Drilling horizontal wells presentsformidable challenges. Planning trajectories,choosing fluids, steering, formation evalua-tion and completion—each stage is a hugetask. Several stages—planning, steering andformation evaluation—benefit from combin-ing the efforts of geologists, log analysts anddirectional drillers.

A powerful partner in all these stages isforward modeling, or log simulation. Otherindustries are using simulation to help trainpilots, model aircraft and automobile relia-bility and response, design buildings, testweapons, record music, predict weather—the list is endless. In the oil field, modelinghelps make efficient use of logs in horizon-tal wells in two ways—first by predictinglogging-while-drilling (LWD) tool responseto guide directional drilling, and second by

Winter 1995

oilell. ofideheny.once tolp

assce

etsffi-es.nglls.lern-

Before drilling a horizontal well, the important question for the operator

is “How can I land the well?” Once the well is drilled, the important

questions are “Where is the well?” and “How good is the reservoir?”

e from an integrated forward modeling

nses along planned or drilled well tra-

lp interpreters evaluate the formations.

David AllenMontrouge, France

Bob DennisMuscat, Oman

John EdwardsJakarta, Indonesia

Stan FranklinJack LivingstonSouth Pacific ChevronBrisbane, Queensland, Australia

Andrew KirkwoodJim WhiteAberdeen, Scotland

Lee LehtonenMobil Exploration and ProducingNew Orleans, Louisiana, USA

Bruce LyonJeff PrillimanNew Orleans, Louisiana

Gerard SimmsAmoco Production CompanyNew Orleans, Louisiana

Modeling Logs for Horizontal Well Planning and Evaluation

1. Teel ME: “Longer Reach is Key to Future Develop-ments,” World Oil 215, no. 4 (April 1994): 27.Deskins WG, McDonald WJ and Reid TB: “SurveyShows Successes, Failures of Horizontal Wells,” Oil &Gas Journal 93, no. 25 (June 19, 1995): 39, 42-45.

For help in preparation of this article, thankBaygün, Charles Flaum, Martin Lüling and Ramamoorthy, Schlumberger-Doll ResearcConnecticut, USA; Kees Castelijns, Schlumton Product Center, Sugar Land, Texas, USAChang, Anadrill, Kuala Lumpur, Malaysia; Keerthi McIntosh and Jessie Lopez, AmocoCompany, New Orleans, Louisiana, USA; SSchlumberger Wireline & Testing, Muscat, Leong Lim, Anadrill, Jakarta, Indonesia; EdChevron, New Orleans, Louisiana; and WeAnadrill, Singapore.

IT

-sis-

-n

c-at-

The 1990s may become known in the field as the decade of the horizontal wDuring the past six years, the numberhorizontal wells drilled annually worldwhas jumped 1200%, from 250 to 3000. Treasons for this dramatic growth are maHorizontal wells can increase productirates and ultimate recovery, and can reduthe number of platforms or wells requireddevelop a reservoir. They can also heavoid water or gas breakthrough, bypenvironmentally sensitive areas and redustimulation costs.1

As exploration and development budgtighten, companies are becoming more ecient by drilling fewer, well-placed holReentry and multilateral wells are growiin number, along with short-radius weThere are greater expectations and smalmargins for error in drilling today’s horizotal wells.

Answers to these questions com

system that simulates log respo

jectories to guide drillers and he

s to BülentRaghuh, Ridgefield,berger Hous-; Huck Hui

Patricia Hall, Productioncott Jacobsen,Oman; Chin Stockhausen,ndy Tan,

In this article ADN (Azimuthal Density Neutron tool), A(Array Induction Imager Tool), ARC5 (Array ResistivityCompensated tool), ARI (Azimuthal Resistivity Imager),CDN (Compensated Density Neutron tool), CDR (Compensated Dual Resistivity tool), DIL (Dual Induction Retivity Log), DLL (Dual Laterolog Resistivity), DSI (DipoleShear Sonic Imager), FMI (Fullbore Formation MicroImager), GeoSteering, IDEAL (Integrated Drilling Evaluatioand Logging), INFORM (Integrated Forward Modeling),IPL (Integrated Porosity Lithology), ISONIC (IDEAL soniwhile-drilling tool), Litho-Density and RAB (Resistivity-the-Bit) are marks of Schlumberger.

47

modeled attenuation and phase shift curvescrossed, because the deeper-reading attenu-ation measurement senses the high-resistiv-ity calcite.

The CDR logs acquired when the wellwas drilled corroborated the modeled pre-dictions. Based on the simulations, the sig-nature of the lower boundary—the deepreading crossing over the shallow—was rec-ognized while drilling, and the well wassteered away. Had the well entered thecemented zone, drillers estimated theywould have spent several days trying to getback on target.

Geologists from Chevron Niugini areusing INFORM forward modeling to planand geosteer horizontal wells in the Iagifu-Hedinia field, within the Southern High-lands Province of Papua New Guinea.Located in the Papuan Fold and Thrust belt,this field is part of a double anticline com-plex in the Hedinia thrust sheet. The majoroil reservoir is the Lower Cretaceous Torosandstone. Within the Toro, the hydrocar-bon accumulation consists of an oil band upto 218 meters [715 ft] thick overlain by agas cap. Gas cap expansion and gravitydrainage are the major drive mechanismsfor the field, with support from the Toroaquifer making a minor contribution.

Development well planning and drillingare complicated by the complex fold geom-etry. Unfortunately, the rugged karst topog-raphy created in the Darai Limestone at sur-face prohibits the acquisition of usableseismic data.6 For predicting the subsurfacereservoir geometry, geologists rely on sur-face geological mapping, side-scan radarimagery, dipmeter data and correlation logsfrom adjacent wells.

In order to maximize productivity and ulti-mate recovery from the horizontal wells,wells are programmed to be horizontal in theToro oil reservoir at a level of 15 m [50 ft]above the oil-water contact. This enables thewells to produce oil at lower solution gas/oilratios (GORs) and should delay breakthroughfrom the advancing gas front.7

During drilling to the Toro objective, thelanding phase is critical to the success of thehorizontal well program. With an unstableAlene shale section overlying the Toro, it isimportant to minimize the amount of hori-zontal section drilled before encountering thetop Toro. Conversely, encountering the Toroduring the build section of the well course,before reaching horizontal, can result in lossof productive interval since this hole section

constraining formation evaluation when theconventional assumptions of a vertical wellno longer hold.

