2

Let’s Get the Most Out of Existing Wells

Client Well Files

Solutio

ns

Services

ActionsProductionEnhancement

Oilfield Review

Steve Bartz Joe M. Mach Jawaid SaeediHouston, Texas, USA

Jay Haskell Caracas, Venezuela

Jorge Manrique Englewood, Colorado, USA

Hemanta Mukherjee New Orleans, Louisiana, USA

Tom Olsen Aberdeen, Scotland

Steve Opsal Texaco Exploration and Production Inc. New Orleans, Louisiana

Eduardo Proano Lafayette, Louisiana

Mark SemmelbeckMidland, Texas

Closing the gaps between current output and productive

capacity is one of today’s best opportunities to quickly

enhance production and improve recovery. A unique service

initiative and focused engineering well reviews help tap into

potential productivity and increase oil and gas asset value.

Geoff SpaldingAmoco (UK) Exploration Co. Aberdeen, Scotland

Jeff Spath Jakarta, Indonesia

In addition to influencing development of the Schlumberger prospecting methodology and PEG analysis function, Production Enhancement Group (PEG) managers that were key contributors to the concepts presented in this article include: Robert Bellavance, Dowell, La Salinas, Venezuela; Jean-Pierre Feraud, Dowell, Caracas, Venezuela; Jose G. Flores, Schlumberger Wireline & Testing, Maturin, Venezuela; Fawzi Guehria, Schlumberger Wireline & Testing, Montrouge, France; Luis Quinterro,Dowell, Houston, Texas, USA; Jose Ignacio Rueda, Dowell, Tia Juana, Venezuela; andDonald Straub, Schlumberger Wireline & Testing, Caracas, Venezuela.

Winter 1997 3

Established fields are the most likely placesto find additional oil and gas output.Improving the performance of wells that arealready producing is a cost-effective way tooffset natural decline, extend field life andimprove hydrocarbon recovery. Productionenhancement (PE) efforts are aimed at evalu-ating wells and recommending ways toincrease productivity. Effective well interven-tions and recompletions, therefore, areessential elements of this endeavor.

But how can oil companies and serviceproviders work together to identify suitablecandidates for production enhancement fromamong thousands of wells? One method is byprospecting—searching in well files foropportunities to get more oil and gas fromexisting wells. And modern computers com-bined with new oilfield technology, tools andservices are facilitating this effort.

In daily operations, E&P companies oftenrequire specific production and reservoirengineering recommendations. Service com-panies can meet this need by helping toidentify underperforming wells and thenassist by providing customized solutions toimprove production. Within Schlumberger,

there are two approaches to productionenhancement: candidate recognition andfield support (above). Schlumberger Wireline& Testing, Dowell and Anadrill solve fieldoperational problems, and perform well con-struction and single-service candidate recog-nition (CR) through field support. Requestsfor integrated solutions, optimized welldesigns, specialized well construction ser-vices and production engineering assistanceare addressed by ad hoc teams that are tai-lored for each situation.

Generally, candidate recognition is ameans of identifying opportunities as theyarise, not merely solving problems in thefield. But rather than wait for opportunities topresent themselves, proactive candidaterecognition (PCR) actively seeks out ways toimprove production, takes full advantage ofoilfield technology and integrated services,and concentrates on producing and shut-inwells. The best engineering answers andmost appropriate well interventions are thetargets for PCR, which is the top priority ofthe Schlumberger Production EnhancementGroup (PEG).

Field Support

• ID Groups• Staff Engineers

• PEGS• DESC-PE

ProactiveCandidate Recognition

Candidate recognitionField support

• PEG-PCR• DESC-PE

Prod

uctio

n an

d

rese

rvoi

r eng

inee

ring

Production Enhancement

Production and

reservoir engineering

• Interpretation, development• Area engineers • Custom-solutions teams

■■Innovative directions and methodology. Production enhancement(PE) applies petroleum engineering calculations to assess andimprove well performance. There are two vectors for PE withinSchlumberger—candidate recognition and field support. Proactivecandidate recognition (PCR) actively seeks out production andvalue beyond what normally results from customers calling servicecompanies to perform work, and is the top priority for theProduction Enhancement Group (PEG).

ClientLink, DESC (Design and Evaluation Services forClients), Dual-Burst, ELAN (Elemental Log Analysis),Enerjet, FoamMAT, NODAL, Pivot Gun, RAPID (Reentryand Production Improvement Drilling), SPAN(Schlumberger Perforating Analysis), TDT (Thermal DecayTime) and WellWatcher are marks of Schlumberger.

For help in preparation of this article, thanks to SteveBodden, Dowell, Lafayette, Louisiana; Christine Ehlig-Economides, GeoQuest Reservoir Technologies, Caracas,Venezuela; Carl Granger, S.A. Holditch & Associates,Inc., College Station, Texas; and Julian Singer,Schlumberger Wireline & Testing, Caracas, Venezuela.

4 Oilfield Review

Specifically, the PEG mission is to optimizewell productivity and increase oil and gasoutput at a pace that exceeds historic indus-try trends. As prospectors, PEG engineers donot stop to make “jewelry” from the “gold”that is found. Instead, they keep looking fornew “nuggets” of opportunity. Design andimplementation of specific services areturned over to one of the Oilfield Servicescompanies or an integrated solutions group.1

This article discusses this focused andaggressive initiative to improve productionfrom client wells.

How PEG Works Candidate recognition began in the late1980s in response to customer needs andrequests. In 1990, the first co-locatedDowell engineers were placed in oil com-pany offices along with the necessary com-puter and communications tools to fulfillclient requirements. At the same time, anintegrated PEG was formed in Houston,Texas. These were among the first stepstoward building new business and workingrelationships in the oil industry.2 With morethan 200 engineers posted in client offices,the DESC Design and Evaluation Servicesfor Clients program continues to grow, facil-itating cooperation and providing intimatecontact with daily operations. Today, thereare also more than 20 PEG locations in keymarkets worldwide, some with multipleteams in place (below). More are plannedfor 1998 and beyond.

The Production Enhancement Group worksoutside of traditional transactions, interac-tions and work flow between operators andservice companies. With permission andcooperation from clients, production spe-cialists look at well files and identify oppor-tunities to increase production—theyrecognize candidates—acting and movingforward instead of reacting and waiting to fillphone-in orders or direct requests. Thisapproach achieves production rates beyondlevels that the industry traditionally expectsand that result from clients initiating a call toa service company.

The PEG engineers evaluate well and pro-duction histories using the latest computersoftware, applying openhole, cased-holeand production logs or interpretation asneeded. Current well performance is ana-lyzed. Pressure, net pay, permeability andskin, or formation damage, are determined.Potential well output is calculated and thebest services are recommended. Results ofthese well interventions are then systemati-cally evaluated after implementation.

Experts from Schlumberger Wireline &Testing, Dowell, Anadrill and, whenrequired, GeoQuest Reservoir Technologiesmake up a typical PEG. As a team, theycooperate with operating company assetmanagers to develop well intervention strate-gies that increase production. In addition,through the ClientLink initiative, the exten-sive Schlumberger intranet provides directaccess to research, technology and innova-

tive solutions tailored to meet specific client,field and well requirements.3

Proactive candidate recognition does notinvolve extensive field studies or exhaustivereservoir evaluations. The heart of theseefforts is an engineering calculation andinnovative methodology based on single-well NODAL production system analysisfrom outer reservoir boundaries to the well-bore sandface, across the perforations andup the production tubing (see “ProductionSystem Analysis,” next page). Any restric-tions, such as safety valves, chokes, surfacefacilities and flowlines, can be included inthis type of analysis.

The PEG engineers perform detailed tech-nical and economic analyses of single wells,groups of wells or fields, and recommendactions with input and support from internaland client experts. There is no charge for thiswell review, evaluation and engineeringfunction. Compensation for productionenhancement recommendations comes fromproviding customized solutions and per-forming value-priced services for clients (see“Turning Cost into Revenue,” page 20). Insome cases, recommendations to optimizewell output involve simply modifying thewellbore flow conduit—tubulars or artificiallift. Except for coiled tubing completions andscale removal, recommendations to changewellbore mechanical configurations—replacing tubing, resizing chokes and addingor modifying artificial-lift methods—are con-sidered an extra benefit of the candidaterecognition process.

PEG Locations

Beijing

Kazakhstan

Moscow

New OrleansHouston

Midland

Calgary

Oklahoma City

Lafayette

Denver

AnchorageAberdeen

La SalinasMaracaiboMaturin

Caracas

Tia Juana

Cairo

Adelaide

Algeria

Dubai

Jakarta

Bangkok

Paris

■■The PEG teams. At this time, there are PEG offices located in key markets around theworld and more are planned. Some of these areas, like Venezuela with six in place, havemultiple teams. Proactive integrated efforts by PEG specialists recommend actions toimprove client production without regard to specific company or individual service considerations within the Schlumberger Oilfield Services group.

