01-isolate and stimulate individual pay zones

8/2/2019 01-Isolate and Stimulate Individual Pay Zones

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60 Oilfield Review

Isolate and Stimulate Individual Pay Zones

Kalon F. Degenhardt

Jack Stevenson

PT. Caltex Indonesia

Riau, Duri, Indonesia

Byron Gale

Tom Brown Inc.

Denver, Colorado, USA

Duane Gonzalez

Samedan Oil Corporation

Houston, Texas, USA

Scott Hall

Texaco Exploration and Production Inc.

(a ChevronTexaco company)

Denver, Colorado

Jack Marsh

Olympia Energy Inc.

Calgary, Alberta, Canada

Warren Zemlak

Sugar Land, Texas

ClearFRAC, CoilFRAC, CT Express, DepthLOG, FMI (FullboreFormation MicroImager), Mojave, NODAL, PowerJet,PowerSTIM, PropNET, SCMT (Slim Cement Mapping Tool)and StimCADE are marks of Schlumberger.

For help in preparation of this article, thanks to TarynFrenzel and Bernie Paoli, Englewood, Colorado; Badar ZiaMalik, Duri, Indonesia; and Eddie Martinez, Houston, Texas.

Coiled tubing-conveyed fracturing is a cost-effective alternative to conventional

reservoir-stimulation techniques. This innovative approach improves hydrocarbon

production rates and recovery factors by providing precise, reliable placement of

treatment fluids and proppants. What began as a fracturing service is evolving into

broad technical solutions for new completions, as well as workovers in mature fields.

Operators traditionally rely on drilling programs to

achieve peak productivity, maintain desired pro-

duction levels and optimize hydrocarbon recovery.

As oil and gas developments mature, however,

reservoir depletion reduces field output and fewer

opportunities exist to drill new wells. Drilling pro-

grams alone may not effectively stem the natural

decline of production. In addition, infill and reen-

try drilling often become less profitable and pre-

sent greater operational and economic risks

relative to their higher capital investments.

In many fields, operators intentionally andunintentionally bypass some pay zones during

initial phases of field development by focusing

only on the most prolific producing horizons.

Cumulatively, these marginal pay intervals con-

tain substantial hydrocarbon volumes that can be

produced, especially from laminated formations

and low-permeability reservoirs. Accessing

bypassed pay zones is economically attractive to

enhance production and increase reserve recov-

ery, but poses several challenges.

Typically, bypassed zones have lower perme-

abilities and require fracturing treatments to

achieve sustainable commercial production.Conventional well-intervention and stimulation

methods involve extensive remedial operations,

such as mechanically isolating existing perfora-

tions or squeezing them with cement and utiliz-

ing multiple runs to perforate bypassed pay.

These procedures are expensive and cannot be

justified for zones with limited production poten-

tial. In the past, fracture stimulations were not

commonly attempted on bypassed pay, especially

when multiple stringers were involved.

The mechanical condition of wellbores can be

a limitation as well. If fracture stimulations are not

anticipated during well planning, completion tubu-

lars may not be designed to withstand high-

pressure pumping operations. Also, scale buildup

and corrosion from prolonged exposure to forma-

tion fluids at reservoir temperatures and pressurescan compromise tubular integrity in older wells. In

slimhole wells, workover options are further lim-

ited by small tubulars. These operational and eco-

nomic constraints often mean that bypassed or

marginal pay remains untapped. Ultimately, hydro-

carbons in these intervals are left behind when

wells are plugged and abandoned.

Integration of coiled tubing with fracturing

operations overcomes many of the constraints

associated with stimulating bypassed or

marginal pay zones using conventional tech-

niques, allowing additional reserves to be tapped

economically. High-strength continuous coiledtubing strings transport treatment fluids and

proppants to target intervals and protect existing

wellbore tubulars from high-pressure pumping

operations, while specialized downhole tools

selectively isolate existing perforations with

increased precision.


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Autumn 2001 6

> A fit-for-purpose CT Express coiled tubing unit performing a selective fracturing treatment in Medicine Hat, Alberta, Canada.


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This article describes operational and design

aspects of coiled tubing-conveyed fracturing

treatments, including enabling technologies such

as surface equipment improvements, high-pres-

sure coiled tubing, low-friction fracturing fluids

and new downhole isolation tools. Case histories

demonstrate how this technique reduces comple-

tion time and cost, improves post-treatment

cleanup, increases production and helps tap

reserves bypassed by conventional completion

and fracturing methods.

Conventional Stimulations

Average recovery factors for most reservoirs from

primary- and secondary-drive mechanisms are

just 25 to 35% of original hydrocarbons in place.

Producible reserves also are left behind in thin,

lower permeability zones of many mature reser-

voirs. One North Sea study, for example, deter-

mined that more than 25% of recoverable

reserves lie in the low-permeability, laminated

horizons of Brent sandstone reservoirs.1

Matrix acidizing and hydraulic fracturing arecommon reservoir-stimulation techniques used to

enhance well productivity, increase recovery effi-

ciency and improve well economics.2 However,

effectively completing and stimulating heteroge-

neous reservoirs and discontinuous pay zones

among numerous shale intervals are challenging,

particularly when fracture stimulations are

required. Reservoir pay thickness, quality, pres-

sure and stage of depletion, and cost to treat an

entire productive horizon all must be considered

when choosing completion strategies.

Conventional fracture stimulations attempt to

connect as many producing zones as possible

with single or multiple treatments performed dur-

ing separate operations. Historically, net pay

zones over several hundred feet of gross interval

are grouped into stages, with each stage stim-

ulated by a separate fracturing treatment. These

massive hydraulic fracturing jobs, pumped

directly down casing or through standard jointed

tubing, are designed to maximize fracture height

while attempting to optimize fracture length.

However, uncertainty associated with predicting

height growth often compromises the stimulation

objectives of large treatments and precludes cre-

ation of the fracture lengths required to optimize

effective wellbore radius and reserve drainage.Proppant placement in individual zones is dif-

ficult to achieve when a single treatment is per-

formed across numerous perforated zones

(below). Thin or low-permeability zones grouped

with thicker zones may remain untreated or may

not be stimulated effectively, and some zones are

occasionally bypassed intentionally to ensure

effective stimulation of more prolific

pay. Limited-entry perforations and ball sealers

distribute fluid efficiently during pad injection,

but less effectively during proppant placement

as perforations are enlarged by erosion or

treatment fluids flow preferentially into higher

permeability zones.3

Unintentionally bypassed and untreated

zones also are attributed to variable in-situ

stresses. In past conventional fracturing designs,

the fracture gradient, or stress profile, was

assumed to be linear and to increase gradually

with depth. In reality, formation stresses often

are not uniform across an entire geologic horizon,

and again, some zones may be difficult to treat

and stimulate effectively (next page, top).

Grouping pay zones in smaller stages over-

comes some of these limitations and helps

ensure sufficient fracture coverage, but multi-

stage treatments usually require several perfo-rating and fracturing operations in succession.

Isolating individual zones for conventional frac-

ture stimulations with workover rigs and jointed

tubing is problematic as well, requiring addi-

tional equipment and workover procedures.

There are fixed costs associated with each stage

of multistage fracturing operations. Conventional

fracturing operations add redundancy to stimula-

tion operations and increase overhead costs.

Every time wireline units and pumping equip-

ment are moved onto a wellsite for perforating

and stimulation operations there are separate

mobilization and setup charges. There are alsoseparate coiled tubing or slickline costs to wash

out sand plugs or set and retrieve bridge plugs,

which have to be purchased or rented. Hauling,

handling and storing stimulation and displacement

fluids for each nonconsecutive fracturing opera-

tion involve additional costs. Testing each individ-

ual stage in a well again requires multiple setups

and significantly increases completion time.

