma ray, resistivityand density) showed the well trajectory went into the top of the pay zone at point A,only to go back out through the top of the pay zone at point B. The pay zone here wasmore than 10 feet [3 m] thick but the drill bit crossed only the top 10 feet. (Adapted fromWhite, and Hansen and White, reference 9.)
aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aHorizontal distance, ft
Poor sand
Thin shale
Mainreservoir
Gam
ma
Ray
CD
R R
esis
tivity
, sha
llow
CD
ND
ensi
ty
True
ver
tical
dep
th, f
t
100 800X50
X75
200 500
0.530
GA
PI
ohm
-mA
B
9July 1992
down the hole, may get stuck or yieldpoor logs. In the UK sector of the NorthSea, as OBM use continues declining forenvironmental reasons, Amoco expectsLWD use to increase. Use of OBM isbanned in exploration wells in Norwayand the Netherlands. The UK is expectedto enact other restrictions by 1994.7
•The well is in an area known for opera-tional difficulties—swelling shales or,most commonly in the North Sea, over-pressured zones. Under these conditions,LWD offers the advantage of insurancelogging. But more importantly, real-timedata can accelerate decisions about wellcontrol and how the well should bedrilled and completed. Amoco finds thatreal-time data provide “an effective meansof minimizing risk and reducing excessiveoperating costs” in exploration wells.Most of this savings is related to savings inrig time. To illustrate this point, Walsgrovecites an instance in which LWD reducedoperating costs by allowing more accu-rate location of coring points within asand/shale sequence.
“From our work on other wells in thisarea,” Walsgrove said, “I knew it washighly probable that the first core wouldbe mostly shale with only minor sandstringers. But with MWD/LWD we wereable to pick the coring point at the top ofa thick sand unit. We saved ourselves thecost of cutting that wasted core, whichtypically takes a day—about $120,000.”
In another instance, the company spentseveral days drilling a rathole in base-ment, including cutting a terminal corethat would confirm that the well was inbasement before logging. If real-timegamma ray and resistivity logs had beenused, the data would have indicated base-ment quickly, saving days of drilling.
•When real-time access to pore pressureanalysis (in undercompacted formations)and petrophysical data are needed fordrilling decisions and planning a wirelinelogging program and completion strategy.
Real-time access to petrophysical datahas led to a new application, calledgeosteering—using real-time measure-ment of geologic and reservoir parametersto help steer the bit along highly deviatedand horizontal trajectories. These parame-ters are added to conventional steeringdata—direction and inclination—and dataabout the shape and extent of geologicstructures, mainly from seismic profiles.The usual goal is to keep the well within aparticular bed or maintain an appropriatedistance from a bed boundary or fluidinterface (right, above and top).
Horiz. distance, ft
Sta
ndar
d D
ensi
ty
Den
sity
ØN
Nor
mal
ized
Sho
rt-S
paci
ngVa
rianc
e
p.u.
g/cm
3
30
0
2.2
2.7
0
4
X700 X800 X900 X1000 X1100 X1200
nDetails of CDN logs for the same well as above. The normalized short-spacing vari-ance is not a regular product but used here to compute the rotational density output.
When geosteering was introduced, theCDR resistivity log was used for detectinghydrocarbons and the gamma ray log forfinding marker beds and kick off points.Because the CDR measurement has higherresolution and precision than the typicalMWD short-normal resistivity measurement,thin beds can be more easily identified. It isalso more sensitive to boundaries betweenbeds of contrasting resistivity—indicated ina deviated well by the characteristic peakon the log curve, called a horn—and has agreater depth of investigation (see “Why aHorn?” below).
Although resistivity remains the mainheadlight, a handful of operators haverecently examined CDN density logs to seeif they can contribute to geosteering (previ-ous page, below). However, the CDN tool isalways farther from the bit than the resistiv-ity measurement so its contribution to steer-ing may be as a confirmation of gamma rayand resistivity logs.
The measurement suite for geosteeringmay be the same as for formation evaluation(see “MWD/LWD Data Frames, next page).The suite typically includes resistivity,gamma ray, short- and long-spacing densityand neutron porosity, downhole torque anddownhole weight-on-bit to determine for-mation properties at the bit—with the addi-tion of tool face, or direction and inclination(D&I). This tells the driller the orientation ofthe bent housing.8 Tool face is needed at ahigh update rate—typically, every 10 sec-onds but as fast as every few seconds isdesirable for accurate steering with poly-crystalline diamond compact bits. Withthese bits, more reactive torque is generatedat the motor, making them go off coursesooner than conventional bits. If a highupdate rate for tool face is used, the updaterate on other data drops. The lower ratereduces resolution of petrophysical data, butnot usually to a significant degree.
Walsgrove’s analysis indicates that wire-line measurements are advantageous when:•Equity decisions are a concern. Because
wireline measurements remain theaccepted standard, both from technicaland legal standpoints, partners may shyaway from relying only on LWD measure-ments when there is a possible equitydebate. Some operators view LWD as lessdesirable in equity decisions because ofthe need to depth match it with wireline.Depth matching LWD to wireline is oftenstraightforward, but may be complicatedwhen invasion or borehole conditionscause large differences between LWD andwireline logs, or when driller’s depthvaries nonsystematically with wirelinedepth. This can happen because of pipestretch, compression or yo-yoing, or mis-counted pipe stands. Absolute depth cor-rection of LWD logs is sometimes doneusing a gamma ray from the cement bondlog when casing is set—usually one tothree days after LWD logging. This delayin absolute depth correction does not stalldrilling-related decisions based on LWDinformation. The relative depths of fea-tures on the LWD log are used to refer-ence formation tester sample, core andcasing points.
•High temperatures (greater than 320°F[160°C]) are encountered. Wireline toolstypically have a higher temperature ratingthan LWD tools, which are limited mainlyby their use of batteries.