1. Bourque J, Tuedor F, Turner L, Gomersall S, Hughes PJr, Klein R, Nilsen G and Taylor D: “BusinessSolutions for E&P Through Integrated ProjectManagement,” Oilfield Review9, no. 3 (Autumn1997): 34-49.

2. Baltz J, Bumgardner S, Hatlen J, Swartzlander H,Basham P, Blessen A, Sarrafian F, Schneider M,Clayton D, Frank T, Gordon D, Taylor B, Kniffin M,Mueller F, Newlands D and White DJ: “The DESCEngineer Redefines Work,” Oilfield Review7, no. 2(Summer 1995): 40-50.

3. Edmonds P: “Linking Solutions to Problems,” OilfieldReview 8, no. 4 (Winter 1996): 4-17.

Winter 1997 5

Production System Analysis

Flowline

Flow conduit

CompletionNode

Reservoir

■■The well production system.

NODAL analysis is used to optimize well produc-

tion systems (below). This technique couples the

capability of reservoirs to produce fluids into a

wellbore with the capacity of tubulars to conduct

the flow to surface, including facility piping if

applicable. The name of this technique reflects

discrete locations—nodes—where independent

equations describe inflow and outflow from reser-

voirs to stock tanks by relating pressure losses

and fluid rates. This engineering methodology

allows calculation of the rate that a well is capa-

ble of delivering and helps determine the effects

of perforations, stimulations, wellhead or separa-

tor pressure and tubing or choke sizes. Future pro-

duction can also be estimated based on

anticipated reservoir and wellbore parameters.1

Computer software based on NODAL analysis

is often used to diagnose and identify system

bottlenecks—completion, perforation and piping

limitations or formation damage—that restrict production or injection. These calculations are

also used to quantify the production increases

that can be expected if restrictions are removed.

The estimated production can then be used in

economic models.

The reservoir section is described by inflow

performance relationship (IPR) curves. Wellbore

tubulars and surface pipes—the flow-conduit

section—are described by vertical or inclined

multiphase flow correlations for tubing outflow,

or intake, performance. The most common

approach is to start at one end of the system, the

reservoir node for example. Subtracting all the

pressure losses at various rates from the reser-

voir pressure defines an IPR curve for fluids flow-

ing into the wellbore. Pressure at the wellbore

node facing the reservoir bottomhole pressure

declines as production rates increase.

Starting from the separator and adding pressure

losses encountered in surface pipes and wellbore

tubing gives the pressure for various rates at the

IPR reservoir node. This calculation results in a

tubing intake, or flow-conduit, curve with bottom-

hole pressure increasing as production rate

increases. The equilibrium point where IPR and

flow-conduit curves have the same pressure and

rate—intersection of the two curves—represents

anticipated production and downhole pressure for

the specific conditions being modeled. Output

from NODAL analysis can be two curves or a set

of curves for sensitivity analysis.

For example, this type of plot can be used to

determine the effect of increasing choke and

tubing sizes. A larger flow diameter moves tub-

ing curves down and to the right, increasing the

flow rate. In production enhancement, IPR

curves are most often used to evaluate the

impact of increasing effective borehole radius by

perforating, acidizing, fracturing or drilling hori-

zontal or lateral drainholes (above). These

remedial well interventions move IPR curves up

and to the right.

7500

6500

5500

4500

350010000 2000 3000 4000 5000 6000 7000 8000 9000 10000

Liquid flow rate, B/D

Bot

tom

hole

flow

ing

pres

sure

, psi

Tubing-head pressure = 300 psi

Tubing-head pressure = 1678 psi

2400 ft

1200 ft600 ft 300 ft

Two 300-ftstacked laterals

Single slantedlaterals

■■NODAL analysis. The intersection of reservoir IPR and flow-conduit performance curves represents estimatedproduction rates under specific conditions and pressures. This plot models two surface pressure conditions andvarious lateral reentry drilling options.

1. Vogel JV: “Inflow Performance Relationships for SolutionGas Drive Wells,” Journal of Petroleum Technology 20, no.1 (January 1968): 83-93.Standing MB: “Inflow Performance Relationships forDamaged Wells Producing by Solution Gas DriveReservoirs,” Journal of Petroleum Technology 22, no. 11(November 1970): 1399-1400.Mach JM, Proano EA and Brown KE: “Application ofProduction Systems Analysis to Determine CompletionSensitivity on Gas Well Production,” paper 81-pet-13, pre-sented at the Energy Resources Technology Conferenceand Exhibition, Houston, Texas, USA, January 18-22, 1981. Meng HZ and Brown KE: “Coupling of ProductionForecasting, Fracture Geometry Requirements andTreatment Scheduling in the Optimum Hydraulic FractureDesign,” paper SPE 16435, presented at the SPE/DOE LowPermeability Reservoirs Symposium, Denver, Colorado,USA, May 18-19, 1987. Mukherjee H: Well Performance Manual. Houston, Texas,USA: Schlumberger Dowell (1991).Economides MJ, Hill AD and Ehlig-Economides C:Petroleum Production Systems. Englewood Cliffs, NewJersey, USA: PTR Prentice Hall (1994): 573-578.

6 Oilfield Review

When operators allow a local PEG to diag-nose production gaps and initiate design,execution and evaluation of services, bothparties focus on production and results. Thisunique interaction ensures optimal recom-mendations to close productivity gaps andapplication of the right services. Focusing onproduction generates more revenue for bothclients and the service company. In today’snew business relationships, operators areagreeing to share some of this added value,and service companies are accepting somedownside risk. Having a vested interest in theoutcome of remedial actions helps the ser-vice provider better understand and meetcustomer needs and expectations.

Producing Wells Existing assets have several distinguishingcharacteristics, both positive and negative, inthe context of production enhancement. Onthe upside, because established fields havewells and facilities in place, productionincreases can generate cash flow withoutadding infrastructure, which reduces leadand cycle times. There are also fewerunknowns. Fluid properties, reservoir driveand recoverable reserves are, in most cases,well understood. On the downside, availableinformation is older, perhaps out of date;data were gathered using possibly obsoletetechnology, tools and techniques; and com-pletion strategies may be outdated. But thesenegatives also present potential opportuni-ties to increase production.

Single-well production enhancementinvolves moving reservoir inflow perfor-mance relationship (IPR) curves up and tothe right, or moving flow-conduit perfor-mance curves down and to the right(below).4 The objective is to recommendsolutions and services that will close identi-fied gaps between current well output andpotential production. To achieve this goal,the components that contribute to a produc-tion gap must be identified and understood(see “Production Gaps: Well PerformanceComponents,” right). The total productionsystem includes reservoir, completion, flow-conduit and artificial-lift components plussurface flowlines and facilities, which areassumed to be a constant in most individualoil and gas well analyses.

Based on what is known about a field, wellfiles and data can be examined with an eyefor likely opportunities from among thesecomponents. A model of the well productionsystem is then developed using this informa-tion and, if required, confirmed by well testsor additional wireline logs to determine netpay, reservoir pressure, permeability, skinand saturations—oil, gas or water. Once amodel is validated, wells are chosen for fur-ther evaluation using the PEG methodology.Remedial interventions are recommended,costs are estimated and viable options arecompared based on estimated well produc-tivity and operator economic constraints.

PEG

Reservoir IPR

Flow-c

ondu

it

perfo

rman

ce

Pre

ssur

e

Pot

entia

l

Cur

rent

Productivity gap

Rate

Reservoir and completion

Add pay

Reperforate

Acidize

Fracture

Drill lateral or horizontal

Control sand

Control water and gas

Flow conduit and facilities

Clean out fill

Remove scale

Optimize tubular designs

Redesign artificial lift

Coiled tubing completions

Early production facilities

■■Closing single-well performance gaps. The objective of production enhancement is toidentify and close gaps between current well output and productive potential. This goalis accomplished by applying solutions and services that move reservoir inflow perfor-mance curves (IPR) up and to the right, and move flow-conduit performance curvesdown and to the right.

Engineering optimum production rates requires

that reservoir deliverability, well stimulation,

recovery efficiency, wellbore hydraulics and sur-

face constraints be addressed. Elements of the

well production system are interrelated, and per-

formance of the entire system is often a function

of the weakest links. During the production

enhancement process, various screening meth-

ods and well-analysis techniques are used to

examine reservoir, completion, flow-conduit—

wellbore tubulars or plumbing—and artificial-lift

system performance (next page).Reservoir performance—A production gap

exists if reservoirs do not effectively deliver

hydrocarbons into a wellbore. The result is low

flow rates at high-drawdown pressures. This

problem may be overcome by increasing effective

borehole radius—fracturing, acidizing or high-

performance perforating. Lateral or horizontal

drainholes are another solution. Nearby injectors

or producers may also affect the region around a

well. A possible solution might be to squeeze off

zones in injectors using cement. Controlling

water influx and mitigating the production of for-

mation fines are also alternatives.