Some gas wells with several large treatment

stages may take weeks to complete. Redundant

charges accumulate quickly on wells with more

than three or four stages and significantly affect

the economics of stimulation procedures. Thesehigher costs typically become a major influence

on completion or workover decisions and strate-

gies and may limit development of marginal pay

zones that cumulatively contain sizeable volumes

of oil and gas.

To stimulate bypassed zones in existing

wells, conventional fracturing requires that lower

producing zones be isolated by a sand plug or

62 Oilfield Review

> Single-stage treatment diversion: radioactive tracers and production logs. With limited-entry tech-niques, some zones are not stimulated effectively and others may remain untreated. In this example,six pay zones over a 300-ft [90-m] gross interval were fractured through 24 perforations. A radioactive-tracer survey shows that the three upper zones received most of the treatment fluids and proppant,while the three lower zones were not adequately stimulated (left). If an interval did not take fluid at thebeginning of a treatment, perforation erosion in other sands eliminated the backpressure necessaryfor diversion. The lowest zone contributes no production; the other two contribute very little flow onthe production log spinner survey (right).


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Autumn 2001 63

downhole mechanical tool such as a retrievable

or drillable bridge plug. Upper perforations are

sealed off by cement squeezes that are often dif

ficult to achieve, require additional rig time and

add to completion costs. There also is a risk that

squeezed perforations will break down during

high-pressure pumping operations.

These limitations, inherent in conventiona

fracturing techniques, reduce stimulation effec

tiveness. Unconventional well intervention and

stimulation techniques are needed to ensure

hydrocarbon production from as many intervals

as possible, especially from zones that previously

could not be completed economically. Coiled tub

ing-conveyed fracturing techniques overcome

many of the limitations associated with conven

tional fracturing treatments (below left).4

Selective Stimulations

Combining coiled tubing and stimulation services

is not new. In 1992, coiled tubing was used to

fracture wells in Prudhoe Bay, Alaska, USA. The

31

2-in. coiled tubing was connected into the wellhead and left in the well as production tubing to

help maintain flow velocity. This technique

never gained wide acceptance because it was

limited to smaller intervals and lower treating

pressures in wells where a single zone was

targeted for completion.

1. Hatzignatiou DG and Olsen TN: Innovative ProductionEnhancement Interventions Through Existing Wellbores,paper SPE 54632, presented at the SPE Western regionalMeeting, Anchorage, Alaska, USA, May 26-28, 1999.

2. In matrix treatments, acid is injected below fracturingpressures to dissolve natural or induced damage thatplugs pore throats.

Hydraulic fracturing uses specialized fluids injected at

pressures above formation breakdown stress to createtwo fracture wings, or 180-degree opposed cracks,extending away from a wellbore. These fracture wingspropagate perpendicular to the least rock stress in apreferred fracture plane (PFP). Held open by a proppant,these conductive pathways increase effective wellradius, allowing linear flow into the fractures and to thewell. Common proppants are naturally occurring orresin-coated sand and high-strength bauxite or ceramicsynthetics, sized by screening according to standard USmesh sieves.

Acid fracturing without proppants establishes conductivity by differentially etching uneven fracture-wing sur-faces in carbonate rocks that keep fractures fromclosing completely after a treatment.

3. Limited entry involves low shot densities1 shot per fooor lessacross one or more zones with different rockstresses and permeabilities to ensure uniform acid orproppant placement by creating backpressure and limit-ing pressure differentials between perforated intervals.The objective is to maximize stimulation efficiency andresults without mechanical isolation like drillable bridgeplugs and retrievable packers. Rubber ball sealers canbe used to seal open perforations and isolate intervalsonce they are stimulated so that the next interval can betreated. Because perforations must seal completely, holediameter and uniformity are important.

The pad stage of a hydraulic fracturing treatment is thevolume of fluid that creates and propagates the fractureand does not contain proppant.

4. Zemlak W: CT-Conveyed Fracturing Expands ProductionCapabilities, The American Oil & Gas Reporter43, no. 9(September 2000): 88-97.

Increasing

depth

> Variations in formation stress. In single, multizone treatments, pressurechanges are assumed to be linear with depth ( far left). Depleted zones causepressure to decrease abruptly (middle left). Excessively depleted sands alsoreduce pressure over extensive intervals (middle right). In some cases, for-mations have pressure and stress variations that make diversion of treatmentfluids and stimulation coverage during a single-stage treatment extremelydifficult (far right).

> Conventional and selective stimulations. Fracturing several zones groupedin large intervals, or stages, is a widely used technique. However, fluid diver-sion and proppant placement are problematic in discontinuous and heteroge-neous formations. Conventional treatments, like this four-stage example,maximize fracture height, often at the expense of fracture length and com-plete interval coverage (left). Some zones remain untreated or may not bestimulated adequately; others are bypassed intentionally to ensure effectivetreatment of more permeable zones. Selective isolation and stimulation withcoiled tubing, in this case nine stages, overcome these limitations, allowingengineers to design optimal fractures for each pay zone of a productiveinterval (right).


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By 1996, coiled tubing-conveyed fracturing

was identified as a preferred completion strategy

for shallow gas fields in southeastern Alberta,

Canada.5 Selective placement of proppant in all

the productive intervals of a wellbore reduced

completion time and enhanced productivity. The

best candidates were wells with multiple low-

permeability zones where gas production was

commingled after fracturing. Previously, these

wells were stimulated by fracturing one interval

per well and then moving to the next well. While

a fracturing crew treated the first interval of thenext well, a rig crew prepared previous wells for

fracturing of subsequent intervals.

Extensive rig-up and rig-down times were

required to treat as many as four wells a day. In

terms of number of treatments performed, this

process was efficient, but moving equipment

from one location to another took more time than

actually pumping the fracturing treatments.

Operators evaluated the possibility of grouping

zones into stages for conventional multizone

stimulations using limited-entry perforating, ball

sealers or other diversion techniques to individu-

ally isolate zones, but could not justify thesestandard industry practices economically.

One solution was to use a coiled tubing ten-

sion-set packer and sand plugs for zonal isolation.

The lowest zones were treated first by setting the

packer above the interval to be fractured.

Proppant schedules for each zone included extra

sand to leave a sand plug across fractured inter-

vals after pumping stopped and before treating

the next zone. Each treatment was underdis-

placed, and wells were shut in to allow the extra

sand to settle into a plug. A pressure test verified

sand-plug integrity and the packer was reset

above the next interval. This procedure was

repeated until all pay intervals were stimulated

(above). The larger coiled tubing string was rigged

down and smaller coiled tubing was brought in towash out sand and initiate well flow.

Coiled tubing-conveyed fracturing has since

expanded to slimhole wells238-, 278- and 312-in.

tubulars cemented as production casingand to

wells with open perforations or questionable

tubular integrity that prevented fracturing down

casing. Conventional workovers and stimulations

that require cement squeezes to isolate open

perforations are expensive and risky under these

conditions. Shallow gas and deeper coiled tubing

stimulations in mature oil and gas regions of the

continental region of the United States formed

the basis for CoilFRAC selective isolation andstimulation services.

In east Texas, USA, coiled tubing was used to

stimulate wells with open perforations above

bypassed zones and wells with low-strength

278-in. production casing weakened further by

corrosion. After the target zone was perforated, a

tension-set packer on coiled tubing isolated the

wellbore and upper perforations (next page, top

left). In south Texas, bypassed pay zones

between open perforations in wells with casing

damage near the surface were stimulated suc-

cessfully by setting a bridge plug below the tar-

get zone and then running a tension-set packer

on coiled tubing (next page, top right). These

fracture stimulations were performed without

cementing existing perforations or exposing pro-

duction casing to high pressures.Early CoilFRAC techniques with tension-set

packers improved stimulation results, but were

still time-consuming and limited by having to set

and remove plugs. The next step was to develop

a coiled tubing straddle-isolation tool that sealed

above and below an interval to eliminate sepa-

rate operations for spotting sand or setting bridge

plugs with a wireline unit (next page, bottom). This

modification allowed coiled tubing strings to be

moved quickly from one zone to the next without

pulling out of the well.