•Hole size is very large. The current maxi-mum hole size for the CDN tool is 133/4in. [35 centimeters (cm)], and for theCDR tool is 171/2 in. [44 cm]; or 26 in.[66 cm] if mud is made with freshwater(1.5 ohm-m).
Other variables may complicate the choicebetween wireline and LWD. Amoco did acost analysis for two wells in which bothwireline and LWD services were run. In one
well, discounting rig time, LWD cost 241%more than wireline. In this instance, thelarge difference was due to LWD tools sit-ting on the rig unused for 21 days becauseof unanticipated problems setting casing. IfLWD had been run promptly, its cost wouldhave been 100% more than wireline.
In the second well, LWD logs were madepromptly. Although the LWD cost wasslightly higher than wireline, when rig costwas added, LWD afforded a net saving. TheLWD service was less expensive than in thefirst case because the operator needed onlythree days to mobilize and demobilize thetools, which were on a nearby rig.
Taking cost analysis one step further,Amoco modeled typical North Sea wells todetermine the most cost-effective triplecombo logging program. Wireline wasmarginally less expensive in the first exam-ple, which had:•straight hole•casing set at 8000 ft [2440 m] and average
ROP of 30 ft/hour [10 m/hr] to reach totaldepth (TD) at 10,000 ft [3050 m]
•two days each to mobilize and demobilizethe tools
•total rig operating cost of $120,000/day.The second model was identical, except thewell was deviated to 45° at 4000 ft [1220m]. Although TD and the casing point werethe same true vertical depth (TVD) asbefore, the openhole footage and total mea-sured depth increased. Again, wirelineoffered a marginal savings. But when welldeviation reached 70°, rig time associatedwith wireline cost exceeded LWD costbecause TLC hardware would be needed toconvey wireline tools. Financial analysis byanother major oil company shows that lost-in-hole cost is always more expensive withLWD than with TLC methods, but that riskof losing the tools is lower with LWD thanwith the TLC system.
10 Oilfield Review
Why a Horn?
A polarization horn on a CDR log in a horizontal
well indicates the tool is crossing a bed bound-
ary. This horn occurs because of charge buildup
at bed boundaries. Because this charge is caused
by the signal from the logging tool, it therefore
oscillates at the same frequency, acting like a
secondary, weak transmitter along the bed
boundary. This effect doesn’t occur in a vertical
well, where bed boundaries are horizontal and
parallel to the current loops generated by the
tool. In this setting, the current loops do not cross
interfaces between formations of contrasting
resistivities and no secondary field is generated.
But in a horizontal well, as the tool moves along
the bed boundary, the current loops pass from
one formation into another, generating a substan-
tial secondary field. At each bed boundary, the
received signal increases, producing the charac-
teristic polarization horns. The magnitude of this
polarization increases with the relative dip angle
and the resistivity contrast between the beds.
11July 1992
Data Transmission: Real Time orRecorded?Combined improvements in MWD teleme-try and LWD technology now permit real-time transmission of any LWD data. But notall data can be sent at once, so a majordecision is what data to send in real timeand what to store downhole for retrievalwhen the BHA reaches the surface (see “ASecond-Generation MWD/Telemetry Sys-tem,” page 13). In the future, through-drillpipe wireline systems will be availableto unload tool memory downhole.
The selection of real-time or downholememory mode depends on the application,and may change from section to section,even in a single well. While real-time datahelp with drilling decisions, the more datasent uphole, the slower the update rate ofeach measurement, so the lower the resolu-tion. The proper balance between real-timeand recorded modes involves determiningnot only what data are needed when, butwhat data quality is needed. The goal is toget the right data at the right time.
The recorded-only mode is commonlyused in formation evaluation for reservoircharacterization in development wells. Real-time data are used mainly in formation eval-uation for well management decisions, suchas whether to run wireline logs and, if so,which ones; where to core and set casing;and when to plug the well, to adjust hole tra-jectory or mud weight, drill deeper or stopdrilling. A typical real-time suite consists ofdirectional surveys, resistivity measurements(resistivity from attenuation—deep, Rad andresistivity from phase shift—shallow, Rps ),gamma ray, short- and long-spacing den-sity, neutron porosity, downhole torque anddownhole weight-on-bit (right ). Most ofthese data are updated every 26.5 seconds,equivalent to a 6-in. [15-cm] sample rate atan ROP of 70 ft/hour [21 m/hr]. In practice,twice the ROP—140 ft/hour [43 m/hr]—gives 12-in. [30-cm] sampling, sufficient formost real-time formation evaluation.
Amoco UK bases its selection of recordedvs. real-time data on comparison of datacost and quality. In exploration wells, thecompany usually transmits the CDR log inreal time to improve drilling efficiency. Indevelopment wells, the company usuallyacquires LWD logs only in recorded mode.This reduces logging cost as a result of nothaving to run an MWD tool for directionand inclination data.
8. There are two tool face measurements. Magnetic toolface is in reference to magnetic north. Gravity toolface is in reference to the high side of the hole.
Typical Formation Evaluation Setup
DownholeMeasurement
MWD sync
Rps
Rad
LWD GR
SS density
LS density
TN porosity
DTRQ
DWOB
Rps
Rad
LWD GR
SS density
LS density
TN porosity
VALT
Rps 26.5
26.5
26.5
26.5
26.5
26.5
53
53
53
68
68
68
68
68
68
34
34
34
Rad
LWD GR
SS density
LS density
TN porosity
DTRQ
DWOB
VALT
TransmittedData
Update frequency(sec)
Equivalent ROP at two data points/ft
Typical Geosteering Setup
DownholeMeasurement
T/F sync
GY [T/F]
Rps
Rad
GZ [T/F]
SS density
LS density
GY [T/F]
TN porosity
LWD GR
GZ [T/F]
DTRQ
DWOB
GY [T/F]
VALT
GZ [T/F]
Gravity T/F 10.6
53
53
53
53
53
53
53
53
53
170
34
34
34
34
34
34
34
34
34
Rps
Rad
LWD GR
SS density
LS density
TN porosity
DTRQ
DWOB
VALT
TransmittedData
Update frequency(sec)
Equivalent ROP at two data points/ft
DTRQ: downhole torque; VALT: MWD turbine voltage output, which is proportional to mud flow, so VALT acts as a downhole flowmeter; T/F sync: a number identifying the sequence of measurement to be transmitted; GY and GZ (T/F) are values of theaccelerometer measurements along the Y and Z axes; the tool is the X axis. GY and GZ are used to compute the orientation ofthe bent sub with reference to the high side of the hole. The DWOB measurement is downhole weight-on-bit. Many downholemeasurements appear more than once in the left column, indicating that they are sent more than once per data frame.
