4

Reentry Drilling Gives New Life to Aging Fields

A recent burst of technical creativity has produced an abundance of new ways to revitalize old fields and

tap bypassed pockets of oil and gas. However, identifying the best solutions requires a team of experts

with a broad range of skills that cross the traditional boundaries of petroleum engineering disciplines.

David HillEric Neme Christine Ehlig-EconomidesSugar Land, Texas, USA

Miguel MollinedoOXYMaracaibo, Venezuela

Over the last ten years, new technologiesand field strategies have converged,enabling operators to give new life to oldwells. Now, reviving production fromdeclining fields has become a major activ-ity for oil and gas companies, and one thatrequires more support to identify the righttechnical solutions. Optimizing well outputand economics are the key goals of theseproduction enhancement projects and ser-vice companies are actively participatingin achieving these goals.

This growing demand has pressed compa-nies in the service sector to diversify theirskills and address a wider range of reser-voir and production problems. It has also

For help in preparation of this article, thanks to OlivierFabvre, Anadrill, The Hague, The Netherlands; DaveBergt, Jaime Bernardini, Ike Nitis and Pearl Chu Leder,Anadrill, Sugar Land, Texas, USA; Jon Elphick and AndyRike, Dowell, Sugar Land, Texas; and Chris Prusiecki,Anadrill, Dallas, Texas.DESC (Design and Evaluation Services for Clients),NODAL (production system analysis), PowerPak (steer-able motors), RAPID (Reentry and Production Improve-ment Drilling), Slim 1, VIPER and VISPLEX are marks ofSchlumberger. A-Z PackStock is a mark of SmithDrilling & Completions.

stimulated a flurry of technical creativity.For example, developments in the area ofreentry drilling alone—coiled tubingdrilling (CTD), slimhole measurements-while-drilling (MWD) systems and newcompletion technologies for multiple side-track boreholes—have produced a wealthof options for maximizing return on invest-ment (ROI). But which approach offers thebest solution; how should it be applied;and in which wells?

To help operators address these questions,service companies have reorganized to pro-vide multiple integrated services.1 With thisbroader outlook comes an extended range ofcapabilities, including identifying underper-forming wells and recommending cost-effec-tive interventions to increase well productivityand maximize net present value (NPV).2

With improved capabilities from newdrilling technologies, a growing number ofwells are candidates for reentry drilling—

Oilfield Review

Producing Bypassed Oil

By-passed zone

Oil

Water

Short-radiussidetrack

Depletedzone

Lateral sidetracks

Optimizing Recovery

Subsea

Multilaterals

Extended reach multilaterals

Tapping Remote Structures

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Sidetracking• Section milling• Window opening

Completion• Sand control• Zone isolation• Flow control• Gravel pack

Completion• Connectivity• Isolation• Access• Liner hanger

Curve drilling• Medium radius• Short radius

Lateral drilling• Geosteering• Drill-in fluids• Underbalance

■■Improving net present value of oldfields. Reentering wells and drilling hori-zontal laterals into bypassed zones cantap new reserves from existing wellbores.

■■Reentry systems. RAPID services cover the key elements of reentry and multilateraldrilling, from pulling old completions to installing the new one and from drilling fluidsto wireline logging.

■■Multiple sidetracks for enhanced pro-duction. Additional drainholes (red) canfan out from existing wellbores or horizon-tal trunks and improve reservoir drainage.

■■Making small fields economical. Innov-ative drilling techniques can improveasset value by tapping small pockets ofoil. Using the latest downhole motor andgeosteering technology, wells extendingseveral kilometers from offshore platformscan be drilled, eliminating the need foradditional structures. Multilateral wellsthat branch out from a main wellbore canaccess several areas of a field and elimi-nate the need for new wells.

1. Chafcouloff S, Michel G, Trice M, Clark G, Cosad Cand Forbes K: ”Integrated Services,” Oilfield Review7, no. 2 (Summer 1995): 11-25.

2. Net present value is today’s value of an assetaccounting for all future expenditures and income.

3. Data from Spears & Associates: “Drilling andProduction Outlook,” March 1996.

4. Maurer WC: ”Recent Advances in HorizontalDrilling,” The Journal of Canadian PetroleumTechnology 34, no. 9 (November 1995): 25-33.

5. Ehlig-Economides CA, Chan KS and Spath JB:”Production Enhancement Strategies for StrongBottom Water Drive Reservoirs,” paper SPE 36613,presented at the 1996 SPE Annual Technical

short- or medium-radius sidetracks andmultilaterals, drilled conventionally or withcoiled tubing. This year, in the USA alone,more than 1500 reentry sidetracks will bedrilled. By 1999, the number is expectedto increase by 25%.3

Revisiting Existing WellboresReentering wells to gain additional produc-tion is not new. Since the mid-1950s, oilcompanies have reentered old wells anddrilled sidetracks to bypass formation dam-age or wellbore mechanical problems, andalso to exploit new zones, saving theexpense of drilling entirely new wells.4

Recent expansion of the reentry drilling mar-ket, however, owes much to improvementsin drilling and completion technology.

Reentry drilling provides a means toreduce horizontal well costs. In addition toboosting well productivity, reentry drillingcan also tap bypassed reserves (top right).Multiple lateral sidetracks can fan out froman existing wellbore for enhanced accessto reservoirs (middle right). And smallerisolated pockets of oil and gas can betapped by extended-reach wells or multi-laterals (bottom right). Typically, a hori-zontal well will triple or quadrupleproductivity over a vertical well, and insome cases, much larger productivityimprovements—up to 17-fold, or more—

Autumn 1996

have been observed. Additionally, in zoneswith underlying water, overlying gas, orboth, horizontal wells can significantlyincrease recoverable reserves.5

Today, service companies use variousapproaches to address the growingdemand for reentry drilling. Baker HughesINTEQ boosted its reentry drilling serviceswith support from sister company BakerOil Tools, and gained a reputation as areentry specialist in the Gulf of Mexico.Within Schlumberger, RAPID Reentry AndProduction Improvement Drilling teamswere created to address this fast-growingdrilling option. Service under the RAPIDumbrella draws on expertise in reservoirengineering, drilling, directional drilling,fluids engineering, petrophysics and com-pletion engineering—the indispensable ele-ments required to plan, drill and completesuccessful reentry laterals (above).

5

Conference and Exhibition, Denver, Colorado, USA,October 6-9, 1996.

6

Gas

Shale

Shale

Shale

Oil

Oil

Water

Thick and homogeneous,no gas cap oraquifer

Poor kv Good kv

Permeability (k), md Vertical, kv Horizontal, kh

Thick and homogeneous,with gas cap and/or aquifer

Not recommended:risk of premature gasor water production

Not recommended:risk of disappointingproductivity or recovery due to low vertical permeability

Intersect as manylayers as possible

Layered

Laminated

Structural compartment

Stratigraphic compartment

Elongated compartment (plan view)

Attic compartments

Naturally fractured

Naturally fracturedunder waterflood

Well Path

Drainage Volume

Characterization

Stacked parallel wells,with branch flowconformance

Drain each with oneor more wells

One well in multiplecompartments

Drain each with oneor more wells

One well in multiplecompartments

One well bed drilledon strike preferred

Single well travers-ing multiple beds

Closely spacedparallel wells preferred

preferred over vertical

Single well traversingmultiple channels

Multiple well paths slanting from single main trunk

Closely spacedshort parallelwells normal tofractures Water injection wells

v ≥ 0.1k kh

v ≥ 0.1k kh

Horizontal well normal to fractures preferred

Intersect vertical andhorizontal fractures

Slanted well Horizontal well

OILFIELD REVIEWAUTUMN 96

■■Optimizing production. Reservoirs can be classified by drainagevolume (left). For each reservoir more than one well type—vertical,hydraulically fractured vertical, slanted, horizontal, hydraulicallyfractured horizontal, and multiple or stacked laterals—may beeffective. Depending on permeability and reservoir characteristics,slanted and horizontal reentry drilling are two methods for improv-ing production and recovery (center and right).

■■A skilled team of experts. Members of the initial RAPID team,based in Sugar Land, Texas, (front row, left to right) directionaldrilling engineer, Ike Nitis; team leader, with drilling experi-ence, Eric Neme; completion and drilling engineer, MarkStracke; reservoir engineer, Christine Economides, (back row)multilateral completions engineer, Herve Ohmer and fluidsengineer, David Anderson.

The RAPID service was established in 1995by a business development team in SugarLand, Texas, USA (above). The lessons learnedand the organizational support structure thathas developed are now being duplicated inlocations worldwide, tapping key specializedskills within all six Schlumberger OilfieldServices companies. In microcosm, the func-tions of the RAPID group reflect the state of theart in reentry drilling services today.

In some wells, production enhancementis best achieved without drilling. Toaddress this need, a targeted effort on pro-duction enhancement was also initiated bySchlumberger. The front line of this effort isled by an integrated, cross-product-lineteam of engineers engaged in identificationof candidate wells. This ProductionEnhancement Group, or PEG, is chieflyresponsible for candidate recognition and

Oilfield Review

Water Coning

Water Cresting

■■Water coning during production andbreakthrough if perforations are too closeto the oil-water contact. Reducing produc-tion rate decreases drawdown pressureand mitigates coning.

■■Effectively producing from horizontallaterals. Drawdown pressure in a horizon-tal lateral is lower than in a vertical well-bore for similar production rates.

6. A production enhancement article will appear in aforthcoming issue of Oilfield Review. Also see the dis-cussion of the DESC Design and Evaluation Servicesfor Clients program: 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 DESC Engineer Redefines Work,” OilfieldReview 7, no. 2 (Summer 1995): 40-50.

7. Ehlig-Economides CA, Mowat GR and Corbett C:”Techniques for Multibranch Well Trajectory designin the Context of a Three-Dimensional ReservoirModel,” paper SPE 35505, presented at theSPE/Norwegian Petroleum Society 3-D ReservoirModeling Conference, Stavanger, Norway, April16-17, 1996.

8. Mobility is the ratio of permeability to viscosity.Low-gravity crude oils have high enough viscosity

solution design.6 PEG engineers performtechnical and economic analysis of prob-lem wells and fields, and then design, withthe support of appropriate experts, such asRAPID teams in the case of reentry drilling,the optimal solution. Depending on theproduction problems encountered, solu-tions may include new well logs, reevalua-tion of existing logs, drilling new or reentrywells, reperforating, well stimulation treat-ments or other workover techniques.7 Thegoal is to provide the best-in-class servicefor every production problem.

Autumn 1996

Candidates for Reentry Drilling Fracturing, reperforating, removing damagewith acid, and recompletion are all widelyused methods to increase production inexisting wells, thereby improving the NPV ofold fields. Now, reentry drilling is generatinghigh interest for its potential to improverecovery from damaged or depleted zones,and tap new zones at lower cost.

So when should reentry drilling be used?Many times, traditional techniques mayhave already been tried unsuccessfully ormay not be advisable. In older wells, reen-try drilling is the best option when there isan identifiable reason for a slanted or hori-zontal well path (previous page, left).Reentry drilling from an existing wellboreis less expensive than a new well. And ithas the advantage that borehole trajectorythrough the production zone is near theoriginal wellbore where more is knownabout the reservoir from cores, logs, testmeasurements and production history.

When the existing wellbore passesthrough or near a gas cap or underlyingaquifer, excess gas or water production usu-ally develops. In the absence of a gas cap, atraditional strategy to delay bottom waterbreakthrough is to perforate near the top ofthe productive interval. However, the pres-sure gradient due to radial flow toward thewell is often sufficient to draw waterupward in the shape of a cone (above left).Once water reaches the deepest perfora-tions, it may be preferentially producedbecause of higher mobility.

Even in the absence of a higher mobilitycontact, the strong bottom waterdrive cancause excess water production.8 Becausehorizontal wells drilled near the top of anoil zone and above the oil-water contactproduce a linear pressure gradient normalto the well path, bottom water will rise inthe shape of a crest instead of a cone (left).The advancing crest-shaped water frontdisplaces more oil than a cone-shapedadvance, which leads to greater recoveryby virtue of flow geometry.

In formations where sand control isrequired, reentry laterals may avoid theneed for expensive gravel-packed comple-tions to improve production rates whileminimizing sanding problems. Comparedto vertical wells, horizontal wells allow the

same or higher production rates at greatlyreduced drawdown pressures.

Another reason for reentry drilling is togain better access to layered reservoirs. If

individual pay zones arethick enough to be tar-geted by horizontal wells,

multiple stacked reentry laterals are ahighly effective strategy. To balance pro-ductivity—barrels per day per unit of pres-sure drop—from reentry laterals, eachdrainhole can be drilled to an appropriatelength inversely proportional to the flowcapacity of that particular layer.

At less cost than stacked horizontal later-als, a slanted borehole boosts productivity

of layered formations. Bydesigning wellbore tra-

jectory with more drilled length in less-productive layers, some conformancecontrol—balanced productivity from indi-vidual zones—can be achieved. However,if early water breakthrough occurs in ahigh-productivity layer, the relative ease ofshutting off production from one of thestacked laterals compared to shutting offproduction from a mid-length section of aslanted well may, in the long run, favorusing a stacked lateral strategy.

A slanted well can produce a marginalincrease in productivity over a vertical well

in laminated formationswhere beds are too thin

for horizontal drilling. Often hydrocarbonzones are missed or not produced in origi-nal completions. Such intervals can bereperforated and a hydraulic fracture maysignificantly improve productivity. However,when the interval is thin, reentry drilling of ahorizontal lateral will outperform ahydraulic fracture.

7

and hence, lower mobility than formation water.

8 Oilfield Review

In some reservoirs, stratigraphic compart-mentalization due to depositional processes

may account for bypassedhydrocarbons both verti-cally and horizontally.Facies with considerablecontrasts in flow charac-teristics may serve as bar-

riers or conduits. In some cases, reservoirsands may be too thin to be individuallyidentified in a seismic section, but have suf-ficient areal extent to be visible in seismicamplitude maps for a given structural hori-zon. In such cases, horizontal wells may bean ideal strategy for producing thin forma-tions and for extended reach into remotehydrocarbon sands.

A major application of horizontal wellshas been in naturally fractured formations

like the Austin Chalk insouth Texas. When hori-

zontal wells are drilled normal (perpendic-ular) to natural fracture planes, they providean excellent plumbing system for enhanc-ing production. Locating natural fracturesand determining their orientation are cru-cial to getting the best well design in theseformations. A horizontal well normal tonatural fractures usually provides betterproductivity than a vertical well stimulatedby hydraulic fracturing. Although naturalfractures are usually vertical, shallowerreservoirs and overpressured zones mayhave horizontal fractures open to flow. Inthese formations, vertical and slanted wellsare reasonable choices. However, in over-pressured deep formations, it may be advis-able to prop the natural fractures open toavoid loss of productivity as productionproceeds and pore pressure declines.

Elongated reservoirs can be the result offluvial deposition or significant faulting.

Both environments arenatural candidates forhorizontal drilling. Ineither case, there areapparent drilling strate-

gies, depending on the objective for thewell. For example, wellbores can be main-tained in an elongated reservoir body, ordirectionally drilled to encounter as many

different reservoir bodies as possible. Thelatter case implies drilling in a directionnormal to the elongation, which, for a flu-vial reservoir, means drilling perpendicularto the downhill direction at the time ofdeposition. Another approach might bemultibranch wells, designed to target chan-nels identified with borehole seismic mea-surements in the horizontal trunk well.

Another application for horizontal drillingdeals with a special structural geometry

called attic compartments.In these cases, steeply dip-ping beds may be in con-

tact with an up-dip gas cap or down-dipaquifer. One strategy is to drill a horizontalwell that passes through several beds, butstays sufficiently below up-dip gas or abovedown-dip water. Although this would seemto be an efficient approach, it suffers distinctdisadvantages. Flow is commingled amonglayers, and gas or water breakthrough willinterfere with production from other layers.A better strategy might be to drill multiplehorizontal wells, each on strike and stayingin a given bed. The advantage of thisapproach is that each well maintains anoptimal distance from gas-oil or oil-watercontacts, thus delaying multiphase produc-

tion as long as possible. Each well can alsobe drilled to the optimal productive lengthwithin the formation.

Reentry Candidate Recognition in ActionThe Western Siberian region in the FormerSoviet Union contains reservoirs that havebeen produced for 10 to 50 years usingconventional vertical wells. Often a simpleworkover, such as reperforating, acid stim-ulation or hydraulic fracture treatment, sig-nificantly improves production. But insome cases, a better solution is to reenterexisting wells and drill a horizontal lateral.

In September 1995, the RAPID team wasapproached to assist in choosing the bestoption for layered reservoirs with thick oilcolumns, where, typically, vertical wellspenetrate the entire productive thickness.Reservoirs are then progressively drainedfrom the bottom up, plugging back andabandoning depleted zones over time.Production from vertically isolated zones isnever commingled in any well.

■■Candidate recognition in the Former Soviet Union (FSU). Field data (top) are used tocalculate production rates (middle) for various well scenarios, including vertical wellwith original damaged skin, vertical well with skin reduced to unity, vertical well afterfracturing and reentry horizontal well with a skin of unity. Only horizontal wells withpredicted production improvement that was greater than two times the fractured verti-cal well case were considered as lateral reentry candidates. These wells would havethe fastest payout time.

Production rate, m3/dVertical well (damaged) 24 22 23 38 37 69Vertical well, skin = 1 41 63 56 59 58 99Vertical well after fracturing 70 94 86 98 97 156Horizontal well, forecast 156 95 169 242 236 323

Production ratiosHorizontal/damaged vertical 6.5 4.3 7.3 6.4 6.4 4.7Horizontal/vertical, skin = 1 3.8 1.5 3.0 4.1 4.1 3.3Horizontal/fractured vertical 2.2 1.0 2.0 2.5 2.4 2.1Payback (days) 20 33 18 13 13 10

Field A B C D E FNet thickness, m 14 37 19 6 8 9True vertical depth, m 2400 2400 2800 2800 2500 2400Permeability, md 3 3 1.5 5 4 6Vertical permeability good in average good poor poor poor

upperPressure, psi 4000 3000 3800 4000 3689 3615Initial pressure, psi 4335 3703 4262 4144 3792 3615Vertical skin 5 12 10 5 5 5

Candidate Recognition Analysis

Autumn 1996 9

To accommodate this request, a question-naire was designed to collect data fromseveral reservoirs. Six wells were selectedthat appeared to be particularly promising.For each of the six cases, productivityimprovement expected from a horizontallateral was calculated (see “EvaluatingProductivity Improvement,” right). Becausevertical wells had been drilled through theentire productive oil column, shallowzones were damaged during drilling asmud weight was increased to reach totaldepth. The sensitivity to skin damage wasinvestigated to compare production rateimprovements that could be achieved froma vertical workover, hydraulic fracture andhorizontal lateral.

To evaluate the potential productivityimprovement from a horizontal well reen-try, a lateral drainhole length of 750 ft[229 m] was assumed for all cases. An idealtarget skin of unity in the lateral wasassumed for productivity comparisons (pre-vious page). Only horizontal wells calcu-lated to be twice as productive asfracture-stimulated vertical wells were con-sidered as candidates for lateral reentry.

The most favorable production enhance-ment plan called for medium-radius drillingwith VISPLEX drilling fluid, and completionof the lateral section with a predrilled liner.9

Proof of the validity of this approach willcome from results of the drilling program,scheduled to begin later this year.

An interesting application for reentrydrilling in difficult structures occurred innorth Texas, where, the operator, TRIO, wasdrilling vertical wells through mound-shaped reefs. The reefs are seen on 3D seis-mic surveys, but hydrocarbons havemigrated into traps, caused by dolomitiza-tion, which cannot be identified by seismicsurveys. Wells are usually drilled into thecenter of the reefs, but this is somewhat of ahit-or-miss proposition.

7500

6500

5500

4500

350010000 2000 3000 4000 5000 6000 7000 8000 9000 10000

Liquid flow rate, B/D

Bot

tom

hole

flow

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

In the Gulf of Mexico, there are many clean sands

with high permeabilities—often in excess of 1000

md—but completion designs must provide sand

control. A typical example illustrates the use of

reentry drilling under these conditions.

A previously drilled well path was deviated at

about 35˚ through the productive sand and

hydraulically fractured for stimulation and sand

control. The post-treatment well test indicated a

high skin of 40 and a permeability of about 180 md.

Because the reservoir contained two approximately

40-ft [12-m] thick, clean sands separated by a

shale bed, the question was whether to design a

slanted reentry well or two stacked laterals.

Since the design was for a reentry well, lateral

diameter was limited to 6 in. [15 cm]. The lateral

completion called for a prepacked screen and

gravel pack for sand control, leaving the internal

flow diameter at just under 2 in. [5 cm]. A NODAL

sensitivity study for this case shows two families

of curves (above). The green curves show the

effect of lowering surface pressure on vertical

flow performance. The steep climb at high rates

suggests, to experienced reservoir engineers,

that larger tubing would allow higher flow rates.

However, the cost of replacing tubing was prohib-

itive. The blue curves show sensitivity of the

inflow performance relationship (IPR) to slanted

or horizontal wellbore length. Because of fric-

tion-induced pressure drop in the small internal

flow diameter, the IPR curves converge for longer

tunnel lengths, and there is little productivity

gain between drilling a 1200-ft [366-m] and a

2400-ft [732-m] hole. The red curve is the total

productivity of two 300-ft [91-m] stacked laterals,

one in each layer. Because of the shorter length,

and therefore less frictional resistance, the two

stacked short (300-ft) laterals should outperform

one long (2400-ft) slanted well.

This illustrates the impact of tubing diameter

on reentry laterals in high-permeability forma-

tions. Since drilling horizontal or slanted wells

increases production rates, frictional pressure

drop in the tubing or lateral can limit production

potential. In this case, another solution could be

to plan to produce the lateral or laterals at a

lower drawdown pressure. This solution could

avoid the need for expensive sand control mea-

sures—prepack screen or gravel pack. Net pre-

sent value analysis, accounting for the costs of

various options and coupled with production fore-

casts for each design, can provide a way to select

the optimal solution.

Evaluating Productivity Improvement

■■Stacked laterals compared to slanted wellbores. A NODAL sensitivity analysis compares two stacked lateralboreholes to various lengths of a single slanted wellbore path through two thick, clean sands in a Gulf of Mex-ico reservoir.