Directional drilling practice and technol-ogy have evolved to the point where, given agood plan, the target can be hit with highaccuracy. The drill bit can be placed within atarget the volume of an engineer’s office at adepth and lateral offset of a few miles. Trajec-tories are becoming more complex as direc-tional drillers push the technology to its limitsin “designer” wells (below).2 To improve theodds of these wells hitting the target, they arecarefully planned in two steps: definition ofthe target from maps and logs, then design ofa wellbore trajectory to hit it.

No plan, unfortunately, is foolproof.Uncertainties in the position of the target,combined with unpredictability of structuraland stratigraphic variations, even in devel-oped fields, can cause directional drillers tolose their way. The chance of going astraydeclines significantly, however, with the useof real-time formation evaluation logs andcomparison of the logs with modeled casesto gauge the position of the tool within thesequence of beds. The INFORM IntegratedForward Modeling program provides aninterface for building a formation model andsimulating log response, allowing drillers toanticipate what’s ahead. We look first atmodeling for horizontal well planning, thenexplore how the INFORM system facilitatespostdrilling visualization and formationevaluation of LWD and wireline logs in hor-izontal wells.

48 Oilfield Review

Model First, Then DrillOften the objective of drilling a horizontalwell is to penetrate the reservoir but stayclose to a caprock shale or gas-oil con-tact—to drill parallel to a boundary or acontrast in material properties—for thou-sands of feet. Such a viewing angle isunusual for electromagnetic tools, the toolsmost commonly used for steering.3 Othermeasurements, such as gamma ray and den-sity, are also affected by the horizontalgeometry, giving an asymmetric response asthey lie against the floor of the borehole.

Because most resistivity tools probe sev-eral feet into the formation, they are affectedby resistivity inhomogeneities in the vicinityof the well and even ahead of the drill bit.This early warning feature is beneficial todirectional drillers, who harness it to steerwells into target layers or away from prob-lem zones before they are encountered bythe bit. This “proximity effect” can beaccurately modeled during predrilling plan-ning to provide a road map for drilling.

In a planning example from the NorthSea, Jim White of Schlumberger Wireline &Testing in Aberdeen, Scotland, used logmodeling to demonstrate the feasibility oflanding the well in a thin sand and avoidinghigh-resistivity, calcite-cemented, tightstreaks (next page ).4 Forward modelingcomputed the response of the CDR Com-pensated Dual Resistivity tool with its twodepths of investigation—shallow from thephase shift measurement and deep from theattenuation log.5 When the wellbore cameto within 3 ft [0.9 m] of the calcite zone, the

nA “designer” well with turns in the horizontal plane.(Adapted from Teel, reference 2.)

During the planning for the first well, IHT-1, gamma ray and resistivity logs from threenearby wells were used to create a modelfor computing CDR responses for the fullrange of possible structural dip magnitudesalong potential well trajectories. Theresponses were stored in a relative angledata base. The programmed well course wasoblique to the strike of the Toro in this areaof the Iagifu anticline, and was designed tobe horizontal 15 m above the oil-water con-tact. This entry point is depth-constrained bythe predicted oil-water contact level, andlaterally constrained by the projected posi-tion of the Toro entry point, determined byprojecting the Toro structural dip away fromwell control points higher on the anticlinalflank. The kick-off depth and deviation

model of the stratigraphic interval above thetarget can be built using well logs and dip-meter data from nearby wells along withgeological structure models developed forthe planned horizontal well. LWD responsesfor the potential range of structural dipswithin a particular area of the anticlinal foldcan be simulated. (For a description of howthe INFORM system works, see “INFORMIngenuity,” page 52.)

As the well course builds to horizontal,the geosteering specialist and geologist cor-relate major stratigraphic LWD markers andestimate the structural dip of a stratigraphicunit in the plane of the well course by opti-mizing the match between the LWD curvesand the model log curves. The calculatedstructural dip estimates are compared tothose in the geologist’s predicted fold geom-etry cross-sectional model. The new dips arethen used to correct the Toro subsurfacestructure model and revise the top Toro tar-get coordinates.

may be too close to the current gas-oil con-tact and would not be perforated. The Aleneis drilled with mud weights in the range of 12to 14 ppg, while the current reservoir pres-sures in the Toro are in the 4.5 to 5.5 ppgequivalent range. To prevent lost circulationproblems and possible loss of the hole, it isnecessary to identify the top of the Toro cas-ing point before penetrating more than 1.5 to3 m [5 to 10 ft] of the sandstone.

An accurate predictive model of the Toroanticlinal geometry resulting from recogni-tion of overlying stratigraphic markers whiledrilling—as well as the ability to determinethe structural attitude of these layers—increases the probability for a successfullanding phase. With INFORM processing, a

49Winter 1995

2. A designer well is defined as one with turns greaterthan 30° in the horizontal plane, combination rightand left turns, and turns not restricted by inclination.From Teel ME: “Extended Reach Becomes Fashion-able,” World Oil 215, no. 6 (June 1994): 27.

3. For discussion of the challenges of modeling andinterpreting while drilling and wireline electromag-netic tool response in deviated and horizontal wells:Betts P, Blount C, Broman B, Clark B, Hibbard L,Louis A and Oosthoek P: “Acquiring and InterpretingLogs in Horizontal Wells,” Oilfield Review 2, no. 3(July 1990): 34-51.Anderson B, Bryant I, Lüling M, Spies B and Helbig K:“Oilfield Anisotropy: Its Origins and Electrical Char-acteristics,” Oilfield Review 6, no. 4 (October 1994):48-56.Anderson B: “The Analysis of Some Unsolved Induc-tion Interpretation Problems Using Computer Model-ing,” Transactions of the SPWLA 27th Annual Log-ging Symposium, Houston, Texas, USA, June 9-13,1986, paper II.Anderson B, Minerbo G, Oristaglio M, Barber T,Freedman B and Shray F: “Modeling ElectromagneticTool Response,” Oilfield Review 4, no. 3 (July 1992):22-32.Allen DF and Lüling M: “Integration of WirelineResistivity Data with Dual Depth of Investigation 2-MHz MWD Resistivity Data,” Transactions of theSPWLA 30th Annual Logging Symposium, Denver,Colorado, USA, June 11-14, 1989, paper C.