MWD/LWD Data Frames
nSample data frames from the North Sea, used for formation evaluation and geosteering.
The application of LWD in North Seadevelopment wells is unique, having to dowith how they are drilled. Many operatorsuse MWD directional and gamma ray infor-mation to position the 95/8-in. [25-cm] cas-ing just above the target. Some also use theCDR resistivity for this task. Casing is setand the hole drilled out with a “locked”BHA, in which stabilizers are arranged tominimize drift of the borehole. From thispoint, MWD is not used because the drillerhas to drill a straight hole a short distanceand can’t miss the target. Once in the target,LWD measurements are used in memorymode to log the reservoir.
12 Oilfield Review
Mainreservoir
GammaRay
LoggedPhase
Resistivity
Rt Input forComputer
Model
SimulatedPhase
Resistivity
Poorsand
Thinshale
Dep
th, m
GAPI ohm-m ohm-m0 100 2 2000 2 2000
x100
x200
x300
x400
x500
nResistivity modeling of the uppermostresistivity horn shown on page 9, top.Here, formation dip, bed boundaries andresistivities were estimated from the geo-logic model and used to develop a modelof Rt and a synthetic resistivity log. Themodel is confirmed because the syntheticlog nearly matches the measured log.This modeling was done because of a dis-parity between nuclear and resistivitylogs. On page 9 (top figure), the densityand gamma ray logs show that the zonebetween the two peaks appears to be ashale. But the resistivity log does not showthe low value normally associated withshales in this area. Because the shale isthin (about 2 ft [60 cm]), it is possible thatthe large volume of rock investigated bythe CDR tool prevented it from seeing theshale. This presented an ideal opportunityto run a resistivity simulation across thiszone. The square log of Rt successfullysimulated the measured log, reinforcingthe model of the formation as a shalewith significant lateral extent. (Adaptedfrom Hansen and White, reference 9.)
aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaA B
A B
A B
A B
Shaleaa Main reservoiraa Poor sand
Deepresistivity
Mea
sure
d de
pth,
ft
ohm-m1 10
100
0
200
300
400
A
B
nFour possibleinterpretations fora deep resistivityresponse in a hori-zontal well. Morelog data areneeded to con-strain the geologicmodel. There areno horns becausethe deep resistivitymeasurementtends not to showhorns and becausethe resistivity con-trast between bedsis small. (FromWhite, reference 9.)
9. White J: “Recent North Sea Experience in FormationEvaluation of Horizontal Wells,” paper SPE 23114,presented at the SPE Offshore Europe Conference,Aberdeen, Scotland, September 3-6, 1991.Hansen RR and White J: “Features of Logging-While-Drilling (LWD) in Horizontal Wells,” paper SPE 21989,presented at the SPE/IADC Drilling Conference, Ams-terdam, The Netherlands, March 11-14, 1991.
10. Leake J and Shray F: “Logging While Drilling KeepsHorizontal Well on Small Target,” Oil & Gas Journal89, no. 38 (September 23, 1991): 53-59. The samephysics, but for induction logging is detailed in KleinJD: “Induction Log Anisotropy Corrections,” Trans-actions of the SPWLA 32nd Annual Logging Sympo-
11. CDRDIP is now a module in ELMOD. For back-ground:Anderson B, Bonner S, Lüling MG and Rosthal R:“Response of 2-MHz LWD Resistivity and WirelineInduction Tools in Dipping Beds and Laminated For-mations,” Transactions of the SPWLA 31st AnnualLogging Symposium, Lafayette, Louisiana, USA, June24-27, 1990, paper A.Anderson B, Barber TD, Singer J, and Broussard T:“ELMOD—Putting Electromagnetic Modeling toWork to Improve Resistivity Log Interpretation,”Transactions of the SPWLA 30th Annual LoggingSymposium, Denver, Colorado, USA, June 11-14,1989, paper M.
A Second-Generation MWD/Telemetry System
Data Processing AdvancesMost data processing routines for logs weredesigned for low-angle holes, typically lessthan 40°. Assumptions in the verticalwell—azimuthal symmetry of formationsand invasion around the borehole, no lat-eral variation in formation properties, andformations becoming older and deeper withmeasured depth—break down for direc-tional and horizontal wells.9 The increasinguse of LWD in horizontal and highly devi-ated holes has stimulated progress in theprocessing of LWD log data.In directional and horizontal wells, dataprocessing and interpretation is a two-stepprocess. The first step, while the well isdrilled, is to determine whether, when andwhere the well trajectory enters the geologictarget and whether it stays there. This isdone by monitoring formation evaluationinformation—cores, cuttings, MWD andLWD data—as the well is drilled, and then,modifying the well path as needed. The sec-ond step, which takes place after the well isdrilled, is detailed appraisal of formationparameters for reservoir evaluation, wellcompletion and field development. To meetthese needs, and interpretation needs inconventional wells, several new data pro-cessing methods for LWD have been devel-oped. These include:•Prediction of CDR resistivity in high-angle
and horizontal holes with varying relativedip between the borehole and beds, usingthe RangDB program (“rang dee bee,” forrelative angles data base)
•Real-time phase-resistivity caliper andborehole correction to phase and attenua-tion measurements
•Correction of the CDR measurements forthe effect of resistivity anisotropy10
•Correction of the density measurement toaccount for elliptical holes.