9. VISPLEX mud (containing a mixed-metal hydroxide) isa high shear-thinning (thixotropic) drilling fluid, pri-marily used for milling windows in casing, which isalso used as a drilling and a drill-in fluid. The mud-cake produced is easily removed from the formation.

10 Oilfield Review

After a dry-hole vertical well was drilled,Anadrill was approached to plan a sidetrackfrom the vertical well, building anglequickly to laterally traverse the reef andincrease the chance of intersecting areas ofvugs—large spaces in the formation—thathold oil. The well had been drilled with a77⁄8-in. vertical hole through the reef, butbecause of the small areal size of the struc-ture, only a maximum 500-ft [152-m] hori-zontal displacement was available for alateral borehole. It is difficult to get a long-or medium-radius sidetrack turned in such ashort distance and it is also a challenge tokick off with a small-diameter drill bit insidesuch a large open hole.

The proposed solution was unique. Thehole was plugged with cement to about100 ft [30 m] above the planned kickoffpoint (KOP). A smaller, 63⁄4-in. pilot holewas drilled to the KOP with a 43⁄4-in. bot-tomhole assembly (BHA). Then a 61⁄2-in. bitwas placed on the BHA with a 43⁄4-in., 3°-bend motor. The smaller bit was used toprevent damage to the cement pilot holewhile running in to the KOP with the bentmotor. The BHA drilled the curved sectionat a rate of 27°/100 ft and found hydrocar-

bons at about 62° inclination. The reentrysidetrack turned a $230,000 vertical dryhole into a well that produced 200 BOPD.Sidetrack cost, including completion, wasabout $140,000.

Another example comes from a majoroil company in Houston, Texas, that askedthe RAPID team for horizontal drillingrecommendations in the difficult condi-tions of a south Texas gas field. The reser-voir was depleted to 300 psi [2070 kPa] ata depth of 10,000 ft [3048 m]. Evendrilling with air would result in severeoverbalance conditions that could dam-age the reservoir. Although coiled tubingdrilling was the only practical drillingtechnique, anticipated production wouldnot justify the cost of this option.

The RAPID team examined well condi-tions and field performance, and discov-ered that the 15-year-old completion designused in the 80 producing wells of this fieldcontained a flow restriction that limitedproduction rates. Well performance analy-sis indicated that reengineered completionsusing larger tubing would double produc-

tion rates (left). The implemented solutioncost 95% less than horizontal drilling withcoiled tubing and was immediately avail-able for every producing well in the field.Gas production from wells worked overaccording to this recommendation doubledfrom about 1 to 2 MMscf/D.

Reentry Drilling SystemsWhen reentry drilling is the optimal solu-tion, one of the first decisions is to choosebetween conventional and coiled tubingdrilling (CTD). Through-tubing reentry andunderbalanced CTD is an economical solu-tion for drilling and workover operations onrigless platforms. Underbalanced drillingminimizes formation damage and increasesdrilling penetration rates.

The majority of older wells will be reen-tered by conventional drilling with long-radius—greater than 500-ft [152-m]—ormedium-radius—200- to 500-ft [61- to153-m]—sidetracks. However, there is amajor trend toward reentry drilling withshort-radius—40- to 100-ft [12- to 30-m]—drilling.10 Short-radius sidetracks requirearticulated drilling systems, which are highlyeffective in competent formations that canbe completed without liners or other com-pletion hardware. Short-radius drilling tech-niques, whether by conventional means orwith coiled tubing, allow drillers to turn welltrajectories in a much shorter distance thanwas previously possible. This allows kickingoff below well hardware, if required, ordrilling a curve and lateral section com-pletely within a reservoir to avoid problemswith overlying formations.

Multilateral drilling, an increasingly popu-lar drilling strategy in new wells, uses multi-ple horizontal sidetracks from a primarytrunk in a parent well. This technique canmake small fields economical and reducethe number of wells needed to drain a reser-voir. Fewer wellheads significantly reducethe cost of subsea completions and tie-backoperations. The multilateral geometry can besimple opposing laterals in the same hori-zontal formation for better penetration, orstacked laterals to gain access, in multilay-ered reservoirs for example, to formations atdifferent depths. A multilateral pattern canbe used in the same horizon to drain larger

5000

Vertical well inflowperformance curve

500

400

300

200

100

00 2000 3000 40001000

Gas rate, Mscf/D

Wel

lhea

d pr

essu

re, p

sig

Tubing uptake curves

2.441 2.992 3.958 5.012 6.276Flow diameter, in.

Well Performance Analysis

(installed in well)

2 7/8 3 1/2 41/2 51/2 7Tubing size, in.

■■Well performance analysis. In RAPID reservoir analysis, selecting a productionimprovement plan begins with well performance matching. In this example, the wellinflow performance relationship (IPR)—wellhead pressure versus flow rate—includesseveral tubing uptake curves. Flow rate can be significantly increased by changing tolarger diameter tubing.

Autumn 1996 11

reservoir areas through parallel laterals or asangled laterals in a fan-shaped pattern.

Reentry Well EngineeringPreparing a well for reentry drilling caninvolve a range of services from supplyingthe workover rig, pulling the old comple-tion and cement squeezing old perforationsto fishing debris from wells and cased-holelogging for corrosion and formation evalu-ation. Depending on well design and con-ditions, there are several possible reentryscenarios ranging from kicking off in openhole or cased-hole sidetracks using a whip-stock to cut a window through the side ofthe casing—window milling—to cutting acomplete section out of the casing orliner—section milling.11

To provide efficient section milling and window opening capabilities,Schlumberger formed an alliance withSmith Drilling & Completions. This partner-ship allows the RAPID group to provideworldwide sidetracking services, includingpermanent and retrievable whipstocks, and

milling systems.12 Complete engineeringand technical support come from Smithspecialists, but crosstraining allows Anadrilldrillers to run Smith equipment.

Sidetracking out of casing begins with agyro survey of the existing hole to preciselydetermine location of the casing. A correla-tion log pinpoints the target formation.Using these data, kickoff depth and positionof the milled section are chosen. A cement-bond log shows whether there is goodcement behind the proposed milled section.If not, an underreamer is run betweenmilling and plug-setting operations to cleanup bad cement and enlarge the borehole.13

For section milling, about 60 ft [18 m] ofcasing is milled if the kickoff is to be steeredmagnetically out of a vertical well (above).The milled length of casing can be reducedif a gyro is used to steer the BHA. A compe-tent cement plug is then set across themilled section. To avoid magnetic interfer-ence, the plug is dressed with a bit to thekickoff point 20 ft [6 m] from the lower cas-ing stub. The disadvantages of section millingare that it requires a secure cement plug forproper sidetracking, and there is a risk of not

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■■Section milling. A specialized bottomholeassembly cuts through the casing and intothe cement at a chosen depth (A). Cutterblades extend from the tool when neededand retract for tripping. Length of themilled section depends on several fac-tors—nominal ID and casing couplingdiameter, bit diameter, and bent housingmotor angle (B). After milling (C), cementis placed across the open interval andnew hole is drilled by kicking off of thisplug (D). When milling is complete, thelower section of the original well is perma-nently isolated from the sidetrack (E).

10. Maurer, reference 4.11. Ehlig-Economides C: ”Improving Production Using

Re-Entry Drilling Techniques,” Petroleum EngineerInternational 68, no. 9 (September 1996): 32-33.

12. Bell S: “Milling Applications DemonstrateVersatility,” Petroleum Engineer International 66,no. 3, Supplement (March 1994): 12-15.

13. Hill D, Askew W, Tracy P and Koval V: “APredictable and Efficient Short Radius DrillingSystem,” paper IADC/SPE 35049, presented at the1996 IADC/SPE Drilling Conference, New Orleans,Louisiana, USA, March 12-15, 1996.

A B C D E

12 Oilfield Review

A B C D E

F G

■■Window milling. Operations tocut an opening out of the casingbegin by running and orienting aretrievable whipstock, which isused to guide mills in the lateraldirection (A). After the whipstockanchor is set, the attaching pin issheared and a starter mill initi-ates the window cut a few inchesinto the casing (B). The windowmill does the bulk of the milling,and is run together with string, orwatermelon, mills that open upand smooth out the new openingthrough the casing wall (C). Oncemilling is completed, lateraldrilling can start (D). The whip-stock is used to guide BHAs andcompletion equipment into thelateral sidetrack (E). After the lat-eral is completed, the whipstockcan be removed to allow accessto lower formations (F and G).

Top of sand

Actual wellbore profile

Bottom of sand

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tical

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t

-50 300 500 1000 1500 1750

5000

5100

5200

5300

5400

Vertical Profile

Lateral section displacement, ft

■■Short-radius drilling in Texas. Frequently the challenge is to drill a short-radius reentrylateral into a small target zone and remain within the hydrocarbon pay while avoidinglease boundaries. In this well, lease restrictions and state regulations defined a narrow116-ft [35-m] target for the first 700 ft [213 m] followed by a turn to the left (right). Thetarget was entered with a 77-ft [23-m] radius and a whipstock set at 5159 ft [1572 m].Drilling continued horizontally with the same BHA. Ability to rotate the Anadrill short-radius drilling system resulted in excellent directional control along the horizontal lat-eral. In addition to avoiding lease boundaries, the wellbore was maintained within thepay zone for most of its 1600-ft [488-m] length (above).

14. “Tips for a Successful Re-Entry,” Petroleum EngineerInternational 66, no. 3, Supplement (March 1994):8-9.

15. Ehlig-Economides et al, reference 5.16. Leazer C and Marquez MR: “Short-Radius Drilling

Expands Horizontal Well Applications,” PetroleumEngineer International 67, no. 4 (April 1995): 21,23-24, 26.

■■A roadmap for the driller. Before reentrydrilling begins, a detailed plan isdesigned. At the Schlumberger SugarLand District in Texas, Catherine Ortiz, a Drilling Planning Center engineer,reviews a trilateral plan with SteveThurston, a well planning engineer,before her crew leaves for a job sched-uled to start within 24 hours.

N

0 ft

1000 ft

1600 ft

500 ft 800 ft0 ft

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Actual wellbore path

467-ft drilling limit

E

Plan View

being able to reenter the lower casing stubafter drilling the lateral. Drilling penetrationrates are often limited by the ability to cleancuttings from the well, and once the well-bore turns horizontal, cuttings removal iseven more difficult. Modern milling tools aredesigned to create small, nonclogging cut-tings that are easily removed from the well.Polymer muds are more effective for millingthan clay-base muds. Oil-base muds are notrecommended for milling operations.14

An alternative to section milling is to cut awindow in the casing. This requires settingan oriented whipstock and milling an open-ing in the casing (previous page). After thewhipstock is set in position, the bolt con-necting the starter mill to the whipstock issheared. Then rotation is started and car-bide tips on the nose of the starter mill cutinto the casing wall. In the next stage, awindow is cut into the casing using a win-dow-milling bit, which is forced into thecasing and the formation by the angle onthe whipstock face. The window isenlarged or polished using the windowmill and one or more watermelon mills rundirectly below the drill collars.

Section milling offers several advantagesover window milling. It can eliminate theneed for gyroscopic orientation, moves thekickoff depth closer to the target for a givencurve radius and requires only one milling

Autumn 1996

operation. Window milling, on the otherhand, uses a whipstock that provides apositive sidetracking mechanism, butrequires several gyro runs to orient boththe whipstock and drilling assembly.Cutting a window also requires multiplemilling operations and a shallower kickoffdepth due to the rathole needed for thesubsequent drilling assemblies.

Whichever system is used, once entry tothe formation is gained, there are morechoices to be made. Besides standardmedium-radius drilling, several recentlyintroduced options for reentry drilling sys-tems can make well reentries more cost-effective.15 Short-radius drilling, coiledtubing drilling, and multilaterals are eachcandidates for thorough cost-benefitanalysis (right).

Short-Radius SystemsShort-radius wells are drilled to avoid tra-versing problem formations that would oth-erwise require a liner to isolate, or becausewells must be kicked off below hardware,such as an external casing shoe.16 In someformations, the kickoff and lateral can bekept entirely in the pay zone, avoidingshale beds and reducing the risk of stuckpipe (above).

13

1

■■Location of the Alturitas field in Venezuela, South America.

Direction and

Battery module

Gamma-ray detector

inclination systems

Upper articulation

Mud pulser

Fishing head

A R G E N T I N A

VenezuelaAtlantic Ocean

Alturitas

Pacific Ocean

Peninsulade Guajira Peninsula de

Paraguana

La Velade Coro

El Mamon

Las Palmas/TigujeMonte Clar

Bolivar fields

BocaEscalante

Rosario

San Lorenzo

PocoLakeMaracaibo

Cerrejon

Guasare

Gulf of Venezuela

The curved section is drilled with a specifi-cally designed short-radius system. Theshort-radius BHA consists of a drill bit, artic-ulated motor, flexible nonmagnetic drill col-lar housing and MWD systems. High-strength drillpipe is run immediately abovethe BHA for easy passage through the curvedsection. Drillstring in the vertical well sec-tion usually contains standard drillpipe.

The curvature of borehole drilled by aconventional—long- or medium-radius—downhole motor is defined by three pointsof contact between the BHA and boreholewall—generally the drill bit, the near-bitstabilizer and the first stabilizer above the

4

Rotating near-bit stabilizerbend1.5° Fixed

Adjustable standoff

Lower articulation

Power sect

motor. On a short-radius system, however,the three points of contact have to be posi-tioned below the motor knuckle joint.Articulations are needed to allow themotor to pass around sharp bends andhave no effect on angle build rate. Theyalso allow rotary drilling. Both roller coneor polycrystalline diamond (PDC) bits canbe used at the operator’s discretion to han-dle different formation characteristics.

Rotor/stator

Stinger

ion

■■Short-radius drilling system. TheAnadrill PowerPak XF short-radius drillingsystem consists of an articulated BHAwith the Slim 1 slim and retrievable MWDsystem. Build angle is controlled by a sur-face-adjustable standoff at the top of theshort rigid motor section behind the bit.

The Anadrill short-radius drilling systemuses a 4-ft [1.2-m] rigid motor section witha surface-adjustable standoff as the thirdpoint of contact to control radius of curva-ture (below). This system maintains contin-uous contact with the borehole, allowingpredictable build rates and easy control ofthe horizontal section. This also avoids theneed to prepare different motors for eachsection of the well.17 Directional control ismonitored with a Slim 1 retrievable MWDsystem that includes a gamma ray measure-ment for geological correlations. This MWDtool was designed to communicate with thesurface through mud-pulse telemetry duringangle-build drilling to a 40-ft minimumradius of curvature. The directional sensorhas been placed in the lowest position,directly above the motor power section, forenhanced trajectory control.18

One recent example of productionenhancement through short-radius drillingtook place in OXY’s Alturitas field, 30 miles[48 km] west of Lake Maracaibo, Venezuela(left). The target Marcelina reservoir liesbelow a coal stringer that is difficult to drillat any inclination other than vertical, whichmade horizontal drilling uneconomical

Oilfield Review

17. Hill et al, reference 13.18. Hutchinson M: “Innovative Short Radius Drilling

System Demonstrates Greater Flexibility andDirectional Control,” Petroleum EngineerInternational 68, no. 10, Supplement (October1996): 14-15.

10900

10920

10940

10960

10980

11000

11020

11040

1

2

3

4

5

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0 200 400 600 800 1000 1200 1400 1600 1800 2000

Lateral section displacement, ft

Orienting tool

Logging toolDrilling head module

Steerable motor

Motor, gear trainand bearing section

Gamma-ray sensors and electronics

Pressure transducers, and electronics

Telemetry and power

Electricaldisconnect

Wetconnect

Coiled tubingand wireline

Checkvalves

Directional and inclination sensors and electronics

Motor/powerelectronics

Articulation

Surface-adjustablebent housing

Nonmagneticpower section

A B

C D

VIPER BHA with PowerPak motor

A B C D

VIPER Coiled Tubing Drilling System

■■Alturitas well profile. The drilling plan called for a short-radius lateral to the bottom ofthe pay, then the lateral was allowed to angle up—cutting through each sand layerbefore turning back down, again cutting through each of the layers. Once the bottomsand was reached, drilling stopped—1933 ft [589 m] from the kickoff point. This lateralproduced a sevenfold improvement in production rate over the original vertical well.

■■Coiled tubing drilling system. The VIPER system consists of a wireline-powered BHAthat includes an instrument package for directional control as well as gamma ray,

until short-radius drilling technologybecame available.

Alturitas 22 was producing 300 BOPD[47 m3/d], so the objective was to increaseproduction by drilling a horizontal lateralusing the Anadrill short-radius drilling sys-tem. The plan was to set a retrievable whip-stock in the 95⁄8-in. casing, mill a window,drill the curve and lateral, and then placethe well on production. The retrievablewhipstock allows the original completionto be reentered, if necessary, or more later-als to be added at a later date.

An A-Z PackStock was set at 10,895 ft[3321 m] and a 20-ft [6-m] window,including about 9 ft [3 m] of formation,was milled using a gel mud to improveremoval of cuttings. Inclination at 10,915 ft[3327 m] was 3°. The mud system waschanged to oil-base and the BHA wasreplaced with an Anadrill short-radiusdrilling system. In another 84 ft [26 m] ofdrilling, 90° inclination was achieved,placing the lateral well within the targetdepth of 10,988 to 11,003 ft [3349 to3354 m] (above right).

Drilling continued horizontally throughthe reservoir, which consisted of a series ofsandstone layers. The horizontal lateral wasallowed to angle upward from the lower-most layer, crossing all the sandstone mem-bers for about half the lateral length. Thewellbore was then steered downwardagain, staying within the pay. Drilling wasstopped after the well path had descendedback through the entire sand sequence—ahorizontal distance of 1933 ft [589 m]from the kickoff point.

Success of this project can be measuredby current production and cost. The lateralwas left as an openhole completion flow-ing 2000 BOPD [318 m3/d]—nearly a sev-enfold rate increase over the production ofa typical vertical well in this field. The costof this workover was $3.2 million, com-pared to an original well cost of $2.4 mil-lion, a nominal increase in cost relative tothe improvement in production. OXY plansto drill more wells of this type.

Coiled Tubing SystemsOne of the newer technologies developedfor the reentry market is coiled tubingdrilling (right). This approach is attractive

Autumn 1996 15

temperature and pressure measurements, a PowerPak downhole motor, an orientingtool that can rotate continuously and a circulating sub. Data and downhole commandsare transmitted via a cable that is pumped down inside the coiled tubing.

16

0 800 1600 2400 3200 4000

5700

6100

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An

adri

ll

Shallow or depleted reservoirs

Layeredreservoirs

Fracturedreservoirs

■■Multilateral drilling for improving productivity. In depleted zones, a network of later-als increases the length of wellbore in contact with the reservoir (top lateral), whichalso reduces adverse pressure drawdown effects. Several isolated layers can also betapped from the same wellbore (middle laterals). In a fractured reservoir, dual lateralsintersect twice as many fractures (bottom laterals).

■■Typical Austin Chalk quadrilateral openhole (barefoot) completion drilled for UnionPacific Resources.

when drilling rig mobilization costs areprohibitive. The most successful applica-tion of CTD is through-tubing reentry com-bined with underbalanced drilling. Coiledtubing allows more precise control of lowdownhole hydrostatic pressure. Not havingto pull production tubing and kill the wellmakes this technology attractive.19

New coiled tubing directional BHAs pro-vide improved directional control and effi-ciency. One such system, called VIPERtechnology, is a wireline-powered BHA thatincludes a downhole orienting tool fordirectional control and MWD system fordirectional measurements. Both are oper-ated from surface via wireline-suppliedpower and signals. Without the wireline,signal transmission is impossible in under-balanced drilling environments wherefoamed, aerated or nitrogenated mud isused. The wireline system also increasesthe data transmission rate by several ordersof magnitude over mud-pulse systems,allowing surface control of sensors.

Another VIPER system benefit is improvedcoiled tubing drilling efficiency. The elec-tric motor in the orienting tool offers highertorque, as well as accurate and uninter-rupted directional control. Continuousslow rotation of the motor drills a smootherborehole profile, allowing longer-reachdrilling by reducing friction and doglegcurves. The ability to continuously monitordownhole pressure during drilling, trippingand circulating ensures accurate mainte-nance of underbalanced conditions.

Multilateral SystemsMultilateral drilling places more than onedrainhole into one or more hydrocarbonintervals (above left). Improved recovery andreduced well construction costs, throughreuse of the parent borehole and surfaceequipment, make multilaterals an attractiveoption. The cost of preparing an existing wellis the same regardless of how many lateralsare drilled. Multilaterals, therefore, cost lessper lateral than single lateral wells.20 Slotmanagement is improved, and the expense ofdrilling additional parent wellbores is elimi-nated.21 Additional reservoirs can be tappedby drainholes that could not have been

Oilfield Review

Autumn 1996

Sidetracking and drillingfrom Anadrill

Drill-in fluids from Dowell

Packers, liners,completion fluidsfrom Dowell

Tubing-conveyed perforating fromWireline & Testing

External casing packers,completion fluids,Maraseal and screenfrom Dowell

Packers from Wireline & Testing

Open Hole

Cemented Liner

Prepacked Screen or Slotted Liner

19. For more information on coiled tubing drilling see:Bigio D, Rike A, Christian A, Collins J, Hardman D,Doremus D, Tracy P, Glass G, Joergensen NB, andStephens D: “Coiled Tubing Takes Center Stage,”Oilfield Review 6, no. 4 (October 1994): 9-23.

20. For some examples showing some cost details ofreentry multilateral drilling: Hall D: “Multi-LateralHorizontal Wells Optimizing a 5-Spot Waterflood,”presented at the SPE Permian Basin Oil & GasRecovery Conference, Midland, Texas, USA, March27-29, 1996.

21. On offshore wells, a slot is a space that accommo-dates one wellhead in a template secured to theocean floor. A template has a limited number ofslots, which cannot be changed once the templateis installed. If one well waters out or is dry, that slotis already used up. Reentry drilling, however, givesnew life to the slot because it allows bypassingunproductive zones with a new drainhole.

drilled previously, and production rates perwellhead can be much greater.

The most basic multilateral application isopenhole, or barefoot, completions incompetent carbonates like the south TexasAustin Chalk (previous page, bottom).Anadrill has drilled more than 50 suchwells to date. Lateral drainholes intersectnatural fractures, increasing productionfrom a single well. Inability to performworkovers, however, is a drawback. Theseare essentially throw-away wells with com-mingled flow and no chance of turning offwater production.