64 Oilfield Review

5. Lemp S, Zemlak W and McCollum R: An EconomicalShallow-Gas Fracturing Technique Utilizing a CoiledTubing Conduit, paper SPE 46031, presented at theSPE/ICOTA Coiled Tubing Roundtable, Houston, Texas,USA, April 15-16, 1998.

Zemlak W, Lemp S and McCollum R: Selective HydraulicFracturing of Multiple Perforated Intervals with aCoiled Tubing Conduit: A Case History of the UniqueProcess, Economic Impact and Related ProductionImprovements, paper SPE 54474, presented at theSPE/ICOTA Coiled Tubing Roundtable, Houston, Texas,USA, May 25-26, 1999.

> Coiled tubing-conveyed fracturing with a single tension-set packer and sand plugs.


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Autumn 2001 65

> Multistage coiled tubing-conveyed fracturing operation with early straddle-isolation tools.

> Coiled tubing-conveyed fracturing with a singletension-set packer for casing and tubing protection.

> Coiled tubing-conveyed fracturing with a singlepacker and mechanical bridge plugs. In southTexas, a well with casing damage near the sur-face and a bypassed zone between existing openperforations was stimulated successfully withcoiled tubing. The operator set a bridge plug toisolate the lower zone before running a tension-set packer on coiled tubing to isolate the upperzone and protect the casing. This technique elimi-nated a costly workover and remedial cement-squeeze operations.


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Elastomer cup-type seals were added above a

tension-set packer to isolate perforated intervals

and eliminate separate plug-setting operations.

However, additional modifications were required

to further reduce time and cost. In Canada, an

isolation tool with elastomer cups above and

below an adjustable ported spacer assembly, or

mandrel, was developed to allow multiple zones

to be treated in one trip (right).

This version of the straddle-isolation tool,

which had no mechanical slips to facilitate quick

moves and fishing, carried shallow-gas projects

in Canada through more than 200 wells and 1000

individual CoilFRAC treatments. Continuing

improvements to this tool allow bypassed and

marginal zones to be stimulated at nominal incre-

mental cost. Efficient isolation and stimulation of

individual sands maximized completed net pay

and made zones previously considered marginal

economically viable.

More Experience in Canada

Wildcat Hills field is located west of Calgary,Alberta, Canada, on the eastern slope of the

Rocky Mountains in a protected grassland area.6

This area has produced natural gas from deep

Mississippian discoveries since 1958. During the

early 1990s, two Olympia Energy wells tested

shallower Viking sands. The wells initially pro-

duced about 900 Mcf/D [25,485 m3 /d], but

declined rapidly to 400 Mcf/D [11,330 m3/d].

Although pressure-buildup and production tests

indicated substantial reserves, the low reservoir

pressure, poor deliverability and high completion

costs precluded development of marginal

Viking zones.A 1998 seismic survey identified a third Viking

target in an area where the formation was

uplifted by more than 3000 ft [914 m], potentially

creating natural fractures that might enhance gas

deliverability. The 3-3-27-5W5M well encoun-

tered about 45 ft [14 m] of pay in five zones

across 82 ft [25 m] of gross interval (next page,

top). An FMI Fullbore Formation MicroImager

microresistivity log verified existing natural frac-

tures in the reservoir, but drillstem testing indi-

cated a low pressure of 1100 psi [7.6 MPa].

Pressure-buildup tests before setting 412-in. cas-

ing and after perforating indicated drilling-fluidinvasion into natural fractures and additional for-

mation damage from completion fluids.

A mud-solvent treatment failed to remove the

damage, so a fracturing treatment was selected

to increase gas deliverability. Fracturing down

casing with limited-entry diversion was not an

option because the well had already been perfo-rated. The operator evaluated diversion with ball

sealers as well as mechanical zonal isolation

with sand plugs, bridge plugs or coiled tubing.

Ball-sealer effectiveness is questionable, espe-

cially during fracturing treatments, so mechani-

cal diversion was deemed the most reliable

method to ensure stimulation of all pay zones.

With only 13 to 16 ft [4 to 5 m] between four

zones, engineers eliminated use of sand plugs

because close spacing made it difficult to accu-rately place the correct sand volumes.

Conventional jointed tubing with packers and

bridge plugs for isolation involved separate oper-

ations to treat individual zones one at a time from

the bottom up. This required repeated equipment

mobilization and demobilization, redundant ser-

vices for each zone and retrieving or moving

bridge plugs after each treatmentall of these

made the costs prohibitive.

66 Oilfield Review

> Coiled tubing isolation tools. The first CoilFRAC operations used a singletension-set packer above a zone with sand plugs or bridge plugs to isolatebelow the zone (left). Subsequent versions were modified to include an upperelastomer seal cup above the zone and a lower packer to isolate below (mid-dle). This second-generation tool was followed by a straddle design with elas-tomer seal cups on the top and bottom of a ported spacer, which increasedthe speed of packer moves, and reduced execution time as well as operationalcosts (right). These specialty tools eliminated rig and wireline operationsbecause sand plugs and bridge plugs were not needed. Coiled tubing couldbe moved quickly from one zone to the next without pulling out of the well.

6. Marsh J, Zemlak WM and Pipchuk P: EconomicFracturing of Bypassed Pay: A Direct Comparison ofConventional and Coiled Tubing Placement Techniques,paper SPE 60313, presented at the SPE Rocky MountainRegional/Low Permeability Reservoirs Symposium,Denver, Colorado, USA, March 12-15, 2000.


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Autumn 2001 67

The operator selected CoilFRAC services to

stimulate each zone separately and treat severa

zones in a single day. On the first day, the jointed

tubing string used to perform production tests and

the solvent treatment was pulled from the well

Coiled tubing, fracturing and testing equipmen

was moved to location on the second day while a

wireline unit set a bridge plug to isolate the lowe

Viking formation. The maximum recommended

interval that the isolation tool could straddle a

that time was 12 ft [3.7 m], which was less than

the length of the lowest interval, so a tension-se

packer was used to fracture the first zone.

Three fracture stimulations were attempted

on the third day. Sticking problems required the

straddle-isolation tool to be pulled for repair o

the elastomer seal cups. A casing scraper run

smoothed the rough casing. This step is now

performed routinely before CoilFRAC treatments

as part of wellbore preparation. Annulus pres

sure increased while pumping pad fluids in the

second interval, indicating possible communica

tion behind pipe or fracturing into an adjacenzone. This treatment was cancelled before initi

ating proppant, and the tool was moved to the

third interval.

After the fourth interval was stimulated, the

straddle-isolation tool was pulled, so that open

ended coiled tubing could be used to clean ou

sand and unload fluids. On the fourth day, a snub

bing unit ran jointed production tubing in the wel

under pressure to avoid formation damage from

completion-fluid invasion.

To eliminate the snubbing unit, coiled tubing

now is used to run a packer with an isolation

plug. After the packer is set, coiled tubing isreleased and removed from the well. The packe

plug controls reservoir pressure until jointed pro

duction tubing is run. A slickline unit then

retrieves the isolation plug, initiating well flow.

Before stimulation, the 3-3-27-5W5M wel

flowed 3.5 MMcf/D [99,120 m3 /d] of gas a

350-psi [2.4-MPa] surface pressure. After three

of the upper four zones were fractured success

fully, the well produced 6 MMcf/D [171,818 m3/d

at 350 psi. The well continued to produce a

5 MMcf/D [143,182 m3/d] and 450 psi [3.1 MPa

for several months. The CoilFRAC treatmen

delivered an economic production gain in addition to reducing cleanup time and simplifying

completion operations (left). Minimal operations

and faster cleanup helped bring production on

line sooner by reducing completion cycle time

from 19 to 4 days.