Prediction of CDR resistivity in high-angleholes with varying relative dip. An objectiveof interpreting CDR logs in high-angle wellsis to build up a model of the formation sur-rounding the borehole. This interpretationmust be made with care because there maybe insufficient data to develop a unique geo-logic scenario (previous page, left). Simula-tion of CDR logs may help clarify this pro-cess (see “Electromagnetic Tool Modeling,”page 22). Often, CDR response in a horizon-tal well can be predicted before drilling. Thismay be critical for identifying log signaturesthat show when a drill bit is entering or leav-ing a target. This prediction of CDR responsein a well with constant, unchanging relative
July 1992
dip is achieved by using the CDRDIP mod-ule in the electromagnetic modeling pack-age, ELMOD11 (previous page, right). Butwhat about the typical high-angle well,where the well inclination changes continu-ously?
For this, a second-generation modelingprogram has been developed, RangDB. Thisprediction has several steps. The first step, aswith any simulation, uses local knowledgeand offset well data to provide a simple, lay-
sium, June 16-19, 1991, Midland, Texas, USA, paper T.“Formation Anisotropy: Reckoning with its Effects,”Oilfield Review 2, no. 1 (January 1990): 16-23.
ered model of the geology. This model isverified using ELMOD data to simulate theresistivity curve from the offset well.
The second step uses this model as inputto several runs of CDRDIP at differentangles (next page, left). The angles are cho-sen to represent the range of dips likely tobe encountered along the trajectory.RangDB then computes values of phase shiftand attenuation resistivities versus TVDinterpolated at 1° deviation steps between
In 1991, Anadrill introduced a second-generation
MWD telemetry system, which is used to convey
MWD and LWD measurements. The new system,
called the M3 MWD Telemetry tool (M for MWD; 3
for 3 bits/second), includes several notable
departures from the first-generation system. Here
are some highlights.
• A mud pulse modulator that resists jamming.
At the heart of mud pulse telemetry is a down-
hole modulator that generates pressure pulses
in the mud. It is placed in the path of the mud
flow and opens and closes to generate pres-
sure pulses. The first-generation modulator
was occasionally jammed by debris and lost
circulation material. The new modulator has
better resistance to jamming because it is self-
cleaning and has lower drag. It performs suc-
cessfully in muds having up to 40 lb/barrel of
loss circulation material.
• Reduction in transmission data error rate by an
order of magnitude. This was accomplished
two ways. The new modulator permits a higher
signal-to-noise ratio, and introduction of a
downhole microprocessor allows finding and
correcting errors in the data stream. After error
correction, the received data contain less than
1 bit error per 1000 bits—an error rate of 0.1%.
• Data compression. The data transmission rate
of the M3 system is 3 bits/sec. However, the
downhole microprocessor makes it possible to
minimize the number of bits in the data stream,
which increases the update rate while keeping
sufficient resolution. This minimization yields
an effective transmission 30% faster than the
first-generation system.
• Reprogramming while downhole. MWD tools no
longer have to be reprogrammed on the sur-
face only. Using surface-to-downhole commu-
nication, achieved by varying mud flow rate,
the engineer can reprogram data transmission
speed, vary in real time which data are
recorded, alter the sample rate and vary the
rate at which data are sent uphole in real time.
• New electronics packaging. The hand-wired
electronics of the first-generation system has
been redesigned using proven LWD technology.
This has resulted in significant improvement in
reliability.
13
Data Services Catalog. Houston, Texas, USA:Schlumberger Educational Services, 1990: 105-106.
True bed thickness, ft
6350 6390 6430 6470 6510
Ohm
-m1000
100
10
1
1
1
1
RelativeDip
85°
75°
45°
0°
RpsRad
nResistivity logs forbeds dipping 0° to85°, showingdevelopment ofhorns as a bedboundary is crossedat increasinglyshallow angles.The 0° example isa modeled CDRlog, based on aninduction log in avertical well. Theothers are modeledCDR logs using theCDRDIP program.These logs showthat variation indip angle, evenwhen adjusting fortrue bed thickness,gives logs of differ-ent character.Comparing curvesat the 4-ohm-m ref-erence line showsthat resistivitycreeps upwardwith increasing dip angle.
14
12 1/4 in.
26
22
18
14
10
Bor
ehol
e di
amet
er, i
n.
50 100 150 200 250 300 350
Depth, ft
LWD phase caliperFour-arm wireline caliper
the chosen dips. These resistivity values areentered in a data base, which allows fast pre-diction of resistivity log response for changesin well deviation or formation dip at anypoint in the well. In the near future, the pro-gram will then take the computed resistivityvalues and, in conjunction with real-timewell directional data, produce a provisional,simulated CDR log along the actual trajec-tory. During drilling, these models can becompared with the real-time CDR resistivitylog to determine, for example, if the bit isapproaching a calcite streak or a bed bound-ary. In particular, the log predictions give thedirectional driller enough information to cor-rect the course of the drill bit.
The RangDB program encourages cross-disciplinary communication by requiringcooperation from the geologist/petrophysi-cist and directional driller when planning adirectional well (next page, left ). Becausethe program integrates the well plan fromthe drilling department with formation topsand dips from the geology department, ittests whether the two are synchronized.
The program also runs at the wellsite,using the actual well trajectory to help mod-ify the trajectory in real time. This is doneby determining whether a differencebetween the modeled and measured CDRlog is due to the trajectory not going asplanned, or the formation depth or dipdiverging from the model.
nComparison ofphase and wirelinecalipers. At a fewplaces—140 to 170feet, 240 and 430feet—the caliperwhile drillingreports a largervalue than thewireline reading,perhaps due toswelling shales.The phase caliperat 60 ft readsbetween the twowireline valuesbecause it reportsan average bore-hole size. Limita-tions of the phasecaliper’s verticalresolution cause itto miss some of thethinner sands. Notethat the shales arealmost uniformlywashed out to 17in. [43 cm]. (From Rosthal et al,reference 12.)