Completing Multilateral WellsIn general, three completion options areavailable for reentry multilateral wells(left). Wells can be left open as in theAustin Chalk, cased and perforated, orcompleted with some variation of a pro-duction screen.

Soft formations that produce from matrixpermeability require normal completions,such as slotted liners and gravel packs ineach branch, connected mechanically to themain wellbore trunk. This connection has tobe pressure-tight to maintain zone isolation.Furthermore, when different reservoir typesare produced through the same multilateralwell, selective accessibility to each lateralmay be necessary throughout the life of thewell. Complete control of each drainhole isessential to avoid jeopardizing productionof the entire multilateral system when onedrain is depleted or produces excessivewater or gas.

Today, most lateral connections are builtdownhole and rely on good cement to pro-vide a seal and isolation. Schlumberger isdeveloping hardware systems that allowseparate completions for each branch ofthe well. These systems include surface-built junctions that can extend into anyportion of the well—vertical or horizon-tal—and each branch can be easily andselectively accessed. With such systems,there are no reductions in internal diame-

■■Reentry completion options. Reentry lat-erals may be left as openhole completionsin competent formations like the southTexas Austin Chalk (top). Alternatively,laterals can be cased, cemented and per-forated (middle). More complex comple-tions, such as gravel-pack completions,are also available (bottom).

ter in the trunk, which allows lateralbranches to be drilled in any sequence,and allows standard tubing and packercompletion strings to be run. An outlet portwill support a liner hanger and packer,making it possible to run any type of stan-dard completion in the lateral, andenabling good sand control practices, iso-lation and flow control.

The OutlookAn explosion of new technologies coupledwith a collapsing of conventional bound-aries between different oilfield services hasgiven operating companies the widest pos-sible range of solutions to increase recoveryin aging fields. A comprehensive toolboxfor production optimization through reentrydrilling and completion can be provided bygroups like the RAPID team. The potentialvalue of these services is dramatic.Thousands of wells have been drilled andcompleted conventionally. Using reentrytechniques to increase production from justa fraction of these wells will be equivalentto discovering several giant new fields.

—RCH, JMK, AM

17

Quo Vadis, Extreme Overbalance?

Perforating and surging techniques using very high wellbore pressures promise dramatic, cost-effective

improvement in initial well productivity—under the right conditions. But what are those conditions, and how

do the procedures work? Leading investigators look at the basics of these new completion methods, and

examine lessons learned to date from Prudhoe Bay, Alaska and the North American midcontinent.

18

For help in preparation of this article, thanks to BobCooper, Dowell, Houston, Texas, USA; Ray Dickes, Glen Edwards, Joe Hromas, Bjorn Langseth, Al Salsmanand Mike Selewach, Schlumberger Perforating & TestingCenter, Rosharon, Texas; Roger Card, Jack Elbel, MarkMack and Ken Nolte, Dowell, Tulsa, Oklahoma, USA;Roger Keese, Dowell, Anchorage, Alaska, USA; GeorgeKing, Amoco Exploration and Production TechnologyGroup, Tulsa, Oklahoma; and Terry Green, Dowell,Sugar Land, Texas.NODAL and X-Tools are marks of Schlumberger.

Larry BehrmannKlaus HuberBryan McDonaldRosharon, Texas, USA

Benoît CouëtRidgefield, Connecticut, USA

John DeesConsultantDallas, Texas

Ron FolseMarathon Oil CompanyLafayette, Louisiana, USA

Pat HandrenOryx EnergyDallas, Texas

Joe SchmidtARCO Alaska, Inc.Anchorage, Alaska, USA

Phil SniderMarathon Oil CompanyHouston, Texas

In the vast majority of wells today, themoment of truth—do we have a producer,or a hole in the ground?—is revealedthrough underbalance perforating. Whenperforating guns fire, pressure in the well-bore is below that of the reservoir, creating apressure differential that helps clean the per-foration tunnels. Formation fluids rush intothe tunnels and flush out metallic chargedebris, surrounding crushed rock, and sandsor clays that were driven into the tunnels. Ifthe drawdown is large enough, inflow cansweep away enough debris to open the mostconductive natural path between the forma-tion and wellbore.

Two-way communication along this pathis essential for optimal well completion andproductivity. When a well goes straight intoproduction, clogged perforations will limitinflow of hydrocarbons. If intervention isplanned, perforations need to be clear toaccept treatment fluids carrying proppantfor fracturing, gravel for sand control, oracid. Hydraulic fracturing and prepackingperforations ahead of gravel packing benefitfrom removal of crushed sand that canreduce injectivity and elevate fracture initia-tion pressures or lead to early screenout ofproppant during fracture stimulations.1

Underbalance perforating works across abroad range of rock properties and reservoirconditions. Its applicability decreases, how-ever, with a decline in reservoir pressure,permeability or rock strength. The trick is to

achieve enough underbalance to generatesufficient flow rate for cleaning, but not toomuch to collapse the perforations and drivesand into the well. Theoretical and appliedstudies have focused on defining the opti-mal underbalance for ranges of reservoirpressure, permeability and rock strength.2

With a good theoretical foundation and arecord of favorable results, underbalanceperforating reigned as the unchallengedchampion until a few years ago, when ahandful of investigators turned underbal-ance on its head (next page). Building onexperimental work by the US Department ofEnergy and others, Oryx Energy and ARCOindependently developed new completiontechniques utilizing extreme overbal-ance—perforating with wellbore pressuresignificantly above the level required to frac-ture the formation. The patented Oryx andARCO methods differ in their approach, buteach involves a process that may genericallybe called extreme overbalance perforating(EOP) and a related method of forcing anextreme overbalance pressure into existingperforations, called extreme overbalancesurging (EOB surging).3

Perforating underbalance or with extremeoverbalance are in many ways opposites,but they are not mirror images of each other.In underbalance perforating, the goal is tocreate a channel and clean the channel with

Oilfield Review

1865 1910 1948 1975 1980 1993

Arrows illustrate pressure differentials

10 to 30 ft

■■The first 130 years of perforating. 1865: Tin torpedoes filled with gunpowder, and later with nitroglycerin, are lowered to the depth ofinterest and detonated. 1910: The single-knife casing “ripper” involves a mechanical blade that rotates to puncture a hole in the casing.1948: The first shaped charges, developed by Welex Jet Perforating Company, are applied to oil wells, generally with a slight overbal-ance for well control. 1970s: Underbalance, under investigation for 20 years, is tied with perforating by Roy Vann. Continued work byothers through the 1980s accelerates its popularity. 1980s: Propellant fracturing produced fractures from the burst of pressure developedby rapid burning of propellant. Although still under investigation, the method encounters problems operationally and in reproducibility.1993: Extreme overbalance perforating, pioneered by Oryx Energy Company, succeeds in commercial wells.

flow from the formation, then stimulate orgravel pack later as necessary. In extremeoverbalance methods, the idea is to simulta-neously create and stimulate the channel,which develops into a small biwing fracturethat obviates the need for cleaning the per-foration tunnel. Some operators have alsoproposed extreme overbalance methods thatsimultaneously place resin for sand controlor acid for etching fracture faces.4

Since extreme overbalance methodsbecame commercial in 1990, their applica-tion has taken a roller coaster ride. Follow-

Autumn 1996

1. Screenout is the point at which no more proppant canbe pumped into a hydraulic fracture system withoutan increase in pump pressure. Early, or premature,screenout is caused by an impermeable bridging ofmaterial across the fluid pathway that prevents furtherextension and propping of the fracture.

2. King GE, Anderson A and Bingham M: “A Field Studyof Underbalance Pressures Necessary to Obtain CleanPerforations Using Tubing-Conveyed Perforating,”paper SPE 14321, presented at the 60th SPE AnnualTechnical Conference and Exhibition, Las Vegas,Nevada, USA, September 22-25, 1985.Tariq SM: “New, Generalized Criteria for Determiningthe Level of Underbalance for Obtaining Clean Perfo-rations,” paper SPE 20636, presented at the 65th SPEAnnual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 23-26, 1990.Behrmann LA: “Underbalance Criteria for MinimumPerforation Damage,” paper SPE 30081, presented atthe SPE European Formation Damage Control Confer-ence, The Hague, The Netherlands, May 15-16, 1995.

ing an initial wave of interest, only a smallbut devout core of proponents continues tocarry the torch—last year about half theextreme overbalance jobs in North Americawere performed by only five operatingcompanies. Nevertheless, limited but per-sistent curiosity from the industry refuses todie. In 1994, seventeen operating and ser-vice companies jointly sponsored experi-ments on large blocks of sandstone toinvestigate EOP fracture mechanics andways to optimize pressure requirementsand perforation design.

3. Three early works:Bundy TE and Elmer MJ: “Perforating a High-PressureGas Well Overbalanced in Mud: Is It Really ThatBad?” paper SPE 16894, presented at the 62nd SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, September 27-30, 1987.Cipolla CL, Branagan PT and Lee SJ: “Fracture DesignConsiderations in Naturally Fractured Reservoirs,”paper SPE 17607, presented at the 1988 SPE Interna-tional Meeting on Petroleum Engineering, Tianjin,China, November 1-4, 1988.Northrup DA and Frohne K-H: “The Multiwell Experi-ment—A Field Laboratory in Tight Gas SandstoneReservoirs,” Journal of Petroleum Technology 42, no. 6 (June 1990): 772-779.The Oryx method:Handren PJ, Jupp TB and Dees JM: “Overbalance Per-forating and Stimulation Methods for Wells,” paperSPE 26515, presented at the 68th SPE Annual Techni-cal Conference and Exhibition, Houston, Texas, USA,October 3-6, 1993.

Field experience has also broadened, withabout 900 EOP jobs performed to date,mostly in North America. Marathon per-formed extreme overbalance procedures in20% of its wells in 1995 and expects thatnumber to reach 35% in 1997. As moredata accumulate, the case for extreme over-balance resurfaces, each time with a bitmore ammunition. The technique hasclearly established a niche, yet its applica-bility remains incompletely defined. Whereare extreme overbalance methods today,and what promise do they hold?

19

The ARCO method:Petitjean L, Couët B, Abel JC, Schmidt JH and Fergu-son KR: “Well Productivity Improvement UsingExtreme Overbalance Perforating and Surging—CaseHistory,” paper SPE 30527, presented at the 70th SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, October 22-25, 1995.For a more recent version of the same work:Couët B, Petitjean L, Abel JC, Schmidt JH and Fergu-son KR: “Well-Productivity Improvement by Use ofRapid Overbalance Perforation Extension: Case His-tory,” Journal of Petroleum Technology 48, no. 2(February 1996): 154-159.

4. Handren PJ and Dees JM: “A New Method of Over-balance Perforating and Surging of Resin for SandControl,” paper SPE 26545, presented at the 68th SPEAnnual Technical Conference and Exhibition, Hous-ton, Texas, USA, October 3-6, 1993.

4000 to 8000 psi(0.8 to 1.4 psi /ft)

Payzone

Hydrostatic oratmospheric

Packer 30 to90 ft above valve

Invadedzone

Isolation valve:either retrievable

SXPV or permanentSXAR equipment

Pressurized N2

Casing

Cement

Fracturing fluid8000 to 12,000 psi

50 to 100 ft,less often to 300 ft

N2 Pump

Well A Well B

2600 ft gas

6753 ft liquid

Surge disk

5472 ft gas

4984 ft liquidW

ellh

ead

pres

sure

, psi

Time, sec

-40 -20 0 20 403000

3500

4000

4500

5000

5500

6000

6500

Well A

Well BActualModeled

■■Extreme overbal-ance perforating.Most proceduresfollow a variant ofthis basicapproach.

■■The 30-second moment of truth. Modeled(solid line) and actual data (circles) for pres-sure drop in two ARCO wells (above). Theslower decay in Well A is due to greaterfriction produced by a large volume offluid (right). The goal is to minimize frictionlosses, increasing propagation speed, min-imizing leakoff into the formation andmaximizing fracture length. (From Coüetet al, reference 3.)

The EOP Why and HowJohn Dees and Pat Handren, extreme over-balance pioneers at the Sun Company (nowOryx Energy), began investigating overbal-ance methods in the late 1980s whenunderbalance failed to give good results inWest Texas fields. The Oryx team foundwhat others had also observed for sometime: Correctly applied underbalance perfo-rating can be compromised by fairly com-mon reservoir and operational conditions. Ifreservoir pressure is low or depleted, thepressure differential may be insufficient toclean perforations. Likewise, if permeabilityis low—probably less than 10 millidarcies(md), but the value depends on reservoirpressure and oil viscosity—formation fluidmay not flow vigorously enough for clean-ing. And if rock strength is low, underbal-ance pressure differential large enough foreffective cleaning may collapse the forma-tion and necessitate further intervention tosave the well.

Underbalance perforating can also be hin-dered by more complex problems. Improperkilling of a well, for example, can replugperforations with filter cake that may not bedislodged during production.5 Sometimes,despite good reservoir pressure and perme-ability, the damaged zone reaches deepenough to limit the effectiveness of under-balance. Also, when permeability variesdramatically—such as a thin, 1-darcy layersandwiched between two thick 10-md lay-ers—the thicker sections will dominate theflow properties and can reduce the effec-tiveness of underbalance.6

Extreme overbalance perforating cansidestep these problems. In EOP comple-tions, tubing pressure is increased before theguns are fired and then released into thewellbore with gun detonation. At this point,

20 Oilfield Review

because wellbore pressure exceeds rockyield strength, perforating initiates one ormore small fractures. These fractures do notdevelop the length or height of conventionalhydraulic fractures, but the event lasts longenough to push the fractures beyond thezone damaged by invasion and past the tipof the perforation (previous page, top ).While EOP fractures are shorter in lengthand height, they may develop greater widthand so possibly have a higher conductivityper foot than hydraulic fractures.

Most EOP jobs follow the same basic pro-cedure (previous page, bottom). Perforatingguns are lowered to the depth of interest,then spotted to the top of the guns is a smallamount of liquid selected for the well con-ditions—brine, lease crude, fracturing fluid,acid or liquid with proppant. All or most ofthe wellbore above the liquid is filled withcompressible gas, usually nitrogen, lessoften carbon dioxide or air. The gas col-umn is then pressured up, like a tightlysqueezed coil spring. Sometimes liquid isalso spotted above the gas to further com-

N2

Pay zone

Invaded zone

Pressurized N2

Rupture disk

Fracturing fluid

4000 to 8000 psi(0.8 to 1.4 psi /ft)

Pump

Time 1

Autumn 1996

■■Extreme overbalance surging. Surging is peIt may follow immediately after perforating orthe sooner after perforating, the more effectivtime 2 (right) shows the penetration of fluid intover time.

press it. Rarely does the liquid fall throughthe gas because compressed gas, typicallyat about 4000 psi [27,500 kPa], develops adensity of 1 to 3 lbm/gal [0.12 to 0.36g/cm3] and a high surface tension. This cre-ates an interface which, in the small diame-ter of tubing, prevents liquid from displacinggas. Because the surface pressure of gas canreach 10,000 psi [69 MPa] or more, tubing-conveyed perforating (TCP) guns are usuallypreferred over wireline-conveyed gunsbecause they are operationally easier tohandle at high pressures.

With detonation of the guns, the liquid isdriven at very high flow rates by the rapidlyexpanding gas and rushes into the perfora-tions. Because the liquid is nearly incom-pressible, it acts as a wedge that initiatesfractures, extending the effective wellboreradius. Erosion from the liquid and anyentrained proppant flowing at more than100 bbl/min [16 m3/min] may scour the for-mation, creating stable flow channels. Inmany EOP jobs, the event is timed to stopjust when the gas reaches the perforations,

PumpN2

Tip offracture

Time 2

rformed on wells with existing perforations. a few hours to a few days later. In general,

e the surge. Comparison of time 1 (left) ando the rock and propagation of the fracture

since the gas would quickly leak off into theformation. Some operators, who have wellswith large tubular volumes, continue apply-ing pressure as the gas enters the perfora-tions. The gas also acts as an abrasive thatscours the perforation. In either case—stop-ping as the gas hits the perforations or con-tinuing—the higher the pressure and largerthe gas volume (a larger “spring”), thegreater the fracturing power.

Pressure generated at the perforations dur-ing EOP or EOB surging must be highenough to overcome two obstacles: it mustexceed the minimum in-situ rock stress,and it must fracture through any imperme-able debris barrier remaining in the perfora-tion. The debris barrier often defeats theconventional process of perforation break-down and cleanup.7 Modeling shows thatto overwhelm the barrier, the extreme over-balance pressure gradient usually needs toreach at least 1.4 psi per foot [31.6 kPa/m]of well depth.8 This gradient produces afracture radius that is on the order of 10 to20 ft [3 to 6 m] although it may extend upto 30 ft [9 m].

In the high-energy context of extremeoverbalance, flow restriction due to perfora-tion damage has such a minor effect on per-foration conductivity as to become almostirrelevant. Charge debris has no time toharden and is thought to be pulverized andblown far back into the created cracks, likea mashed up cork pushed into a wine bot-tle. The low permeability of the shatteredzone is more than compensated for by thehigh permeability of the fractures. In addi-tion, gas jetting into the tunnel at nearly thespeed of sound may erode and scour wallsof the tunnels and fractures.

An extension of this method involvespumping additional fluid at a high rateimmediately following EOP or EOB surging,with or without proppant, to drive the frac-tures farther (left ). Pump rates have to be

21

5. Mason JN, Behrmann LA, Dees JM and Kessler N:“Block Tests Model of the Near-Wellbore in a Perfo-rated Sandstone,” paper SPE 28554, presented at the69th SPE Annual Technical Conference and Exhibi-tion, New Orleans, Louisiana, USA, September 25-28,1994.

6. Hsai T-Y and Behrmann LA: “Perforating Skin as aFunction of Rock Permeability and Underbalance,”paper SPE 22810, presented at the 66th SPE AnnualTechnical Conference and Exhibition, Dallas, Texas,USA, October 3-6, 1991.

7. Behrmann LA and McDonald B: “Underbalance orExtreme Overbalance,” paper SPE 31083, presented atthe SPE International Symposium on Formation Damage Control, Lafayette, Louisiana, USA, February14-15, 1996.

8. Prudhoe Bay seems to be the exception. ARCOreports good results there with only 1.1 psi/ft [24.2 kPa/m].

22 Oilfield Review

high enough to keep the fluid above the for-mation fracture pressure. The injection rateneeded for success depends on formationcharacteristics and in some cases, up to15,000 ft3/min [420 m3/min] has been used.ARCO also developed a gas-surging tech-nique that enhances hydraulic fracturing inwells previously perforated. (see “Elementsof EOP Design: Operations,” page 31.)9

What can be expected from an extremeoverbalance operation? Recoverablereserves may be increased, and under favor-able conditions production rates canincrease dramatically, due to reduction innear-wellbore pressure loss and in reservoirskin—70% of EOP wells show a negativeskin (see “EOP for Skin Reduction,”below).10 In one Oryx field, where conven-tionally completed wells—fracture treatedwith 20,000 gallons [3180 m3] of gelleddiesel and 20,000 lbm [9070 kg] of 20/40sand—produced 500 Mcf/D, EOP wells pro-

duced initially at twice that rate anddepleted in 3 years instead of 7 to 10 years.

EOP also facilitates lower treating pressuredue to creation of a more conductive flowpath. In addition, EOP and EOB surgingallow for placement of a higher percentageof proppant when followed by a conven-tional frac job. ARCO, for example, reportsplacement of 95% of sand in extended-reach wells, probably due to higher conduc-tivity of flow paths into the formation.11 Itformerly placed only 35% of sand.

The economics of extreme overbalance isnot clear-cut, and has contributed to skepti-cism. One-to-one comparison with conven-tional completions is sometimes difficult.Should EOP be compared to underbalanceperforating alone, or to perforating andhydraulic fracturing? While the latter mayseem logical, in practice EOP does not fullyreplace hydraulic fracturing. Marathon, forexample, will later frac more than a third of

its EOP wells, and about 80% of wells thatwere surged after EOP. Marathon finds thatEOP operations average one day longer, butproduce first oil one to three days earlier.

Some operators use EOP as a cost-effectiveway to identify hydraulic fracturing candi-dates, as a means to minimize near-well-bore tortuosity and thereby reduce hydraulicfracturing costs (less fluid pumped andlower surface pressures), or as a low-costmeans to establish a high flow rate early.The biggest benefit of EOP, however, is theability to place more sand and prevent anear-wellbore screenout during a subse-quent frac job.

Costs for EOP can vary widely, and dependmostly on availability of compressed nitro-gen. With easily accessible nitrogen, tubu-lars fit for EOP pressures, and a completionthat would normally include TCP guns, EOPcosts slightly more than a small hydraulicfracture. If nitrogen is not readily available,

EOP for Skin Reduction

In 1994, Marathon stood at a completion cross-

roads in an eastern New Mexico gas field. In the

30-year-old field, Marathon and other operators

produced from 35 wells, each making 4 to 6

MMcf/D. In a typical completion, skin averaged

around 50 but reached as high as 150. The reser-

voir, an upper Pennsylvanian carbonate, averaged

39 md with a reservoir pressure of about 1000 psi

[6890 kPa]. Could skin be reduced?

Studying the success of nearby operators who

use extreme overbalance methods, Marathon

decided to try extreme overbalance surging to

reduce skin. The first candidate well was in the

North Indian basin section, with a perforated

interval of 171 ft [52 m].

A fairly conventional completion design was

used for extreme overbalance surging with acid.

A 60° shot phasing was chosen to evenly distribute

20% HCl acid and encourage development of a

biwing fracture. Previous jobs were at two shots

per foot (spf), but this low shot density was

thought to contribute to high skin. Inflow perfor-

mance and NODAL analysis indicated that 4 spf

would probably result in more effective acid place-

ment. Deep penetrators were used to reduce flow

restriction thought to be associated with big-hole

charges. And the pressure gradient was designed

to be 1.4 psi/ft—low by today’s standards, in

which some jobs are designed at 2 psi/ft

[45 kPa/ft].

About 500 ft [152 m] of fluid was spotted at the

bottom of the string, and the tubing was charged

with N2. Fluid pumped after the gas achieved a

flow rate of 200 bbl/min [31.8 m3/min] after the

guns had fired. When the well came in, skin was

computed at 5, a dramatic 10-fold reduction.

