4 Oilfield Review Over the last ten years, new technologies and field strategies have converged, enabling operators to give new life to old wells. Now, reviving production from declining fields has become a major activ- ity for oil and gas companies, and one that requires more support to identify the right technical solutions. Optimizing well output and economics are the key goals of these production enhancement projects and ser- vice companies are actively participating in achieving these goals. This growing demand has pressed compa- nies in the service sector to diversify their skills and address a wider range of reser- voir and production problems. It has also stimulated a flurry of technical creativity. For example, developments in the area of reentry drilling alone—coiled tubing drilling (CTD), slimhole measurements- while-drilling (MWD) systems and new completion technologies for multiple side- track boreholes—have produced a wealth of options for maximizing return on invest- ment (ROI). But which approach offers the best 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 this broader outlook comes an extended range of capabilities, including identifying underper- forming wells and recommending cost-effec- tive interventions to increase well productivity and maximize net present value (NPV). 2 With improved capabilities from new drilling technologies, a growing number of wells are candidates for reentry drilling— 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. For help in preparation of this article, thanks to Olivier Fabvre, Anadrill, The Hague, The Netherlands; Dave Bergt, Jaime Bernardini, Ike Nitis and Pearl Chu Leder, Anadrill, Sugar Land, Texas, USA; Jon Elphick and Andy Rike, 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 of Schlumberger. A-Z PackStock is a mark of Smith Drilling & Completions. David Hill Eric Neme Christine Ehlig-Economides Sugar Land, Texas, USA Miguel Mollinedo OXY Maracaibo, Venezuela
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4 Oilfield Review
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 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—
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.
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.
David HillEric Neme Christine Ehlig-EconomidesSugar Land, Texas, USA
Miguel MollinedoOXYMaracaibo, Venezuela
Autumn 1996 5
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—
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).
nImproving net present value of oldfields. Reentering wells and drilling hori-zontal laterals into bypassed zones cantap new reserves from existing wellbores. nReentry systems. RAPID services cover the key elements of reentry and multilateral
drilling, from pulling old completions to installing the new one and from drilling fluidsto wireline logging. nMultiple sidetracks for enhanced pro-
duction. Additional drainholes (red) canfan out from existing wellbores or horizon-tal trunks and improve reservoir drainage.nMaking 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 TechnicalConference and Exhibition, Denver, Colorado, USA,October 6-9, 1996.
6Oilfield Review
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
Gas
Shale
Shale
Shale
Oil
Oil
Water
Thick and homogeneous, no gas cap or aquifer
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 gas or water production
Not recommended: risk of disappointing productivity or recovery due to low vertical permeability
Intersect as many layers as possible
Layered
Laminated
Structural compartment
Stratigraphic compartment
Elongated compartment (plan view)
Attic compartments
Naturally fractured
Naturally fractured under waterflood
Well Path
Drainage Volume
Characterization
Stacked parallel wells, with branch flow conformance
Drain each with one or more wells
One well in multiple compartments
Drain each with one or more wells
One well in multiple compartments
One well bed drilled on strike preferred
Single well travers- ing multiple beds
Closely spaced parallel wells preferred
preferred over vertical
Single well traversing multiple channels
Multiple well paths slanting from single main trunk
Closely spaced short parallel wells normal to fractures Water injection wells
v ≥ 0.1k kh
v ≥ 0.1k kh
Horizontal well normal to fractures preferred
Intersect vertical and horizontal fractures
Slanted well Horizontal well
OILFIELD REVIEW AUTUMN 96
nOptimizing 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).
nA 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.
Autumn 1996 7
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.
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 (p revious 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.
Water Coning
Water Cresting
nWater coning during production andbreakthrough if perforations are too closeto the oil-water contact. Reducing produc-tion rate decreases drawdown pressureand mitigates coning. nEffectively 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 viscosityand 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.
nCandidate 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
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
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.
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 ImprovementnStacked 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.nWell 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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yyyyyy�y��������yyyynSection milling. A specialized bottomhole
assembly 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
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.
nWindow 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).
Autumn 1996 13
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
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).
Top of sand
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Lateral section displacement, ftnShort-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.
nA 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
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14 Oilfield Review
nLocation of the Alturitas field in Venezuela, South America.
Direction and
Rotating near-bit stabilizerbend1.5° Fixed
Adjustable standoff
Rotor/stator
Stinger
Battery module
Gamma-ray detector
inclination systems
Lower articulation
Power section
Upper articulation
Mud pulser
Fishing head
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
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.
A R G E N T I N A
VenezuelaAtlantic Ocean
Alturitas
Pacific Ocean
Peninsula de Guajira Peninsula de
Paraguana
La Vela de Coro
El Mamon
Las Palmas/TigujeMonte Clar
Bolivar fields
Boca Escalante
Rosario
San Lorenzo
PocoLake Maracaibo
Cerrejon
Guasare
Gulf of Venezuela
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
nShort-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.
17. Hill et al, reference 13.18. Hutchinson M: “Innovative Short Radius Drilling
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
10900
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Orienting tool
Logging toolDrilling head module
Steerable motor
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Gamma-ray sensors and electronics
Pressure transducers, and electronics
Telemetry and power
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VIPER BHA with PowerPak motor
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VIPER Coiled Tubing Drilling System
nAlturitas 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.
nCoiled tubing drilling system. The VIPER system consists of a wireline-powered BHAthat includes an instrument package for directional control as well as gamma ray,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 Oilfield Review
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
0 800 1600 2400 3200 4000
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Top ofAustin Chalk
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BudaGeorgetown
Bentonite
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Shallow or depleted reservoirs
Layered reservoirs
Fractured reservoirsnMultilateral 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).nTypical Austin Chalk quadrilateral openhole (barefoot) completion drilled for UnionPacific Resources.
Autumn 1996 17
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 (p revious 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-
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
Sidetracking and drilling from Anadrill Drill-in fluids from Dowell
Packers, liners, completion fluids from Dowell Tubing-conveyed perforating from Wireline & Testing
External casing packers, completion fluids, Maraseal and screen from Dowell Packers from Wireline & Testing
Open Hole
Cemented Liner
Prepacked Screen or Slotted Liner nReentry 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).
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.