Oilfield Review
-bit size
400 450
12. Rosthal RA, Best DL and Clark B: “Borehole CaliperWhile Drilling From a 2-MHz Propagation Tool andBorehole Effects Correction,” paper SPE 22707, pre-sented at the 68th SPE Annual Technical Conferenceand Exhibition, Dallas, Texas, USA, October 6-9, 1991.
Resistivity caliper and borehole correction.The phase caliper is computed from the rawphases of a 2-MHz electromagnetic wavemeasured at two receivers and from thephase shift between the receivers.12 The rawphase is strongly dependent on mud resistiv-ity and borehole size, whereas the phaseshift is only slightly affected. Since mud con-ductivity is known, the measurement can beused to calculate large changes in boreholediameter from bit size in conductive muds(previous page, bottom). This caliper can beused to monitor borehole stability duringdrilling or tripping. Calculation of the phasecaliper does not require special equipmentand does not compromise the tool’s standardmeasurements. Mud, however, must be atleast 1 siemens/m (S/m) [1 mho/m] more
CDR modeling for curved traject
Modeledlog #1
Modeledlog #2
Modeledlog #3
We
6500
7000
6000
5500
0
TVD
, ft
Anticipated Geologic Model
ELMOD(CDRDIP)
0
-40
-80
40
80
Dep
th, f
t
Well traject
Well traject
Well traject
Modeling of CDR logs at various
deviations from 0° to 90°
Formationdip andhorizon
TVD
Resistivity, ohm-m
•TVD•Relative dip between borehole and beds•Electromagnetic phase shift•Electromagnetic attenuation
RangDB data base:
July 1992
nInputs for CDR resistivity modeling of varioucome from both the drilling and geology dep
conductive than the formation. Accuracy ofthe borehole diameter measurement is ±1/2in. [1.3 cm], the vertical resolution is about36 in. [91 cm], and it will work in boreholediameters up to 24 in. Because the phasecaliper works best for large variations inborehole diameter, it complements the ultra-sonic caliper, which works best where bore-hole variation is no larger than about 6 in.
The calculated borehole diameter can beused to apply a borehole correction to thetwo resistivity measurements. This correctionis needed most in large boreholes filled withvery conductive muds.
Resistivity anisotropy code. Resistivityanisotropy—different resistivity values inhorizontal and vertical directions—may pro-duce markedly different resistivity logs of the
ories
Modeledlog #4
Well trajectory
#1
Plannedllbore Trajectory
400 1200800
Horizontal offset, ft
ory #2
ory #3
ory #4
Welltrajectory#1
s well trajectoriesartments.
Shale
Sand
same bed measured in a vertical well andmeasured in a well deviated more than 70°(below). Resistivity anisotropy is typicallyseen in formations with laminations less thanabout 3 in. [8 cm] thick, with alternatinghigh and low resistivities. Induction andCDR resistivity measurements in such a for-mation will read lower in a vertical well thanin a horizontal well. The opposite is true fora laterolog resistivity measurement. A codeto handle this problem, and correct the resis-tivity measured in the deviated well, was
nCoping with resis-tivity anisotropy.Measurement ofresistivity in a ver-tical well is alwaysof the horizontalvalue, whereas ina horizontal well, itis some combina-tion of vertical andhorizontal values.In the horizontalwell, where adja-cent shales distortthe current, thevalue of horizontalresistivity is neededto compare logvalues with thoseof offset verticalwells. The resistiv-ity anisotropy codeprovides this,using CDR toolmeasurementsand relative dipangle between thehorizontal welland formations. (From Leake andShray, reference 10.)
15
nResistivity modeling showing that resistivity anisotropy explained why pay zone resis-tivity in a horizontal well was higher than expected. The model demonstrates thatinequality between horizontal and vertical resistivities could reproduce the measuredlog results. The right inset shows that anisotropy is represented by a series of thin bedsof alternating high- and low- resistivity streaks. The two models, one vertical (0°) andthe other horizontal (89°), successfully reproduced the measured log responses—4-ohm-m in the vertical well and 9 to 10 ohm-m in the horizontal well. (From Leake and Shray, reference 10.)
16
Gam
ma
Ray
True
Ver
tical
Dep
thR
ps
Rad
0
120
0
20
GA
PI
ft
0
30
ohm
-m
Rps
Rad
Rt
0 7ohm-m 0 50
0 20
ohm-m
Top
of ta
rget
Measured depth, ft 100 200 300 400 500 600
Rps
Rad
Rt
Vertical Well Horiz. Well0° apparent dip 89° apparent dip
Sand
Shale
Rad
Rps
Estimateddielectric value
Res
istiv
ity, o
hm-m
1000
100
10
1
X450 X470 X490 X510 X530 X550
Depth, ft
developed to address resistivity anisotropy ina US Gulf Coast well. It has subsequentlybeen used in wells elsewhere in the US GulfCoast, Alaska and the North Sea.10
Jack Leake of Oxy and Frank Shray andRichard Rosthal of Schlumberger, comparedthe resistivity of a pay zone measured by theCDR tool in a horizontal well with thatmeasured by the wireline induction tool in anearby vertical well. A 4-ohm-m pay zoneon the induction log from the vertical wellappeared in a horizontal well as a 9-ohm-mzone on the Rad and 15 ohm-m on the Rpsmeasurements. At first glance, the separa-tion of the deep and shallow measurementscould have been due to invasion, but closerexamination showed this was not likely.Invasion was unlikely because the well waslogged while drilling, the hole was thoughtto be in gauge and the sensors were only 30minutes behind the bit. Although invasionhas been observed under these conditions,the amount of separation seemed too greatfor that explanation. The discrepancybetween vertical and horizontal logs couldhave been caused by neighboring bedswithin 2 vertical feet of the LWD sensor, butthere was no corroborating evidence thatthey were present. This left anisotropy as theprime suspect.