Well production was higher than expected—over 5

MMcf/D, compared to 4 MMcf/D for conventionally

completed wells. Although completion costs were

about 8% higher, the initial rate gain quickly paid

back the higher cost. Today, the well continues

producing at a higher rate than conventionally

completed wells of similar age.

Since this job in 1994, Marathon has moved

toward a new completion strategy. During the two

years of production, decline in reservoir pressure

from 1000 to 800 psi [5512 kPa] means that skin

plays an increasingly significant role in well pro-

ductivity. Because every well intervention risks

an increase in skin, Marathon is attempting the

least intrusive completion strategy: air drilling in

slight underbalance and completing open hole

(barefoot), without perforations. The carbonate is

fractured enough to produce without perforations,

yet competent enough to withstand production.

Other operators in the region report wells produc-

ing over 5 MMcf/D with this approach.

If reservoir pressures were 2000 to 3000 psi

[13.8 MPa to 21 MPa], according to Ron Folse,

a Marathon engineer who works in the field,

then extreme overbalance might be the method of

choice. But with the lower reservoir pressures,

Marathon is able to drill underbalance with air,

and with the barefoot completion achieve the ben-

efit of minimizing completion skin. Proof of this

new method is pending pressure transient analy-

sis, which is expected to indicate a lower skin and

less fluid invasion than with EOP.

Createdfracture

Preferredfracture plane

Maximumhorizontal stress

Min

imum

horiz

onta

lst

ress

Maximumhorizontal stress

Pre

ssur

e

Logarithmic time

1000µsec

1000msec

1000sec

HydraulicPropellantOverbalanceDetonation

23Autumn 1996

■■The ideal relationship between perforations and the in-situ stress field. Fractures aligned with the direction of maximum horizontal stress will openin the plane of least resistance, against the minimum horizontal stress. The closer the fracture and maximum stress planes align, the less tortuosityfractures develop, resulting in less pressure drop. Fractures generally initiateat the sandface, the base of the perforation where it meets the formation.

■■Timing of down-hole events.Whereas hydraulicfracturing can lasttens of minutes tohours, extremeoverbalance perfo-rating is finished in20 or 30 seconds.

9. Petitjean et al, reference 3.10. Skin is a dimensionless value that refers to the pres-

sure drop near the wellbore during production orintervention. The pressure drop indicates a resis-tance to flow attributable to reduction in permeabil-ity near the wellbore occurring during drilling, com-pletion or operations. A positive skin value denotesformation damage; a negative skin indicates anincreased ease with which fluid can flow betweenthe wellbore and formation.

11. Couët et al, reference 3.12. Phasing is the angle between shots. Phasing of 180°

means two shots in opposite directions, whereas a120° phasing distributes three shots around the well-bore circumference, one every 120° degrees.

■■A long way to Tipperary. Hydraulic frac-tures may have to march around the bore-hole circumference before extending intothe formation, depending on the distancebetween the perforation and the preferredfracture plane (PFP). Here are two scenar-ios for a 120° phased gun with conven-tional hydraulic fracturing. If the perfora-tion lies in the PFP (A), one wing of thefracture will initiate from the perforation,and the other winds around the boreholefrom the perforation base until it turns intothe PFP. If the perforation is 30° or morefrom the PFP (B), multiple parallel fracturesmay develop from the perforation.(Adapted from Behrmann and McDonald,reference 7.)

A

B

30°

Perforation

Preferred fractureplane

Createdfracture

EOP can cost more than twice that of a con-ventional completion. While EOP wells payout faster, with higher initial production, itremains unclear under what conditions thelong-term payout from EOP is comparable tothat of hydraulic fracturing.

Economic uncertainty aside, the lack ofearly enthusiasm for these methods alsoresulted from unclear explanations for theirsuccess and benefits, and inconsistentresults probably related to misapplication.Today, with the analysis of more data, theproper role of EOP is coming into focus.Central to this understanding is an apprecia-tion of EOP mechanics.

Are EOP Fractures Different?The most effective fracture, regardless of thegenerating mechanism, paves an autobahnbetween the reservoir and wellbore: a sin-gle, straight parting of significant width withfew smaller, competing fractures. This ideal

would be achieved with perforations 180°apart and aligned with the maximum in-situstress (top). But this direction, called thepreferred fracture plane (PFP), is oftenunknown, and many operators cannot yetroutinely control gun orientation. Still, it ispossible to approach this ideal with bothhydraulic fracturing and EOP. They work bydifferent mechanisms, however, and pro-duce fractures with different characteristics.

In hydraulic fracturing, pressure at the rockface rises gradually from a slight overbal-ance to the point of failure, after which the

fracture propagates as long as the treatmentcontinues—and it doesn’t screen out ordehydrate. This gradual buildup of pressureis equivalent to opening a door by pushingit slowly (above). Two events probably takeplace. First, multiple fractures may developfrom the perforation base or tip, dependingon proximity of perforations to the PFP andon shot phasing.12 If perforations are morethan 30° from the PFP, fractures may takecircuitous routes around the cement-forma-tion interface before turning to align in thePFP (right).

24 Oilfield Review

■■The long and short of EOP. If a perforationis more than 45° from the PFP, EOP frac-tures tend to propagate immediately froma point on the wellbore wall aligned withthe PFP, rather than wind around the well-bore from another initiation point (A). The channel shown between the perfora-tion and fracture develops after the frac-ture initiates and is eroded during the EOPprocess. Where perforations are within 45°of the PFP (B), fractures initiate from theperforation. Only small fractures initiatefrom perforations more than 45° from thePFP. These fractures do not grow. Note thatfractures initially ignore the in-situ stressfield and probably extend straight fromthe wellbore. Within a few wellbore diame-ters they turn into the PFP. The absence of multiple parallel fractures is thought tobe related to the sudden pressure load on the cement-by-formation microannulus,sealing off a path for the development ofsecondary fractures.

■■Rate of reorientation of an extreme over-balance fracture into the PFP. Angles ofless than 15° (A) result in rapid reorienta-tion. From 15 to 30° (B), reorientation ismore gradual. At 30 to 60° (C), the fractureinitiates at the base of the perforation andruns parallel to the tunnel before turning.Beyond 60° (D), the fracture ignores theperforation and initiates at the sandface.[From Salsman A, Behrmann L and Brown-ing G: “Extreme Overbalance Perforating,”The Perforating and Testing Review 8, no. 1 (May 1995): 1-8.]

A

B

30°

A

B

C

D

<15°

15 to 30°

30 to 60°

> 60°

Perforation

Preferred fracture plane

Createdfracture

The second event is development of a sin-gle, dominant biwing fracture initiating atthe borehole wall. Within about two well-bore diameters, this major fracture curvesuntil it aligns with the PFP, and becomesresponsible for most communicationbetween the wellbore and formation. Com-peting with it, however, may be the manysmall, curving fractures near the wellbore.These fractures act as chokes that increasethe near-wellbore pressure drop.

By contrast, an EOP fracture is producedby a sudden burst of pressure. This high-ratepressurization of the rock results in a rate-dependent fracture mechanism thatapproaches the ideal fracture system moreclosely than hydraulic fracturing. Instead ofopening the door by pushing gradually, anEOP operation is analogous to breaking thedoor down with a sledgehammer. Becauseextreme overbalance pressure overwhelmsthe fracture breakdown pressure, EOP frac-tures initially overwhelm the in-situ stressfield and probably extend straight from thewellbore, like spokes from the hub of awheel, then turn gradually into the PFP(left). Fractures may form at all perforations,but extend only from those nearest the PFP,creating a biwing fracture.

Multiple parallel fractures are not seen inEOP studies, possibly because the suddenpressure load closes the microannulusbetween the cement and formation, shuttingoff a path for secondary fractures. Anotherpossible explanation for the absence of mul-tiple fractures is that rate-dependent fractureinitiation favors only weakest portions of therock. This observation is borne out in con-ventional fracturing, where high-rate injec-tion is known to minimize creation of multi-ple fractures. EOP also allows a larger anglebetween the PFP and perforations beforefractures ignore the perforations and initiateat a site on the wellbore aligned with thePFP (right).13

EOP CandidatesWidely accepted candidate criteria for EOPare low permeability (below about 10 md),reservoir pressure insufficient to achievecleaning with underbalance, a highlymobile clay content, and the need to estab-lish a fracture in multiple layers, even thosewith different mechanical or flow properties.Other reasons to use EOP are reduction innear-wellbore damage and pressure dropassociated with poor linkage of fractures fol-lowing underbalance perforating, to avoidseveral days of swabbing before the resultsof underbalance perforating are known, andto eliminate near-wellbore tortuosity duringhydraulic fracture stimulation of extended-reach wells.14

Dees lists two leading reasons for EOP:immediate indication of well producibility(which can be delayed with underbalanceperforating) and skin reduction. Behrmannand McDonald also list as applicationsdiversion of acid in carbonates and intersec-tion of natural fractures.15 Other authors

25Autumn 1996

13. Behrmann and McDonald, reference 7.14. Petitjean et al, reference 3, ARCO method.15. Behrmann and McDonald, reference 7.16. Petitjean et al, reference 3.

■■Theoretical modeling of fracture extension versus time for various permeabilities. The zone of fracture extension corresponds to the sloping section of the curves. Where thecurves flatten indicates the time after which only fracture erosion takes place. At 100 md,fracture extension reaches its maximum of about 10 m in 15 seconds. The remaining timeprobably represents only erosion in the fracture. Fracture extension in a 0.1-md settingcontinues for about 30 seconds and reaches 45 m [148 ft]. (From Couët et al, reference 3.)

0

10

20

30

40

50Fr

actu

re e

xten

sion

, m

Time, sec0 5 10 15 20 25 30 35

0.1 md

1.0 md

10 md

100 md

1 darcy

present several scenarios for application ofEOP in high-permeability settings, often forplacement of acid or proppant. Marathonengineers, on the other hand, use EOP inthe Rocky Mountains of the USA mainly inhard rocks, where they assume perforationspenetrate only 10 in. [25 cm] and so remainin the damaged zone. In hard rocks, EOPdrives the effective wellbore radius wellbeyond the damaged zone.

The majority of extreme overbalance pro-ponents view it as complementary to con-ventional underbalance perforating and as aprecursor to conventional hydraulic fractur-ing. Bryan McDonald, who studies extremeoverbalance methods for Schlumberger, hasranked variables that influence the choicebetween EOP and underbalance perforating.In order of importance, the leading variablesare as follows:

Well depth—The limiting influence withdepth is friction between the fluid and tubu-lars, which reduces ability to deliver suffi-cient pressure at the perforations. The mini-mum pressure gradient was originallyplaced at 1.2 psi/ft [27 kPa/m], but this hasinched up as insufficient pressure wasthought responsible for early failures. Someoperators today use gradients as high as 4psi/ft [90 kPa/m]. In general, deeper wellsrequire a lower pressure gradient because

the energy available to propagate a fractureis proportional to:

(pressure gradient × depth) – in-situ stress

in which the in-situ stress is given by thefracture gradient × depth, so the expressionbecomes:

(pressure gradient – fracture gradient) ×depth.

The fracture gradient may vary from 0.4 to1 psi/ft [9 to 22 kPa/m], with a typical valueof 0.7 psi/ft [15.8 kPa/m], so that withincreasing depth, the gradient differencecan be reduced. Even with the lower pres-sure gradients required in deep wells, depthcan become a limiting factor at 10,000 to15,000 ft [3000 to 4500 m].

Technique, however, sometimes compen-sates for physical limitations. Oryx has suc-cessfully treated an interval at 19,000 ft[5790 m] by placing calcium bromide waterabove nitrogen to deliver 24,000 psi [165MPa] at the perforations. “We always placeless than 1000 ft [300 m] of fluid on bot-tom,” said Pat Handren of Oryx. “This way,energy goes into fracturing, not into over-coming fluid friction.” Still, most operatorsare more comfortable performing EOPabove 10,000 ft true vertical depth.

Permeability—There may be no more con-troversial an EOP topic than how permeableis too permeable. The concern is that leakoffwill outpace the flow rate needed to main-tain a pressure that exceeds rock strengthand extends the fractures. High rates of spurt

and leakoff result in significantly shorter frac-tures (above).

Work by Petitjean and Couët indicates thatat 100 md, up to 80% of fluid can leak off inless than 10 seconds, limiting an alreadyshort fracturing event.16 Some operatorsplace the cutoff at 100 md, although othershave claimed success at 1 darcy. John Dees,who has a patent on continuous pumpingimmediately after the extreme overbalanceevent, maintains that EOP followed by surg-ing with resin can succeed even with perme-ability in the 1-darcy range.

Pat Handren considers permeability-lengtha more useful parameter than permeabilityalone. This takes into consideration verticallyvariable permeability, which can affect flowproperties. Handren’s breakpoint is about 20md-ft. If permeability hits this value, Han-dren would choose underbalance perforat-ing—unless reservoir pore pressure is below0.35 psi/ft [8 kPa/m] in which case he prefersEOP to be sure perforations are cleaned. Atpermeability around 1 darcy, some forma-tions may be friable enough to require EOPwith injection of resin to prevent sand from

Shockabsorber

Before

Shearpins

Airchamber

Operatingpiston

Pressureports

Firing pin

After

Sandstone (some carbonates)

Sandstone with water retention

Carbonate

Sandstone with severewater sensitivity

Carbonate and sandstone

Shaly low-pressure gas,or <1000 psi

Heavy oil, paraffin present or welldrilled with oil-base mud

Gas sandstone <1000 psi

Reservoir Conditions Fluid Type

2% KCl water

2% KCl water with alcohol

15 to 20% HCl

Less crude

10% acetic acid

10% acetic acid or 1.5% HF

Xylene

Diesel

26 Oilfield Review

■■EOF firing head before and after firing.The firing head nests inside either a pro-duction valve or a gun release system,and is designed for no-delay firing.

■■Rules of thumb in fluid selection.

flowing out the tunnel or to prevent the tun-nel from collapsing.

Tubular and wellhead ratings—Tubingdiameter and pressure ratings limit gas pres-sure and volume, which determine horse-power deliverable at the perforations. Biggeris always better, and biggest and strongest isbest. At a minimum, tubing needs to endure1.4 psi/ft. ARCO uses up to 7-in. tubing onthe North Slope in Alaska, USA, andMarathon has moved from 31/2-in. to 41/2-in.tubing wherever possible.

Likewise, wellhead pressure controlequipment must at least match tubular rat-ing. The objective is to have tubulars thatcan safely withstand the pressures neces-sary to deliver a fracturing pressure at theperforations. ARCO’s rapid overpressuredperforation extension, or ROPE, methodowes much of its development to theopportunity at Prudhoe Bay, Alaska, ofworking on closely spaced wells with largetubing (more than 2 7/8 in.).

Perforated interval length—Dissipation ofpressure over distance limits the intervallength that can be effectively treated withextreme overbalance. Treatments on inter-vals of up to 1000 ft have been performedin a few wells, but most operators are confi-dent that uniform, effective treatments canbe carried out over only 70 to 100 ft [21 to30 m]. Shot density and permeability alsoinfluence treatable interval length. As arule, Oryx finds that 1 shot every 2 ft [60cm] will maintain sufficient pressure overseveral hundred feet. Marathon prefers tolimit intervals to about 50 ft [15 m].

Elements of EOP Design: HardwareTo one degree or another, the first genera-tion of EOP jobs was constrained by precon-ditions of the well completions. Now, oper-ators recognize that success of theprocedure often relies on planning comple-tions to optimize EOP jobs. The main con-straints are surface-control equipment andtubular ratings. ARCO makes routine use ofa wellhead isolation tool, or tree saver. Thisdevice fits on top of the wellhead and has amandrel that extends through the wellhead,sealing in the tubular. Downhole, Oryx willuse casing with a higher pressure rating, andrun cement bond logs to determine whetherthe interval to be perforated is fullycemented. When cement bond cannot beconfirmed, Oryx prefers to keep pressureonly on the tubing, using an isolation valveto avoid exceeding the casing burst rating.17

In addition, Oryx uses the largest possibletubing diameter to deliver the largest possi-ble volume of gas, and always pressure teststubing to be sure it meets its rating.

After the completion configuration, thenext most important variable is wellborefluid composition. All operators agree thatwhatever type and quantity of fluid areused, friction reduction polymers are amust. In many operations, they are already agiven. A review of fluid design criteria andtheir application has been prepared by JohnDees (below).

EOP calls for new thinking about down-hole equipment, from the firing head to theguns. A new kind of firing head, for exam-ple, has been designed to better accommo-

■■SXAR system for extreme overbalance operations. A member of the X-Tool equipmentfamily for permanent completions, in which guns are dropped into the wellbore ratholeafter firing, this completion tool makes use of a break-plug mechanism for rapid releaseof guns and allows production immediately after perforating. Applied pressure (red),before and after activation, is typically 10,000 psi.

Applied Hydrostatic Atmospheric

Pressure

Releasehousing

Releasepin

Releasepiston

Breakplugs

SXAR Equipmentas Assembled

Detonating Cord Initiated,Guns Shot

Guns Dropped,Pressure Applied

date the special needs of EOP jobs. Conven-tional TCP firing heads are activated by posi-tive pressure, but have a hydraulic time-delay mechanism that stalls firing for up to15 minutes until activating pressure is bledoff to achieve underbalance. This delay isunnecessary with EOP—good safety practiceminimizes exposure of surface and down-hole equipment to high pressure. For thispurpose, Schlumberger introduced the EOF-BA extreme overbalance firing head, whichhas no time delay (previous page, right). Thefiring head starts the train of events leadingto gun detonation when pressure exceedsthe predetermined strength of shear pins.This pressure drives an operating pistonupward to release a firing pin. Because thepiston must move against gravity, the firinghead is unaffected by vertical drops.

The EOF firing head nests inside either agun-release or an isolation valve system,depending on completion type. The Explo-sively Initiated Automatic Release (SXAR)system is used for permanent completions,in which the guns are fired and immediatelydropped into the rathole, allowing the wellto come on line immediately after perforat-ing (right). The Explosively Initiated Produc-tion Valve (SXPV) is used for “shoot-and-pull” operations, in which the well is oftenkilled and the guns removed to provide anunobstructed flow path, to run the comple-tion string or to perform other work such asa frac job.

In both completion types, safety and wellperformance depend on quick and preciselytimed release of pressure. The valve andgun-release system must assure that releaseof pressure from the tubing is synchronizedwith detonation of the guns, thereby keep-ing excess pressure off the casing. If unper-forated casing is subjected to extreme over-balance pressure, it can damage mechanicalcomponents in the well, cause a packerleak, blow packers uphole (packers areoften the weakest link), burst casing or col-lapse perforating guns.

For this reason, Schlumberger developed aunique mechanism that assures rapid

27Autumn 1996

17. For a safety checklist prepared by Oryx, see theappendix in Handren et al, reference 3.

28

Flow portsclosed

Firing head

Detonatingcord tubeadapter

Operatingpiston

Release pins

Supportsleeve

Break plugsupport

Flow portsopen

SXPV Equipmentas Assembled

Detonating CordInitiated, Guns Shot Pressure Applied

Break plugs

■■SXPV equipment for EOP. This X-Tool is used when wells are killed to remove guns—shoot-and-pull—for unobstructed flow, running completions or to perform other work.Break plugs ensure rapid opening of the production valve. Red is applied pressure, blueshows hydrostatic and green is atmospheric pressure.

■■Heart of the X-Toolsystem, before andafter detonation.Whole break plugs(beside the golf ball)support the tripmechanism, butshatter when thedetonating cord,passing throughtheir center, under-goes a high-orderdetonation. This vir-tually assures thatguns release or theproduction valveopens at themoment the gunsfire, safely keepinghigh pressure offcasing, packers andsurface equipment.

release of pressure only when perforation iscertain. The heart of this device is a stack ofbreak plugs that have high compressivestrength, but low lateral strength (left). Theplugs can support the compressive force ofthe pressure applied to the valve, but nothigh lateral stress. The detonating cordpasses through the plugs and if it undergoesa high-order detonation—which virtuallyassures firing of the guns—the lateral shockof the cord detonation shatters the plugs andtrips the mechanism. Because the SXPV andSXAR are activated by the detonation trainthat fires the shaped charges, there is littlechance of loading the casing prematurely.The SXPV and SXAR belong to a family offive new completion tools, the X-Tools, thatmake use of this gun-activation method.

The SXPV design enhances EOP perfor-mance by opening the flow ports faster thanany other valve (below left). Rapid transferof pressure to the perforations is essential,since a typical EOP event lasts 15 secondsat most, and must take advantage of eachsecond to maximize the amount of workapplied to the formation. Loss of time con-veying fluid from the tubing to the perfora-tion translates into reduction in fracturelength and possibly in fracture width.

The SXPV valve begins opening 8 to 20milliseconds (msec) after gun detonation,and is fully open after another 4 msec (nextpage, top). This high-speed operation meansthe valve opens fully before fluid pressurestarts transferring from the tubing to the per-foration tunnels. With a conventional,hydraulically activated valve, detonation tofull opening of the valve can take a full sec-ond, or 10% of a typical 10-second EOBevent. This time delay means that less energygoes into creation of fractures, resulting inless fracture length (next page, bottom). Inaddition, the SXPV flow ports provide a flowarea 11/2 times that of the tubing diameter,which minimizes friction and maximizestransfer of pressure from the tubing.

In permanent completions, where guns aredropped into the rathole after detonation,the release system must overcome two engi-neering challenges: It must assure isolationof completion hardware from gun shock,which can unseat packers, and it must over-come friction in deviated wells that preventsthe guns from falling. Unassisted, guns usu-ally will not drop until well deviationreaches 40 to 45°. Excessive sanding anddebris can also prevent gun release.

Oilfield Review

Jet i

nter

actio

n w

ithw

ellb

ore

fluid

Jet t

ail f

orm

ed

Max

imum

ann

ulus

pres

sure

from

gun

swel

l

Slu

g ex

its g

un

End

of

pene

trat

ion

Gun

ope

n to

wel

lbor

e flu

id in

flow

Time, µsec

Time, msec

0 1000

0 1 2 3 4 5 6-2000

-1000

0

1000

2000

3000

4000

5000

6000

7000P

ress

ure,

psi

Gun shock

X-valveopens

Gunfiring

Hydrostatic

Ext

rem

e ov

erba

lanc

e pu

lse

Pulse lasts 15 to 20 secondsafter this point

■■A simplified viewof the first millisec-onds of perforating.The SXPV valvebegins opening asearly as 8 msecafter gun detona-tion, and is fullyopen after another4 msec. Rapidopening means thevalve opens fullybefore fluid pres-sure starts transfer-ring from tubing tothe perforation tun-nels, maximizingenergy that goesinto creation offractures.