> Well 3-3-27-5W5M, Wildcat Hills field. Previous attempts to stimulate the Viking formation as a contin-uous interval were not successful because of difficulty in intersecting multiple zones with conventionalsingle-stage fracture treatments. Closely spaced perforated intervals prohibited isolation with a packerand sand or bridge plugs. Selective CoilFRAC treatment placement simulated four zones individually toincrease recovery by isolating and fracturing pay that often is bypassed or left untreated. Secondarygoals were to simplify several days of completion operations into a single day and reduce cost.

> Comparison of conventional and CoilFRAC Viking completions. Coiled tub-

ing-conveyed fracture stimulations required 58% less total proppant, reducedoverall completion operations from 19 days to 4, and improved well cleanupand fracturing fluid recovery. CoilFRAC treatment placement and simultane-ous flowback improved fluid recovery and saved Olympia Energy about$300,000 per well in the Wildcat Hills field, which reduced cost per Mcf/D byabout 78%.


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Olympia Energy drilled six more wells in the

Wildcat Hills field after completion of the 3-3-27-

5W5M well. Because the Viking formation varies

from well to well, the operator selected fractur-

ing techniques based on sand thickness, fracture

containment barriers, vertical spacing between

sands and required number of treatments. Three

of these wells contained two or three thick Viking

sands that were fractured down casing. The

larger zones required higher pump rates to opti-

mize fracture height and length, which ruled out

use of coiled tubing because of potentially exces-

sive surface treating pressures.

Like the 3-3-27-5W5M well, the other three

wells had similar interbedded sand-shale

sequences and 6- to 13-ft [2- to 4-m] pay zones,

so Olympia Energy used CoilFRAC selective stim-

ulations. This approach increased productivity

and recovery by selectively treating pay that had

been bypassed or not stimulated effectively, and

it ultimately decreased operational costs.

Pre- and post-treatment production logs were

run on the 4-21-27-5W5M well to evaluateincreased production from zones in one of the

wells that was fractured using coiled tubing

(below). Prior to fracturing, the well produced

2 MMcf/d [57,300 m3 /d] with flow from

two intervals. After CoilFRAC treatments on

five intervals, gas production increased to

4.5 MMcf/D [128,900 m3/d] with flow from four

of the five intervals. Olympia Energy saved

$300,000 per well on fracturing operations alone

by using CoilFRAC techniques to stimulate

Wildcat Hills Viking wells. One of the original Viking

gas wells has been reevaluated and identified as

a candidate for stimulation with coiled tubing.

At a depth of 8200 ft [2500 m], this coiled tub-

ing-conveyed application demonstrated the

impact of combining coiled tubing and stimula-

tion technologies on well productivity and

reserve recovery. The smaller surface footprint,

less time on location and fewer wellsite visits

combined with less gas emissions and flaring as

a result of flowing, testing and cleaning up all the

pay zones at one time make CoilFRAC treatments

particularly attractive in environmentally sensi-

tive areas like the grasslands around WildcatHills field.

Fracturing Designs and Operations

Coiled tubing-conveyed fracturing is constrained

by restrictions on fluid and proppant volumes

related primarily to smaller tubular sizes and

pressure limitations. The application of CoilFRAC

services requires alternative fracture designs,

specialized fluids, high-pressure coiled tubing

equipment, and integrated fracturing and coiled

tubing service teams to ensure effective stimula-

tions and safe operations.7

Injection rates, fluid parameters, treatment

volumes, in-situ stresses and formation charac-

teristics determine the net pressure available

downhole to create a specific fracture geo-

metrywidth, height and length. Minimum

pump rates are required to generate the desired

fracture height and to transport proppant along

the length of a fracture. Minimum proppant con-

centrations are needed to attain adequate frac-

ture conductivity.

Coiled tubing strings have a smaller internal

diameter (ID) than the standard jointed work-

strings used in conventional fracturing opera-tions. At the injection rates required for hydraulic

fracturing, frictional pressure losses associated

with proppant-laden slurries can lead to high

treating pressures that exceed surface equip-

ment and coiled tubing safety limits. Using larger

coiled tubing reduces friction pressures, but

increases equipment, logistics and maintenance

costs, and may not be practical for small-diame-

ter slimhole and monobore wells.

This means that treatment rates and proppant

volumes for coiled tubing-conveyed fracturing

must be reduced compared with those of con-

ventional fracturing. The challenge is to achieveinjection rates and proppant concentrations that

transport proppant effectively and create the

required fracture geometry. Coiled tubing-con-

veyed fracturing requires alternative equipment

and treatment designs to ensure acceptable sur-

face treating pressures without compromising

stimulation results.

Reservoir characterization is the key to any

successful stimulation treatment. Like conven-

tional fracturing jobs, coiled tubing treatments

must generate a fracture geometry consistent

with optimal reservoir stimulation. The preferred

approach is to design CoilFRAC pumping sched-ules that balance required injection rates and

optimal proppant concentrations with coiled tub-

ing treating-pressure constraints. Fracturing fluid

selection depends on reservoir characteristics

and fluid leakoff, downhole conditions, required

fracture geometry and proppant transport. Fluids

68 Oilfield Review

> Pre- (left) and post-stimulation (right) evaluation. Production log spinner surveys in Viking Well 4-21-27-5W5M confirmed that CoilFRAC selective fracturing treatments in each Viking sand improved theproduction profile and total gas rate (right).


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Autumn 2001 69

for CoilFRAC treatments include water-base lin-

ear or low-polymer systems and polymer-free

ClearFRAC viscoelastic surfactant (VES) fluids.8

In the past, polymers provided fluid viscosity

to transport proppant. However, residue from

these fluids can damage proppant packs and

reduce retained permeability. Engineers often

increase proppant volumes to compensate for

any reduced fracture conductivity, but slurry

friction increases exponentially with higher prop-

pant concentrations and can limit the effective-

ness of CoilFRAC treatments. Increased surface

treating pressure from frictional pressure losses

is the dominant factor in coiled tubing-conveyed

fracturing, so reducing surface pump pressures is

critical in CoilFRAC applications, particularly in

deeper reservoirs.

Because of their unique molecular structure,

VES fluids exhibit as much as two-thirds

lower frictional pressures than polymer fluids

(right). Nondamaging ClearFRAC fluids may pro-

vide adequate fracture conductivity with lower

proppant concentrations at acceptable surfacetreating pressures. This facilitates optimized frac-

ture designs. These fluid characteristics make

coiled tubing-conveyed fracturing feasible at com-

monly encountered well depths.

Another advantage of ClearFRAC fluids is

reduced sensitivity of fracture geometry to fluid

injection rate. Height growth is better contained,

resulting in longer effective fracture lengths,

which is particularly important when treating thin,

closely spaced zones. Fluids based on a VES also

are less sensitive at downhole temperatures

and conditions that cause fracturing fluids to

break prematurely.If pumping stops because of an operational

problem or fracture screenout, the stable suspen-

sion and transport characteristics of ClearFRAC

fluids prevent proppants from settling too quickly,

especially between the seal cups of straddle-iso-

lation tools. This allows time to clean out remain-

ing proppant and decreases the risk of stuck pipe.

In addition, these fluids provide a backup contin-

gency in high-risk environments, such as high-

angle or horizontal wells, where proppant settling

also can be a problem.