Evidence for anisotropy came from theELMOD resistivity modeling program thatwas able to simulate both the wireline (ver-tical) and LWD (horizontal) logs. The modelconfigured the top 3 ft [1 m] of pay as aseries of high- and low-resistivity streaks,which represents the effects of formationanisotropy. CDR logs were simulated in thissetting in a vertical well and a horizontalwell. Although these logs do not represent aunique solution, they reproduced the fieldresults (above, left).
Existing CDR software was modified tooutput a continuous log of horizontal andvertical resistivities. Inputs are Rad, Rps andthe angle between the hole and the bed inquestion. The vertical resistivity componentis used only for the calculation, not for trueresistivity. The horizontal component corre-lated closely with that measured by theinduction log in the vertical well.
nA pronounced dielectric effect causingan anomalously high, deep attenuationmeasurement. This example is from a vol-canic rock in a North Sea well. Theexpected dielectric constant for this for-mation was about 50, whereas the actualvalue was over 500. The same effect, butnot as dramatic, has been observed inshales in the US Gulf Coast, Alaska andthe Far East.
Oilfield Review
Another advance concerns correctingCDR measurements in conventional wells(deviated less than 40°) for dielectric effects.In formations with a high dielectricconstant13—typically highly resistive rockand some shales—the Rad value is anoma-lously high. Significant elevation of Radoccurs in most shales and some volcanicrocks. The problem is evident in thickshales, where there is no invasion and noborehole effect, yet Rad exceeds Rps (previ-ous page, bottom). A log processing routinehas been developed that uses Rad and Rps tosolve for the dielectric constant and correctresistivity for dielectric effects.
The routine uses information about dielec-tric constants collected from analysis of 300rock samples worldwide, performed at
13. A dielectric constant is a measure of the ability of amaterial to store electric charge for a given appliedfield strength. A dielectric is a material having a lowelectrical conductivity compared to that of metal.Fresh water, for example, has a dielectric constant ofabout 80; quartz is 4.65. The shale dielectric con-stant varies strongly with frequency of the electro-magnetic field and with mineral content. It typically
July 1992
Res
istiv
ity R
ad, o
hm-m
Att
enua
tion,
dB
Re
0 1 2 3
5.8
5.6
5.4
5.2
5.0
4.8
4.6
εR
10050
30
20
150
ε=300
5
7
10
20
50
100 50 30 20
Schlumberger-Doll Research, Ridgefield,Connecticut, USA. A data base was thencompiled, relating dielectric constant toconductivity as a function of frequency.
The data base provides an estimate of thedielectric constant as a function of conduc-tivity at the 2-MHz frequency of the CDRtool.14 An anomalously high Rad valueresults when the actual dielectric constant islarger than the estimated value. The dielec-tric processing program for the CDR toolcomputes from the two recorded CDR resis-tivities an apparent dielectric constant andits corresponding, dielectrically correctedresistivity, Reps, for epsilon, the symbol fordielectric constant. The program does thisautomatically, but a chartbook-type versionof this correction is shown (below).
has a dielectric constant of up to 10,000 at induc-tion log frequency (10 to 40 kHz), 100 to 200 atCDR log frequency (2 MHz) and 5 to 25 at the fre-quency of the EPT (Electromagnetic PropagationTool) (1.2 GHz). Measurement of the dielectric con-stant, in the case of the EPT tool, is used to distin-guish two fluids that have the same resistivity: freshwater vs. a mixture of saltwater and oil.
14. Clark B, Lüling MG, Jundt J, Ross M and Best D: “A Dual Depth Resistivity Measurement for FEWD,”Transactions of the SPWLA 29th Annual LoggingSymposium, San Antonio, Texas, USA, June 5-8,1988, paper A.
Phase shift, deg
sistivity Rps, ohm-m
4 5 6 7 8
ad=40
ad=19
Rps=11ε ps=45
15
10
7
Dielectrically correctedresistivity=12.5
Apparent dielectricconstant=180
15 10 7
Interpretation AdvancesMany advances in LWD pertain to log inter-pretation in horizontal wells, a setting inwhich LWD commonly has economicadvantage over basic wireline measure-ments. One interpretation considerationbeing given more attention, with the grow-ing number of horizontal wells, is gravitysegregation of fluids in the invaded zone(next page, top).
An example of this was seen in a NorthSea deviated gas well logged with LWDwhile tripping three days after drilling. Therewere two CDN density outputs: bulk densityand the rotationally corrected density. Agreater rotational density than bulk densitysuggested an oval hole.15 Amoco thoughtthe greater rotational density value was not
17
nCorrection for dielectric effect on 61/2-inch CDR logs. The red curve, just belowthe top of the fan, is the estimated dielec-tric value versus resistivity, derived fromlab studies. This curve predicts, for exam-ple, that a phase shift of 5° will producean Rps of 11 ohm-m and an attenuation of5.2 dB will produce an Rad of 19 ohm-m.These correspond to estimated dielectricvalues of about εps=45 and εad=40,respectively. The intercept of these tworesistivity values, however, gives thedielectrically corrected resistivity, whichis 12.5 ohm-m. The line on which theintercept falls indicates an apparentdielectric constant of 180, four to fivetimes greater than the predicted dielec-tric constant. The dielectrically correctedresistivity always falls between the othertwo resistivities, Rad and Rps, making it arobust computation.