29Autumn 1996

■■How valve speed makes a difference. The more energy that goes into creatingfractures, the greater potential to extend fracture length. In these five ARCO wells,examples A, B, D and E had enough nitrogen to cause significant erosion, whereasexample C ran out of gas, literally, before the curve plateaued and fracturesreached full extension. (From Petitjean et al, reference 3.)

0

16

20

Frac

ture

rad

ius,

m

Time, sec

0 5 10 15 20 25 30 35 40

12

4

8

A

B

D

E

C

■■Fastest gun this side of the Pecos. The shot detectionsystem, which records accelerometer and acoustic(hydrophone) signals during gun firing, documentsthe rapid gun release of the SXAR system. In this well,a 150-ft gun deviated 76° dropped in 3.07 seconds intoa 66-ft [20-m] rathole.

Guns firedand dropped

Guns hitbridge plug

3.07

sec

(66.

68 ft

)

Accelerometer Hydrophone

The SXAR addresses both shock and fric-tion problems by timing the firing of gunsshortly after disintegration of the last breakplug. At the instant the guns fire, they havealready been released, so the shock wave isexpended overcoming friction rather thantraveling up the completion string. Tests andfield trials show the system works in a rangeof settings. In vertical wells, guns drop at 20ft/sec [6 m/sec] and reach terminal speed afew milliseconds after release.18 The detona-tion shock also effectively moves guns inhighly deviated wells. In one well, the SXARsystem successfully released a 150-ft [46-m]gun that was deviated 76° at the top and86° at bottom (above).

30

The guns themselves provide the final linkin the perforating chain. Charge type cansignificantly influence results. Failure ofsome early EOP jobs was traced to a kind ofscreenout caused by plugging of perfora-tions with debris. Evidence for this was sur-face pressure that did not decline after theguns went off. Investigators discovered thatperforator debris behaves differently underdifferent settings. It can be permeable underthe slowly rising pressures of hydraulic frac-turing, which can pump through somedebris. But to the high-speed extreme over-balance pressure pulse, debris can act as animpermeable barrier. Behrmann and col-leagues demonstrated that in EOP jobs,accumulation of this debris, and subsequentincrease in pressure required to blastthrough it, is minimized by use of deep pen-etrators instead of big-hole charges.

Shot phasing also plays a role. In verticalwells, a minimum of 120° phasing will typi-cally result in two thirds of the perforationslying within 45° of the PFP, the maximumdistance before EOP fractures start formingaway from perforations. Phasing choice isalso affected by procedures following EOP.If EOP is a precursor to hydraulic fracturing,a single biwing fracture is most desirable. Inthis case, 60, 90 or 120° phasing is optimal.However, if matrix acidizing is to follow,then a higher, 45° phasing will help dis-tribute acid around the wellbore.

While most operators use 60 to 120°phasing, ARCO prefers 180°. Based onlarge near-wellbore pressure losses in Prud-hoe Bay wells deviated 30 to 50°, ARCOdetermined that multiple fractures weredeveloping from 60° phase shots. Bychanging shot phasing to 180°, the pressuredrop fell from 2000 psi [13.8 MPa] to under500 psi [3445 kPa], which contributed toplacement of a larger amount of proppant.“We think this suggests a single, biwing frac-ture,” said Joe Schmidt, the ARCO engineerwho helped develop the ROPE program. Ingun systems with phasing other than 60°,maximum benefit is obtained by keeping thesame alignment for all gun segments.

Shot density—the number of shots per ver-tical foot—becomes increasingly importantin longer perforation intervals. Too high adensity can result in excessive leakoff. Toolow a density can result in longer exposureof tubulars to high pressure and increasedrisk of unseating a packer. In general,because extreme overbalance proceduresproduce instantaneous flow at 100 to 200barrels per minute, a rule of thumb is a shotdensity two to four times normal. ARCO,for example, typically shoots EOP jobs at 4shots per foot using 120° phasing over a20-ft interval.

Oilfield Review

40% of wells with production increase of 10 to 20%

80% of wells requiringlow frac pressure when frac job follows

Additional 15 to 20%of frac sand placed

Comparison of Extreme Overbalance Methodologies

Interval, ft

Depth, ft

Bottomhole pressure, psi

Permeability, md

Gradient,2 psi

Fluid/gas

Guns

Other

Increased productionrates and oil cuts in highly saturatedintervals

Completion timereduced 30%

Completion costreduced 11%

35% of TCP jobsfraced later

Negative skin on 88%of wells

No increase in recoverable reserves,just in recovery rate

Fractures likely to stay in zone due to low volume and shortperiod of fluid/gasinflow

EOP as screening for

1.2 to 1.6

<300 ft fluid; N2 at>50,000 scf, with slick water on top and 15% acid

TCP guns; wirelineguns with big-holecharges for new completions; 180° phasing

Surge disk for previ-ously perfed wells

Large-diameter tubu-lars to reduce frictionloss and increase N2volume

High-Energy ROPEmethod, in which N2in a nearby well ispressured and pipedto the well beingtreated

1.8 to 2.1

<1000 ft fluid; N2 at>50,000 scf, with slick water on top

TCP guns, usually 60° phasing, 4 to 6 spf

Proppant carrier overTCP carrier

Surge disk for previ-ously perfed wells

1.4 to 3.0

<1000 ft fluid; N2 at50,000 to 100,000scf, with slick wateron top

TCP guns, 60° or 120° phasing, 4 ormore spf

Resin gel typical forsand control

Clean fluids essential to success

Pump after all jobs,same day or next day

20 to 60

8000 to 15,000

10,000 to 11,000

10 to 300

20 to 120

4000 to 9000

500 to 4000

10 to 150

4 to 1501

4000 to 15,000

500 to 11,000

<100 or 100 to 300 ifpressure insufficientfor underbalance perforating

ARCO Marathon Oryx

Job Design

Results

Reservoir Properties

Elements of EOP Design: OperationsToday’s extreme overbalance operations fol-low one of two basic routes: perforating as astand-alone event followed by pumping, orperforating and surging at the same time(right). In the Oryx method, EOP is followedby high-rate pumping. In wells that arealready perforated, Oryx finds that continuedpumping after overbalance surge can reduceskin, as long as the pumping precedes flowfrom the reservoir.19 The surge method, usinga frangible disk or expendable plug, hasproved to reduce pressure requirements ofsubsequent hydraulic fracturing.

ARCO, working on the Alaskan NorthSlope, reports similar results with its ROPEmethod and, since 1994, a high-energy ver-sion nicknamed HE ROPE. The main differ-ence between the Oryx and ARCO methodsis that ARCO uses nearby wells as holdingtanks for high-pressure nitrogen. Instead ofpumping, ARCO pressures up nitrogen innearby wells, connected by hard line to thetreated well. A plug is set in the tubing tail ofthe storage well, and both the target welland storage well are simultaneously pres-sured. At the appropriate time, the surge diskruptures with firing of the perforating guns,releasing all the gas into the target well.

The HE ROPE method uses nearly 100%nitrogen, with a small amount—10 to 20 bbl[1.6 to 3.2 m3]—of liquid over the guns. Bot-tomhole pressure exceeds 10,000 psi, withan overbalance of about 6500 psi [45 MPa].The high pressure and high volume of nitro-gen lead to injection rates close to 270 bar-rels per minute [40 m3/min]. This rate resultsin greater fracture width, erosion of the for-mation by gas and reduced near-wellborepressure losses.20 The high-energy versiondoubles fracture radius over conventionalROPE, and because fractures tend to propa-gate in a straight line, also allows for better

31Autumn 1996

18. Huber K and Egey J: “SDET-B Confirms SXAR FastRelease and High Speed of Dropping Guns,” ThePerforating and Testing Review 6, no. 3 (October1993): 19.

19. Dees JM and Handren PJ: “Extreme OverbalancePerforating Improves Well Performance,” World Oil215, no. 1 (January 1994): 96-98.

20. Couët et al, reference 3.

1 With significant wellbore storage effect, the interval maximum rises to 500 ft.

2 Achieved gradients sometimes fall slightly below the designed value, mainly because crews may feel more comfortable with lowerpressures. At the 1.4-psi gradient, however, the pressure on tubulars is usually no greater than that encountered during screenoutof a conventional frac job, although EOP pressure may be applied for a longer period.

Higher percentage offrac sand placed other treatments: if

no response to EOP,no further interventionplanned

32 Oilfield Review

■■Hot proppant. A gamma raytracer log in aMarathon wellshows a concentra-tion of tagged proppant in perfo-rations (yellow)More proppantappears to havebeen injected intothe upper two inter-vals than into thebottom interval.Subsequent produc-tion testing con-firmed that therewas no communi-cation behind pipe.(From Snider et al,reference 21.)

Extreme Overbalance Perforating Underbalance Hydraulic Fracturing

Time 1

Time 2

Time 1

Time 2

Maximumhorizontal stress

Minimum

horizontal stress

■■The many becomeone. Extreme over-balance perforatingin a horizontal wellcauses a single frac-ture to develop frommultiple perfora-tions, since theapplied pressureexceeds in-situstress. By time 2 (bottom left), separatefractures from sepa-rate perforationshave merged androtated into theplane of maximumhoriztonal stress.With hydraulic frac-turing in the samestress scenario (right),separate fracturesdevelop.

height control during fracturing of thin inter-vals (above).

Several operators have looked into sus-pending proppant in extreme overbalancefluids, in hopes of blowing it into the perfo-rations and propping the fractures. Mostefforts have failed because of the high shearrate of fluid-proppant mixtures. At pumprates used in treatments, the fluid becomesa “plug” and will not flow. Another prob-lem is suspending the proppant uniformlyin the fluid while it is being pumped downthe tubing.

Nevertheless, progress has been made.Marathon, for example, along with OwenOil Tools has developed a proppant deliv-ery system positioned just above the gunsthat minimizes difficulties of mixing prop-pant with completion fluids (such as uncer-tain suspension time and increased viscos-ity). Marathon has run tests with 200 to 400lbm [90 to 180 kg] of radioactively taggedproppant. Gamma ray scanning logs runafterward indicate no proppant in therathole and high radioactivity at perforationentrances (right).21 “We know it’s going intothe holes,” said Phil Snider of Marathon.“But we still don’t know if we’re runningenough proppant volume, or for enoughtime, to get effective propping.”

Work is just starting on EOP in horizontalwells, which present a new range of chal-lenges related to gravity. An underbalanceperforating experiment at TerraTek showsthat detonation products could not beflushed from down-side perforations in awellbore deviated 29°, even with a 400-psi[2756 kPa] underbalance differential. Basedon this result, some operators are using ori-ented guns and perforating horizontal drainson the top and sides only. Applying extreme

overbalance methods in this setting mayrequire a higher pressure gradient, wellabove 1.4 psi/ft, to pulverize and movedebris that tends to fall to the low side of thehole. Mobil and Halliburton have used EOPsuccessfully in a horizontal well at 15,693 ft[4783 m] true vertical depth to tap a tightgas reservoir. Perforating guns were con-veyed on drillpipe.22

33Autumn 1996

21. Oriold F and Snider PM: “TCP Proppant Carrier Sys-tems for Extreme Overbalance Perforating: Experi-ence to Date,”paper CIM 96-82, presented at the47th Annual Technical Meeting of the PetroleumSociety, Calgary, Alberta, Canada, June 10-12, 1996.Snider PM, Hall FR and Whisonant RJ: “Experienceswith High Energy Stimulations for Enhancing Near-Wellbore Conductivity,” paper SPE 35321, presentedat the International Petroleum Conference and Exhi-bition, Villahermosa, Mexico, March 5-7, 1996.

22. Chambers MR, Mueller MW and Grossmann A:“Well Completion Design and Operations for aDeep Horizontal Well with Multiple Fractures,”paper SPE 30417, presented at SPE Offshore Europe1995, Aberdeen, Scotland, September 5-8, 1995.

23. Snider et al, reference 21.24. A big-hole charge increases hole diameter at the

expense of penetration depth. Hole diameter in cas-ing is two to three times greater than with a deeppenetrator, but penetration is substantially reduced.

Unanswered Questions“Most of the time, we know when extremeoverbalance will work,” said Phil Snider ofMarathon. “But the few jobs that go wrongare the ones driving our research.”

This sentiment informs much of today’sinvestigations into extreme overbalancemethods. But as knowledge increases, so dothe apparent number of unknowns. Mostworkers in EOP have a wish list of whatwould make their lives easier and more pro-ductive. Highlights of this list include thefollowing questions:

What is the pressure-rise time? Knowingthe shape and exact length of the pressure-time curve from the moment of gun dis-charge will allow calculation of the numberof fractures and fracture width. In addition,watching what happens in the first few sec-onds can shed light on friction levels to opti-mize job design. To achieve this, Snider isusing a downhole high-speed pressure gaugethat measures 20,000 data points per sec-ond. Early results indicate that perforationand fluid influx may behave more as a singleevent than as two distinct ones. In addition,results indicate that optimization requireslimiting flow restrictions in tubing andreducing the height of liquid in tubulars.23

How does gun system design affect frac-tures—big hole or deep penetrators? 24

Marathon’s experience indicates that big-hole charges may lay down filter cake thatprevents injection of the surge. Except forgravel packing, deep penetrators are gener-ally the charge of choice.

How conductive are EOP fractures, andhow long do they work? Experience showsthat short, unpropped fracs have a useful lifeof 6 to 12 months. As Marathon hasobserved, proppant may pack EOP perfora-tion tunnels, but may function more as anabrasive than a proppant. And the abrasiveaction decreases near the fracture tip, asflow velocity decreases. In support of thisclaim, large gains in well productivity withthe addition of a small volume of prop-pant—100 to 200 lbm [45 to 90 kg]—sug-gest scouring as the mode of action. Bauxitehas proved to provide better scouring thanconventional frac sand.

Over what distance do EOP fractures turn?Experiments in large blocks of rock indicateturning is complete in two or three wellborediameters, but there is evidence that in situ,turning may take 5 to 10 ft [0.6 to 3 m].

Does EOP mean that subsequent fracjobs require more or less horsepower?Again, experience is ambiguous. Someoperators report always needing less horse-power, while others say sometimes less,sometimes more. Oryx finds that regardlessof horsepower required, EOP jobs alwaysresult in placement of a higher proppantconcentration during subsequent frac jobs.The treatment screens out, for example, at8 lbm/gal [958 kg/m3] instead of 4 lbm/gal[479 kg/m3].

Where Are You Going, EOP?There are parallels between the develop-ment of extreme overbalance perforatingand tubing-conveyed perforating. In the1970s, TCP burst on the scene with RoyVann’s innovative designs for downholeequipment. Hailed by proponents as a per-forating panacea, and by others as an aber-ration that would soon disappear, it was ini-tially adopted by a few operators. Trial anderror smoothed out the rough edges, con-vincing the industry at large of its technicaland economic benefits. Eventually, TCP set-tled in as a niche service, which todayaccounts for more than 25% of the perforat-ing business.

EOP emerged in a slightly different con-text. After 1986, low and stable oil pricesinstigated a flurry of engineering creativity,moving completion designs toward furtherspecialization and producing a change inperspective. The idea of “completion equalsplumbing”—seals, tubulars, valves andpackers—began to give way to the view that“completion equals well optimization.” Bythe beginning of the 1990s, the completionsworld was no longer neatly divided intowireline, slickline, tubing and coiled tubingtechniques. Now the approach is to find thebest mix of solutions to optimize recovery.

Extreme overbalance is one such develop-ment that blurs old boundaries. Usually per-formed on tubing, EOP can be achievedwith wireline; it also marries perforating andpumping, and inches toward stimulating,but stops short at near-wellbore enhance-ment. In the continuum of well treatments,it more closely resembles matrix acidizingthan hydraulic fracturing, although its tech-niques borrow more from the latter.

Whether EOP will join the mainstream inthe style of TCP or remain a small niche ser-vice depends mainly on proof of its eco-nomic viability. This proof requires furthertechnical refinements so that results can beclearly related to technique.

One trend that may prove fruitful is therecent move away from the pressure gradi-ent rule and toward the tubular limitrule—selecting the highest pressure safelyallowed by the tubular rating. ARCO, forexample, keeps pressure to within 80% oftubular burst rating. However, it is stillunclear whether more pressure is alwaysbetter. By contrast, there is a move towardlarger diameter tubing, which typically has alower pressure rating but allows a highervolume of gas. Also under investigation isthe use of proppant carriers, which havebeen tried in only a few dozen wells.

ARCO has been looking to test the ROPEmethod, with its precise control of fractureheight, on coal degasification projects,where water intrusion often limits develop-ment. Another possible use of this method isin remote wells, where highly mobile nitro-gen generation equipment could be readilymoved on site.

“We think of EOP not as a replacement forthe hydraulic frac,” said Joe Schmidt ofARCO, “but as a pretreatment for fast return.If we have trouble with a conventional fracbecause of earth stresses or well deviation,this works.”

Schmidt’s view represents that of manyworkers trying to define the limits of theEOP frontier. True, it is known to work insome settings, and yes, the mechanics maynot be clear, but that is simply a problemthat will wash away with more study.

“We know just about all we can aboutunderbalance perforating,” said Phil Sniderof Marathon Oil Company. “Extreme over-balance still presents the possibility of dis-covering new benefits.” —JMK

Multipurpose Service Vessels: Versatile Toolkits for Well Intervention

The oil industry’s push toward greater efficiency and more integrated services is profoundly impacting

marine support activities. New concepts and designs that offer an expanded range of capabilities from

a single vessel rather than multiple boats and barges are rapidly transforming the face of well workover

and remediation operations. This article describes how innovative approaches are solving logistics and

performance problems that have challenged offshore operators and service providers for decades.

34

Sam AdamsonFrancisco CupelloJohn HicksMalcolm KeenleysideLas Morochas, Venezuela

Dave FormasClaude GabillardMontrouge, France

Francisco GamarraAlexis SanchezLagoven SATia Juana, Venezuela

For help in preparation of this article, thanks to LarryHibbard and Yves Lemoign, Sedco Forex, Montrouge,France.WASP is a mark of Schlumberger. Swiss Army is a markof Victorinox.1. Chafcouloff S, Michel G, Trice M, Clark G, Cosad C

and Forbes K: “Integrated Services,” Oilfield Review 7,no. 2 (Summer 1995): 11-25. Austin CB, Dole S, Chmilowski W, Vernon G, HeidtJH, Lewis R, Thompson J, Vinson M and Watson T:“Alliances in the Oil Field,” Oilfield Review 7, no. 2(Summer 1995): 26-39.

2. Offshore 55, no. 5 (May 1995): 36.3. “Venezuela Awards Exploration Risk Contracts,” Oil &

Gas Journal 94, no. 30 (July 22, 1996): 28-29.

In today’s oil field, delivering cost-effectivesolutions to difficult problems is para-mount. As oil companies continue theirintense drive to lower finding and produc-ing costs and increase efficiency in everyfacet of operations, service companies areworking closely with them as proactivesolution-providers. Success hinges onexploiting the new business relationshipsthat have sprouted and thrived during thepast few years, typified by a proliferation ofalliances and integrated services contracts.At the core of these initiatives are align-ment of fundamental goals and an unparal-leled application of cutting-edge technol-ogy targeted at productivity enhancement.1

Cooperative operator-service companyprograms are closely examining the cost-effectiveness of oilfield equipment usedthroughout the field development cycle.Radically different approaches are beingadopted to reduce logistical complexity andnonproductive time, deficiencies associatedwith many long-standing practices. This isparticularly true for well construction, inter-vention and remediation where a combina-tion of innovative thinking and technical

advances is ushering in a new era of perfor-mance from offshore barges and lift boats.

Former single-purpose or limited-use ves-sels are being retrofitted to enhance effi-ciency and upgraded to add capabilities.Purpose-built vessels, which can swiftlydeliver a wide spectrum of services, withfewer constraints and with a smaller cadreof highly skilled personnel, are beingdesigned and commissioned in key oil-producing regions worldwide.

To put it simply, today you can have aSwiss Army knife at your disposal insteadof a common penknife.

Progress in the LakeLake Maracaibo, Venezuela remains one ofthe most prolific oil-producing areas of theworld—contributing over 1.5 millionBOPD [240,000 m3/d] to help satisfy theever-increasing global demand for energy.This represents more than 50% of the 2.9million BOPD [460,800 m3/d] producedby Venezuela. Lake Maracaibo is alsohome to a unique field developmentscheme of over 11,000 wells and a uniqueset of well maintenance problems.

State-owned Petroleos de Venezuela SA(PdVSA) has committed to more than dou-

Oilfield Review

Maracaibo

Tia Juana

Lagunillas

La Ceiba

Venezuela

29%Heavy

3%Condensate

14%Light

54%Medium

Lake Maracaibo

Crude production

■■Lagoven operations in Lake Maracaibo.Lagoven produces from over 4900 activewells, mainly in the Campo-Costanero-Bolivar region of the Lake (light blue).Eighty-three percent of the wells producemedium to heavy crude. Nearly 4000 outof a total inventory of over 8000 wells cur-rently require some type of workover.

ble oil production capacity by the year2005 with an impressive assembly ofdrilling and workover programs. Three-dimensional seismic mapping of the entireLake, completed in 1994, paved the wayfor a new, intensive exploration campaignthat has already led to several importantlight-oil discoveries.2

PdVSA’s programs are being comple-mented by aggressive efforts from interna-tional oil companies, including Mobil,Enron, British Petroleum, Shell, Amoco,Maxus, Conoco and Elf Aquitaine, as theydevelop acreage acquired in recent offer-ings. Earlier this year, Venezuela leasedacreage in the first bidding round since itreopened to foreign investment in 1993.Profit-sharing contracts covering explo-ration on eight tracts with a combined areaof 18,000 km2 [6950 square miles] wereawarded. Undiscovered oil reserves in the

Autumn 1996

newly assigned areas are projected at 7 to23 billion bbl [1 to 3.6 billion m3].3

Lagoven, the company that along with sis-ter affiliates Maraven and Corpoven consti-tute PdVSA, has seized the initiative with avengeance. In 1994, for example, 77 mil-lion bbl [12 million m3] of light crude wereadded to reserves with three major discover-ies in the Lake that helped boost Lagoven’sproduction. Currently, Lagoven maintainsover 8000 wells and produces about730,000 BOPD [116,000 m3/d] from 4940active wells mainly in the eastern sector ofthe Lake (right). Water depths in the sectoraverage about 60 ft [18 m] and well depthsaverage around 4000 ft [1220 m].