Single-well inflow performance relationships

(IPR) are a function of time and original oil in

place. Near-wellbore effects and mechanical

physical description, Darcy’s law and pressure-

volume-temperature (PVT) behavior affect an

IPR. Diagnostics, including transient testing, arti-

ficial-lift or permanent monitoring, saturation log-

ging, production logging, sonic imaging and

economic analysis, can be performed to obtain

needed information. Remedial actions include

high-performance perforating, stimulations,

drilling laterals, squeeze cementing, water con-

trol and fines mitigation.

Completion performance—The completion,

which includes perforations, liner slots, the

cement-by-borehole annulus, sand-control

screens, gravel packs and any zone of formation

damage, dictates fluid movement from reservoirs

to wellbores. Pressure drawdown at the comple-

tion is a function of flow rate. Factors that influ-

Production Gaps: Well Performance Components

4. Economides MJ, Hill AD and Ehlig-Economides C:Petroleum Production Systems. Englewood Cliffs,New Jersey, USA: PTR Prentice Hall (1994): 173-185.

Winter 1997 7

ence completion performance are perforation

entrance-hole diameter and depth of penetration

into a formation, sand control, stimulation, zonal

isolation and damage, or partial formation pene-

tration. Drawdown through a completion is

reduced by reperforating or acidizing and by per-

forating a larger interval to reduce classical skin,

resulting from a limited perforation interval. If not

in place, a gravel pack or other sand-control

method may be required. A cement squeeze may

be needed if some zones produce unwanted water

and gas, or take fluids that crossflow from another

zone. Poor cement may also allow communica-

tion behind casing.

Tools used for evaluation include perforation-

analysis programs, saturation logs, ultrasonic

imaging tools, production logs and economic

analysis. Services that improve completion per-

formance include high-performance reperforating,

sand control—gravel or fracture-packing sand-

control jobs, squeeze cementing and acidizing.

Flow-conduit performance—Wellbore

hydraulics may also limit flow if tubulars are

improperly sized, and if there are unnecessary

mechanical restrictions like tapered strings and

profile nipples, or scale buildups inside the tubing

and casing. Flow efficiency is a function of

restrictions or leaks in wellbore tubulars. Tubing

type, traps, restrictions, erosional velocity and

crossflow can also limit performance efficiency.

Required information may be obtained from

calipers, ultrasonic imaging tools, production

logs, water-flow logs and economic analysis.

Solutions include acidizing, scale removal with

coiled tubing, coiled tubing completions and early

production systems.

Artificial-lift performance—Since flowing

bottomhole well pressure is a function of artifi-

cial-lift efficiency, lifting system problems can

impact well performance. Data useful for perfor-

mance evaluation may be obtained from produc-

tion logs, artificial-lift monitoring and economic

analysis. Services to pull and replace or redesign

rod pumps, gas-lift valves or electric submersible

pumps can remediate performance problems.

• Perforate• Acidize• Fracture• Drill drainholes• Squeeze cement• Control water and gas• Mitigate fines

• Perforate• Reperforate• Acidize• Sand control• Squeeze cement

• Clean out fill• Remove scale• Acidize• Replace tubing• Resize chokes• Eliminate restrictions• Coiled tubing

completions

• Rod pumps• Gas lift• Submersible pumps• Operating conditions

Completionperformance

Actual

Actual

Potential

Potential

2 spf

12 spf

Flow-conduitperformance

Actual

Actual

Artificial-liftperformance

Potential

Flow Rate

Bot

tom

hole

flow

ing

pres

sure

San

dfac

e dr

awdo

wn

Bot

tom

hole

flow

ing

pres

sure

Bot

tom

hole

flow

ing

pres

sure

Potential

Production Gap Solutions

Reservoir performance

■■The components of well performance.

8 Oilfield Review

Production Enhancement Opportunities to enhance production—untapped primary, secondary and tertiaryrecovery—are abundant. On average, lessthan 35% of original hydrocarbons in placeare recovered from millions of wells world-wide. These remaining reserves representone of the best opportunities for operators toimprove production. And this potential oiland gas output is fertile ground for prospect-ing (above). The PE portion of this prize, real-izing an incremental 5% increase nominallyfrom just one out of ten wells for example,could yield billions of barrels in additionalproduction and reserves.

Unlike our automobiles, however, mostwells do not have their filters checked regu-larly. Recall any number of stories, from themid-1980s until today, about oil companiesthat sold mature fields to other operatorswho then significantly improved productionfrom these supposedly unprofitable,marginal or poor assets. Situations likethese—success for one company, disap-pointment for another—are not unique.

Untapped reserves, formation damage andwells that need modern, full-service tune-ups are the factors that combine to makemany assets, some with significant remain-ing reserves, ripe for auction blocks or aban-donment (see “New Life for a North SeaField,” page 10). There are even more wellsand reservoirs that still produce economi-cally which have additional potential waitingto be identified. These opportunities promptoperators and service providers alike to asksuch questions as: In any theater ofpetroleum operations, from the PermianBasin of west Texas with over 100,000 wellsto the North Sea with more than 2000, howmany wells have skin effects that can beeliminated; or could oil and gas output beimproved using new technology, moderntechniques, improved tools and better fluidsystems? Answers to these questions are thebasis for production enhancement.

Because of this industry’s preoccupationwith drilling and production operations, themany recent improvements in well services,and today’s powerful computers and modernsoftware, operators can now take full advan-tage of PE opportunities for the first time.Recently as well as in the past, the industryconcentrated primarily on exploration,drilling, well construction and field opera-tions, assigning lower priorities to produc-tion engineering and well performanceoptimization. Initial flush production, limitedproduction quotas and government-regulated allowables meant that many wells were produced at rates far below theirtrue potential.

■■The PE opportunity. One way to increase production is by looking where oil and gas have already been found. Existing wells withgaps in performance are the target of a focused and aggressive initiative to enhance production. The prize—more stock tank barrels ofoil and greater volumes of natural gas.

Present PEG function

Establish key client contact

Collect well data

Analyze well data

Set goals, objectives and terms

Execute service solutions

Evaluate PE jobs

Evaluate overall project

Make specific proposals

• Analyze production history

• Analyze current performance

• Study enhancement options

■■Typical PEG project loop. Aphased approach with shortcycle times reduces operatorexposure to risk and providestimely feedback.

Because porous formations act as filters,most wells become damaged, or develop asignificant “skin,” at some time during thedrilling and production life cycle. Skin is azone of reduced permeability around thewellbore that causes an excessive pressuredrop across the completion face and limitsfluid flow from the reservoir. Formation dam-age is a natural consequence of well drilling,completion activities and production flow.Drilling mud, completion fluids, crude oil,gas and formation water deposit clay parti-cles, formation fines, asphaltenes, paraffinand scales that can block rock pore spacesand reduce matrix permeability. Damagecan also result from mechanical crushingand compaction of the near-wellbore regionas a result of pressure drawdown.5

5. Economides MJ, Hill AD and Ehlig-Economides C:Petroleum Production Systems. Englewood Cliffs,New Jersey, USA: PTR Prentice Hall (1994): 83-115.

Winter 1997 9

Completions did not have to be optimizedif wells were producing their allocated vol-umes. The only way to obtain higher allow-ables and increase production was to drillmore wells. As a result, optimal completionswere not always a priority. With few excep-tions, however, the days of drilling into giant,prolific, near-darcy-permeability reservoirsare gone. Allowables, quotas and productionlimits are becoming a thing of the past; targetreservoirs are more complex, smaller andtighter—lower permeability; many existingfields, large and small, are in mature stagesof their production life cycle; and older fieldsneed more attention to maintain output andidentify overlooked opportunities.

It Begins With “Where are the Files?” A unique new interaction between operatorand service provider begins when PEG repre-sentatives are allowed access to relevant wellfiles by an oil and gas company. The goal is tocollect and analyze data quickly so that addi-tional information needs can be determinedor specific service proposals can be made(previous page, bottom). This phasedapproach with short cycle times—look atwell files, recommend and execute services,evaluate results, then re-analyze and makeimprovements based on new data—reducesoperator exposure to risk while providingtimely feedback about the effectiveness ofproduction enhancement. When proprietaryclient information and well data are beingused by a local PEG, complete confidential-ity is maintained at all times.

Proactive candidate recognition using theprospecting methodology and PEG analysisfunction is an iterative cycle (right). Data ona given field, reservoir or well are collected,cataloged and evaluated; and any produc-tion anomalies are noted. The best screeningtechniques and software are then used tothoroughly diagnose and assess well produc-tivity in order to identify prospective candi-dates for remedial actions. The PEG softwaretool box—Production Enhancement AnalysisKit (PEAK)—includes Schlumberger andavailable industry programs, but PEG engi-neers are not limited to any particular soft-ware. They can use software that is preferredby a client or other programs with whichthey are familiar.