15. For a discussion of rotational density:Best D, Wraight P and Holenka J: “An InnovativeApproach to Correct Density Measurements WhileDrilling for Hole Size Effect,” Transactions of theSPWLA 31st Annual Logging Symposium, Lafayette,Louisiana, USA, June 24-27, 1990, paper G.Betts P, Blount C, Broman B, Clark B, Hibbard L,Louis A and Oosthoek P: “Acquiring and Interpret-ing Logs in Horizontal Wells,” Oilfield Review 2,no. 3 (July 1990): 34-51.
due to ovalization but because invadedfluid, after three days, lay on the low side ofthe hole. “Since the introduction of LWD,failure to account for density variation asso-ciated with invasion in gas-bearing reser-voirs could lead to an erroneous interpreta-tion,“ Walsgrove said. ”Now I mentallymodel what’s going on in the formationbefore I begin log analysis.”16
Amoco has progressed in its interpretationof LWD logs in deviated holes. A case inpoint is a highly deviated well that pene-trated a known oil zone, but that LWD logsindicated anomalously high water satura-tions as determined from the deep resistivity(Rad) log. The zone in question was asand/shale sequence. Close examinationshowed that the deep resistivity was beingsuppressed so much by the overlying shalesthat the sands looked wet (see “Amoco,North Sea,” page 20). This suppressioneffect was proved by modeling the forma-tion and using tool response functions topredict log response.
Advances have also been made in inter-pretation of nuclear logs. Since the intro-duction of LWD, differences have some-times been noted between wireline andLWD nuclear logs in the same well. Recentwork has shed light on two mechanisms forthis disagreement: differences in how thetools make their measurements and changesin wellbore conditions in the time betweenlogging with LWD and wireline—namely,displacement of reservoir fluid by invadingmud filtrate of a different density, chemicalalteration of shales by drilling mud andincreased rugosity.17 How these effectsinfluence the preference for wireline orCDN logs is summarized (right).
For density measurements, the main dif-ference in response to wellbore conditionsis due to the different mechanical arrange-ment of the tools. Wireline density tools usepad-mounted sources and detectors that areheld against the formation, minimizing per-turbation of the signal by mud. The CDNtool makes its measurement through a full-gauge stabilizer (the same as bit size). Aslong as the hole remains in gauge, the stabi-lizer removes virtually all mud from in frontof the sensor, yielding a reliable measure-ment. The rotational density algorithm cancorrect for a small degree of standoff—1 to2 in. [3 to 5 cm], depending on mud weight
18 Oilfield Review
WirelineHole Condition
CDN HoleCondition
Smooth andin-gauge
Smooth, in-gauge
with mudcake
Smooth andenlarged
Smooth,enlarged
with mudcake
Smoothand altered
formationdensity
Enlargedand rugose
Enlarged,rugose
and alteredformation
density
Excellentagreement
Rotationalprocessing
required
Time-lapse densityinterpretation possible
CDN density preferred Sonic porositypreferred
nComparison ofhow wellbore con-ditions affect CDNand wireline den-sity measurements.(From Allen et al, reference 17.)
and mud chemistry. Greater standoffexceeds the algorithm’s ability to furnish ausable correction.
For neutron measurements, differentdesigns of wireline and LWD tools alsocause differences in how the tools respondto wellbore conditions (next page). Thewireline neutron measurement is made froma mandrel pressed against the borehole
wall, whereas the CDN measurement ismade from a tool centered in the borehole.The borehole effect for the wireline tool isnot important compared to the mudcakeeffect. On the contrary, the borehole sizeeffect on the CDN tool is large because thetool is centered in the hole. The wirelinetool standoff effect is comparable to theCDN borehole effect in amplitude.
Filtrate heavier thanformation fluid
Limit offiltrate
invasion
Pad tool
Volume seenby pad tool
Filtrate lighter thanformation fluid
nRadial asymmetry of the invasion profile in a horizontal wellthrough a homogeneous, permeable formation. A sufficient dif-ference in the densities of the filtrate and formation fluids willcause filtrate to form a teardrop oriented either up or down. Padand mandrel tools facing the low side of the well will see a dif-ferent invasion than those facing the upper side. These asym-metric effects are time dependent as the invasion profile devel-ops. (From White, reference 9.)
nComparison of wireline and CDN density and neutron porosity logs in a vertical southTexas well drilled with fresh mud. Above and below the bar, the hole was smooth andin gauge during CDN logging. The zone marked by the bar was logged with the CDNtool during a bit trip after being open several hours. Here, the CDN ∆ρ is high, consis-tent with a 9 pounds per gallon [lbm/gal] mud weight, and DCAL is close to zero. Thiscombination of readings indicates the hole was enlarged enough to prevent the CDNtool from maintaining contact with the formation. The combination of a well-stabilizedBHA and lack of hole deviation produced this standoff. By wireline time, the caliperindicates mudcake had formed. Arrows mark rugose intervals where wireline densityreads too high. In these intervals, the CDN measurement would be preferred, while inthe zone by the bar, wireline density would be preferred. (From Allen et al, reference 17.)
19July 1992
MWD Gamma Ray
Wireline Gamma Ray
CDN ∆
Wireline ∆
0
-0.9
0
-0.9
150
0.1
150
0.1
60
0
60
0
0
10
0
10
x700
x800
Dep
th, f
t
CDN ØN
CDN ØD
CDN Rotational DCAL
Wireline ØN
Wireline ØD
Wireline DCALρ
ρ
16. Others have noted the special case of invasion in ahorizontal well. See Woodhouse R, Opstad EA andCunningham AB: “Vertical Migration of Invaded Flu-ids in Horizontal Wells,” Transactions of the SPWLA32nd Annual Logging Symposium, Midland, Texas,USA, June 16-19, 1991, paper A.
17. Allen DF, Best DL, Evans M and Holenka J: “TheEffect of Wellbore Condition on Wireline and MWDNeutron Density Logs,” paper SPE 20563, presentedat the 65th SPE Annual Technical Conference andExhibition, New Orleans, Louisiana, USA, Septem-ber 23-26, 1990.
Charles Flaum of Schlumberger in Mon-trouge, France, studied CDN density logsand helped solve a key problem in horizon-tal drilling: knowing whether a formationboundary is crossed from above or below.