Of the total number of wells, nearly 1000are presently shut-in, and as many as 4000require some type of workover operation.As the fields in this area of the Lake havematured, the need for more frequent and

35

Current

Conventional drilling and workover barges; support barges (cementing, coiled tubing, gravel packing, logging)

Major scheduling andlogistics problems

Excessive weather-related delays

Organization andcommunications deficiencies

Insufficient, poor-quality data

Streamlined schedulingand logistics

Stable platform,enhanced mooring capabilities

Efficient, multiskilledorganization

Rapid, high-quality data generation

Integrated multipurpose units

Future

■■Evolution in well workover practices. The logistical and coordination problems and excessive downtime currently experienced usingsingle-service barges can be solved by integrated, multipurpose vessels capable of more rapid, efficient, less costly operations.

complex workover and remediation proce-dures has grown accordingly.

Although wells in Lake Maracaibo aretechnically “offshore,” many operations arereminiscent of land development. Flat-bot-tom barges with cantilevered derrick setsare used for drilling. Historically, Lagovenbuilt drilling barges up to 220 ft [67 m] inlength and then adapted them for a rangeof workover functions. An array of separatebarges, outfitted to provide one or two spe-cialty services each, such as cementingand coiled tubing, supports the drilling andworkover barges. Currently, Lagoven owns11 out of 28 barges and three jackups ser-vicing its sector of the Lake.

When well construction or interventiontasks call for multiple barges in a pre-arranged sequence, the logistics of bargescheduling and positioning are compli-cated and inefficient. Time spent waitingfor the next barge to arrive is often exces-sive. Lake Maracaibo is prone to rapidweather fluctuations, further impedingoperations since most barges have minimal

36

tolerance to waves. Delays waiting forweather to improve increase nonproduc-tive time. The scene evokes visions of aqueue of rain-delayed jets awaiting takeoffat a major airport. These constraints, andhaving a limited fleet of service vessels,restrict rig-based workovers to about 400per year, far fewer than needed.

Lagoven’s efforts to sustain productionfrom depleting zones and increase overallhydrocarbon recovery rely heavily on wellreentries and workovers. Lagoven viewsthis as the most economical way toenhance hydrocarbon production and stopits primary nemesis—water production.

This, in turn, has prompted a rethinkingabout how workovers should be per-formed. An evaluation of existing deficien-cies and benefits from an integrated ser-vices approach convinced Lagoven topropose multipurpose barges for deliveringa suite of services from a single vessel.Smaller, more flexible and cost-effective,these vessels solve scheduling problemsand eliminate the excessive downtimeplaguing current operations (above).

The changeover will, of necessity, be evo-lutionary. The progression from dedicated,single-use barges to custom-designed, mul-tipurpose vessels is currently passingthrough an interim stage—barge retrofitting.

More Than a Cosmetic MakeoverFor several years, service companies havesporadically reconfigured—or retrofitted—drilling and specialty service barges toincrease functionality by adding dedicatedequipment. These attempts represented thefirst valid steps toward more efficient wellworkover services. Today, efforts are moredirected and less experimental.

A notable effort by Dowell, based onwork in the late 1980s when barges werefirst outfitted with coiled tubing units, hashelped bolster confidence in coiled tubingdrilling on the Lake. A 140-ft [43-m] bargewas specially configured to support eitherconventional or coiled tubing drilling. Todate, nearly 50 wells have been drilledfrom the barge with coiled tubing. Initially,

Oilfield Review

Coiled tubingreel

Deck level

Drill floor

Coiledtubing

power pack

WASP sandmixer

Engineand

pump

Engineand

pumpTanks

■■The Lagoven406. This can-tilevered drillingbarge has beenretrofitted to pro-vide integratedservices byadding coiledtubing and fluidmixing, blendingand pumpingcapabilities.

■■ReconfiguredLagoven 406deck layout withnew equipment.The addition ofcoiled tubingand WASP sandmixer moduleson the deck levelprovides addi-tional flexibilityfor well workoverand remediationprograms.

hole sizes were 37⁄8-in. diameter. Now, wellsare being drilled through shallow gas areaswith diameters as great as 123⁄4 in. Well cas-ing, up to 103⁄4 in. in diameter, is run andcemented with the same unit. The success ofthis approach paved the way for the evenmore ambitious efforts that followed.

Recently, two barges in the Lagovenfleet—Lagoven 405 and Lagoven 406—were retrofitted. Lagoven 406 (LV-406), acantilevered drilling barge with on-boardderrick set and wireline logging unit, wasthe first vessel with hoisting and rotatingcapabilities to be retrofitted (above). Work-ing alongside Lagoven, Schlumberger Oil-field Services, with Sedco Forex as projectmanager, reconfigured the barge in orderto provide integrated services.

The barge was delivered for retrofitting inmid-February 1996 and equipped with a1.5-in. diameter coiled tubing unit (controlcabin, power pack, reel and injector head),WASP water and sand proportioning mixerfor blending gravel pack slurries, fluid fil-tering system, silo, displacement tanks andrecirculating pump—replacing the barepipe racks on the deck of LV-406 (right).

Autumn 1996 37

38 Oilfield Review

■■Deck and mez-zanine levelsshowing individ-ual equipmentmodules. Optimalmodule place-ment was deter-mined by a teamof experiencedDowell engineers.The placement ofeach unit wasbased on control,interface and pip-ing criteria.

■■Looking acrossthe deck towardthe cantileveredderrick. One goalof the retrofitteddesign was afunctional, safeand uncluttereddeck. Equipmentmodules arearranged foreasy change-outand efficientdelivery of thewidest possiblerange of services.

Upgraded piping and new systems forair, water, fuel and electricity were added.During the construction phase, a premiumwas placed on efficient use of deck space.Since the reconfiguration primarilyinvolved coiled tubing and pumpingequipment, a team of experienced Dowellengineers was appointed to define an opti-mal deck arrangement (left).

Although over 100,000 lbm [45,360 kg]were added to the vessel, the excellent load-bearing capacity of LV-406 ensured that vari-able deck load limits were not exceeded. Acomprehensive stability analysis conductedby a naval architect confirmed that vesselstability would not be compromised.

The reconfigured barge was placed inoperation in mid-April 1996 (below left). Inits first few months of operation, the retrofit-ted LV-406 has mainly performed horizontalwell cleanouts and cement plug place-ments with coiled tubing, as well as wire-line operations, including perforating andsetting bridge plugs or permanent packers.

Previously, cleanouts of produced sandrequired use of larger diameter drillpipe orcontracting for a separate coiled tubingbarge to work in tandem with LV-406. Theformer was expensive and time-consuming;the latter meant dealing with ever-presentscheduling and positioning problems. Withtwo barges, the well would often sand upagain after cleanout, before the rig could berepositioned to install a prepacked sand-control screen.

With the retrofitted LV-406, however,cleanout of a 3000-ft [914-m] horizontalsection typically requires only 17 hourscompared to 36 hours with multiple bargeoperations, a savings of 53%. Worked-overwells now produce sand-free.

According to Francisco Gamarra, Drillingand Workover Manager for Lagoven’s TiaJuana District and Alexis Sanchez,Workover Engineer in charge of LV-406,$220,000 and 15 days were saved workingover the first 10 wells.

“With everything now on the same barge,multiple barge moves have been eliminatedand logistics have improved significantly,”says Gamarra. “We have taken a major stepforward in the quality and efficiency of ouroperations. Cross-training between coiledtubing and conventional workover experts

Autumn 1996 39

Main deck

Helideck

1

2

3

4

5

6

Coiled tubing reel

Injector head

Jib, 8.5 metric ton capability

Injector head (working position)

Riser

BOP stack

1

2

3

4

5

6

1

2

3

4

5

Crane, 100-ft boom length

Folding mast

Drill floor

Stern thrusters

Bow thruster

Helideck

Main deck

Bottom deck

1

2

3

4 5

■■Barge configuration. Starting with a clean slate, Schlumberger engineers designed acustomized vessel—PRISA—to fulfill the well workover and intervention needs ofLagoven. The efficient, compact design affords modular flexibility and adheres tostringent quality, health, safety and environmental guidelines. The barge version ofPRISA is shown with a modified cantilevered derrick, supplemented by a coiled tubingunit for reentry and underbalanced drilling.

■■Lift-boat configuration. This self-propelled version of PRISA is equipped with bow andstern thrusters to permit easy mobilization and precise positioning.

has reduced rig-up time. Based on this suc-cess, we plan to convert our remainingbarges over the next three years.”

Designing the Ultimate ToolkitRetrofitting has its place as a logical,intermediate measure. The long-term goal,however, is a fleet of versatile, purpose-built vessels. “We don’t have a singlemindset on how to accomplish this. Weare willing to listen to the innovative ideasservice companies are proposing,”Gamarra indicates.

Designing vessels for the stringentworkover and intervention activitiesexpected in the future requires anexhaustive analysis of the parametersaffecting practices on the Lake. Whatbasic vessel structure should be used?How can deck equipment best be inte-grated to maximize functionality and effi-ciency? Reconfiguration of LV-406 pro-vided invaluable experience in thedefinition and selection process—high-lighting what worked and what didn’t.The assessment required three iterations,with each revision giving a tighter, morecost-effective design.

The result is a new vessel concept calledPRISA—a Spanish term which translates ”todo things quickly”—symbolizing the objec-tive established at the outset. PRISA is envi-sioned as the solution to Lagoven’sworkover and intervention needs for thefuture—a multipurpose unit that reduceslogistical complexity, improves operationalflexibility and efficiency, and decreasestime spent waiting on weather.

Two design variations are possible. Thefirst is a barge style, 180 ft [55 m] in lengthwith a 4000-ft2 [370-m2] deck, capable ofoperating in water depths to 150 ft [46 m],wave heights to 6 ft [1.8 m] and surfacecurrents to 2 knots (above right).

The second is a self-propelled, lift-boatstyle, 180 ft long with a 6000-ft2 [558-m2]deck, able to operate in water depths to100 ft [30 m] (right). This configuration isbottom-supported for better stability over awider range of environmental conditions.

40 Oilfield Review

Maximumhorizontal extension,

2000 ft

Cementplug 6 1/4-in. sidetrack with drillpipe

or coiled tubing

Targetreservoir

Maximumwell depth,

8000 ft

Maximumexisting wellbore,

7-in. casing

■■Well reentry and drilling of laterals with drillpipe or coiled tubing. The ambitious workover and production enhancement pro-grams of Lagoven emphasize reentry of existing wells to drill deviated or horizontal sections to reach previously untapped areas ofthe reservoir.

Services in both configurations include:• conventional well repair and workover,

including workover fluid services• conventional reentry drilling and snub-

bing (barge configuration only)• coiled tubing drilling, including under-

balanced air or foam drilling withquick changeover to conventionaldrilling and pulling mode in the bargeconfiguration

• measurements- and logging-while-drilling

• wireline logging and perforating• pumping mud, cement, acid, gravel

packs and completion fluids• slick-line operations.But the design goes further, providing

capabilities for reentry and productionimprovement drilling of short-radius hori-zontal sections and multilaterals (see “Reen-try Drilling Gives New Life to Aging Fields,”page 4) from existing wellbores with casingsizes up to 7 in. [18 cm] (above). These tech-

niques will proliferate rapidly as crucial ele-ments in the long-term production improve-ment strategy for Lake Maracaibo. Late in1996, Lagoven plans to drill two wells usingmultilateral technology. For 1997, this num-ber jumps to 25.

PRISA includes an integral, cantileveredderrick and major support facilities—moor-ing system, crane, living quarters, powergeneration, and fluid pumping and storageequipment. The deck space is readilyaccessible by the main crane, allowing effi-cient placement of service modules.Hydraulic and power units support multi-ple applications.

Automation and process control maxi-mize productivity during running, trippingand pulling of completion equipment. Acentral control cabin monitors functions inthe derrick and on the drill floor, as well aselectric and slick-line operations.

In stark contrast to existing vessels, PRISAsimplifies logistics and enhances onboardoperator-service company coordination,allowing rapid, sequenced operations. Thestable platform and an advanced position-

ing system decrease waiting-on-weathertime. Better equipment layout, modularconstruction and tighter organization ofdeck personnel reduce nonproductive time.Quality, health, safety and environmentalperformance improves, combined withlower operating and maintenance costs—overall, an impressive list of benefits.Lagoven currently envisions construction ofup to six such vessels to support its produc-tion enhancement initiative.

Indonesia and West Africa: Reflecting Similar NeedsThe well workover and intervention marketin Indonesia is sizable. As primary fieldsmature, they require increased attention.Estimates indicate that this market willgrow in the near term, with yearlyworkover targets of 500 wells or more.

Today, there simply aren’t enough servicevessels. Oil companies plan workoversusing the available, diverse assortment of

(continued on page 43)

1. O’Callaghan MJ: “Jackup Workover Platform BeginsNew Era in Europe,” Offshore 55, no. 12 (December1995): 42-43.

A New Generation of Capabilities

300 ft

Sternthruster

Crane with120-ft boom

14 ft

7 ft

Flare boom

Sterncontrols

Radio room/wheel house

Navigation mast

Anchorrack

Bowthruster

HelideckJack house

■■Multipurpose Service Vessel. Outboard profile of the MPSV showing the primary control, lifting and propul-sion systems.

Autumn 1996 41

Performance and reliability in compact packag-

ing have epitomized the last decade of computer

and electronics breakthroughs. In similar fash-

ion, technical innovations are streamlining oil-

field equipment, decreasing failure rates and

delivering increasingly accurate data more

rapidly. Whether it’s onboard processing for

seismic surveys, revolutionary downhole wire-

line logging tools, or integrated fluid mixing and

blending systems, an insistence on speed, quali-

ty and versatility is permeating the industry.

Offshore well construction, maintenance and

intervention services that require vessel support

are being closely scrutinized. These tasks can be

performed more efficiently and cost-effectively

with multipurpose service vessels—MPSVs—

than with an assembly of traditional, single-ser-

vice units. With the number of deviated, horizon-

tal and multilateral wells mushrooming, and

revisited reservoirs requiring more complex well

completion schemes, custom-designed vessels

are increasingly viewed as the preferred equip-

ment of choice.

Multipurpose service vessels provide the ser-

vice company with an arsenal of capabilities and

integrated platforms for delivering a veritable

smorgasbord of services. At the same time, they

offer oil companies more options for improving

hydrocarbon recovery and extending the life

expectancies of offshore wells. The MPSV is a

win-win solution for both parties.

In late 1995, a self-propelled MPSV, Irish SeaPioneer, was commissioned by Halliburton Energy

Services for well workover and intervention activ-

ities in the BHP Petroleum Liverpool Bay field off

the west coast of England. It is the largest such

vessel built to date and underscores the benefits

that operators and service companies alike per-

ceive in the MPSV concept.1

The MPSV initiative within Schlumberger is a

natural outgrowth of the drive toward integrating

services and supplying value-added solutions in

direct response to client needs. Defining specifi-

cations for and designing the first-generation

MPSVs required the combined strengths and

expertise of the Schlumberger Oilfield Services

companies—led by Sedco Forex for vessel man-

agement and drilling expertise, Anadrill for direc-

tional drilling and measurements-while-drilling

services, Wireline & Testing for logging and well

testing services, and Dowell for pumping, fluids

engineering and coiled tubing services.

The resulting design adheres to the fundamen-

tal quality, health, safety and environmental

tenets being applied uniformly by Schlumberger

worldwide and conforms to standards estab-

lished by regulating organizations, including the

American Bureau of Shipping and International

Maritime Organization, and initiatives such as

Safety Of Life At Sea.

The chosen blueprint is a jackup-style vessel—

properly termed a lift boat—with four, 300-ft

[91-m] legs (above). The vessel is self-propelled

at speeds up to 6 knots, compared to jackups that

are towed at a sluggish 1 to 2 knots by tugboats.

It is smaller than a normal jackup, requires less

steel and is sleeker than the flat-bottom barges

typically used in areas like Lake Maracaibo.

The MPSV is equipped with four legs. This

configuration saves time during vessel moves,

improves safety, reduces maintenance costs and

provides greater space for equipment on and

below the main deck.

The MPSV has a streamlined bow and stern to

minimize hull resistance, and utilizes state-of-the-

art azimuthal thrusters for precise station keeping

and maneuverability. It can be used safely in

water depths as shallow as 10 ft [3 m] or as deep

as 170 ft [52 m] and is stable in 60-knot winds

and 29-ft [9-m] waves. Fully-retractable spud cans

are integrated into the hull design, minimizing

drag during transit. Top and bottom jetting capa-

bilities aid removal when leaving location.

The MPSV is self-elevating with leg-jacking

speeds of 6 to 8 ft/min [1.8 to 2.4 m/min], five

times faster than a conventional jackup. A

power-generation system that isolates propulsion

functions from jacking functions ensures that the

1 Twin pump skid

2 Nitrogen storage tank

3 Nitrogen pump

1 Burner head

2 Crude oil reinjection pump

1 Container

2 Surge tank or knock-out drum

3 Crude oil export pump

4 Control skid

5 Gauge tank

6 Air compressor

7 Oil manifold

8 Production separator

9 Lab cabin

10 Logging cabin

1

1 2 2

3 3

45

78

8

8910

6

1

2

2

3

1

1

2

2

3

3

4

5

6

78

9

4

5

1 Twin pumpskid

2 Blender

3 Power pack

4 Reel

5 Injector head

1 Logging cabin

2 Container

3 Surge tank or knock-out drum

4 Gauge tank

5 Air compressor

6 Crude oil reinjection pump

7 Oil manifold

8 Production separator

9 Choke manifold

■■Equipment configuration for extended well testing. The large, accessible deckprovides ample room for the variety of equipment modules needed to support anextended well test.

■■Equipment configuration for horizontal production logging. The addition of acoiled tubing unit and auxiliary equipment supports logging of horizontal wells, akey duty expected for MPSVs as the emphasis on horizontal and multilateral wellsexpands worldwide.

42 Oilfield Review

vessel can maintain accurate position, even in high currents, during jack-

ing operations and when adjacent to wellheads.

The 6000-ft2 deck is open, usable and supports a 1.5 million-lbm

[0.7 million-kg] deck load with the legs elevated and a 1.0 million-lbm

[0.5 million-kg] load at other times. Twin 100-ton cranes with 120-ft

[37-m] booms are capable of moving equipment modules onto and around

the vessel, and are qualified for major lifts directly to and from attended

platforms or wellheads. The cranes revolve a full 360° without interference

from the legs, increasing flexibility and reducing deck space requirements.

To permit extended, 24-hour operation, accommodations and water

production facilities are provided for up to 60 people, as operations

dictate. Additional personnel can be housed in temporary modules on

the main deck, if necessary. Quarters are located for ready access to the

helideck and lifeboats or life rafts.

MPSV services cover the spectrum from routine, daily repair and mainte-

nance on wells and platforms to short or extended well tests, horizontal

production logging and acid stimulation with coiled tubing, and drilling mud

treatment. The MPSV can be equipped as an early production system during

the initial stages of field development, allowing operators to fully evaluate

reservoir potential while generating immediate cash flow.

A single process-control system, ergonomically designed primary con-

trol cabin and modular, integrated equipment layout simplify operations,

improve safety and permit staffing by a smaller cadre of multiskilled

personnel than with a random assortment of single-purpose vessels.

Modularity allows rapid, easy customization. In the extended-well-test-

ing mode, the vessel is outfitted with production separators, surge tanks

or knock-out drums, export and reinjection pumps, a special logging

cabin, a twin, high-pressure pumping skid, flare boom and burner (top). For horizontal production logging, a coiled tubing unit—including

power pack, reel and injector head—blender, a twin, high-pressure

pumping skid, production pump, and surge tank or knock-out drum are

used (bottom). For acid stimulation, a pressure-swing absorption nitrogen

unit and acid storage tank are added. Other coiled tubing applications—

nitrogen lift, logging and cementing—can be accommodated easily.

Electric or hydraulic high-volume, high-pressure pumps can be added to

extend the operating range of coiled tubing and snubbing units.

For well repair activities, a cantilever, mast and hoisting facilities, mud

pumps, fluid storage tanks and mud treatment skids are provided. The

cantilever offers versatility by permitting direct positioning over the well-

head. The MPSV can also serve as a diving-support vessel or as a tempo-

rary logistics and supply vessel for platforms or other offshore facilities.

Currently, MPSVs based on this design are being evaluated for

diverse areas, such as the Gulf of Mexico, west coast of Africa,

Malaysia and Indonesia.

boats and barges, and must live with thetechnical and operational restrictions inher-ent in their designs. High-efficiency, flexibleunits—at least four just to satisfy the demandsof major international players—are desper-ately needed both to increase workover fre-quency and to optimize scheduling.

The majority of today’s fleet are floaters,mainly flat-top barges. Historically, thesewere the cheapest to build and operatewhile offering modest flexibility. But theyhave severe limitations, require substantialmarine support—up to three auxiliary boatsfor moving and positioning—and largecrews, 50% greater staffing than for effi-cient vessels. They are also highly sensitiveto weather, often unusable if swells exceeda few feet. Nonproductive time rigging up,rigging down and waiting on weather runsas high as 40 to 50%. These barges caninterface only with platforms equipped witha derrick set or designed to accommodate arig or coiled tubing unit. This lack of con-formance restricts certain operations andpromotes substandard quality and safety.

With a purpose-built intervention unit,capabilities to run completions, perforateand clean up wells—common practices inmany parts of world, but currently difficultto impossible in Indonesia—can be added.Today, importing specialized units for thesepurposes is an option, but usually prohibi-tive due to mobilization costs and incom-patibilities with platform designs.

A Schlumberger study outlines the idealsolution: a versatile, self-propelled, multi-purpose service vessel—or MPSV—to min-imize transport time and the amount ofmarine support needed (see “A New Gen-eration of Capabilities,” page 41). Modularconstruction allows fit-for-purpose equip-ment sets to be placed and changed outrapidly and efficiently on deck, reducingrig-up and rig-down time. The vessel has aworking deck at the same level as those onproduction platforms to minimize lost timeand eliminate the need to transfer equip-ment from barge to platform. The vessel’sdeck accommodates most service equip-ment for greater efficiency, safety andimproved communications. Staffing is

Autumn 1996

reduced through multitasking and cross-training in several services.