A minimum amount of information isneeded to perform PCR; and there are usu-

Production history

Current performance

Enhancement options

PEG Analysis Function

Well files

Search throughwell information andproduction histories.

Experience

Identify intuitivelyobvious productionperformance gaps.

Identify productionanomalies through

indexing and mapping.

Field surveillance

No

Yes

No

Yes

Quantify well-performance gaps

NoYes

No Yes

Yes

No

Analyze results versus preditionsand targets. Review this feedback

with the client.

Post-job evaluation

Analysis complete.

PE Prospecting Methodology

DoesNODAL

analysis matchexisting wellproduction

?

Determine the bestengineering solutions.

Report production gapand solution to client.

Oilfield Services company or integratedsolutions group designs, implements and

follows up on specific solutions and services.

Issolution

related solelyto flow-conduitor artificial lift

?

Isthe well

performancegap significant

?

Predict maximum production potentialusing validated well parameters. Analyze adding pay

zones, reperforating, acidizing, fracturing, reentry drilling,installing or changing artificial-lift method, and modifying

flow-conduit tubulars or surface facilities.

Canunknown wellparameters be

obtained from iterativeNODAL production

historymatching

?

Recommend anddesign well testingor wireline logging.

Arethere

sufficient datain the well

files?

Select well files.

Use feedback andnew data as input

for the next analysiscycle.

Reanalyse andoptimize PE efforts.

■■Prospecting methodology and the PEG analysis function. The typical process for analyzing producing zones, identifying well candidates and select-ing solutions is an iterative cycle. Data are catalogued and productionanomalies are noted. Candidate wells are chosen and current output alongwith production history are analyzed. In the enhancement study step, various well service and intervention options are evaluated and prioritizedbased on risks—reservoir and mechanical—and economics.

10 Oilfield Review

Decline-curve projections indicated that production

from the Amoco N.W. Hutton field would fall below

the break-even economic limit of 6000 BOPD

[950 m3/d] in 1996, and signal the beginning of

decommissioning for 1997 (right). This would

have been the first North Sea field to be com-

pletely abandoned, not a comforting prospect in

light of environmental controversy surrounding

other field abandonments and proposed disposal

of their platforms.1

Reservoir studies, however, indicated that fac-

tors other than natural decline could have caused

the poor performance of this field. Most wells

demonstrated significant declines within the first

year of production. Although declines were initially

believed to be the result of reservoir complexity,

further investigation indicated that formation dam-

age and scale in the immediate wellbore region of

productive zones might be a more likely cause.

Productivity also declined after well or field shut-

downs. There was no flush production from

recharging when wells were brought back online;

productivity losses were permanent; and gas/oil

ratios (GOR) remained constant during the initial

decline phase, which was not consistent with struc-

tural compartments. Production below bubblepoint

pressure should cause the GOR to increase, so

drastic declines could not be attributed to pressure

depletion of small drainage areas.

The field production platform was designed to

handle 120,000 BOPD [19,070 m3/d], but actual

production peaked at 83,000 BOPD [13,190 m3/d]

for only a short time. The initial 280 million bbl

[44.5 million m3] estimate of recoverable reserves

had been reduced over the life of the field and pro-

duction averaged 7000 BOPD [1112 m3/d] in 1996.

Only about 120 million bbl [19 million m3], or 24%

of the 487 million STBO [77 million m3] estimated

to be in place originally, had been recovered. Most

of the area’s Brent fields have recovery factors of at

least 40%. Amoco wanted to determine if the sus-

pected damage mechanisms could be successfully

treated and if new technology—sidetracks, confor-

mance control, injection management or stimula-

tion—might improve oil recovery.

GeoQuest Reservoir Technologies for reservoir

technical expertise, Schlumberger IPM for project

coordination and the PEG Production Enhancement

Group located in Aberdeen, Scotland, conducted a

technical review of the field. This evaluation indi-

cated a high probability of significant additional

mobile oil, possibly 20 to 50 million bbl [3 to 8

million m3], remaining to be exploited. The opera-

tor was willing to share incremental value in

return for engineering and services that would

address limited resources, reduce uncertainty and

risk, and facilitate project implementation.

An action plan and commercial proposal were

presented to Amoco and the field partners.

Schlumberger would risk intervention and engi-

neering revenue to enhance field production, man-

age production and development operations, and

optimize reservoir performance. In return, as the

integrated service provider, Schlumberger would

recover costs plus a gain-share compensation

component from incremental oil. For each dollar

invested, an agreed-upon multiple would be paid

back. After the gain-share cap is reached, all rev-

enue reverts to the N.W. Hutton field owners. This

proposal was accepted and the project was initi-

ated in the fall of 1996. The scope of work includes

coiled tubing operations, matrix acidizing, water

shutoff, fracturing, scale management, wireline

logging, testing, perforating, lateral drilling and

reservoir modeling. IPM manages the project,

which is now generating incremental oil revenue.

A three-phase redevelopment plan was pro-

posed with each phase dependent on the success

of the previous work. Investments were staggered

and to some degree self-funding. The first phase

involved rate maintenance and data acquisition.

Scale inhibition was initiated, up-time improve-

ments were made and a production logging pro-

gram was performed. Phase two involved fracture

and diagnostic matrix stimulations to address skin

damage. Conformance and gas-lift optimization

were also initiated. The goal of the third phase is

to generate high-risk, high-reward opportunities to

add reserves through a full reservoir study.

The first and second phases of this project are

under way. Production enhancement stimulations

were undertaken to generate positive cash flow,

demonstrate the potential to produce this field

economically and instill confidence in the pro-

ject’s future. These efforts are also providing data

to supplement reservoir studies that are targeting

options for extending the productive life of the

N.W. Hutton field.

Skin, reservoir description, reserves, pressure

and water chemistry data were used to generate

intervention proposals—candidate recognition.

Four intervention techniques to remove or bypass

near-wellbore damage have been proposed:

New Life for a North Sea Field

■■The Amoco N. W. Hutton field platform in the North Sea UK sector.

Winter 1997 11

ally enough data in the well files. Ideally,available data should include formationevaluation logs, buildup or production tests,and a well history. In addition to well logs, orif logs are not available, field net-porosityand net-hydrocarbon-thickness maps may beused. Ideally, both logs and maps should beused, and in some cases, seismic data maybe helpful. New wireline formation evalua-tion logs may be needed to verify productionpotential. When there are no production orwell-test data, new pressure buildup or pro-duction well testing are often recommended.If well data are incomplete, it may be possi-ble to “back into” well and reservoirunknowns by iterating through a NODALanalysis until a good fit with known parame-ters is obtained. This type of analysis can bestbe described as reverse, or inverse, engi-neering. Typically, relevant data are gatheredand compiled in a spreadsheet or database.

Candidate recognition may include calcu-lating skin and damage effects, determiningproduction potential at a reduced skin,quantifying available reserves, running eco-nomic evaluation and making recommenda-tions based on risk versus return or costversus benefit. Current well output is ana-lyzed along with production history and theeffects of various PE options. Additional for-mation evaluation logs may help verify pro-ductivity before economic and risk analysesare performed.

Analyzing current performance using thebest available data establishes the most likelyreservoir parameters for a well. If build-up ordrawdown tests are available, transient-pres-sure-analysis programs help calculate pres-sure, permeability, skin and reservoirboundaries. Four-point and backpressuretests can be used to determine initial reser-voir pressure. Iterative NODAL analysis canalso be used to match pressure and perme-ability, and obtain skin at a given time. Themost useful skin information comes fromrecent time. “Snapshots” of a well produc-tion system can be obtained at the start ofproduction, before a well is put on gas lift orrod pump, after a well is put on artificial lift,and at current rates. These reference pointsinclude reservoir pressure, wellhead pres-sure, production rates—oil, gas and water—skin and cumulative production.

Since the objective is to predict futureoutput, only production rates at the presentskin value are important. This means thatcumulative production since the last signifi-cant event that altered the skin is all thatneeds to be examined. Data are normalizedby selecting this event as the initial time.Cumulative time and oil, gas and water pro-

duction can be calculated from this point.Initial pressure—reservoir pressure at thetime of that event—is derived from materialbalance programs.

Production history analysis is used to verifythe current performance analysis. Generalmaterial balance programs with single-layermodel solutions for homogeneous reservoirsquickly evaluate reservoir performance andobtain reliable initial pressure estimates,pore volume and average aquifer-waterinflux rate. Sensitivity analysis can beperformed with these models to evaluatedrainage area, initial pore pressure and the influence of water influx on reservoirpressure history. Once a satisfactory pro-duction history match is obtained andunknown parameters are determined, thesemodels can help forecast future well perfor-mance and recovery by extrapolating fromprevious production to an average reservoirpressure or time using conventional rate-decline relationships.6

Other programs and production-historyanalysis are also used to model wells andcheck values obtained using NODAL analysisand material balance programs. Programsthat give a continuous production picture,rather than just a few snapshots over time,can be particularly helpful. NODAL analysissoftware is used to match production at sev-eral times during the productive life of a well,and these reference points are used to verifythe production history model. Excellentmatches between estimates and real dataprovide confidence in well model validityand the accuracy of their predictions.