Flaum examined the rotational densityoutput in a horizontal well that both enteredand exited the top of a pay sand (page 9,top). The rotational correction makes use ofthe statistical variance of the near-detectorcount rate as the tool turns in the hole. Inthis computation, a normalized statisticalvariance of 1 indicates an in-gauge hole,assuming no radial variation in density.When the hole is in gauge, further excur-sions of the variance are not caused bychanges in standoff but by the tool crossinga density boundary at a low angle. Thesedeflections may be used to determinewhether the well is approaching a densitycontrast boundary from above or below.Flaum found that in a smooth hole drilledwith undergauge stabilizers, the variancewill have a positive shift in the absence of adensity contrast boundary. If a denser forma-tion approaches from below, the variancewill increase until the boundary is passed. Ifa denser formation approaches from above,variance will decrease. The opposite effectswill be observed if the approaching forma-tion is of lower density. The density “horns”may also help identify boundaries betweenbeds that have insufficient resistivity contrastto produce horns on the resistivity log.
These advances in LWD technology andtechnique are some of the innovations beingcombined in new ways with drilling-relatedmeasurements that are more quantitative.This synergy of LWD and drilling measure-ments may take geosteering, now a newtechnique, into the realm of the common-place. This will lead to the next step, whichmight be called geodrilling—real-timemerging of petrophysical and drilling data tofind more efficient and safe ways not only toposition the bit, but also to drill the well.
—JMK
Amoco UK first decided to use LWD when a 60°
development well had reached TD and the opera-
tor could not get wireline tools downhole. The
cause of difficulty was suspected to be post-
drilling degradation of the borehole. A triple
combo LWD suite made a single trip in the well.
The logs appeared valid, except for a density dis-
crepancy—0.03 g/cm3 too high.
In a subsequent well, drilled with oil-base
mud, Amoco determined that a comparison was
required between LWD and wireline measure-
ments. The LWD-wireline comparison showed
excellent agreement. The ρb from LWD and wire-
line almost match (right). The LWD neutron
porosity, however, was lower than wireline partic-
ularly in shales because the LWD measurement,
unlike the wireline measurement, accounts for a
combination of thermal and epithermal neutrons
and here was significantly affected by epithermal
neutrons.
Examination of the LWD logs shows that the
higher vertical resolution of the CDR tool in this
conductive environment (less than 2 ohm-m),
compared to the wireline medium induction
resistivity log, improved calculation of water sat-
uration in thin sands (right). This resulted in a
lower water saturation, increasing the deter-
mined oil in place.
nHigher thin-bedresolution on theCDR log, com-pared to that of themedium induction.
nClose agreementbetween wirelineand LWD densitylogs in a North Seawell. Divergence ofneutron porosities isprobably due todifferences in thephysics of wirelineand CDN measure-ments—wirelinedensity is a purelythermal measure-ment, whereas theCDN density mea-sures a combina-tion of thermal andepithermal neutrons.
20 Oilfield Review
-3 7
6 16
CDN Pe
Wireline Pe
CDN Caliper
Wireline Caliper
in
2.10 2.60 36 6
-0.8 0.2
CDN Density
Wireline Density
CDN ØN
Wireline ØN
g/cm3
g/cm3
p.u.
Dep
th, f
t
x000
x050
x100
Wireline ∆ρ
CDN ∆ρ
x700
x750
Dep
th, f
t
0 100 0.2 20 0.2 20GAPI ohm-m ohm-m
LWDGamma Ray
WirelineGamma Ray
LWD, Rps
Wireline,Medium Induction
Wireline,Deep Induction
LWD, Rad
Amoco, North Sea
LWD Case Studies
x700
x800
Dep
th, f
tShale Indicators Wireline Resistivity Porosities
Wirelinegammaray
LWDgamma ray
Diff.caliper
Deepinduction
Mediuminduction
Wirelinedensity
CDNneutron
Wirelineneutron
Wireline Caliper
LWD Density
Wireline Density Dep
th, f
t
7100
7150
7200
7250
6 in 16 1.7 g/cm32.7
nCorrugation of the wellbore wall from turbodrilling, evidencedby oscillation of the wireline caliper. In the gas sands, LWD den-sity is higher than the wireline value because the CDN toolmade better contact with the formation.
nGas sands in Southeast Asia less affected by excavationeffect—a decrease in apparent neutron porosity—at LWD timecompared to wireline time. Farther up the well, borehole condi-tions deteriorated by wireline time, preventing good pad contactof the nuclear tool, which masked other gas sands.
Unocal, Indonesia
Unocal has drilled a series of wells with MWD/
LWD tools in offshore Kalimantan, Indonesia. A
notable gas discovery was made in the second
exploration well in the Serang field. LWD was
planned over a long section.1 The objectives were
to evaluate the CDN measurements, obtain real-
time CDR measurements for comparison with
wireline logs in a nearby well and provide early
detection and evaluation of pay zones.
21July 1992
1. Norby P and Henry K: “Logging While Drilling (LWD)Results in Indonesia,” paper OTC 6862, presented at theOffshore Technology Conference, Houston, Texas, USA,May 4-7, 1992.
Use of OBM complicated evaluation with wire-
line logs because the mud masked many pay zones
on mud logs. The real-time CDR log, however,
identified pay zones in what turned out to be a sig-
nificant gas discovery. Downloading of CDN data
confirmed the top of the gas sand had been pene-
trated (above, left). These gas sands were later
verified by formation tester sampling. These zones
could have been mistaken for oil zones because
of deep invasion at the time of wireline logging.
The CDR log was 60 minutes or less behind the
bit and the CDN log was less than 3 hours behind
the bit. The CDN differential caliper, between
tracks two and three, indicates the hole was still
in good condition at this time, with no washouts
greater than 1/2 in. But at wireline logging, five
days later, washouts went off the scale—recorded
subsequently at 16 in. [40 cm].
In the lower gas sand, above 7200 ft, the wire-
line caliper shows a slight oscillation associated
with a regular corrugated effect on the borehole
from turbodrilling (above). In this interval, the
maximum density from the CDN tool is higher due
to better contact with the formation than that of
the wireline tool.