4. White J: “Geological Steering Assists Cost EffectiveExploitation of Marginal Reserves,” paper SPE 30362,presented at the Offshore Europe Conference,Aberdeen, Scotland, September 5-8, 1995.

5. The attenuation resistivity probes roughly twice asdeep as the phase-shift resistivity. Absolute depths ofinvestigation vary with background resistivity,decreasing with decreasing resistivity. For more onthe subject, see Allen and Lüling, reference 3.

6. Karst is a type of topography formed on carbonaterocks by dissolution.

7. Magner TN and McKay WI: “PNG’s Kutubu Project:Lessons in the First 100 Million Barrels,” paper SPE28784, presented at the SPE Asia Pacific Oil & GasConference, Melbourne, Australia, November 7-10,1994.

nModeled andacquired logs in aNorth Sea horizon-tal well. Modelingof CDR Compen-sated Dual Resistiv-ity tool andgamma ray logs(top) shows that the high-resistivitycalcite-cementedzone at the base of the pay shouldbe detectablewhile drilling. Thedeep-sensing atten-uation resistivitylog (purple) crossesover the shallow-reading phase-shiftlog (brown) as thehigh-resistivity zoneis approached.Acquired logs (bottom) show asimilar feature, asthe well wassteered to avoid the calcite-cemented zone.

Gam

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, AP

I 200160

120

80

400

XX20

XX44

XX68

XX92

X116

X140True

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Distance along the section, ft

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hm-m

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5200 6000 6800

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200Distance along the section, ft

Res

istiv

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10

51000

X70

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X80X85

deviation angle build rate depend on know-ing this entry position (left).

During the drilling of well IHT-1, a com-puter structure model with sections of 6°and 8° apparent dip was constructed withthe INFORM system, using data transmittedvia satellite link (above).8 The stratigraphichorizon boundaries, dip magnitude and truevertical depth of each section was deter-mined from the match between the mea-sured CDR logs and the modeled logs (nextpage, left). This match is consistent down tothe Toro, indicating the structural dip modelis a good representation of the actual Torosubsurface structure.

Typically the CDR tool, producing charac-teristic horns at high-angle bed boundaries,is run to land wells. For the IHT-1 well bot-tomhole assembly configurations, however,this tool is located 18 m [60 ft] behind thebit. To precisely locate the 95/8-in. casingsetting depth at the top Toro, the last bit tripis run with the GeoSteering tool, an instru-mented steerable downhole motor with tworesistivity sensors.

50 Oilfield Review

Oil-water contact

TVD target level

Initialwellplan

Revisedwell plan

Steeper dipTop Toro

target

Initialstructure

model

Toro sand

Kick-offpoints

12.2620.0923.9529.1356.8258.8960.2961.5462.8364.2666.1068.1470.6773.4180.23

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t

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7800

8000

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8800

9000400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800

Section departure, ft

GR, API

Top Toro Ain IHT-1

Top Toro Ain IHT-1A

■■Kick-off points and build rates varying with entry point positionand structural dip. In this case, the location of the crest of theanticline was known, but the dip of the flanks was not. For an initial well position, a steeper dip requires a shallower kick-offpoint and slower build rate to reach the entry point at the correctlocation.

■■Cross-sectional model of the Chevron Niugini IHT-1 well trajectory. This 200-layer model was built using logs from threenearby wells with the INFORM Integrated Forward Modeling system. Formation dips were constrained by the matchbetween modeled logs and logs acquired while drilling. Well IHT-1 is in green, its gamma ray reading in magenta, andnearby Well IHT-1A in blue. A plan view of the two trajectories is inset. Layers are colored according to gamma ray values,with light colors indicating low readings, dark colors indicating high values. Water is indicated with blue-green shading.

51Winter 1995

The primary purpose of the GeoSteeringtool is to drill the horizontal drainhole andconfirm that the well is above the oil-watercontact in each sand. Normally GeoSteer-ing tool data are not acquired in the upper6 to 9 m [20 to 30 ft] of the Toro, until thetool signal receiver clears casing. Becauseof mechanical problems, the 95/8-in. casingin IHT-1 ended 27 m [90 ft] above the Toro.This allowed the GeoSteering tool toacquire data across the shale-sandstoneresistivity contrast at the top of the Toro.

The GeoSteering tool’s two resistivity sen-sors measure different rock volumes: thetoroid at the bit is hemispherically focusedaround the bit and the bit box; the arc-shaped electrode is azimuthally focused ina 120° arc perpendicular to the tool axis.9

The gamma ray sensor is also azimuthallyfocused with back shielding. While rotarydrilling, the arc and gamma ray sweep thefull 360° of borehole wall. When the motoris sliding, however—in this example, build-ing angle with zero tool face—the bit resis-tivity measures omnidirectionally, while thearc measures upward and the gamma raymeasures downward.

Across the top of the Toro Sandstone, thebit resistivity, arc resistivity and gamma rayhave an apparent depth mismatch (above).The unit above the Toro entry point isAlene shale with true resistivity, Rt, of 6 to10 ohm-m, while directly below it is a sec-tion of tight, calcite-cemented Upper Toro

Dep

th, f

t

8100

Top of Toro A

B3 @ TVD8166

J1 @ TVD8467

A1 @ TVD8606

A2 @ TVD8683

OWC @8741 TVD

8500

8900

9300

10100

10500

ohm-mAPI0 150 2 200

Measured CDRGamma Ray

MeasuredGeoSteeringGamma Ray

Modeled CDRGamma Ray

ModeledGeoSteeringGamma Ray

Measured CDRAttenuation

Measured RBIT

Modeled CDRAttenuation

Modeled RBIT

nModeled and measured gamma ray,GeoSteering and CDR logs from theChevron Niugini IHT-1 well. Log signaturesthrough marker beds coincide with thoseat marker depths predicted before drilling.

8. Dip is called apparent when it is measured in a dif-ferent direction from that of the steepest dip.

9. Bonner S, Burgess T, Clark B, Decker D, Orban J,Prevedel B, Lüling M, and White J: “Measurements atthe Bit: A New Generation of MWD Tools,” OilfieldReview 5, no. 2/3 (April/July 1993): 44-54.

nMeasured gamma ray and bit and arc resistivities showing an apparent depth shiftas the GeoSteering tool slides across the top reservoir interface. The shift can beexplained by the counteracting effects of the high inclination of the trajectory and adip in the interface. Insets show simulated bit and arc resistivity logs for models withthree dips—6°, 8° and 10°. An 8° dip fits both resistivities.