At this stage, it may be evident that moredata or full reservoir simulation are neededto determine candidate economic viability.Not all production gaps can be addressedthrough candidate recognition with theprospecting methodology. Some problemsdo take weeks or months to solve, and PEGengineers must recognize these problemsand refer them to reservoir study groups for evaluation.

Once required well data are compiled, thenext step is to study enhancement options,which establishes viable PE alternatives, andthe production increases and economic ben-efits associated with them. After all of thesesteps are applied to the wells being consid-ered, PE candidates are prioritized in termsof risk versus net-present-value (NPV) eco-nomics, and appropriate recommendationsand well interventions are selected, designedand executed. The final step in this process is

scale dissolver treatments to address barium sul-

fate deposition in the rock matrix, diverted acid

stimulations to treat calcium-carbonate scale and

fines migration, tip screenout hydraulic fracturing

and short coiled tubing drilled laterals to bypass

skin damage.

Three of the four proposed well interventions to

remove or bypass skin—scale inhibitor, acid and

fracturing—have been applied, resulting in signif-

icant improvement in well productivity. Prior to

fracturing, one candidate well produced at a rate

of 700 BOPD [111 m3/d]. Three weeks after the

stimulation treatment, the well was producing

about 3200 BOPD [510 m3/d]. Scale dissolver and

acid treatments have also been successful. More

than 500 BOPD [80 m3/d] of additional oil produc-

tion were realized from one well. The criterion to

begin phase three, a goal of 6000 BOPD incre-

mental production, was achieved and surpassed.

The Amoco and GeoQuest Reservoir Technolo-

gies team is revising N.W. Hutton reservoir

descriptions and evaluating development scenar-

ios that will increase the value of this field by

improving productivity. The proposed redevelop-

ment includes production enhancement, well

construction and project management efforts

aimed at improving production and increasing

reserves through application of leading-edge tech-

nologies. It will be managed and coordinated by

IPM working in conjunction with the Schlumberger

Oilfield Services companies.

The organization and process were developed

jointly by Amoco and Schlumberger to create an

alliance structure and contractual provisions that

are equitable and beneficial to all parties. The

alliance approves budgets and proposals consistent

with the strategies of both the operator and the ser-

vice company. Sharing financial risks and rewards

through value-pricing results in a high degree of

alignment between companies and refocuses

efforts and resources on achieving common goals.

1. Comrie P and Olsen T: “A Risk Sharing Alliance BreathesNew Life into a Mature North Sea Field,” paper SPE 38822,presented at the 65th SPE Annual Technical Conference andExhibition, San Antonio, Texas, USA, October 5-8, 1997.

6. Economides MJ, Hill AD and Ehlig-Economides C:Petroleum Production Systems. Englewood Cliffs, New Jersey, USA: PTR Prentice Hall (1994): 187-205.

12 Oilfield Review

to compare actual results to predicted out-comes and carefully analyze the details ofthis feedback. Results—successes and fail-ures—are evaluated, reviewed with theclient and then used as additional input inanother cycle of the PEG analysis process.Out of 100 wells, for example, a PEGevaluation might find as many as 10 poten-tial candidates. Successful interventions on these wells may then generate additionalPE opportunities.

The PEG process, which is always appliedone well at a time, is used for individual sin-gle-well evaluations, but is perhaps mostsuccessful when employed to analyzegroups of wells or a field. This allows engi-neers to look at a statistically significantnumber of wells, which can compensate forsome unsuccessful jobs and help ensureoverall project success. Wellbore mechani-cal modifications on some of the wells beingevaluated may also improve production andcontribute to overall production enhance-ment success.

Why Proactive? Candidate recognition performed proac-tively is the antithesis of chance occur-rence—waiting until wells go off line ordrop below economic limits before initiat-ing action. Another reason to take advantageof PCR is synergy, those actions taken jointlyto increase overall effectiveness beyond thesum of their individual effects. Productionenhancement efforts create a partnership, orteam, often based on a handshake agree-ment, consisting of the client and a localPEG organization working together withSchlumberger Oilfield Services companies(above right). Cooperation between thesegroups, in concert with advanced technolo-gies and well servicing methods, can beeffectively employed to improve productionfrom existing wells.

With the exception of tubulars, downholeequipment and other stock warehouse parts,Schlumberger provides services from discov-ery to depletion, including seismic surveying,data processing and interpretation, drilling,well logging, perforating, well testing,cementing, acidizing, fracturing, and coiledtubing or abandonment services. And manyof these applications—cleaning out fill, per-forating or reperforating, logging, interpretingand evaluating data to find more pay, acidiz-ing to remove damage, fracturing to createconductive flow paths, water and gas control,and infill, directional, horizontal or lateraldrilling—are directly related to moving IPRcurves and increasing productivity.

The style of proactive PEG evaluations isquick—hours and days, not weeks andmonths—and action oriented, generatingspecific recommendations to be imple-mented, not reports or studies to be read andreviewed. In most cases, these “action” plansare a simple list of wells, or sometimes a sin-gle spreadsheet page, with recommenda-tions to gather more data or apply a specificsolution, technology, service or integratedapplication (next page).

Among the short-term benefits of produc-tion enhancement, PCR generates candi-dates for well interventions, demonstratesproduction potential for added confidence inwell or field viability and provides additionalcash flow for funding further productionenhancement. The long-term upside poten-tial includes maintaining profitability,increasing asset value and extending well orfield productive life.

But why are operators allowing PEG repre-sentatives access to their prized well files?One answer lies in leveraging the best mix ofknowledge, experience and technicalresources to address production engineering.Another reason is that E&P company person-

nel have a limited amount of time, which canoften be taken up by higher priorities likedrilling new wells and maintaining theirmore prolific producing properties. It can bedifficult to consistently maintain effectivesurveillance, perform production engineeringand identify opportunities across an entireasset portfolio, and still keep up with the lat-est techniques and technological advances.In addition, it is helpful to have input fromexperts who look at production enhancementopportunities and potential well productivityfrom different points of view.

Unlike the period following oil price col-lapses in the 1980s, experienced service per-sonnel are now available to undertake PEprojects. Over the past several years, servicecompanies, including Schlumberger andHalliburton, have been among the toprecruiters of petroleum engineers. In addi-tion to filling entry-level technical positions,these companies are also adding mid-careerprofessionals, many with oil company andconsulting backgrounds, that expand the ser-vice sector experience base.

Integrated Services

Dowell

Geco-Prakla

Anadrill GeoQuest

Sedco Forex

SchlumbergerWireline &

Testing

PEG and client

■■Cooperation andintegrated services.Production enhance-ment involves apartnership, or team,made up of theclient and a localPEG organizationplus applicableOilfield Servicescompanies. Whencoupled with inte-grated service com-pany advancedtechnologies, jointactions taken bythese groups cansignificantly improveproduction fromexisting wells.

Winter 1997 13

Commentsand

recommend-ations

Clean out filland acidizePressure buildup test and acidizeClean out filland acidizeRepair tubing,clean out fill,pressurebuildup testand acidizeClean out filland acidizeClean out filland acidizeBuildup test and acidizeBuildup test,clean out filland acidize

Phase 1 Candidate Recognition: Gulf of Mexico Acid Treatments

Buildup analysis Current production PEG prediction

Well Reservoir Reservoir Permeability, Wellhead Oil Water rate Gas NODAL NODAL Wellhead Target Skin Incrementalzone pressure, mD pressure, rate, B/D rate, analysis analysis pressure, oil rate, oil

psig psig B/D Mscf/D skin maximum psig B/D production,oil rate, B/D B/D

1 A 1844 60 250 70 2 30 20 150 300 120 10 50

2 A 1640 180 — 250 62 198 25 550 — 400 10 120

11 B 1844 60 250 50 26 44 35 175 300 110 10 60

21 C Partially collapsed tubing 35 0 121 — 175 — — — 140repair 35

andacid job 105

31 D 1844 60 250 70 1 8 25 Unkown 300 120 10 50

32 D 1160 170 375 60 15 2 30 130 460 110 10 50

33 D 1715 226 550 200 194 121 40 310 700 350 15 150

34 D Based on well production history 40 117 — — 120 — — — 80

Incremental enhanced production total: 700

■■Action plans. The final product of a PEG analysis is often a simple, one-page list of wells, sometimes in spreadsheet format, with specificsolutions and recommendations about actions, services or integrated applications that need to be performed to enhance production.