Recovering treatment fluids is critical when

target zones have low permeability or low bot-tomhole pressure. Another benefit of VES fractur-

ing fluids is more effective post-stimulation

cleanup. Field experience has shown that VES

fluids break down completely in contact with

reservoir hydrocarbons, through extended dilu-

tion by formation water or under prolonged expo-

sure to reservoir temperature, and are

transported easily into wellbores by produced flu-

ids. Retained permeability is close to 100% of

original permeability with VES fluids. In addition,

treating and flowing back all the zones at onetime improve fluid recovery and fracture cleanup.

High-strength, 134- to 278-in. coiled tubing is

used to accommodate higher injection pressures.

Coiled tubing for fracturing operations is fabri-

cated from high yield-strength, premium-grade

steels with high burst pressure. For example,

134-in., 90,000-psi [621-MPa] yield strength coiled

tubing has a burst-pressure rating of 20,700 psi

[143 MPa] and can withstand collapse pressures

of 18,700 psi [129 MPa]. Coiled tubing is hydro-

statically tested to about 80% of its burst-pressure

rating, 16,700 psi [115 MPa] for this 1 34-in. string

prior to pumping operations, and maximum pumppressure is set at 60% of the design

burst pressure, or about 12,500 psi [86 MPa], for

this example.

Because the entire coiled tubing string con-

tributes to friction pressure, regardless of how

much is inserted in a well, the length of coiled

tubing on a reel should be minimized relative to

the deepest interval. There has been concern

that centrifugal forces on the proppant would

erode the inner wall of spooled coiled tubing.

However, visual and ultrasonic inspection before

and after fracturing found no erosion inside the

coiled tubing and detected only minor erosion atcoiled tubing connectors after pumping as many

as nine treatments.

Operational safety is critical at the high pres-

sures required for hydraulic fracturing treat-

ments. For example, personnel should not be

permitted near wellheads or coiled tubing equip-

ment during pumping operations. Coiled tubing-

conveyed fracturing requires specialized surface

equipment and innovative modifications to

ensure safe operations and to deal with contin

gencies in the event of a screenout.9

On thesurface, coiled tubing equipment, such as quick

response, gas-operated relief valves, remotely

operated fracturing manifolds and modifications

to coiled tubing reels and manifolds, allow high

rate pumping of abrasive slurries.

Precise depth control also is important fo

selective stimulations. Inaccurate positioning o

coiled tubing results in serious and costly prob

lemsperforating off-depth, placing a sand plug

in the wrong place, problems positioning straddle

isolation tools or stimulating the wrong zone

Straddle-isolation tools must be positioned accu

rately across perforated intervals. Five types odepth measurements are used: standard level

wind pipe measurements as coiled tubing comes

off the reel, a depth-monitoring system in the

injector head, mechanical casing-collar locators

and two new independent systems used

by Schlumbergerthe Universal Tubing-Length

Monitor (UTLM) surface measurement and the

DepthLOG downhole casing-collar locator.

7. Olejniczak SJ, Swaren JA, Gulrajani SN and OlmsteadCC: Fracturing Bypassed Pay in TubinglessCompletions, paper SPE 56467, presented at the SPEAnnual Technical Conference and Exhibition, Houston,Texas, USA, October 3-6, 1999.

Gulrajani SN and Olmstead CC: Coiled Tubing ConveyedFracture Treatments: Evolution, Methodology and FieldApplication, paper SPE 57432, presented at the SPEEastern Regional Meeting, Charleston, West Virginia,USA, October 20-22, 1999.

8. Chase B, Chmilowski W, Marcinew R, Mitchell C, Dang YKrauss K, Nelson E, Lantz T, Parham C and Plummer J:Clear Fracturing Fluids for Increased Well Productivity,Oilfield Review9, no. 3 (Autumn 1997): 20-33.

9. A screenout is caused by proppant bridging in the frac-ture, which halts fluid entry and fracture propagation. Ifa screenout occurs early in a treatment, pumping pres-sure may become too high and the job may be termi-nated before an optimal fracture can be created.

> Effect of friction-reducing fluids. As CoilFRAC applications expand to includedeeper wells, low-friction fluids will be a key to future success. This plot com-pares surface-treating pressure versus depth for 2-in. coiled tubing using apolymer-based fracturing fluid and a ClearFRAC viscoelastic surfactant (VES)fluid, both with 4 ppa proppant concentrations.


11/18

In the past, the accuracy of standard coiled

tubing depth measurements was about 30 ft

[9.1 m] per 10,000 ft [3048 m] under the best con-

ditions and as much as 200 ft [61 m] per 10,000

ft in the worst cases. The dual-wheel UTLM sur-

face measurement is self-aligning on the coiled

tubing, minimizes slippage, offers improved wear

resistance and measures unstretched pipe

(below).10 Two measuring wheels constructed of

wear-resistant materials, on-site data processing

and routine calibration eliminate the effects of

wheel wear on surface measurement repeatabil-

ity and provide automatic redundancy in addition

to slippage detection.

The remaining factors that affect measure-

ment accuracy and reliability are contaminants

and buildup on wheel surfaces, and thermal

effects that change wheel dimensions. An anti-

buildup system prevents contamination of wheel

surfaces. Downhole coiled tubing pipe deforma-

tion is evaluated using computer simulation.

For thermal pipe deformation modeling, a well-

bore simulator provides a temperature profile.The total deformation can be estimated with an

accuracy of about 5 ft [1.5 m] per 10,000 ft. The

combination of more accurate surface measure-

ments with modeling and improved operational

procedures result in about a 11 ft [3.4 m] per

10,000 ft accuracy, and a repeatability of about

4 ft [1.2 m]. In most cases, a value of less than 2 ft

[0.6 m] is achieved.

70 Oilfield Review

> The UTLM dual-wheel surface depth-measurement device.

> Hiawatha field producing horizons. In the Hiawatha field of northwestColorado (insert), pay zones historically were grouped in intervals, or stages,of 150 to 200 ft [46 to 61 m] and stimulated with a single fracture treatment.Thin sands were grouped with thick sands, and occasionally thin sandswere bypassed to avoid less effective stimulation of more prolific sands.Multiple hydraulic fracture stages were still required to treat the entirewellbore. Each fracture stage was isolated with a sand plug or mechanicalbridge plug. Justifying completion of thin sands capable of 100 to 200 Mcf/D[2832 to 5663 m3/d] was difficult.


12/18

Autumn 2001 7

Previously, depth correction with wireline

inside coiled tubing or memory gamma ray log-

ging tools, flags painted directly on the coiled

tubing and mechanical casing-collar locators

often were inaccurate, costly and time-consum-

ing. Schlumberger now uses a wireless

DepthLOG tool, which detects magnetic varia-

tions at joint casing collars as tools are run into a

well and sends a signal to surface through

changes in hydraulic pressure. Subsurface

depths are determined quickly and accurately by

comparison with baseline gamma ray correlation

logs. The use of wireless technology decreases

the number of coiled tubing trips into a well and

saves up to 12 hours per operation on typical

coiled tubing-conveyed perforating and stimula-

tion operations.

In the past, separate coiled tubing services, if

required, followed fracturing operations to clean

out excess proppant. Coiled tubing-conveyed

fracturing, however, requires the combined

efforts of fracturing and coiled tubing personnel.

Initially, service crews faced a steep learningcurve as they began working together to reduce

the time required for various operations.

Subsequent CoilFRAC projects increased opera-

tional efficiency and reduced completion time. To

further increase efficiency, Schlumberger has

formed dedicated CoilFRAC teams to integrate

coiled tubing and fracturing expertise.

Revitalizing a Mature Field

Texaco Exploration and Production Inc. (TEPI),

now a ChevronTexaco company, extended

the productive life of West Hiawatha field in

Moffat county, Colorado, USA, with CoilFRACtechniques.11 Discovered in the 1930s, this field

has 18 pay sands over 3500 ft [1067 m] of

gross interval. Gas production comes from

the Wasatch, Fort Union, Fox Hills, Lewis and

Mesaverde formations (previous page, right).