The vessel is capable of running andpulling completions and can incorporate aderrick with rotating capabilities to drill outcement, mill windows and washoverdownhole equipment. Onboard livingquarters and support facilities allow 24-hour operation.

A generalized strategy, based on MPSVs,is emerging to satisfy the burgeoning needsof the Indonesian workover market. Even-tually, when service vessel capabilitiesexpand sufficiently, there will be an addi-tional benefit—the size, complexity andcost of production platforms will decreasesubstantially since fewer, lighter facilitieswill be needed.

Similar well servicing challenges andopportunities exist off the west coast ofAfrica. Here, MPSVs will have to meet therigorous demands of a wide range ofclients and incorporate servicing modulesfor well testing, early production facilities,wireline logging and coiled tubing.

This means more deck space, variableload capacity, hefty cranes, permanentonboard equipment and a large workshopto carry out maintenance and repair workon platforms and wellheads. Many suchoperations are currently performed by con-ventional drilling jackups at high day rates.

Like operations in Indonesia, a nearlyidentical MPSV concept provides theanswer. Since it is designed to be moved fre-quently, mobilization is rapid and easy.Transit times and costs are reduced, andtowing vessels are not required. To be finan-cially attractive to operators, costs must belower than for conventional drilling jackups.The MPSV is expected to bring greater func-tionality at considerably lower day rates.

Managing a Successful ChangeoverThe drive to eliminate core inefficiencies inequipment and operations is spreadingglobally as a result of open communica-tions and teamwork between operators andservice companies. The results are innova-tive concepts to solve industry problemsthat have lingered for decades.

Advances in offshore support vesseldesign and functionality are opening upnew avenues for greater productivity andefficiency. The evolution from single-pur-pose to retrofitted designs and from inte-grated service vessels to custom-designed,multipurpose vessels has been a phased,but relatively rapid, one. While each oil-producing area has specialized needs thatmust be fully addressed during design,operators and service companies are real-izing that a common strategy, MPSVs, canbe the ultimate answer—a versatile toolkitfor well intervention.

Implementation, however, is the realchallenge. It will require investing capital innew equipment, instilling an across-the-board commitment to quality and efficiencyin offshore servicing, and training a largenumber of multiskilled teams to staff thesevessels. The potential rewards in terms ofproductivity enhancement and improvedfield economics, however, are enormous.

—DEO

43

44

Darwin EllisRidgefield, Connecticut, USA

Bob EngelmanJohn FruchterBill ShippBattelle Pacific Northwest National LaboratoryRichland, Washington, USA

Robert JensenRick LewisEnglewood, Colorado, USA

Hugh ScottSugar Land, Texas, USA

Steve TrentBechtel Hanford Inc.Richland, Washington

Environmental Applications ofOilfield Technology

For help in preparation of this article, thanks to AndrewBowden and Robert Chaplow, United Kingdom NirexLimited, Harwell, Oxford, England; Kevin Dodds,Schlumberger Wireline & Testing, Aberdeen, Scotland;Philippe Guerendel, Rachel Kornberg, Richard Parker,Simon Robson and Pieter van der Groen, GeoQuest,Gatwick, England; Michael Kane, Schlumberger-DollResearch, Ridgefield, Connecticut, USA; Greg Kubala,Schlumberger Limited, Sugar Land, Texas, USA; and TimScheibe and Steve Yabusaki, Battelle Pacific NorthwestNational Laboratory, Richland, Washington, USA.FMI (Fullbore Formation MicroImager), FormationMicroScanner, Litho-Density and UBI (Ultrasonic Bore-hole Imager) are marks of Schlumberger.

Investigation of subsurface sites before and after disposal of

hazardous waste is a new and growing field for oilfield technology.

Whether the problem is identifying and monitoring contaminated

layers in the subsurface or characterizing a potential waste

repository, techniques designed for hydrocarbon exploration and

production are finding applications in a new environment.

Keeping the Earth’s ecosystem a safe andhealthy place to live and work is a chal-lenge today and will remain so into the 21stcentury. For thousands of years, humanityhas sought protection from natural hazardsand defense against predators and foes.Ironically, some activities designed to pro-vide such protection—the energy, defenseand medical industries—also threaten uswith another danger: hazardous andradioactive waste. To safeguard againstunnecessary exposure to these wastes, gov-ernments now regulate the treatment, dis-posal and storage of industrial leftovers. Awhole new industry, for management ofenvironmental protection, has sprung up todefy this new danger with technologies tai-lored to the specific substances and hydro-geological settings in question.

The goals of environmental managementare many: to minimize generation of andexposure to hazardous waste; to dispose ofwaste in a manner that meets governmentregulations and community standards; andto assess, monitor and remediate damagecaused by disposal gone awry. Several disci-plines, including agriculture, soil andgroundwater engineering, and hydrocarbonexploration and production (E&P), are con-tributing measurement methods, modeling,and treatment and containment technolo-gies to achieve these goals. This articleexamines how oilfield technologies arehelping to identify and characterize zoneswhere waste or other substances have accu-mulated after leakage or disposal and toassess potential subsurface repositories for

hazardous and radioactive waste. (For defi-nitions of types of waste see “HazardousWaste and Radiation Basics,” page 48.)

Successful application of oilfield technol-ogy for disposal site characterization andmonitoring is based on understanding thedifferences and similarities between the E&Pindustry and the environmental manage-ment industry. The most significant differ-ence is in the economic incentives in thetwo fields. In the oil industry, the drivingforce behind use of technology is increasedoil recovery, leading to increased profits. Incontrast, in environmental management thedriver is cost-effective protection of peopleand the environment in compliance withgovernment regulations. In the latter case,simple, inexpensive technologies are usuallychosen over sophisticated, expensive ones.Soil and groundwater samples are more rou-tine data sources than borehole logs; insome environmental management firms“logging” is a term generally associated withforestry, not with boreholes.

In spite of the emphasis on low-cost solu-tions, the environmental managementindustry worldwide has annual revenuesestimated at $250 billion. Demonstratingthe value of E&P technologies is a first stepto ensuring that site evaluation and restora-tion efforts harness the most effective tech-nologies available.

The main similarity between the oilfieldand environmental management industriesis the need to describe subsurface fluidbehavior through cost-effective technologies(next page ). This implies accurate

Oilfield Review

45

■■Characterization of soil, rock and fluids for managingenvironmental protection. As in the oil field, descriptionof subsurface layers and prediction of fluid movementrequire cost-effective technologies.

■■Hanford Site onthe banks of theColumbia River inthe state of Wash-ington, USA, chosenin the 1940s for itsremote location andample supply ofcooling water.N Reactor

Hanford SiteBoundary

N

0

0

10

10

km

miles

Richland

Columbia River

Yakima River

Seattle Spokane

W A S H I N G T O N

Richland

C A N A D AU N I T E D S T A T E S

measurement of fluid constituents and pre-diction of their movement with time. Othersimilarities—such as the actions taken tomobilize, extract or contain fluids—dependon the disposition of fluids and the desiredresults. In the oil field, the goal is to extractthe maximum percentage of hydrocarbonswhile keeping injected or connate wateraway from producing wells. In the arena ofwaste disposal, characterization is requiredfor design of repositories, so that hazardousmaterials are kept out of aquifers and reser-voirs that may communicate with the sur-face ecosystem. Whenever water suppliesare threatened to unacceptable levels,action is necessary to extract, treat or iso-late the contaminants.

In both industries, characterization of thesubsurface is essential. The following casestudies show how technologies designed forunderstanding hydrocarbon reservoirs arebeing advanced to address this need.

Hanford Site, Washington State, USAAn example of successful application of E&Ptechnology for environmental managementis the delineation and monitoring of radioac-tive and hazardous wastes in the sedimen-tary layers below the Hanford Site in Wash-ington, managed by the US Department ofEnergy (DOE) in the northwestern USA.

Built on the banks of the Columbia River inthe 1940s, Hanford is the site of the world’sfirst full-scale nuclear reactor and spent-fuelreprocessing plant, designed to produce plu-tonium (239Pu) for atomic weapons (aboveright ). The location was chosen for itsremoteness, ease of defense, mild climate,ample supply of electricity and availability ofwater for cooling the reaction process.

■■Tanks for storing waste from nuclear reactorat Hanford, 28 are double-shelled and 149 areThe carbon-steel tanks (left) are encased in ce(right). Sixty-seven of the single-shelled tanks h

46

Plutonium was produced at Hanford from1944 to 1987. At one time up to nine reac-tors and five reprocessing plants were activeat the site. All are still present, though inac-tive and scheduled for decontamination anddecommissioning. High-level radioactivewaste from the plutonium extraction chemi-

s. Of the 177 tanks single-shelled.ment and buriedave leaked.

Liquid

Processedair intakeLeak

detection pit

cal separation process, or reprocessing, wasplaced in single- and double-shelled car-bon-steel tanks (below). The tanks wereencased in cement and buried in “tankfarms” located on the Hanford site centralplateau, approximately 10 miles [16 km]west of the Columbia River and about 200 ft

PrimarytankSecondarytankReinforcedconcrete

Filteredair exhaust Liquid level gauge

Annular spacefor leak detection

Carbonsteel

Sludge

Oilfield Review

■■Unsaturated matrix. Air in the porespace requires new models for derivingporosity from density measurements.

■■Comparisons between laboratory (dots) and HNGS-logged values (solid curve) for cobalt, 60Co, (left) and cesium, 137Cs (right). Atradioactivity concentrations less than about 2 pCi/g, laboratory measurements are not sensitive enough to give quantitative read-ings, while the HNGS maintains sensitivity.

0.1 10,000

HNGS Cobalt-60-in. pCi/g

0.1 10,000

HNGS Cesium-137-in. pCi/gD

epth

, ft

10

20

30

40

50

60

Cobalt-60 Activity from 222-S Laboratory Cs-137 Activity from 222-S Laboratory

<

<<

<

<<

<<

<

<<

1. Ellis DV, Perchonok RA, Scott HD and Stoller C:“Adapting Wireline Logging Tools for EnvironmentalLogging Applications,” Transactions of the SPWLA36th Annual Logging Symposium, June 26-29, 1995,Paris, France, paper C.

2. For background on the HNGS: Flanagan WD, Bram-blett RL, Galford JE, Hertzog RC, Plasek RE and Ole-sen JR: “A New Generation Nuclear Logging System,”Transactions of the SPWLA 32nd Annual LoggingSymposium, Midland, Texas, USA, June 16-19, 1991,

[60 m] above the water table. Tank wasteincludes about 250,000 metric tons ofmostly sodium nitrite and nitrate plus 215million Curies of mostly cesium (137Cs) andstrontium (90Sr) and smaller quantities ofvarious metal hydroxides. With time, how-ever, 67 of the 149 single-shelled tanks(none of the 28 double-shelled tanks) haveleaked or are suspected to have leaked. It isnow the responsibility of the US DOE toclean up the site, and the DOE has awardedthe environmental restoration contract toBechtel Hanford Inc. This contract includescleanup of groundwater and soil anddecommissioning of surplus facilities.

If the exact locations of leaked contami-nants are not known, they must be identi-fied cost-effectively before restoration isundertaken. Though several large plumes ofcontaminated groundwater exist beneathHanford, most of the waste intentionally orunintentionally released into the subsurfaceremains in the vadose zone—the partiallysaturated layers above the water table.Observation boreholes drilled in the tankfarms and surrounding areas are air-filledand steel-cased with no cement and norathole. They occasionally contain radioac-tive contamination. Ordinary cased-holelogging tools and interpretation techniquesare ineffective in this environment. Under acooperative research and developmentagreement (CRADA)—initiated and fundedby the Department of Energy—with groupsat the Hanford site, Schlumberger modifiedexisting wireline logging tools and con-ducted extensive computer and laboratorymodeling to calibrate tool responses to theunique operating conditions.1

Autumn 1996

paper Y.

The initial effort focused on modificationof natural gamma ray spectroscopy andneutron porosity tools. The natural gammaray system was aimed at efficient identifica-tion of gamma-emitting waste and litho-logic correlation. Neutron porosity logswere to be used for characterization ofhydrogeologic properties. Specifically, theywould help determine moisture content.Unlike in fully saturated environments,moisture content in unsaturated sedimentsis not equal to porosity (above).

Data quality objectives (DQOs) wereestablished for each of the measurements,based on requirements set by a CRADAcommittee consisting of data users, technol-ogy providers, state and federal regulatoryagency representatives and service com-pany representatives. For natural gammameasurements, the DQOs included opera-tion in high-level radioactive fields andidentification of man-made radioisotopes ofcobalt (60Co) and cesium (137Cs) in additionto naturally occurring radioisotopes tho-rium (Th), uranium (U) and potassium (K)measured during oilwell logging. All con-

centrations were to be reported in pico-Curies per gram (pCi/g).

To achieve these objectives, the HostileNatural Gamma Ray Sonde (HNGS), whichmeasures the energy of incident gammarays with two scintillation detectors, wasadapted to allow interpretation of high lev-els of radioactivity and man-madeisotopes.2 This required modifications to thetool gain regulation system and new meth-ods for constructing elemental standards forcalibration. No 60Co- or 137Cs-rich test for-mations or API test pits were available, asare used for Th, U and K. Calibration wasachieved through measurements in scaledmodels of field conditions built in a labora-tory and combined with Monte Carlo simu-lations for normalization. The sonde wasalso turned upside down so that the detec-tors—now 4 ft [1.3 m] from the bottominstead of 40 ft [13 m]—could log more ofthe borehole. Acceptable comparisons arefound between HNGS-logged values andradioactivity of samples evaluated in thelaboratory (top).

An additional objective of the CRADA wasto measure formation moisture. Withouthuman intervention or natural disturbance,such as earthquakes, waste is assumed tostay where it is placed, discharged or leakedas long as it is not dispersed by fluid flow. If

47

Well Numbering Scheme

Cutaway View of Injection Experiment

Injector well1m

E-7 E-5 E-3 E-1 A-1 A-3 A-5 A-7

■■Tracer-injectionexperiment at Han-ford. Cesium andstrontium injectedin the central hole(left) in 1980 weremonitored usingSchlumbergernuclear probes inobservation holes(red) 15 years later(below).

48 Oilfield Review

1. “Committed to Results: An Introduction to DOE’s Environ-mental Management Program,” Office of EnvironmentalManagement, US Department of Energy, Washington DC,USA, Document DOE/EM-0152P (April 1994).

2. For more on radiation effects and oilfield practice: Bram-blett D, Kurkoski P and Racster C: “Advancing WellsiteRadiation Safety,” Oilfield Review 2, no. 4 (October 1990):13-23.

Hazardous Waste and Radiation Basics

liquid, or moisture, is not present, contami-nants are immobile, and so less likely tomove away from the site. The DQO setaccuracy standards for measuring moisturein formations of up to 40% porosity with12.5%, 30% and 50% of the porosity filledwith water. Standards were also set for mea-surements in beds of different thicknessesand through different casing size. TheAccelerator Porosity Sonde (APS), a neutronporosity tool that emits neutrons and detectsthem again after they have interacted withhydrogen in the formation, was chosen.3

No calibration standards existed for log-ging moisture content, so these had to bedesigned and built. By carefully mixing drypure-quartz sand, SiO2, and aluminum tri-hydrate, Al(OH3)—a dry material containinga known amount of equivalent boundwater—and presettling the mixes on vibrat-ing tables, well understood moisture modelswere created.4 Precision and accuracy ofthe moisture measurements were demon-strated to meet or exceed required specifica-tions in tests on the specially designed cali-bration standards.

The natural gamma and moisture measure-ments were successful, so the CRADA wasextended to develop a through-casing den-sity measurement for porosity determination.The Litho-Density Sonde, an openhole den-sity tool, was altered for this purpose. This

Every country uses different terminology to cate-

gorize hazardous waste, but the two main types

contrasted here are nonradioactive and radioac-

tive. Nonradioactive hazardous waste means

chemicals and materials that are toxic, corrosive,

reactive or ignitable. These may include hydro-

carbons, explosives, asbestos, metals, solvents,

medical wastes, pesticides and polychlorinated

biphenyls—PCBs. In the groundwater, many of

these contaminants are considered hazardous

at levels several parts per billion (ppb). In the

US, for example, groundwater limits in ppb

are 0.5 for PCBs, 5 for benzene, 5 for carbon

tetrachloride and 15 for lead. Limits in soil

may be different.

Within the radioactive waste category, there

may be further distinctions depending on the con-

centration levels of radioactive material and the

half-life of the radionuclides. Low-level radioac-

tive waste, such as clothing, equipment and soil

contaminated with minute concentrations of

radioactivity, or medical and oilfield tracers that

decay rapidly with time, constitute the largest

volume of radioactive waste. These wastes are

generally considered safe if stored in the shallow

subsurface. High-level radioactive waste, such as

spent fuel from nuclear reactors, must be iso-

lated from the surface for thousands of years.

Standards of isolation differ from country to

country. In the United States, the Environmental

Protection Agency standards state that a high-

level waste repository may pose no greater risk

than unmined uranium ore from which the high-

level waste was produced.1

Radiation Basics

The four principal types of nuclear radiation are

alpha particles, beta particles, gamma rays and

neutrons. Alpha and beta particles are both

charged, so they are easily stopped by electro-

static forces in matter. An alpha particle is a

helium atom nucleus, and can be stopped by

paper, clothing or skin. Beta particles—high-

energy electrons—can be stopped by a thin sheet

of metal or wood, but will penetrate water or

skin. Gamma rays and neutrons are highly pene-

trating and require dense shields, such as lead or

thick concrete. Natural radiation from the sun and

earth makes up about 82% of the average per-

son’s exposure to radiation. The rest typically

comes from medical sources, such as X-rays.2

■■Nuclear log datainterpolated alonga transect of theinjection test vol-ume. The matrixbulk density logs(top) from the Litho-Density tool chartthe natural sedi-mentary layering ofthe Hanford forma-tion. The grossgamma ray logs(middle) from theHNGS show thesame layering, aswell as the anoma-lously high levels of134Cs radioactivitynear the injectionwell. Moisture logs(bottom) from theAPS show noanomaly associatedwith the injection,indicating that theformation hasreequilibrated to itspreinjection mois-ture profile. Thismeans the injectedradionuclides areimmobile.

Matrix Bulk Density g/cm3

2.031.91.81.71.61.51.41.31.21.12

E-7 E-5 E-3 E-1 A-1 A-3 A-5 A-7

400 600 800cm

100012001400N

200

400

600

800

1000

cm

1400

1200

1600

1800

INJ

Gross Gamma

AEI

76.472.068.064.060.056.052.048.044.040.7

E-7 E-5 E-3 E-1 A-1 A-3 A-5 A-7

400 600 800cm

100012001400N

200

400

600

800

1000

cm

1400

1200

1600

1800

INJ

Volumetric Fractionof Water

%

22.520.018.016.014.012.010.08.06.04.53

E-7 E-5 E-3 E-1 A-1 A-3 A-5 A-7

400 600 800cm

1000 12001400N

200

400

600

800

1000

cm

1400

1200

1600

1800

INJ

49Autumn 1996

3. For background on the APS: Flanagan et al, reference2; and Scott HD, Wraight PD, Thornton JL, Olesen J-R,Hertzog RC, McKeon DC, DasGupta T and Albertin IJ:“Response of a Multidetector Pulsed Neutron PorosityTool,” Transactions of the SPWLA 35th Annual Log-ging Symposium, Tulsa, Oklahoma, USA, June 19-22,1994, paper J.

4. Engelman RE, Lewis RE, Stromswold DC and HearstJR: “Calibration Models for Measuring Moisture inUndersaturated Formations by Neutron Logging,”Pacific Northwest National Laboratory Report PNL-10801 (1995).

5. Fayer MJ, Lewis RE, Engelman RE, Pearson AL, MurrayCJ, Smoot JL, Randall RR, Wegener WH and Lu AH:“Reevaluation of a Subsurface Injection Experimentfor Testing Flow and Transport Models,” Pacific North-west National Laboratory Report PNL-10860 (Decem-ber 1995).

6. The half-life of 134Cs is 2.06 years and that of 85Sr is64.8 days—short compared to 30.2 years for 137Csand 27.7 years for 90Sr.

density logging sonde irradiates formationswith medium-energy gamma rays that col-lide with electrons in the formation. Witheach collision, a gamma ray loses some of itsenergy and continues. The reduced-energygamma rays that reach the detector arecounted as an indication of the electron den-sity of the formation.

The Litho-Density algorithm for measuringdensity was calibrated to compensate forcasing and the air gap between casing andformation, since there is no annular fill mate-rial in the Hanford holes. Laboratory experi-ments were conducted at the SchlumbergerEnvironmental Effects Calibration Facility inHouston, Texas, USA to verify that the newalgorithm performed within the data qualityobjectives set by the CRADA committee.

The modified measurement techniqueshave been run commercially in 75 bore-holes at Hanford, including an injectionexperiment designed to predict subsurfacetransport models (previous page).5 Radioac-tive tracers 134Cs and strontium (85Sr) wereinjected in a central well in 1980. These areshort-lived isotopes of the same elementswhose long-lived isotopes, 137Cs and 90Sr,have contaminated portions of the Hanfordsubsurface.6 In 1995, the three modifiednuclear probes were run in eight holesalong a transect of the injection test volume(right). Density logs from the Litho-Densitytool chart the natural sedimentary layeringof the shallow unconsolidated formation.Gamma ray logs from the HNGS show thesame layering, as well as noticeably highlevels of 134Cs radioactivity near the injec-tion well. Moisture logs from the APS showno anomaly associated with tracer injection.

The logging was able to locate the 15-year-old cesium plume and verify that theonly detectable 134Cs remaining from theinjection was located near the injectionpoint. No strontium was detected. Duringthe 15 years since the injection, 85Sr had

50 Oilfield Review

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t

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100 10,000,000

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LDS Short-Spaced Detector Counts (Source Removed)1/s

■■Natural gamma and Litho-Density logs revealing a highlyradioactive, contaminated zone less than a foot thick at the Han-ford N reactor site. Natural gamma readings taken by the HNGSran off scale at 200,000 API units at a depth of 10 ft [3m], but theLitho-Density tool delineated the thin contaminated layer.