2

2

0.2

0.2

2000

2000

200

200

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Arc-up measured

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Measured Gamma Ray

Modeled Gamma Ray

0 API 100

RBIT modeled

Arc-up modeled

10° dip

8° dip

6° dip

10° dip

8° dip

6° dipBitresistivity

Arc resistivity

Gamma ray

(continued on page 56)

The INFORM system allows the analyst to con-

struct a detailed model of the geometry and petro-

physical properties of the layers that have been or

will be penetrated by the well. Then tool

responses along the well trajectory through that

model are simulated.

Building the Model

Building the 2D petrophysical description of the

prospect from offset well logs and production data,

geologic maps and cross sections is the most time-

consuming part of the INFORM process. The tool

response calculation can be run over a coffee or

lunch break. Once the basic geometric framework

is built, additional information—improved esti-

mates of structure or stratigraphy from reprocessed

seismic data, more detailed correlation studies,

logs from the pilot hole—can be incorporated.

Logs and other petrophysical data from offset or

pilot wells provide the foundation for the INFORM

model, defining layer thicknesses and properties.

In a process called log squaring, bed boundaries

are determined from inflection points on the logs,

and the average layer properties are extracted

from the log values. INFORM modeling offers a

combination of automatic and interactive, or man-

ual, tools for log squaring (right). The squared log

layers are then stretched or squeezed to fit the

expected model at the location of the horizontal

well. Squared logs from other wells may indicate

lateral facies changes in the model.

Geologic maps and a cross section of the

prospect, oriented along the proposed drainhole,

provide the dip along the plane of the well, the

number and throw of faults, and additional informa-

tion about lateral facies changes. With this infor-

mation the analyst can subdivide the model into a

small number of simple blocks, with faults, dip

changes and other lateral variations as boundaries.

The beds, their thicknesses and petrophysical

properties are represented in the INFORM method-

ology as a “layer column”—a table that contains

all parameters describing one block of the 2D

model. Properties include gamma ray (GR) in API

units, horizontal and vertical resistivities (Rh and

Rv), bulk density (RHOB), photoelectric factor (Pe),

neutron porosity (NPHI) and sonic transit time

(DT). For simple formations, in which the forma-

tion is laterally homogeneous, only one layer col-

umn is necessary. For more complex cases, a

series of layer columns is required. This method-

ology separates the analysis of formation proper-

ties and bed thicknesses—stratigraphy—from for-

mation dip and depth—structure. Once layer

columns are constructed, it is a simple matter to

rotate coordinates to change dip or translate

columns to introduce faults.

Finally, the geometry of the well trajectory is

input so relative angles can be computed.

Relative Angle Data Base

As the well deviates with depth, in addition to vari-

ations in formation properties, the distance and

the angle between the tool and layer boundaries

change, affecting logging tool response. The angle

between the tool axis and the normal to the layer

is called the relative angle. Modeling tool

response through these continuous changes

requires an efficient code, one that is both fast and

accurate. The simplest technique is to approxi-

mate the actual well trajectory with a small num-

ber of straight-line modeling runs. This is fast, but

not accurate. Another method, which computes

tool response at every point on the trajectory, is

accurate, but too slow for geosteering purposes.

A compromise was proposed by Martin Lüling

while at Schlumberger LWD Engineering in Sugar

Land, Texas, USA. For a given trajectory, the

INFORM technique computes relative angles at

52 Oilfield Review

INFORM Ingenuity

■■Log squaring, the first step in building a formation model for integrated forward modeling. In this example,an FMI Fullbore Formation MicroImager log from an offset well (track 1) guides manual layer placement forfine-tuning an automated log squaring result. The resulting squared log (red, track 2) is compared with themeasured resistivity log (blue, track 2). Modeled and measured logs are compared in track 3.

TopDepth

BottomDepth Value0.2 0

0.2 0

Input

Squared

Computed

Input

0.2 0

0.2 01.20

1220

1212.85

1213.35

1213.85

1214.40

1215.1

1215.8

1216.33

1216.83

1217.41

1217.71

1218.57

1219.03

1219.63

1220.15

1220.67

1221.06

1221.46

1221.72

1222.20

1213.35

1213.85

1214.40

1215.1

1215.8

1216.33

1216.83

1217.41

1217.71

1218.57

1219.03

1219.63

1220.15

1220.67

1221.06

1221.46

1221.72

1222.20

1223.02

0.067

0.135

0.009

0.069

0.015

0.001

0.031

0.101

0.095

0.100

0.072

0.063

0.077

0.066

0.099

0.076

0.051

0.069

0.103

every point along the well path (above). Next the

tool response to each layer column is computed at

specified relative angles and stored in a lookup

table (right). The program then interpolates

between tabled values to deliver a modeled

response at any desired sampling along the well-

bore. If the tool responses are found to be extra-

sensitive to changes in depth or angle, a more

finely sampled relative angle table may be con-

structed. The lookup procedure is rapid, so investi-

gation of multiple scenarios, involving changes to

the trajectory, formation dip or true vertical depth

is feasible.

Each output case can be stored for access by the

GeoSteering screen at the drillsite. Then modeled

logs and logs recorded while drilling can be com-

pared, helping to identify marker beds that guide

the well, and avoiding problem zones.1

The flexibility that comes with speed of compu-

tation allows testing of scenarios both before

drilling and after, for formation evaluation. A

53Winter 1995

Recommendedangles

3840

3850

3860

3870

86 88 90Relative angle, degree

True

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dep

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843880

0 45 65 70 75 80 85 90

Shale 1

Shale 2

Oil sand

Watersand

Shale 3

Relative angle, degree

1. For an example of the technique: McCann D,Kashikar S, Austin J, Woodhams R and Siddiqui S:“Geologic Steering Keeps Horizontal Well on Target,”World Oil 215, no. 5 (May 1994): 37-43.

■■A relative angle plot—a graph of the relative angles at which the given trajectoryintersects bed boundaries. This relative angle plot corresponds to the formationmodel shown on page 63.