Proactive Candidate Recognition Screening: West Texas

Potential production enhancement opportunities

Well Zone Limited Lack of Inadequate Injecting Poor Fill across Fractured in Comments and PEdrainage waterflood stimulation above artificial-lift pay zone the direction recommendations

area fracture performance of another well pressure

21 Lower and Possible Yes Water control and evaluate

middle rod pump performance

25 Upper Yes Replace, resize

rod pump

36 Upper Yes Yes Drill or convert injector

and water control

50 Upper Yes Yes Drill or convert injector

and acidize or fracture

104 Upper Yes Yes Clean out fill and acidize

or fracture stimulation

106 Upper Yes Yes Clean out fill

and water control

148 Lower Yes No additional potential

201 Lower Possible Possible Evaluate stimulation

and middle and rod pump

performance

204 Lower Possible Yes Water control and

and middle evaluate stimulaton

14 Oilfield Review

Current PEG teams include the talents,expertise and experience of petroleum engi-neers with PhD degrees, and some topexperts and specialists in key productionengineering disciplines. SchlumbergerOilfield Services also recently acquired S. A.Holditch & Associates, Inc., College Station,Texas, a worldwide petroleum engineeringcompany that offers consulting services inwell stimulation, completion design andreservoir analysis. This acquisition broadensthe range of production enhancement activ-ities and reservoir engineering services thatcan be provided to operators.

Proactive candidate recognition can beperformed solely by PEG specialists, butperhaps works best as an operator-Schlumberger team approach. Oil companypersonnel are most familiar with the overallproduction history and reservoir view, butintegrated service providers invest time andmoney for research to commercialize newtechnology and, therefore, are knowledge-able about specific applications of the tools,methods and services that are developed. Asa result, PEG engineers review well files anddata from a fresh perspective and mayrecognize opportunities to apply specifictechniques, unique combinations of tech-nologies or an integrated solutions approachthat might otherwise be overlooked.

Result-Based Experience Typical well interventions for productionenhancement include jobs that address thefull range of performance-gap components.Reservoir- and completion-related interven-tions, however, usually represent most of thejobs and dominate the mix (above right). Theremaining well productivity gaps are theresult of artificial lift and tubing perfor-mance. Reservoir IPR curves can be movedand productivity gaps can be closed by: • finding bypassed pay • perforating • acidizing • fracturing • drilling laterals. Since being established in 1990, the PEGorganization has worked to improve pro-duction and increase reserves for clientsthrough PCR and the production en-hancement process using these types of wellinterventions.7

Recompleting older wells using new meth-ods may be what is needed to improve pro-ductivity. Oil and gas technology hasimproved by orders of magnitude over thepast 15 years, and many of today’s producing

wells were drilled and completed beforethese newer techniques were in full use. Justten years ago, completion and stimulationpractices were not as effective as they aretoday. Research and development have pro-vided innovative new technologies that, on awell-by-well basis, can greatly increase pro-duction and improve recovery.

Finding additional pay—For example, rein-terpreting existing logs, pressure-buildupand production well testing, and new tech-nologies for evaluating formations, includingdeep-investigating logs, azimuthal and bore-hole imaging logs, multiprobe formationtesters, cased-hole logs and modern transienttests, are critical for analyzing and diagnos-ing wells. Early production facilities can alsobe used to get first oil and gas sooner, andimprove initial field development eco-nomics.8 Advanced perforating, acidizingand fracturing methods, and coiled tubingservices are key techniques to increase pro-duction, along with horizontal or multilat-eral reentry drilling. Modern computercapabilities also play a vital role, facilitatingand supporting these oilfield serviceimprovements and developments.

Several PE activities help identify addi-tional pay or bypassed productive intervals.Surveillance methods, like net-porositymapping and hydrocarbon indexing, can beused to locate behind-pipe productionpotential in existing fields (next page, top).Older logs can be reevaluated or interpretedusing new techniques, or modern wirelinelogs can be run to acquire more information.Recompletions can tap bypassed hydrocar-bons. In one case, an old electric log wasreviewed to identify possible zones of inter-est. Through-casing potential was determinedby running a Dual-Burst TDT Thermal DecayTime log and performing an ELAN ElementalLog Analysis evaluation. A previously undis-covered gas zone was perforated with athrough-tubing Enerjet gun. The new zoneproduced 770 Mscf/D [22 Mscm/d] and paidout in eight days (next page, bottom).

Reservoir

8%

25%

Artificial lift

65%

Flow conduit

Completion

2%

■■Typical well candidates. The majority of PE wellinterventions in North America fall into the reservoirand completion performance gap categories.

7. Tremble PT and Haskall J: “Production ReviewsPayout Quickly for Two Texas Operators,” Oil andGas Journal 93, no. 7 (February 13, 1995): 60-63.

8. Baustad T, Courtin G, Davies T, Kenison R, Turnbull J,Gray B, Jalali Y, Remondet JC, Hjelmsmark L, OldfieldT, Romano C, Saier R and Rannestad G: “CuttingRisk, Boosting Cash Flow and Developing MarginalFields,” Oilfield Review8, no. 4 (Winter 1996): 18-31.

Winter 1997 15

10 20 30 40 50 60

Potential candidates for production enhancement

0

10

20

30

40

50

60

70

70

0

40+

35 to 40

31 to 35

26 to 31

22 to 26

17 to 22

13 to 17

8 to 13

4 to 8

Unperforatedhydrocarbon

index, ft

■■Reservoir surveillance.Methods like porosity map-ping and hydrocarbonindexing help locatebehind-pipe productionpotential in existing fields.

Processed TDT Thermal Decay Time log

PHITSIGM

FluidAnalysis

SW

5000

1953 Electric log

PHIC60 p.u. 0

GR0 API 150

0 API 50 60 p.u. 0

100 p.u. 075 p.u. 100

0 p.u. 100

ELAN Elemental Log Analysis

5100

No gas show

5000

5100

770 Mscf/D

New zone

■■Finding new pay zones. New formation evaluation tech-niques—logs and processing software—also locate bypassedoil and gas. A previously undetected zone produced 770Mscf/D [22Mscm/d] and paid out in eight days.

16 Oilfield Review

Perforating—Modern perforating guncharges make bigger holes in casing andpenetrate deeper than older versions.9 Wellscompleted with charges that penetrated 12 in. can now be reperforated with gunsthat create tunnels more than 26 in. intoformations. Entry-hole diameters larger than3⁄4 in. can be obtained compared to less than 1⁄2 in. in the past. Perforating chargeperformance can also be designed and pre-dicted with greater accuracy and confi-dence.10 In addition, new techniques likeextreme overbalance perforating (EOP)offer innovative and unique ways toenhance well productivity.10

Adding perforations using a through-tub-ing expendable Enerjet gun increased reser-voir inflow performance and the additionalproduced gas improved flow-conduit liftperformance. NODAL analysis indicatedthat well output could potentially be closeto 300 BOPD [48 m3/d]. Production fromthis offshore Louisiana well was enhancedfrom 22 to 260 BOPD [3.5 to 41m3/d]. Theclient accepted a value-pricing arrange-ment and agreed to pay a percentage overexisting contract prices if this PE well inter-vention broke even sooner than the esti-mated payout. Schlumberger agreed toshare some risk by agreeing to receive mar-ket price less 20% if the job took longer topayout. Total job costs were recouped injust 12 days and the operator paid a 30%value-price premium (left).

In another example, reperforating withhigh-performance charges can increase pro-duction and realize the predicted productionpotential of wells. Deep-penetrating perfora-tions or larger entry holes reduce drawdownacross the completion. Analysis of a well ina dolomite oil reservoir in Texas indicated a 6-in. damage zone with a 0.85-mD perme-ability. The 1.6-mD dolomite reservoir was20 ft [6 m] thick with an 8500-psi reservoirpressure. The well was completed by perfo-rating with a casing gun and tested at 55BOPD [8.7 m3/d] rate. When reperforatedusing an expendable through-tubing gun, thewell produced 148 BOPD [23.5 m3/d].NODAL analysis predicted that this wellshould be capable of making 270 BOPD [43m3/d] (next page, top). A recommendation toshoot the well with a Pivot Gun perforatorresulted in a rate of 277 BOPD [44 m3/d].

Pre

ssur

e, p

sig

4000

500

3000

2000

1000

0100 200 300 4000

Liquid rate, B/D

Offshore Louisiana

Productivity gap

Adding perforations increases reservoir performance

Initial flow-conduit performance

Additional gas improves flow-conduit performance

Initial reservoir performance

■■Adding perforations. Additional perforations improved production from this offshore Louisiana well. Increased gas production also improved flow-conduit liftingperformance. The 12-day payout for this PE job was less than the initial estimate,resulting in a 30% price premium.

9. Jimenez M Jr: “Tests Reveal Perforating ChargePerformance,” Oil and Gas Journal 90, no. 1(January 6, 1992).Smith PS, Behrmann LA and Yang W: “Improvementsin Perforating Performance in High CompressiveStrength Rocks,” paper SPE 38141, presented at theSPE European Formation Damage Conference, TheHague, The Netherlands, June 2-3, 1997.