■■Hanford worker onduty in the highlyrestricted zonearound a tank farm.

decayed to less than 0.01% of the originalamount, and 134Cs to less than 1%. The factthat after 15 years Cs was detected onlynear the injection point is an indication ofthe high sorption potential in the sediments.

In another part of the Hanford facility, at theN reactor site near the river, Bechtel Hanfordhas recently completed a limited field investi-gation of two radioactive liquid waste dis-posal facilities (LWDFs). An LWDF is an engi-neered soil-column waste disposal systemdesigned for reactor effluent disposal. Startingin 1963, demineralized Columbia River cool-ing water was run through the N reactor.Sometimes the cooling water became con-taminated with radioactive waste products.This water was discharged into LWDFs up tomillions of gallons per day. From there it per-colated through surface layers, and most ofthe contaminants were retained in the soilcolumn. Tritium and strontium were amongthose contaminants that reached the ground-water and eventually contaminated someriver bank seeps—known as the N-springs. Asecond facility was constructed farther fromthe river in 1985, but contamination in thegroundwater and N-springs remained. Cur-rently a “pump and treat” process has beenimplemented to protect the Columbia Riverfrom contaminant migration. Contaminantsare pumped, or extracted, for treatment at thesurface. Bechtel and Battelle Pacific North-west National Laboratory (PNNL) are investi-gating permeable barriers for long-term pro-tection of the river (see “ContainingContaminants,” next page).

To design a remediation program, Bechtelmust locate and quantify the volume of con-taminated soil and groundwater in a cost-effective way. Usually, subsurface samplesare collected and analyzed to help charac-terize the contaminated volume. The use ofwell logs enhances the characterization bygiving continuous readings with depth,reduces worker exposure to contaminants,and helps keep costs down. In one area, thecost of a multimillion-dollar characteriza-tion program was cut in half by optimizingthe drilling and sampling plan and supple-menting it with logs.

The logs revealed a highly contaminatedzone less than a foot thick (above left). Nat-ural gamma readings taken by the HNGSran off scale at 200,000 API units and wereunable to resolve the bed thickness, but theLitho-Density tool without the loggingsource maintained gain and delineated thethin contaminated layer.

The integration of sample analysis and logdata is providing a quantitative measure ofthe concentration and thickness of the con-taminated layer. The results will be used byBechtel engineers to assess the feasibility ofrestoring the environment near the N reactorto a condition to be determined by the DOEand state and federal regulatory agencies.

Safe Logging at HanfordWorking near hazardous waste requires pre-cautions and special training to assureworker health and safety. At contaminatedsites, access to all areas is highly restrictedand monitored (above).

Training required for workers at Hanfordand other US environmental managementsites includes a 40-hour OccupationalSafety and Health Administration course,consisting of instruction on hazardousmaterials, cardiopulmonary resuscitationand emergency first aid, and training onuse of respirators and special personal pro-tective equipment (PPE).

There are four levels of PPE, from A for themost stringent requirements to D for theleast. Level D, reminiscent of oilfield opera-tions, requires steel-toed shoes, coveralls,eye protection, gloves and hard-hat. Level Crequires chemical-resistant clothing andboots, inner and outer chemical-resistantgloves and a full-face air-purifying mask withspecially designed filters to remove antici-pated contaminants. For level B, the highestPPE level required at Hanford, impermeablesuits and supplied-air respirators arerequired (next page, top left). The respira-tors— connected to portable air tanks or tostationary air tanks with umbilicals—are

51Autumn 1996

■■Injectable permeable barrier concept. Contaminants flow through a volume of injected treatment materialthat acts as a subsurface filter.

���������������������������� ���� �yyyyyyyyyyzzzzzzzzzzzz{{{{{| |||| |

Mixed waste

Liquid waste disposal facility

Reagent injection

Vadose zone

Borehole

Treated waste

Confining layer

Saturated zone

Uranium TechnetiumChromate

Chlorinated solvents

Permeabletreatment

barrier

Containing Contaminants

■■Dressed for work. Personal protectiveequipment (PPE) level B is required for thisworker lowering a video camera into ahole at Hanford. The worker must bequalified through special safety trainingto wear a respirator and to operate equip-ment near hazardous materials.

7. Savannah River, near Aiken, South Carolina, is aDOE-managed site where tritium was produced.

necessary for work at Hanford where theexact combination of contaminants to beencountered is unknown. Level A, an abso-lutely impermeable “moon-suit,” is requiredwhen there is risk of contaminants that canbe absorbed through the skin.

On-site health and radiation protectiontechnologists caution workers on all aspectsof job safety. Typically the biggest health riskto Hanford workers is overheating broughton by the cumbersome protective equipmentand the high summer temperatures—inexcess of 100°F [38°C]. The technologists’role ranges from reminders about bringingwater to drink when it’s hot out and whereworkers can sit during lunch breaks, to mon-itoring tools for contamination as they comeout of the hole. Any tool found with thesmallest amount of contamination is wipedclean, and the contaminated cloth disposedof in an impermeable barrel stored on site.

Field crew at the Schlumberger Wireline &Testing division in Bakersfield, California,USA who work at the Hanford site, andthose at the division in Charleston, West Vir-ginia, USA—in preparation for work at theSavannah River site in South Carolina,USA—have completed training required forlogging hazardous waste sites.7

(continued on page 54)

Current practice for addressing a subsurface vol-

ume of liquid hazardous waste, or plume, is to

pump and treat the liquid. Once the contaminated

liquid is located, it is pumped out and treated

to remove or neutralize the contamination. In

some cases the treated water is reinjected.

Pumping continues until the incoming liquid is

contaminant free, at which point the site may be

considered restored—but subject to further

monitoring. This process may take years.

When contaminants attain parts per billion con-

centrations, often the process of treatment

reaches an asymptotic level.

This technique may have some merit in homo-

geneous formations, but inhomogeneities—

the bane of the oil and gas reservoir—also

plague environmental management sites. In an

inhomogeneous formation, pumping draws liquid

only from high-permeability zones. In cases of

large permeability contrast, it can be easier to

pump liquid from a high-permeability zone miles

away than from a low-permeability zone only a

few feet away. Pumping may continue until water

comes out clean, but a few months later, moni-

toring may indicate that the water is contami-

nated again due to the desorption of contami-

nants from the soil.

Rather than pumping contaminated liquids to

the surface, scientists at Battelle Pacific North-

west National Laboratory (PNNL) are capitalizing

on the dispersive nature of the contaminants to do

part of the work. Treatment is accomplished by

creation of a permeable barrier—also called a

permeable reactive wall—to treat the contami-

nated liquids as they pass through.

Permeable barriers can be constructed by at

least two different methods. The first, and sim-

plest, is a ditch filled with gravel or absorbent or

chemically reducing material through which

waste liquids are drained. Gravel ditches are

known as trenches, and typically are used to treat

solvent-contaminated shallow groundwater by

aeration. Absorbent minerals such as zeolites,

which act like “kitty litter,” can trap some spe-

cific contaminants. Reducing agents, such as

finely ground particles of iron, are sometimes

effective for treating some contaminants, espe-

cially chromate, uranium and chlorinated sol-

vents. Chemically reducing treatments work by

reducing the valence state of the contaminant.

This reduction in valence destroys organic con-

taminants, such as chlorinated solvents, and

causes certain metallic contaminants to precipi-

tate, trapping them in the filter.

If the contaminants are already deep below the

ground surface, conventional trenching methods

will not be able to reach them. Researchers at

PNNL are investigating a second category—the

injectable permeable barrier—that acts as a sub-

surface filter to treat spreading contaminated liq-

uids (above). Injectable permeable barriers have

Oilfield Review

Groundwaterflow direction

Injection well

Treated volumeTransect

H5-3p H5-4pH5-5p

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■■Hanford chromate-removal field experi-ment. Sodium dithionitewas injected in a layer inthe central well to treatthe shaded volume.Chromate was theninjected in the centralwell and chromate con-centrations were moni-tored in 10 nearby wells.

■■Chromate levels monitored in wells surrounding the injector. Wells within 30 ft of the injector showed nochromate for more than ten months after injection.

1. For a video rendition see the PNNL web site:

http://etd.pnl.gov:2080/EESC_public/vis_examples/scaling/part.mpg

■■Laboratory experiment testing removal of chro-mate contamination. Soil reduced, or treated, withsodium dithionite was then flushed with contami-nated liquid containing chromate. Concentration ofchromate in the contaminated water (influent) washeld at more than 800 parts per billion (ppb). Morethan 120 pore volumes of liquid had passed beforethere was evidence of chromate in the liquid filteringthrough the treated soil (effluent).

Influent

Effluent

Chr

omat

e, p

pb

Pore volumes

2401801206000

200

400

600

800

1000

been tested in the laboratory and in pilot-scale

field experiments at Hanford. In addition to

absorbent filters and chemical-reducing materi-

als, iron-reducing bacterial treatments—

similar to those applied in the oil field to treat

sour wells—have been tested.

Laboratory tests conducted on soils reduced

by one chemical agent, sodium dithionite,

indicate a strong ability to treat chromate-con-

taminated liquid (left). Soils treated with dithion-

ite were able to filter up to 120 contaminated

pore volumes.

A field experiment monitored the same reac-

tion, but at full scale (left). Dithionite was

injected to reduce the iron in a volume of the sub-

surface, then chromate was injected. Chromate

levels were sampled in monitor wells surround-

ing the injector out to a radius of 90 ft [27 m].

Over the course of more than ten months, in wells

monitored within 30 ft [9 m] of the injector, no

chromate was detected (below).Similar tests are under way for examining the

ability of the technique to handle greater time

and length scales. A current experiment is using

a line of injector wells to treat a 2000-ft [608-m]

wide chromate plume, already identified on the

Hanford site.

Modeling

Modeling the distribution of fluids and contami-

nants is a vital part of planning any containment

or treatment effort. As in the case of oil and gas

reservoirs, small-scale variations in formation

properties can have large-scale effects on ulti-

mate fluid distribution.

Scientists at PNNL are simulating fluid and con-

taminant flow through small but realistically

complicated 3D volumes in hopes of understand-

ing flow in larger volumes. A 3D cube represent-

ing part of a complexly layered river sand has

been constructed based on field observations on

a meandering river (next page, bottom). Migration

of a nonreactive tracer through the cube has been

modeled at a series of five time steps (next page,top).1 Tracer migration is constrained by low-per-

meability features in the model volume.

53Autumn 1996

■■Three-dimensionalrepresentation of per-meability distribution ina complexly layeredriver sand. Yellow-greenrepresents high perme-ability and blue repre-sents low permeability.The small-scale sedi-mentary features arebased on field observa-tions on a meanderingriver in Indiana, USA.Development of thismodel is described inScheibe TD and Frey-berg DL: “Use of Sedi-mentological Informa-tion for GeometricSimulation of NaturalPorous Media Struc-ture,” Water ResourcesResearch 31, no. 12(1995): 3259-3270.

■■Simulated nonreactive tracer transport through the3D model at five different time steps. Tracer particleswere released as an instantanous pulse in a plane atthe rear of the cube (white line), and their movementis constrained by the low-permeability layers. Usingmassively parallel computers and particle-trackingmethods, transport was simulated through the modelcomposed of nearly 17 million grid cells. Furtherdescription of these studies—including an animationof the particle plume—is available on the world-wideweb at:http://etd.pnl.gov:2080/EESC_public/vis_examples/scaling/scaling.html.

Time Step 1

Time Step 4 Time Step 5

Time Step 2 Time Step 3

8. “Going Underground,” United Kingdom Nirex Lim-ited, Harwell, Oxford, England (November 1993).

9. Chaplow R: “The Geology and Hydrogeology of Sellafield: An Overview,” Quarterly Journal of Engi-neering Geology 29 (1996): S1- S12.

10. Michie U: “The Geological Framework of the Sellafield Area and Its Relationship to Hydrogeol-ogy,” Quarterly Journal of Engineering Geology 29(1996): S13-S27.

11. For a description of the technique: Hornby BE, LuthiSM and Plumb RA: “Comparison of Fracture Aper-tures Computed from Electrical Borehole Scans andReflected Stoneley Waves: An Integrated Interpreta-tion,” The Log Analyst 23, no. 1 (January-February1992): 50-66.

■■Sellafield—concept for a UK national facility for solid intermediate-level and low-level radioactive waste. Geological and hydrologic investigations are under way todetermine whether the site is suitable as a deep repository.

Characterization Before StorageA primary lesson learned from the restora-tion of sites contaminated with hazardousmaterials is that future waste storage facili-ties must be engineered with care. Countriesthat rely on nuclear energy are taking a hardlook at how to manage the inevitable wasteproducts. Most countries plan deep under-ground repositories, and the search contin-ues for the best locations.

The goal is to isolate hazardous materialfrom the surface for tens of thousands of

54

years—no small task. The subsurface vol-ume selected should be an effective shield,remain tectonically stable, reduce contact ofwaste with groundwater and air, and con-tain no useful mineral resources that wouldtempt human intervention. The storage facil-ity should allow for retrieval of the waste atsuch time that technologies become avail-able for treatment. Some countries, includ-ing Belgium, Finland, France, Germany,Sweden, Switzerland, the UK and the USAhave identified locations that appear to havemany of the desired qualities.8

In the UK, United Kingdom Nirex Limited(Nirex) is responsible for providing and man-

aging a national facility for undergroundstorage of solid intermediate- and some low-level radioactive waste. Geologic and hydro-logic investigations have been in progressaround Sellafield in West Cumbria, Englandsince 1989, to determine whether a siteadjacent to the existing nuclear establish-ment is suitable for a deep repository (left).9

Groundwater is the most likely medium bywhich radioactive waste from a repositorycould return to the surface. Controls ongroundwater flow include driving forces,such as gravity and salinity, and also thegeometry of rock units and properties of therock mass, such as permeability and fracturecharacteristics.10

The building blocks for the geological sitecharacterization consist of 27 deep bore-holes, some down to 1900 m [6200 ft] andthe majority with continuous core; 2000 km[1250 miles] of 2D seismic data and 8000km [5000 miles] of airborne geophysicaldata. Hydrogeological testing and ground-water sampling provide additional informa-tion on flow properties of the volcanic for-mation targeted for study.

A volume of the Borrowdale VolcanicGroup at about 650 m [2133 ft] below sealevel, is under consideration as an under-ground laboratory, or rock characterizationfacility (RCF). The RCF is being constructedto permit detailed examination and testingof rock at depth before selecting a finalrepository design and location. Investiga-tions have shown that groundwater flowwithin the volcanic formations occursthrough a limited number of fractures, andcurrent work focuses on characterizinghydrogeologically significant fractures.

Many techniques developed to identifyand characterize fractures in the oil field areplaying the same role at Sellafield. Integra-tion of several measurements at many scalesis essential for determining which fracturesare open and connected. At the finest scale,electrical conductivity logs of the borehole

Oilfield Review

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■■Fracture orienta-tion and aperturevisualized with the UBI Ultrasonic Borehole Imagertool. Like threadwinding around a spool, ultrasonicscans of the bore-hole track holerugosity in detail.In this image,breakouts—stress-related damage inthe plane of leasthorizontal stress—are seen on oppo-site sides of theborehole.

wall, such Formation MicroScanner and FMIFullbore Formation MicroImager scans,show where fractures intersect boreholes.These borehole images help identify andorient fractures, but may also be combinedwith other data, such as sonic waveforms, tocalculate fracture aperture.11

Fracture orientation and aperture may alsobe interpreted on borehole scans made bythe UBI Ultrasonic Borehole Imager tool.The UBI tool takes 180 transit-time samplesaround the borehole circumference forevery 0.2 in. [0.5 cm] the tool movesuphole. Transit times converted to distanceyield an image that looks like a mold of theborehole. Where fractures intersect theborehole, extra rugosity may occur, and the3D UBI image allows visualization of thesegeometries. Stress-related borehole damagemay also occur in the direction of least hori-zontal stress and manifest itself as holeenlargement, or breakouts, on oppositesides of the borehole (right). The breakoutdirection is an important clue to the stressregime present in the Sellafield area.

Looking beyond the wellbore, boreholeacoustic reflection surveying (BARS) offers agreater range of penetration for fracturetracking. Similar to surface seismic surveysbut recorded in the borehole, this new tech-nique can image fractures extending as faras 30 ft [9 m] away from the borehole(below). In other situations, BARS images

55Autumn 1996

■■Borehole acousticreflection surveys(BARS) for trackingfractures far fromthe borehole. Inthis case, sonic-fre-quency data froma research proto-type tool weremigrated to obtainreflections of pri-mary (P) waves(left) and convertedwaves (right). The center of eachimage correspondsto the wellboreposition (yellow).Fractures identifiedon borehole tele-viewer images areplotted in blackalong the borehole.

Dep

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may be obtained of fractures and other fea-tures near but not necessarily intersectingthe borehole. These sonic waveform dataare acquired with multiple source andreceiver arrays on a single tool. For Nirex,BARS data were recorded with a researchprototype tool; commercial introduction ofthe service is scheduled for early 1997.

56

P

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Converted-WaveReflections

■■Reflections recorded in a boreholeacoustic reflection survey. Primary (P)waves (left) and shear (S) waves (right)reflect at different angles and can beused to image different features or por-tions of the same feature. 12. Sutton JS: “Hydrogeological Testing in the Sellafield

■■Network of boreholes linked with crosswell shaded “curtains” between pairs of holes signhave been imaged with a seismic source in oof hydrophone receivers in the other.

The signals of interest—those from reflec-tions—arrive after the primary (P) andbefore the shear (S) waves that are typicallyanalyzed for borehole sonic slowness val-ues (left). Borehole acoustic reflection sur-veys are processed using seismic data-pro-cessing algorithms, and yield both P and Sreflections. Shear waves help image fea-tures at high angles to the borehole, and arebetter than P waves at resolving some near-wellbore features.

At a larger length scale, seismic imageshave been obtained for several pairs of bore-holes (below left). Seismic travel-time dataare acquired with a downhole seismicsource in one borehole and the Cross WellSeismic Imager—an array of 16 hydrophonereceivers spaced at 4 m [13 ft]—in thesecond one. Travel times are processed toyield an image of velocities in the inter-borehole region. Abrupt changes in veloc-ity, represented by changes in color, indi-cate discontinuities. Combined with otherlog data, borehole-to-borehole correla-tions become clear, reinforcing the inte-grated interpretation (next page). Forexample, fractures evident in one boreholecan be tracked across seismic images, andlinked with fracture indicators in neigh-boring boreholes.

Incorporating flow information is vital toan integrated interpretation. To identify sig-

0

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■■Multipacker systemand testing. These s1500 m [4920 ft] wit

seismic images. Theify the areas thatne hole and an array

nificant fractures, flow tests have been car-ried out. Testing is conducted while thedrilling rig is on location, and with aworkover rig after drilling. Long-term moni-toring and testing with permanent multi-packer systems is continuing in severalboreholes (below right).12 These systemsallow liquid samples and pressures to beanalyzed at multiple levels in any one bore-hole with only one tool position.

Hydraulic conductivity of the volcanic for-mation is typically low, even measured overfractured intervals. Most fractures intersect-ing boreholes have no detectable flow, butthose that do are characterized and relatedto structural features such as faults. As moredata are acquired and interpreted to helpbuild and test conceptual models, scientistsat Nirex will improve their understanding ofthe controls on groundwater flow throughthe subsurface volume.

Future EffortsMany challenges await the environmentalmanagement industry. Parties responsiblefor hazardous waste sites and repositoriesneed to be able to make informed deci-sions. Service providers help by acquiringdata and turning them into usable informa-tion. The application of wireline logging tosite characterization and monitoring pro-

Oilfield Review

Pumpwell

s for long-term hydrogeologic monitoringystems have been deployed to depths of h up to 30 zones isolated in any one borehole.

Area,” Quarterly Journal of Engineering Geology 29(1996): S29-S38.

SonicFormation�

MicroScannerApparent�

DipsApparent�

Dips

FMI Images

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Fault

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Apparent�Dips of:

Pseudo-�Layering

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.30 150.0

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Waveform 1

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vides a comprehensive body of informationand early warning of possible problems. Ifmigration of contaminants is discovered,then there is time for an informed decisionon whether to remediate. If the choice is todo nothing—either because the problemisn’t severe enough or more time is requiredto develop the proper technology—the sitestill must be monitored for regulatory pur-poses and for continued decision making.

If action is required, adequate characteri-zation of the site is necessary to build con-ceptual models for simulating treatment andoptimizing treatment strategies. Duringremediation, monitoring can provide valu-able feedback that ensures success. Andonce remediation has been achieved, fur-ther monitoring is required. Geophysicallogging provides a means for permanentand remote monitoring.

The environmental management industryis growing at different rates in differentcountries, and changing as it grows. Manag-ing the vast amount of data requires specialskills and tools. The rapid pace at whichnew technologies are introduced leadssome environmental managers to predictthat the industry is moving toward deferredremediation. Full site characterization—with sensitive detection of contaminantmigration before it exceeds regulatoryguidelines—allows time for solutions totough problems to be developed. Regula-tions also change, usually becoming morestringent and all-embracing. Informationfrom geophysical logging allows the designof environmental management schemesflexible enough to accommodate changes.

Also predicted is a move toward perfor-mance-based compliance, in which govern-ments regulate what the end results of com-pliance and remediation should be, but nothow to achieve them. As the industryevolves, environmental management firmswill continue to require technologies thatsolve problems in a cost-effective manner sothat decisions can be made in a frameworkof knowledge. —LS

57Autumn 1996

■■Complete set of image data for one pair of boreholes—B2 (left) and B4 (right). Dipmeterstick plots (track 1) indicate apparent dip of identifiable fractures (red sticks). A Forma-tion MicroScanner image (track 2) shows disruptions at depths corresponding to thestick plot. Sonic waveform displays (track 3) plot fracture indicators as breaks in thecontinuity of vertical color stripes. The event at 650 m in B2 can be tracked across thecrosshole seismic image (center) to a similar signal in the sonic display of B4 at 840 m.High-velocity (orange) and low-velocity (blue) zones indicate different lithologies. Lin-ear discontinuities in color may be interpreted as fractures. Intervals in which flow isdetected in B2 (blue circles) and B4 (purple circles) are plotted on either side of thecross-well image. Logs for B4 are in the reverse order of those for B2, with the exceptionof an FMI image in B4 instead of a Formation MicroScanner image.