■■The relative angle data base. The INFORM program computes the tool responseto each layer column at specified relative angles and stores them in a lookup table,or data base. The program then interpolates between stored values to output amodeled response along the wellbore. This figure represents one layer column.

predrilling planning example shows the effect of a

minor change in formation dip (left). With an

added half-degree of formation dip, the pay zone

at 4330 ft TVD is completely missed.

In a postjob formation evaluation example,

acquired CDR Compensated Dual Resistivity phase

shift and attenuation resistivities can be matched

best by introducing resistivity anisotropy—unequal

vertical and horizontal resistivities (next page). In

such formations the phase shift resistivity reads

higher than the attenuation measurement.2 The

INFORM software can simulate CDR curves in an

anisotropic formation, to distinguish its log

response from other phenomena that might have

similar signatures, such as nearby beds of con-

trasting resistivities.

INFORM Capabilities

The INFORM system is evolving rapidly. Currently

it can model responses for a variety of tools in sev-

eral environments. The catalog includes:

• 3D finite-element method laterolog codes for

wireline logs—ARI Azimuthal Resistivity Imager

and DLL Dual Laterolog Resistivity Logs; and

LWD tools—RAB Resistivity-at-the-Bit and

GeoSteering tool measurements in anisotropic

formations with dipping beds and invasion.

• 2D analytical induction codes for modeling wire-

line logs—AIT Array Induction Imager Tool mea-

surements and DIL Dual Induction Resistivity

Logs; and LWD logs—ARC5 Array Resistivity

Compensated and CDR logs. These can be mod-

eled in anisotropic formations with dipping beds.

• 2D sensitivity function density codes for model-

ing wireline measurements—IPL Integrated

Porosity Lithology and Litho-Density logs; and

LWD measurements—ADN Azimuthal Density

Neutron and CDN Compensated Density Neutron

tools in formations with dipping beds.

• 2D ray tracing sonic codes for modeling wireline

measurements—DSI Dipole Shear Sonic Imager

logs; and LWD measurements—ISONIC (IDEAL

sonic-while-drilling tool) logs in formations with

dipping beds.

• 1D convolution filter codes for modeling gamma

ray and neutron tools.

54 Oilfield Review

■■Modeling the effect of slight changes in formation dip with the INFORM system. Uncertainty in formation dipcan cause failure to reach a horizontal well target. The first model (top) is designed to land the well in the payzone at 4330 ft TVD, then build angle to investigate other layers. Keeping the same trajectory but adding ahalf-degree to the formation dip (bottom), the pay zone is completely missed. The two models can be com-puted before drilling, using the same relative angle data base, and stored for access by the GeoSteering screento help real-time drilling decisions.

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, ft

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0200

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4240

4280

4320

4360

4400500 1000 1500 2000

Distance along the section, ft

750 1250 1750

4050637075808590

Phase shiftAttenuation

GR, API

2. Lüling MG, Rosthal RA and Shray F: “Processing and Modeling 2-MHz Resistivity Tools in Dipping,Laminated, Anisotropic Formations,” Transactions ofthe SPWLA 35th Annual Logging Symposium, Tulsa,Oklahoma, USA, June 19-22, 1994, paper QQ.

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-mTr

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ertic

al d

epth

, ft

150

0200

0.24200

4240

4280

4320

4360

4400500 750 1000 1250 1500 1750 2000

Distance along the section, ft

Resistivity,ohm-m

0.150.24

0.400.500.600.750.901.051.202.002.206.00

0.30

Phase shiftAttenuation

55Winter 1995

150

0

200

0.2

4310

4320

4330

4340

4350

43601000 1200 1400 1600 1800 2000

Distance along the section, ft

Tru

e ve

rtic

al d

epth

, ft

Res

istiv

ity, o

hm-m

Gam

ma

Ray

, AP

I

Modeled

Measured

Modeled phase shiftMeasured phase shiftModeled attenuationMeasured attenuation

0.240.300.400.460.470.480.600.750.901.2010.030.0

HorizontalResistivity,ohm-m

Modeled phase shiftMeasured phase shift

Modeled attenuationMeasured attenuation

200

2Res

istiv

ity, o

hm-m

20

200

2Res

istiv

ity, o

hm-m

20

200

2Res

istiv

ity, o

hm-m

20

2

200

Res

istiv

ity, o

hm-m

20

200

2Res

istiv

ity, o

hm-m

20

Rh = 10Rv = 10

Rh = 30Rv = 30

Rh = 60Rv = 60

Rh = 10Rv = 50

Rh = 10Rv = 90

nMatching modeled andmeasured CDR phase shiftand attenuation resistivitiesby introducing resistivityanisotropy. In formationswith resistivity anisotropy—Rv greater than Rh—theattenuation and phase shiftresistivities separate: thephase shift resistivity readshigher than the attenuationmeasurement. This phe-nomenon can be simulatedwith the INFORM software toproduce formation modelsconsistent with measuredlogs and offset wells. Thebest fit here is with Rv = 90ohm-m and Rh = 10 ohm-m.The model with Rv and Rh =60 ohm-m seems to fit theacquired logs well, but con-flicts with offset well informa-tion in the same formation.

sandstone with an Rt of 210 ohm-m, whichoverlies porous sandstone. As the nearly hori-zontal GeoSteering tool slid across the dip-ping interface, the downward lookinggamma ray was the first to register the tightsand, while the upward looking arc resistivitywas the last. Modeling after the job with theINFORM program shows that this mismatchcan be explained by the counteracting effectsof the high inclination in the trajectory andan 8° apparent dip at the top Toro.

Unexpectedly, IHT-1 entered the dippingToro reservoir beneath a present-day oil-water contact at 8741 ft true vertical depth(TVD). The contact was apparently 15 to 18 m [50 to 60 ft] shallower than predicted,probably due to pressure depletion of theupper Toro reservoir in this area of the field.The bit resistivity gave an immediate indica-tion of water-saturated Toro. The plannedtrajectory was modified to build angle togreater than 90 degrees in an upward trajec-tory, crossing the oil-water contact fromunderneath. During drilling in the mid-Toro,the well encountered lost fluid circulationproblems, possibly at a fault or fracturezone. With sudden unloading of the bore-hole, collapse occurred in the unstableshale openhole section above the Toro, andthe hole was lost.