10. Karakas M and Tariq S: “Semi-Analytical ProductivityModels for Perforated Completions,” paper SPE18271, presented at the 63rd SPE Annual TechnicalConference and Exhibition, Houston, Texas, USA,October 2-5, 1988. Cole E Jr: “Normalize Data for Better Shaped ChargePrediction,” Petroleum Engineer International 63, no.1 (January 1991): 37-43.Halleck PM, Wesson DS, Snider PM and NavarettaM: “Prediction of In-Situ Shaped Charge PenetrationUsing Acoustic and Density Logs,” paper SPE 22808,presented at the 66th SPE Annual TechnicalConference and Exhibition, October 6-9, 1991. Cosad C: “Choosing a Perforating Strategy,” OilfieldReview 4, no. 4 (October 1992): 54-69.

Ott RE, Bell WT, Harrigan Jr JW and Golian TG:“Simple Method Predicts Downhole Shaped-ChargeGun Performance,” SPE Production Facilities 9, no. 3(August 1994): 171-178. Brooks JE: “A Simple Method for Estimating WellProductivity,” paper SPE 38148, presented at the SPEEuropean Formation Damage Conference, TheHague, The Netherlands, June 2-3, 1997. SPAN Schlumberger Perforating Analysis version 5.0,Schlumberger Perforating & Testing documentation,Rosharon, Texas, USA (1997).

11. Behrmann LA and McDonald B: “Underbalance orExtreme Overbalance,” paper SPE 31083, presentedat the SPE International Symposium on FormationDamage Control, Lafayette, Louisiana, USA,February 14-15, 1995. Behrmann L, Huber K, McDonald B, Couet B, DeesJ, Folse R, Handren P, Schmidt J and Snider J: “QuoVadis, Extreme Overbalance?” Oilfield Review8, no.3 (Autumn 1996): 18-33.

12. Crowe C, Masmonteil J, Touboul E and Thomas R:“Trends in Matrix Acidizing,” Oilfield Review4, no.4 (October 1992): 24-40. Economides MJ, Hill AD and Ehlig-Economides C:Petroleum Production Systems. Englewood Cliffs,New Jersey, USA: PTR Prentice Hall (1994): 347-389, 391-420.

Estim

ated

pay

out

Market price plus 30%

Market price less 20%

Market price

Com

pens

atio

n fo

r se

rvic

es

Payout time

Winter 1997 17

Acidizing—Stimulation technologies havebeen improved as well. Today’s acid systemsremove damage more effectively, and thesematrix treatments can be designed, placedand diverted with greater efficiency.12

Matrix acid jobs reduce skin and improvewell productivity. In south Texas, a matrixacidizing treatment was used to stimulate anEdwards Lime well with 40 ft [12 m] of 1-mD gas pay and 2200-psi bottomhole pres-sure. Gas production before acidizing was750 Mscf/D [21 Mscm/d], but NODAL anal-ysis predicted that production potential fromthis well was 1270 Mscf/D [35 Mscm/d](right). Actual production after a FoamMatacid treatment was 1400 Mscf/D [40Mscf/d], almost a two-fold increase.

0 250 500 750 1000

0

2500

5000

7500

10000

Production rate, B/D

Flow

ing

wel

lhea

d pr

essu

re, p

sig

IPR before reperforating

Productivity gap

IPR after reperforating

Flow conduit

NODAL Production

System Analysis ModelWell: Dolomite reservoirLocation: Texas

8-in. perforation length22-in. perforation lengthAbsolute open-flow potential

■■Reperforating. NODAL analysis predicted that this well could produce 270 BOPD. After perforating with a Pivot Gun perforator the well tested at a 277-BOPD rate.

0

Production rate, Mscf/D

IPR before acid

Flow conduit

500 1000 1500 2000

IPR after acid

0

750

1500

2250

10000

Flow

ing

wel

lhea

d pr

essu

re, p

sig

NODAL Production

System Analysis ModelWell: Edwards LimeLocation: Texas

Skin = 3Skin = 1Absolute open-flow potential

Productivity gap

■■Acidizing. A south Texas gas well produced 1400 Mscf/D after a FoamMat acid treatment. Before acidizing, production was 750 Mscf/D. NODAL analysis estimated potential production at 1270 Mscf/D.

18 Oilfield Review

800

Bot

tom

hole

pre

ssur

e, p

sig

2500

2000

1500

1000

500

0100 200 300 400 500 600 700

Productivity gap

Venezuela

0

Total liquid rate, B/D

Inflow performance relationship (IPR)Gas-lift performance

■■Drilling lateral drainholes. A well in Lake Maracaibo, Venezuela, had not producedsince 1986 because of mechanical wellbore problems—junk in the hole. NODAL analysispredicted 275 BOPD from a 70-ft lateral sidetrack. The well actually produced 250 BOPDand paid out in 13 months.

NODAL Production

System Analysis Model

0

Production, Mscf/D

WELL: WilcoxLOCATION: Texas

500 1000 1500 2000

0

2500

3750

5000

Flow

ing

wel

lhea

d pr

essu

re, p

sig

1250

IPR after fracturing

Productivity gap

IPR before fracture fracturing

1000-psi wellhead pressure 2600-psi wellhead pressure

■■Fracturing. A low-permeability gas well was shut in. NODALcalculations estimated post-fracture stimulation potential to be550 Mscf/D. After fracturing the well produced 600 Mscf/D.

Winter 1997 19

Fracturing—Today’s fracture stimulationsuse cleaner fluids and more effective prop-pants to provide the most conductive pathpossible from the formation to the well-bore.13 Retained fracture permeabilities, forexample, have been increased from lessthan 10 to several hundred darcies.

Fracture stimulation treatments createconductive paths from the formation intothe wellbore. In low-permeability reser-voirs, propped fractures serve as a highwayfor hydrocarbons. NODAL production sys-tem analysis for another south Texas wellpredicted that the Wilcox formation couldproduce 550 Mscf/D [16 Mscm/d] at a2600-psi wellhead pressure after fracturing(previous page, top left and right). This wellpenetrated 45 ft [14 m] of 0.09-mDformation and had a reservoir pressure of4500 psi. The well would not produce ini-tially, but made 600 Mscf/D [17 Mscm/d]after the fracture stimulation.

Drilling laterals—Reentry drilling technol-ogy, such as RAPID Reentry And ProductionImprovement Drilling, has also developed tothe point where horizontal and multilateralwells provide options for tapping bypassedreserves from existing wellbores.14 And mod-ern coiled tubing techniques can unlock thepotential of these high-angle or horizontal

wells, not only through drilling but also byefficiently conveying logging tools and plac-ing stimulation fluids.15

In Lake Maracaibo, Venezuela, NODALanalysis forecast that a 70-ft [21 m] sidetrackwould produce 275 BOPD [44 m3/d] (previ-ous page, bottom and below). This well hadbeen shut in since 1986 because of mechan-ical wellbore problems—a lost fish or junk inthe hole. After the sidetrack was drilled, thiswell produced 250 BOPD [40 m3/d]. Thepayout for this production enhancementintervention was 13 months.

Computer and communications capabili-ties have advanced as well. A little more than10 years ago, personal computers were usedalmost exclusively for word processing.Today, these computers provide the compu-tational horsepower for engineering pro-grams that help select, design and evaluatewell interventions. Previously, reservoir andproduction calculations were time consum-ing, made by hand or on massive mainframecomputers. Now, service company represen-tatives can quickly forecast the effects ofcompletion and stimulation actions withportable laptop computers while sittingacross the desk from clients in their offices.Reservoir surveillance capabilities, datamanagement and information technologyhave also improved.16

In most PEG evaluations, the overall reser-voir development plan is fixed, but produc-tion enhancement may be an integral part ofmore extensive reservoir management pro-jects that are directed at optimizing field,production and reservoir performance. Dataand results from the PE process also provideinsights and input for further detailed reser-voir studies and simulation. On larger, com-plex projects, like the Amoco N.W. Huttonfield, production enhancement during earlystages can jump-start oil and gas productionand boost income to help generate funds forinitial remedial efforts. Efforts to improveproductivity should not be directed solely atmarginal wells, completions on the struc-tural flanks of fields or areas with limited payor potential. Like fracture stimulation wellcandidates, the best producers often makethe best PE prospects. Each well should beevaluated to determine if it is producing at itsfull potential.