Previously, wells were completed with 412-, 5- or

7-in. casing and stimulated using conventional

staged fracturing treatments.

A common practice was to stimulate zones

from the bottom upward until production rates

were satisfactory. As a result, thin zones often

were ignored and undeveloped uphole potential

existed throughout the field. In 1999, TEPI evalu-ated bypassed pay in the field to identify and rank

workover potential based on reservoir quality,

cement integrity, completion age and wellbore

integrity. New drilling locations were identified

after a successful workover on Duncan Unit 1

Well 3, but the challenge was to develop a strat-

egy that could effectively stimulate all of the pay

zones during initial completion operations.

The operator chose CoilFRAC services to

selectively stimulate Wasatch and Fort Union

sands, which comprise multiple sands from 5 to

60 ft [1.5 to 18 m] thick from 2000 to 4000 ft [600

to 1200 m] deep. This approach provided flexibil-

ity to design optimal fracture treatments for each

zone rather than large jobs to intersect multiple

zones over longer intervals.

In the first drill well, individual CoilFRACtreatments were performed on 13 zones in three

days. Seven zones were treated in a single day.

This wells average first month production was

2.3 MMcf/D [65,900 m3/d]. The second drill well

involved eight treatments in one day. Average

production from the second well during the first

month was 2 MMcf/D. Treating pressures ranged

from 3200 psi [22 MPa] to the maximum allow-

able 7000 psi [48 MPa].

Zones separated by 10 to 15 ft [3 to 4.6 m

were fractured with no communication between

stages. Pump-in tests verified that fracture gradi

ents between zones varied from 0.73 to 1 psi/f

[16.5 to 22.6 kPa/m]. The variation in fracture

gradient for each zone confirmed the difficulty o

stimulating multiple zones with conventiona

stage treatments (above). In addition to eigh

workovers with mixed success, nine successfu

10. Pessin JL and Boyle BW: Accuracy and Reliability ofCoiled Tubing Depth Measurement, paper SPE 38422,presented at the 2nd North American Coiled TubingRoundtable, Montgomery, Texas, USA, April 1-3, 1997.

11. DeWitt M, Peonio J, Hall S and Dickinson R:Revitalization of West Hiawatha Field Using Coiled-Tubing Technology, paper SPE 71656, presented at theSPE Annual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 30-October 3, 2001.

> Evaluating single-stage Hiawatha field fracture stimulations. Without selective isolation of individuasands, variations in fracture gradients make it difficult to optimize fracture lengths with a single con-ventional treatment and limited-entry perforating. For two Wasatch zones that would be grouped when

stimulating multiple intervals with a single treatment, StimCADE hydraulic fracturing simulator plotsindicate that about two-thirds of the proppant is placed in the upper interval (top). This results in awider, more conductive fracture and a half-length almost 50% greater than in the lower interval(bottom). If there are more than two zones, this problem is further compounded by variations in dis-continuous sands from wellbore to wellbore.


13/18

wells were drilled in Hiawatha field from May

2000 through July 2001. These new wells were

completed with CoilFRAC stimulations in the

Wasatch and Fort Union formations, and conven-

tional fracture treatments for the more continu-

ous Fox Hills, Lewis and Mesaverde intervals

below 4000 ft [1220 m].

To quantify coiled tubing stimulation results,

the CoilFRAC completions were compared with

wells fractured conventionally between 1992 and

1996 (right). Average production from CoilFRAC

completions increased 787 Mcf/D [22,500 m3/d],

or 114%, above historical rates. However, pro-

duction from individual wells may be misleading

if reserves are drained from offset wells. Field

output will not increase as expected when there

is interference between wells; natural pressure

depletion should result in new wells producing

less, not more.

From 1993 to 1996, Hiawatha field output

increased from 7 to 16 MMcf/D [200,500 to

460,000 m3/d] as a result of the 12-well drilling

program. Production doubled again from 11 to22 MMcf/D [315,000 to 630,000 m3/d] as a result

of workovers and new wells completed mostly

with coiled tubing-conveyed stimulations. Field

production is at the highest level in 80 years.

Stimulating each zone individually during initial

completion operations is believed to be the key

to improving production and increasing reserve

recovery in this mature field.

State-of-the-Art Downhole Tools

Isolation tools have evolved along with CoilFRAC

treatments and specific requirements generated

by various stimulation applications. Coiled tubing-conveyed fracturing operations are performed

under the most dynamic reservoir stimulation

conditions. Treatments take place in live wells at

formation temperatures and pressures, and with

the completion of each selective stimulation,

these conditions change. As a result, increasingly

demanding applications in deeper wells require

more reliable, multiple-set isolation tools.

Driven by a need to minimize operational and

financial risks and reduce the impact of

unplanned events, like proppant screenout,

Schlumberger developed the CoilFRAC Mojave

line of downhole tools (next page). This improvedstraddle system consists of three technologies

the pressure-balanced disconnect, the modular

straddle assembly with ported sub, and the slurry

dump valve. In combination, these components

provide selective placement of sequential acid or

proppant fracture stimulations, and matrix acid,

screenless sand-control or scale-inhibitor treat-ments in a single trip with coiled tubing.

The pressure-balanced disconnect features a

mechanical shear disconnect that is pressure-

balanced to coiled tubing treating pressure. Only

mechanical coiled tubing loads are transferred to

the shear-release pins; treating pressure does

not affect the shear-pin release function. This

reduces the likelihood of leaving the tool in a

well as a result of unexpectedly high downhole

treating pressures during CoilFRAC stimulations,

such as a screenout. The pressure-balanced dis-

connect allows coiled tubing to be run deep

because the disconnect does not require extrashear pins to account for pressure loads during

treatments. If the tool becomes stuck, it can be

fished by overshot or internal fishing neck.

The CoilFRAC Mojave isolation tool has

opposing elastomer cups for 412- to 7-in. casing.

The tool functions in vertical or horizontal wells

and has no mechanical slips and no moving parts.

An internal fluid bypass in the tool body permits

running to deeper depth10,000 ft instead of

less than 4000 ft. This feature lightens coiled

tubing loads during trips in and out of wells to

reduce elastomer wear, minimize swab and surge

forces on formations and decrease the risk of atool sticking between zones. A modular design

and special 2-ft [0.6-m] ported fracturing sub

allow 4-ft sections to be assembled for spacing

elastomer cups up to 30 ft apart.

The CoilFRAC fracturing sub also includes afluid bypass and resists erosion when pumping

up to 300,000 lbm [136,100 kg] of sand. It is pos-

sible to pump up to 500,000 lbm [226,800 kg] of

less erosive resin-coated and man-made

ceramic proppants. Reverse circulation is

required to clean the coiled tubing and CoilFRAC

Mojave isolation tool when run without a slurry

dump valve. A lower reversed bottom cup

seals during reverse circulation to improve

post-treatment cleanup. A gauge port is built

into the tool for downhole pressure and temper-

ature measurements.

Since the slurry dump valve (SDV) is flow-operated, no coiled tubing movement is required.

One SDV design in two sizes is compatible with

standard 412- to 7-in. CoilFRAC Mojave tools

and functions in vertical or horizontal wells.

Incorporating a SDV allows slurry to be dumped

from the coiled tubing between zones and facili-

tates stimulations in low-pressure reservoirs and

formations with fracture gradients of less than a

full water gradient, or 0.4 psi/ft [9 kPa/m].

The SDV is closed and acts as a fill valve

when running in a well. It also reduces formation

damage during multizone well treatments.

Reverse circulation is not required for coiled tub-ing cleanup, which reduces total stimulation fluid

requirements, eliminates the environmental

impact of slurry returned to surface, reduces

elastomer wear by equalizing pressure across

elastomer seal cups, and reduces abrasive wear

on coiled tubing and surface equipment.