IHT-1A, a sidetrack designed to take a par-allel well path, was planned using the struc-tural attitude data and oil-water contactinformation from IHT-1. A short 30.5-m[100-ft], 81/2-in. pilot hole was drilled at theend of the buildup section with theGeoSteering tool to “geostop” exactly on theshale-sandstone reservoir boundary (right).This hole was enlarged, and the 95/8-in. cas-ing set just on the reservoir top. As expected,dips were close to those in IHT-1, and thewell was landed within the Toro oil leg asplanned, 15 m above the present-day oil-water contact. It continued for 427 m [1400 ft]across the three main Toro reservoir sand-stone members (next page, top). The wellwas completed as an oil well, producingmore than 10,000 stock tank barrels of oilper day, at solution GOR.

Another well, IHT-2, on the same struc-ture, encountered 55° dips, much steeperthan the 22° anticipated (next page, bottom).These were successfully modeled with theINFORM program and the well path modi-fied to hit the target.

After Drilling, Model AgainOnce drilled and logged, horizontal wellscontinue to pose challenges in visualizationand formation evaluation. Log simulationcan help verify a formation model or thelocation of a well in space, to use for futuredevelopment planning and quality control.More importantly, modeling helps untangle

nModeled andlogged gammaray and GeoSteer-ing tool responsefor the ChevronNiugini IHT-1Awell.

56 Oilfield Review

Modeled Gamma Ray

Logged Gamma Ray

API

API0 150

0 150 ohm-m

ohm-m2 2000

2 2000

Mea

sure

dde

pth,

ft

9800

10,000

10,200

10,400

10,600

10,800

11,000

11,200

11,400

Modeled GeoSteeringBit Resistivity

Logged GeoSteeringBit Resistivity

Top of Toro AGeostop

true formation properties such as formationfluid resistivity, Rt, and water saturation, Sw,from the melange of shallow and deepresponses of while-drilling and wirelinetools. The INFORM program takes an inte-grated approach to log simulation for forma-tion evaluation by modeling a wide range oftool measurements simultaneously.

In the Gulf of Mexico, Lee Lehtonen atMobil Exploration and Producing in NewOrleans, Louisiana, USA tested simulationto validate the model of a horizontal well

57Winter 1995

8400Tr

ue v

ertic

al d

epth

, ft

8500

8600

8700

8800

8900

90002000 2200 2400 2600 2800 3000 3200 3400 3600 3800

Section departure, ft

12.2620.0923.9529.1356.8258.8960.2961.5462.8364.2666.1068.1470.6773.4180.23

GR, API

0 200 400 600 800 1000 1200 1400 1600 1800 2000

Section departure, ft

True

ver

tical

dep

th, f

t

7000

7100

7200

7300

7400

7500

7600

7700

7800

7900

8000

8100

8200

8300

Ga 12.9018.2323.2140.26101.99105.81108.68110.83113.43116.03120.92123.96126.50129.68136.79

GR, API

■■Cross-sectional model encountered by the IHT-1A well. The well was steered to penetrate the reservoir above the oil-watercontact in the top sand, and to thread through the three main sands of the reservoir. Layer color indicates gamma ray value.

■■Cross section for Well IHT-2, the second well in the Chevron Iagifu-Hedina horizontal development program. The CDRlogs were matched with dip panels from 55 to 24°. This provided an approximate top Toro landing point for trajectorycontrol. The exact landing point was determined by “geostopping” with the bit resistivity from the GeoSteering tool inthe last trip. Each dip panel in this example has the same true stratigraphic thickness. The true vertical thickness ofeach panel will vary with dip. The depth of each panel is adjusted to keep the formations continuous at the panelintersections along the well path. The gamma ray log is shown in magenta.

10. Prilliman JD, Allen DF and Lehtonen LR: “HorizontalWell Placement and Petrophysical Evaluation UsingLWD,” paper SPE 30549, presented at the 70th SPEAnnual Technical Conference and Exhibition, Dal-las, Texas, USA, October 22-25, 1995.

11. Holenka J, Best D, Evans M, Kurkoski P and SloanW: “Azimuthal Porosity While Drilling,” Transac-tions of the SPWLA 36th Annual Logging Sympo-sium, Paris, France, June 26-29, 1995, paper BB.

designed to tap multiple compartments in afaulted reservoir (left).10 The horizontal wellwas to traverse four fault blocks (below). Payin the first and fourth blocks would be iso-lated by enough shale to allow setting exter-nal casing packers. In this case, INFORMmodeling showed how LWD porosity logscould be used to distinguish a change in for-mation properties associated with faultingfrom changes encountered in a new strati-graphic layer.

The ADN Azimuthal Density Neutron toolmeasures—while drilling—bulk density,ultrasonic standoff, photoelectric factor andneutron porosity.11 Magnetometers continu-ously measure tool orientation, and resultsare distributed into readings above, belowand to each side of the borehole (next page,bottom). This allows discrimination of theorientation of planes of porosity and densitydiscontinuity in the formation.

In the Mobil well, CDR and ADN datawere recorded into memory while drilling,and data were brought uphole with each bitchange. These logs were compared withlogs simulated using a formation modelbuilt from the known structure and pilotwell logs. During the fifth bit run, the den-sity tool encountered a shale-sand contact(next page, top). Examination of the densityporosity logs shows that the average andbottom quadrant curves both detect theinterface at the same measured depth,XX340 ft. Comparing the acquired and sim-ulated logs shows the contact can be mod-eled as a fault separating shale from sand.

During the seventh bit run, the wellencountered a shale-sand interface beforecrossing the next fault. As the tool enteredthe sand, the bottom quadrant densityporosity saw the sand, while the average ofall four quadrants still indicated a shale

58 Oilfield Review

0.310

0.50

mile

km

N

Dis

tanc

e, ft 1500

2000

1000

500

00 500 1000 1500 2000 2500 3000 3500 4000

Plan View

Offsetwell

Pilot well

Trapping fault

Fault 4

Fault 3Fault 2

Fault 1

Horizontal well

nPlan view of a Gulf of Mexico horizontal well trajectorythrough a compartmentalized gas reservoir. In the seis-mic amplitude plot inset above, yellow and red indicatehydrocarbon extent. Amplitudes are bounded to thenorth by a large sealing fault. Breaks in color continuityhighlight additional faulting. The drilling plan called forintersecting each of these compartments.