13. Brady B, Elbel J, Mack M, Morales H, Nolte K andPoe B: “Cracking Rock: Progress in FractureTreatment Design,” Oilfield Review 4, no. 4(October 1992): 4-17. Hanna B, Ayoub J and Cooper B: “Rewriting theRules for High-Permeability Stimulation,” OilfieldReview 4, no. 4 (October 1992): 18-23. Economides MJ, Hill AD and Ehlig-Economides C:Petroleum Production Systems. Englewood Cliffs,New Jersey, USA: PTR Prentice Hall (1994): 421-456, 457-494, 495-521. Armstrong K, Card R, Navarrete R, Nelson E,Nimerick K, Samuelson M, Collins J, Dumont G,Priaro M, Wasylycia N and Slusher G: “AdvancedFracturing Fluids Improve Well Economics,” OilfieldReview 7, no. 3 (Autumn 1995): 34-51. Chase B, Chmilowski W, Marcinew R, Mitchell C,Dang Y, Krauss K, Nelson E, Lantz T, Parham C andPlummer J: “Clear Fracturing Fluids for IncreasedWell Productivity,” Oilfield Review 9, no. 3 (Autumn1997): 20-33.

14. Hill D, Neme E, Ehlig-Economides C and MollinedoM: “Reentry Drilling Gives New Life to Aging Fields,”Oilfield Review8, no. 3 (Autumn 1996): 4-17.

15. Ackers M, Doremus D and Newman K: “An EarlyLook at Coiled-Tubing Drilling,” Oilfield Review 4,no. 3 (July 1992): 45-51. Bigio D, Rike A, Christensen A, Collins J, HardmanD, Doremus D, Tracy P, Glass G, Joergensen NB andStephens D: “Coiled Tubing Takes Center Stage,”Oilfield Review 6, no. 4 (October 1994): 9-23.

16. Baker A, Gaskell J, Jeffery J, Thomas A, Veneruso Tand Unneland T: “Permanent Monitoring—Lookingat Lifetime Reservoir Dynamics,” Oilfield Review 7,no. 4 (Winter 1995): 32-46. Beham R, Brown A, Mottershead C, Whitgift J, CrossJ, Desroches L, Espeland J, Greenberg M, Haines P,Landgren K, Layrisse I, Lugo J, Morean O, Ochoa E,O’Neill D and Sledz J: “Changing the Shape of E&PData Management,” Oilfield Review9, no. 2(Summer 1997): 21-33. Arango G, Colley N, Connelly C, Greenes K, PearseK, Denis J, Highnam P, Durbec C, Gutman L, SimsD, Jardine S, Jervis T, Smith R and Miles R: “What’sin IT for Us?” Oilfield Review 9, no. 3 (Autumn 1997):2-19.

20 Oilfield Review

Turning Cost into Revenue An important aspect of production enhance-ment and the PEG function, in addition toactively prospecting for well candidates, isundertaking projects on a contingency, risk-reward or value-price basis. Until recently,charges for well services were usually basedon service cost or prevailing market rates.But compensation for integrated, solution-based services that deliver an incrementallygreater return can also be based on perfor-mance, benefits or the extra value gener-ated—value pricing (right). Value pricingmakes sense when customized solutionsresult in measurable savings or increasedincome that is quantifiable and differentiatedfrom other products, services or methods.

Helping clients meet incremental produc-tion targets is the foundation for customizedsolutions and contingency payments orresult-based rewards (below right). For risk-ing some service revenue down to a lowercost limit, Schlumberger receives a fair shareof the added value generated by PEG recom-mendations. Operators share this additionalvalue, up to a reward cap, in return forreduced financial exposure, technology andservice resources, and a mutual workingarrangement that helps overcome risk andtechnical obstacles, resistance to applyingnew technology and pricing fixations thatare left over from the low-bid days andindustry downturns of the past decade. Thisapproach focuses on generating, measuringand sharing greater value.

Payment for PEG recommendations could,for instance, be calculated based on incre-mental production. The operator might share50% of incremental production, after payingtaxes and royalties, for a mutually agreeableperiod of time. In short, to the extent that ser-vices provide two dollars of extra value, theclient shares some amount less than a dollar.Compensation can also be based on job suc-cess using a sliding scale. Payments for ser-vices can be determined by multiplyingmarket or alliance price rates by a predeter-mined percentage (next page, top left). Theoperator could agree to pay market rates orless for services that are unsuccessful or formarginal production increases. Successfuljobs that return large increases in productionwould be invoiced at higher percentages.

Schlumberger

Cost and market-driven pricing

Value pricing

Products and

services

Cost Price Sales Customers

Clients Production enhancement opportunities

Schlumberger

Customized products

and integratedsolutions

Share rewards and risks based

on added value

■■Costs versus solutions. Value pricing moves customers and solutions forward in the serviceprocess. Customized solutions emphasize production not low-bid jobs and can generategreater value for both operators and an integrated service provider like Schlumberger.

Reward cap

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■■Sharing risk and value. In value-pricing arrangements, operators share the rewards, up to a cap, from projects that enhance production, add reserves, improve efficiency orincrease service quality. For risking some service revenue, down to a limit, Schlumbergergets a fair share of this value. Value pricing makes sense if customized solutions, differenti-ated from other products and services, deliver measurable savings or increased revenue.

Winter 1997 21

Value-based pricing and contingent pay-ment philosophies help buyers and serviceproviders think, act and make decisions interms of value rather than price, and there-fore concentrate on optimum solutions andresults instead of the lowest price tools andservices. When Schlumberger as an inte-grated service company is given the task ofhelping operators achieve a target incremen-tal production, NPV or return-on-investment(ROI) in exchange for a fair share of incre-mental production, costs are more effectivelyturned into revenue. The result is a new focuson the outcome, production to be generatedand value that is provided instead of the cost,or expense, of services. Focusing on produc-tion generates more revenue and, as a result,additional value for both the client and theintegrated service company.

The service sector, now more than ever, isable to assume more responsibility for pro-duction operations. A complete range ofSchlumberger service capabilities is avail-able to deliver customized solutions, andmanage well construction, productionenhancement interventions, field operations,major projects and reservoir performance(above right). But the blurring of traditionalboundaries between clients and serviceproviders can be complicated. Schlumbergerbelieves that service companies should beindependent, maintaining consistent rela-tionships with all clients. Actions that mightresult in overlap, confusion and potentialconflicts of interest are avoided even whensharing risks and rewards.

Integrated service providers should becompensated for service quality, perfor-mance and the value that is delivered, butwithout taking an equity position in oil andgas assets. Value-pricing ensures that the ser-vice provider is fairly compensated for inte-grated skills and services, such as productionenhancement, project management andreservoir optimization, and ensures that theextra value generated by customized solu-tions is distributed equitably.

What Does the Future Hold? In the arsenal of services available to oilcompanies, production enhancement israpidly gaining acceptance. The future forPEG includes expansion into more marketsand continuing advances in computer capa-bilities and data management. Candidaterecognition, including well monitoring andevaluation, will become more automated.Real-time data measurement, communica-tion and management tools—like theWellWatcher system—will help track surfaceand subsurface parameters, such as temper-ature, pressure, flow rate and fluid densities,and then transmit this information to opera-tor offices continuously or on command.

The Production Enhancement Analysis Kit(PEAK) will be further developed into atightly integrated reservoir and productionengineering software support package. Andfinally, production enhancement efforts willbe further integrated with future well con-struction, project management, reservoirenhancement, field study and reservoir man-agement processes.

Increasingly, efforts by PEG teams may alsobe an integral element in larger projects. As alogical next step in new business relation-ships between clients and service companies,production enhancement can be a startingpoint to further expand integrated productionmanagement and customized service solu-tions. Operators benefit from improvedproduction, reduced risk and more effectiveuse of service sector knowledge and experi-ence. As the integrated service provider,Schlumberger gets an improved return forservices rendered and an expanded marketfor solutions, services and tools, in additionto more opportunities to prove new tech-nologies and ideas, demonstrate integratedservices concepts and gain experience.

On a daily basis, oil and gas operatingcompanies must deal with many existingwells and reservoirs while trying to improveor maintain output from an increasing num-ber of new wells. Proactive efforts to opti-mize the productivity of client-operatedwells through production enhancement arehelping to get the most value out of existingwells. This engineering methodology breaksdown traditional barriers between petroleumdisciplines as well as producers and inte-grated service companies, providing a moreopen exchange of information that results inadditional production, increased recoveriesand the sharing of value. —MET

Incremental production

0 to 10

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Price for services

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MR

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MR – Market rate or alliance priceQs – Stabilized rate per day or month after PE jobQi – Initial rate per day or month before PE job

■■A sliding scale. Prices for PE servicescan be based on job success. Operatorspay market price or less for marginalproduction increases or unsuccessfuljobs. But they would share the valuefrom successful jobs by agreeing to paya percentage above cost-based marketor alliance rates for services.

Individual services

Integrated solutions

Candidate recognition

• PEG–PCR• DESC–PE

Field support

• Interpretation, development (ID)• Area engineers (AE)• Custom solutions teams• RAPID reentry drilling

Reservoir studies

• Well studies• Reservoir studies • Field studies

Reservoir management

• Integrated project management• Integrated reservoir optimization

Well Field

■■The spectrum of integrated solutions and customized services.