72 Oilfield Review

> Analyzing Hiawatha field coiled tubing fracturing results. Production fromwells completed with CoilFRAC selective isolation and simulation treatments(red) was compared with production from wells that were previously frac-tured conventionally (black). Average daily well rates for each month wasnormalized to time zero and plotted for the first six months. Initial productionfrom the CoilFRAC completions was about 787 Mcf/D [22,500 m3/d], or 114%,more than historical rates.


14/18

Autumn 2001 73

Optimizing Recovery in South Texas

Samedan Oil Corporation operates North Rincon

field in south Texas, producing gas from various

zones of the Vicksburg formation at 6000 to

7000 ft [1800 to 2100 m]. The Martinez B54 wel

completed in a single 25-ft [7.6-m] zone, had an

initial production rate of 4.5 MMcf/D before

declining to 1 MMcf/D. In December 2000

Samedan evaluated fracturing this zone for the

first time as well as completing deeper pay in the

Martinez B54 well. Openhole logs had identified

several other productive zones that had been

intentionally bypassed because of marginal eco

nomics. In February 2001, Schlumberger assem

bled a multidisciplinary team to integrate

petrophysical and reservoir knowledge with

completion design, execution and evaluation

services using the PowerSTIM stimulation opti

mization initiative.12

Samedan and the PowerSTIM team analyzed

well data to determine reservoir size and remain

ing reserves for the current producing zone

These calculations indicated a 19-acre [7700-m2

drainage area and confirmed that a nearby geo

logic unconformity acted as a seal. Production

and NODAL analyses matched the 1-MMcf/D

production and indicated that, based on a limited

drainage area and low formation damage

remaining reserves could be recovered in a

few months.13 This interval was not a candidate

for stimulation.

Samedan decided to deplete the existing

zone before completing the most attractive

bypassed zones. Reinterpreted logs indicated

77 ft [23 m] of high-quality net pay with signifi

cant recoverable reserves in five deeper zonesover 700 ft [213 m] of gross interval

Conventional stimulation techniques required

limited-entry perforating for diversion of large

fluid and proppant volumes pumped at high rates

to cover and fracture this entire interval.

The operator considered setting production

tubing and a packer below existing perforations

and completing only one or two of the uppermos

bypassed zones. This approach, however, would

leave a significant volume of additional reserves

untapped behind pipe. The PowerSTIM team rec

ommended CoilFRAC selective isolation services

with optimized fracture designs to complete andindividually stimulate all five bypassed zones. A

2-in. coiled tubing string was selected to convey

fracturing fluids and proppant at the required

rates. An SCMT Slim Cement Mapping Tool log

confirmed cement integrity and adequate zona

isolation behind pipe across the proposed

completion intervals. The existing perforations

were sealed with a cement squeeze prior to

CoilFRAC operations.

12. Al-Qarni AO, Ault B, Heckman R, McClure S, Denoo S,Rowe W, Fairhurst D, Kaiser B, Logan D, McNally AC,Norville MA, Seim MR and Ramsey L: From ReservoirSpecifics to Stimulation Solutions, Oilfield Review12,no. 4 (Winter 2000/2001): 42-60.

13. NODAL analysis couples the capability of a reservoir toproduce fluids into a wellbore with tubular capacity toconduct flow to surface. The technique name reflectsdiscrete locationsnodeswhere independent equa-tions describe inflow and outflow by relating pressure

> CoilFRAC Mojave isolation tools. From single mechanical packers to elas-tomer cup and packer combinations and the earliest versions of opposingelastomer-cup straddle tools, the suite of CoilFRAC tools has expanded toinclude specially designed straddle assemblies. The effectiveness of CoilFRACstraddle assemblies for zonal isolation has been aided by more reliable seal-ing technologies. An annular flow path within the assembly allows for easydeployment and retrieval.

losses and fluid rates from outer reservoir boundariesacross the completion face, up production tubing andthrough surface facility piping to stock tanks. Thismethod allows calculation of rates that wells are capa-ble of delivering and helps determine the effects of dam-age, or skin, perforations, stimulations, wellhead orseparator pressure and tubular or choke sizes. Futureproduction also can be estimated based on anticipatedreservoir and well parameters.


15/18

In May 2001, Samedan and Schlumberger

performed a five-stage CoilFRAC selective

stimulation (next page, top). On the first day, the

five zones were perforated with deep-penetrat-

ing PowerJet premium charges to maximize

perforation entry-hole size and reservoir penetra-

tion. After perforating, the commingled zones

produced 1.1 MMcf/D [31,500 m3 /d] during a

prestimulation test.

On the second day, each zone was isolated

sequentially with a 5-in. CoilFRAC Mojavestraddle tool and fracture-stimulated with a non-

damaging ClearFRAC fluid and 136,000 lbm

[61,700 kg] of man-made ceramic proppant. All

five zones were treated within a 24-hour period.

Pump rates ranged from 8 to 10 bbl/min [1.3 to

1.6 m3 /min] with treating pressures up to

11,000 psi [76 MPa]. Because of potentially high

gas production rates, PropNET fiber additives

were incorporated at the end of the pumping

schedules to prevent proppant flowback.14

When all the zones were commingled and

tested, the well flowed more than 5.1 MMcf/D

[146,000 m3/d] and 120 B/D [19 m3/d] of conden-sate, which closely matched production predic-

tions. A production log spinner survey indicated

that four of the five Vicksburg zones had been

stimulated successfully (above and left). One month

later, the well was still producing about 5 Mcf/D,

which did not follow the expected decline.

Estimated payout was three months. Samedan

engineers evaluated the next three drill wells, but

none of these new wells were viable candidates

for coiled tubing-conveyed fracture stimulation.

Completing five zones in a single trip miti-

gated the risk of formation damage from multiple

well interventions, and risk of fluid swabbingassociated with conventional fracturing opera-

tions, jointed tubing and standard downhole

tools. This CoilFRAC treatment took only two

days, while a conventional five-stage fracturing

job might have taken up to two weeks.

74 Oilfield Review

< Martinez B54 well CoilFRAC treatment stimulation results for five zones.


16/18

Autumn 2001 75

Additional Applications

The combination of reservoir-stimulation and

well-treatment technologies with coiled tubing

conveyance is expanding selective CoilFRACtechniques to include applications, like acid frac-

turing, and specialized completion techniques

such as scale inhibition, controlling proppant

flowback and screenless sand control (above).

With advances in friction-reducing fluids,

injection rates are sufficient for coiled tubing

and CoilFRAC tools to be used as mechanical

diversion during acid fracturing. This capability is

increasingly important in mature carbonate

reservoirs when small zones within larger pro-

ducing intervals require stimulation. CoilFRACstimulations help operators deplete reserves uni-

formly across an entire hydrocarbon-bearing

interval and facilitate reservoir management.

The downhole buildup of scales, asphaltenes

or migrating fines and the plugging of perforations

and completion equipment impair permeability

and can restrict or prevent production altogether.

Accurate CoilFRAC selective placement allows

scale inhibitors to be conveyed deeper into the for

mation during fracturing or acidizing stimulation

treatments. Integrating scale inhibitors and stimu

lation treatment fluids into a single step ensures

that the entire productive intervalincluding the

proppant packis treated.

Performing multiple, smaller fracture treat

ments is another approach to reduce scale

buildup and sand production. This method

reduces the pressure drop across the formation

face, which decreases or, in some cases, pre

vents scale and asphaltene formation. During

production, pressure drawdown increases the

vertical stress on producing intervals and exacer

bates sand production. An alternative is to trea

smaller intervals and reduce the pressure drop

across the formation face.