XX90

X120

X130

X140

X150

X160

X170

7300 7800 8300 8800 9300 9800

Fault 2 Fault 3 Fault 4

X100

X110

Top B

Tight zone

Top A

Top B

Top A

Top A

Dep

th, f

t

nCross section of the faults and formations penetrated by the well.

59Winter 1995

Ultrasonic Caliper

Gamma Ray

Rate of Penetration5 Ft Average

True Vertical Depth

Resistivity AttenuationDeep

Resistivity Phase Shift

Bottom Quadrant

Average DensityPorosity

Neutron Porosity

XX400

XX300

Dep

th, f

t80 18

0 150

500 0

XX60 XX10

in.

GAPI

ft/hr

ft

0.2

0.2

200

200

ohm-m

ohm-m

60

60

60

0

0

0

p.u.

p.u.

p.u.

XX350

Gam

ma

Ray

, AP

I 10084

68

52

3620

Res

istiv

ity, o

hm-m

1

10

100

1000

RH

OB

, gm

/cm

3

1.651.85

2.05

2.25

2.452.65

XX10

XX12

XX14

XX16

XX18

XX20

True

ver

tical

dep

th, f

t

X200 X250 X300 X350 X400

Di t l th ti ftFa

ult

2

Measured

Modeled

Modeled Measured

Modeled

Measured

Left Right

Bottom

Top

nThe ADN Azimuthal Density Neutrontool reading above, below and to eachside of the borehole while drilling. Mag-netometers continuously measure ADNtool orientation, and processing groupsbulk density, ultrasonic standoff, photo-electric factor and neutron porosity mea-surements into quadrants.

nLogs acquired while drilling through a fault in the Mobil offshore Louisiana well. The density porosity logs show that the averageand bottom quadrant curves detect the interface at the same measured depth, XX340 ft (left). The difference between the bottomand average density porosity in the zone XX340 ft to XX370 ft is due to vertical segregation of invading mud filtrate. The logs can bemodeled by a nearly horizontal well intersecting a vertical fault separating shale from sand (right).

zone (left). As the well cut deeper, the aver-age and bottom quadrant readings cametogether 40 ft [12 m] beyond the first indica-tion of the shale. Simulation with theINFORM system indicates the log responsescan be explained by a slightly dipping, 5-ftclean sand. Modeling the azimuthally sensi-tive response of the ADN tool allowed theorientation of the interface to be verified,constraining the subsurface structure andstratigraphy.

In another well offshore Gulf of Mexico,the Amoco team of Patricia Hall, KeerthiMcIntosh, Jessie Lopes and Gerard Simmsenlisted the INFORM system to add con-straints to the structural interpretation afterdrilling. The reservoir structure had beenmapped from log and 3D surface seismicdata, but the scarcity of wells in the southernblock of the reservoir left uncertainties instructural detail. In particular, the location ofthe crest of the targeted anticlinal featurewas poorly constrained on early maps (nextpage, top).

The horizontal well ran under the crest ofthe structure, and gamma ray and ARC5Array Resistivity Compensated logs wereacquired in memory while drilling.12 Afterdrilling, several structural and stratigraphicmodels were input to the INFORM programto determine the one that best explained therecorded logs. In this way, the relationshipbetween the well and the formations couldbe visualized, and completion and produc-tion strategies weighed.

A preliminary attempt to model the struc-ture as a simple anticline gave disappointingresults. Enhancements to the model—in theform of minor faults near the crest of theanticline and a facies change on the far sideof the structure—produce simulated logsthat begin to mimic some of the complexityof the acquired logs (next page, bottom).

In addition to evaluating LWD logs for for-mation properties, the INFORM method canalso be used to extract petrophysical proper-ties from wireline tools conveyed bydrillpipe or coiled tubing. Bob Dennis at theSchlumberger Wireline Division in Muscat,Oman has interpreted Rt from AIT ArrayInduction Imager Tool responses in some ofOman’s horizontal wells.

In Oman, horizontal wells make up morethan 80% of the wells drilled per year. The

60 Oilfield Review

12. For information on the ARC5 Array Resistivity Compen-sated tool: Bonner SD, Tabanou JR, Wu PT, Seydoux JP,Moriarty KA, Seal BK, Kwok EY and KuchenbeckerMW: “New 2-MHz Multiarray Borehole-CompensatedResistivity Tool Developed for MWD in Slim Holes,”paper SPE 30547, presented at the 70th SPE AnnualTechnical Conference and Exhibition, Dallas, Texas,USA, October 22-25, 1995.

nLogs recordedwhile grazing ashale-sand inter-face. As the toolentered the sand,the bottom quad-rant density poros-ity saw the sand,while the averageof all four quad-rants still indicateda shale zone (top).As the well cutdeeper, the aver-age and bottomquadrant readingscame together 40 ft[12 m] farther on.The logs are consis-tent with a modelthat includes agently dippingsand (bottom).

Gam

ma

Ray

, AP

I 150120

90

60

300

Res

istiv

ity, o

hm-m

0.2

20

200

2000

RH

OB

, gm

/cm

3

1.51.7

1.9

2.1

2.32.5

XX00

XX10

XX20

XX30

XX40

XX50

True

ver

tical

dep

th, f

t

X100 X150 X200 X250 X300

Distance along the section, ft

Faul

t 3

MeasuredModeled

Clean sand

Bottomof hole

Topof hole

Ultrasonic Caliper

Gamma Ray

Rate of Penetration5-ft Average

True Vertical Depth

Resistivity AttenuationDeep

Resistivity Phase Shift

Bottom Quadrant

Average DensityPorosity

Neutron Porosity

X200

X100

Dep

th, f

t

80 18

0 150

500 0

XX60 XX10

in.

API

ft/hr

ft

0.2

0.2

200

200

ohm-m

ohm-m

60

60

60

0

0

0

p.u.

p.u.

p.u.

Bottomquadrantreads sand

61Winter 1995

A5A9

nReservoir structure mapped before and after the Amoco horizontal well. The structure mapped from log and 3D surface seismicdata (left) was refined with data from the horizontal well (right).

8320

8328

8336

8344

8352

8360True

ver

tical

dep

th, f

t

1800 2000 2200 2400

Distance along the section, ft

0.1

1000

Res

istiv

ityG

amm

a R

ay

150120

90

60

300 Modeled

Measured

AP

Ioh

m-m

Modeled

Measured

0.301.002.0020.00

Resistivity, ohm-m

8320

8328

8336

8344

8352

8360True

ver

tical

dep

th, f

t

1800 2000 2200 2400

Distance along the section, ft

0.1

1000

Res

istiv

ityG

amm

a R

ay150120

90

60

300

Modeled

Measured

AP

Ioh

m-m

Modeled

Measured

1.0015.0040.00

Resistivity, ohm-m

nStructural models input to the INFORM program to determine which best explained the recorded logs. Early attempts (left) to simulta-neously model the ARC5 resistivity and gamma ray curves were unsuccessful using an oversimplified formation model. A more com-plex model with minor faults and a lateral facies change (right) begins to produce modeled logs that better match the measured logs.

B11ST1 B11ST2

objective is to optimize oil recovery indeveloping and mature fields. A commontarget is the Shuaiba Limestone, in whichhorizontal wells are designed to run parallelto the reservoir top within 3 to 5 m [10 to16 ft] of the overlying Nahr Umr shale.

The Nahr Umr-Shuaiba interface, though auseful feature for steering horizontal wells,creates problems later when logs are inter-preted for Rt. For example, at the interfacebetween a 0.8-ohm-m shale and a 50-ohm-mlimestone, AIT resistivities can fall 50% belowactual Rt values when within 3 m of the inter-face (below). This suggests that in many hori-zontal wells, measured resistivities may bearlittle resemblance to true resistivities. How-ever, simulation can help arrive at true forma-tion properties: by testing several scenarios forcomparison with measured results, the forma-tion resistivity model can be found that bestexplains the real logs.13 This model can thenbe further evaluated for water saturation.

62 Oilfield Review

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaDepth, m Actual Sw (50%)

AF10 AF20 AF30 AF60 AF90

Sw Sensed by AF60

Actual Sw (10%)

Sw Sensed by AF60

100

200

300

400

ohm-m2.0

AITResistivity Distance from Interface, m

7.5 6.0 4.5 3 1.5 0 100Water Saturation

% 050

Shale2 ohm-m

Limestone50 ohm-m

nTranslating errorsin Rt into errors inSw. AIT resistivitieswith five depths ofinvestigation (lefttrack) diverge asthe low-resistivityshale is approach-ed (middle track).Water saturationscalculated fromthe AF60 curve areplotted for twocases (right track).The error in Swincreases as Sw increases.

1.003.004.505.506.007.009.0010.0011.0014.0017.0018.0019.0020.0022.00

Resistivity,ohm-m

4550

4575

4600

4625

1000 1500 2000 2500 3000

Distance along the section, ft

True

ver

tical

dep

th, f

t

500

4525

4650

nBuilding a resistivity profile from offset vertical well logs. Resistivitiesfrom a vertical well are extrapolated along a predicted dip to createthe initial model for the structure penetrated by the horizontal well.nModeled response of AIT curves

varying with distance to an adjacentbed approached at high angle.Within 3 m of a low-resistivity bed—acommon occurrence in horizontalwell trajectories—the AIT resistivitiesread significantly below actual Rtvalues. Shown are AF10 throughAF90, representing AIT 4-ft verticalresolution resistivities with 10-through 90-in. depths of investigation.

Dis

tanc

e fro

m in

terfa

ce, m

10

5

0

10

5

100101

AIT resistivities, ohm-m

AF10 AF20 AF30 AF60 AF90

0.2�

0.8 ohm-m

50 ohm-m

Without the modeling step, errors in Rt translateinto large errors in Sw (previous page, top).

The first step in evaluating resistivity logsin a horizontal well is to build a resistivityprofile using an offset vertical well or a near-vertical pilot section of the horizontal well(previous page, right). The layers are charac-terized by their thickness and average petro-physical values and are entered into theINFORM program as the initial model. Geo-logical and structural knowledge of the fieldis used to provide the INFORM model withdip and azimuth information on the layers. Ifavailable, FMI Fullbore Formation MicroIm-ager and ARI Azimuthal Resistivity Imagerlogs are checked to confirm the bed geome-try and to identify fractures in the formations.The depth interval and relative anglesrequired for the forward modeling are deter-mined from the relative angle plot, andfinally the modeled resistivity is computed.

After the first modeling run, the simulatedlogs are compared with the actual logs(above). Iterations of the model are tested todetermine if the differences in resistivitiesare due to offsetting beds across a fault orchanges in the formation resistivity. Once amatch of the resistivities is obtained, the Rtsquare log—the resistivity model—is used todetermine water saturation, giving a betteranswer for Sw and providing guidance forreservoir management decisions.

Showing the WayIntegrated forward modeling for planning andevaluating horizontal wells is an evolvingtechnology. Presented here is a snapshotshowing the progress to date in answeringthe important questions about landing thewell, visualizing it once it is drilled, andassessing reservoir quality. As more peopletest the technique and gain experience in themethod, the scope of forward modeling inhorizontal wells will widen.

Improvements in the INFORM system areexpected to be in the form of modelingcodes for more tools, both LWD and wire-line tools. And as more measurementsbecome available while drilling, forwardmodels for their responses can be added.Plans call for 3D visualization and more 3Dtool response modeling to be able toinclude invasion and proximity effectssimultaneously. —LS

63Winter 1995

1.003.004.505.506.007.009.0010.0011.0014.0017.0018.0019.0020.0022.00

Resistivity,ohm-m

AP

IG

amm

a R

ay10080

60

40

200

Res

istiv

ity

1.0

100

4520

4540

4560

4580

4600

4620True

ver

tical

dep

th, f

t

500 1000 1500 2000 2500

Distance along the section, ft3000

1.0

100

Modeled

Measured

ModeledILM

Measured ILM

Rt

Measured ILDModeledILD

ohm

-mR

esis

tivity

ohm

-mnComparison of horizontalwell induction logs withthose simulated using theoriginal, predrilling, forma-tion model. The measuredlogs do not match the mod-eled logs, and show higherthan expected resistivities(bright green). The next itera-tion is to update the modelby increasing resistivities inthat zone.

13. Anderson BI, Barber TD and Lüling MG: “TheResponse of Induction Tools to Dipping,Anisotropic Formations,” Transactions of theSPWLA 36th Annual Logging Symposium, Paris,France, June 26-29, 1995, paper D.