Screenless Sand-Control Completions

Innovative screenless completions provide sand

control without the need for downhole mechani

cal screens and gravel packing by using technologies such as resin-coated proppants and

PropNET fibers to control proppant flowback and

sand production. The primary challenge of apply

ing screenless technology is ensuring coverage

of all perforated pay zones. In general, interva

length is the controlling factor. Thicker intervals

typically reduce treatment success rates. Coiled

tubing-conveyed fracturing, with the capability o

treating numerous zones, increases screenless

completion effectiveness and reduces overal

costs while increasing net pay potential

Treatments in North America have reduced prop

pant flowback by five-fold.PT. Caltex Pacific Indonesia, a ChevronTexaco

affiliate, operates the Duri field in the Centra

Sumatra basin.15 Primary recovery is low, so

steam injection is used to achieve higher recov

ery factors. This multibillion-barrel steamflood cov

ers 35,000 acres [14 million m2] and produces

280,000 B/D [44,500 m3 /d] of high-viscosi

crude oil. Oil-bearing sands are highly unconsoli

dated, Miocene-age formations with permeability

14. Armstrong K, Card R, Navarrete R, Nelson E, Nimerick KSamuelson M, Collins J, Dumont G, Priaro M, Wasylycia Nand Slusher G: Advanced Fracturing Fluids ImproveWell Economics, Oilfield Review7, no. 3 (Autumn 1995):34-51.

15. Kesumah S, Lee W and Marmin N: Startup of ScreenlessSand Control Coiled Tubing Fracturing in Shallow,Unconsolidated Steamflooded Reservoir, paper SPE74848, prepared for presentation at the SPE/ICOTACoiled Tubing Conference and Exhibition, Houston,Texas, USA, April 9-10, 2002.

> Martinez B54 well in the North Rincon field, south Texas (Courtesy of Samedan Oil Corporation).

> Unconventional coiled tubing-conveyed treatments. CoilFRAC treatments also are applicable forchemical scale inhibition and sand-control methods. Coiled tubing places scale inhibitors included in apreflush before fracturing or proppant impregnated with scale inhibitors more effectively than conven-tional treatment techniques ( left). Novel screenless completions provide sand control without down-hole mechanical screens and gravel packing by using technology like resin-coated proppants andPropNET fibers to control proppant flowback and sand production (right). The primary challenge ofapplying these techniques is ensuring coverage of all perforated pay zones.


17/18

as high as 4000 mD (right). Combined pay thick-

ness is about 140 ft [43 m] over an interval from

X430 to X700 ft. In addition to 3600 producing

wells, the operator maintains about 1600 steam-

injection and temperature-observation wells.

Heat requirements are lower in temperature-

mature areas where the steamflood has been in

operation for an extended period of time. Steam

injection can be reduced, allowing the operator

to convert injectors and observation wells into

producers. Low reservoir pressure causes

drilling, completion and production problems

including lost circulation, hole collapse and sand

production. Severe sanding leads to frequent

well servicing to replace worn or stuck artificial-

lift equipment. The marginal nature of these

wells, initially completed with 4-, 7-, or 958-in. OD

monobore casing, limits conventional gravel-

packed screens for sand control. In most wells,

screens are not installed because of restricted

wellbore access, smaller pump sizes and, conse-

quently, unfavorable production rates.

In a recent field test on several wells, theoperator in Duri field used CoilFRAC techniques

to perform screenless completions using curable

resin-coated sand and tip-screenout fracture

designs to prevent proppant flowback and migra-

tion of formation grains.16 After resin-coated sand

is placed and cured, proppant packs are locked

in place to create a stable filter against the

formation in perforation tunnels and near-

wellbore regions.

Using resin-coated proppant to control sand

without mechanical screens is not new. In 1995, a

Duri field pilot project used conventional fractur-

ing with resin-coated sand to complete Rindusands at about X450 ft. Single-stage tip-scree-

nout treatments attempted to place resin-coated

proppant in multiple zones across 50 to 100 ft [15

to 30 m] of gross interval. This technique failed to

achieve acceptable results because the gross

intervals were too long and not all perforations

received resin-coated sand. In addition, produced

formation sand covered some lower zones and

steam injection did not cure the resin-coated sand

across the entire section.

The primary objectives of the most recent

field test were to ensure complete treatment

coverage of all perforations and achieve tip-screenout fractures for proper proppant packing.

Grain-to-grain contact and closure stress improve

the curing process and ensure a strong com-

pacted filter medium. Heat or alcohol-base fluids

cure phenolic resins. The operator uses both

methods to ensure a complete resin set.

CoilFRAC selective isolation and treatment

placement provided accurate and complete per-

foration coverage, which made screenless

completions a viable alternative to gravel

packing or frac packing with screens, and

previous screenless completions that were

attempted conventionally.

Fracture treatments and pumping schedules

were designed to achieve required fracture half-

length and conductivity. Relatively low pumping

rates control vertical coverage, while higher

proppant concentrations are needed to ensure

fracture conductivity and achieve tip screenout.

The maximum rate is usually about 6 bbl/min

[1 m3 /min] with proppant concentrations of

8 pounds of proppant added (ppa). The number of

treatment stages in a given well was determinedby evaluating perforated interval length and

spacing between zones.

Interval length needed to be less than 25 ft to

ensure complete coverage with a minimum of 7 ft

[2 m] between intervals to allow the isolation

tool to set properly. The operator verified cement

bond and quality to ensure isolation behind the

pipe and avoid proppant channeling. Extra resin-

coated sand deposited after each treatment iso-

lated that interval from subsequent treatment

intervals. After all zones were treated, the oper-

ator left the well undisturbed for about 12 hours

to allow the resin to set and obtain adequate

strength. Partially cured resin-coated sand in the

wellbore was drilled out prior to production.

With the exception of one well, screenless

completions significantly increased cumulative

oil production during nine months of evaluation

(next page, left). Average failure frequency

before CoilFRAC screenless completions was 0.5

per well per month. The operator allocated 36 rig

days and 32,000 bbl [5080 m3] of deferred oil pro-

duction for all four wells to clean out sand. After

CoilFRAC screenless treatments were performed,failure frequency dropped to 0.14 per well per

month, resulting in an extra five months of oil

production per well per year. Screenless

76 Oilfield Review

16. In standard fracturing, the fracture tip is the final areato be packed with proppant. A tip-screenout designcauses proppant to pack, or bridge, near the end of thefractures in early stages of a treatment. As additionalproppant-laden fluid is pumped, the fractures can nolonger propagate deeper into a formation and begin towiden or balloon. This technique creates a wider, moreconductive pathway as proppant is packed back towardthe wellbore.

> Duri field, Indonesia, producing horizons and typical well completion.


18/18

CoilFRAC treatments paid out in 35 to 59 days.

However, the use of resin-coated sand in

extremely hot steamflood conditions was found

to have limitations.

Early in the application of screenless comple-

tions, the operator recognized a need to use inert

proppant flowback control. The resin coating used

initially in CoilFRAC screenless completions was

thermally stable to 375F [191C], but could fail in

steam environments of 400F [204C]. As a result,

periodic steam injection and flowback to stimu-late oil output could cause stress cycling and

proppant-pack failure that resulted in sand pro-

duction. Proppant flowback control using PropNET

fibers rated to 450F [232C] is proving to be a

solution to this problem.

The operator selected a local sand combined

with PropNET fibers in place of resin-coated sand

for eight recent screenless completions in Duri

field. The PropNET fibers were added throughout

sand-laden treatment stages to ensure complete

interval coverage. Optimized perforating tech-

niques also has been introduced for screenless

sand control. These wells have minimal production

data, but early production results are encouraging.

Milestones in Selective Stimulations

Selective coiled tubing-conveyed isolation and

stimulation have established a template for

future workovers on existing wells and new well

completions. The CoilFRAC methodology allowscontrolled delivery and accurate placement of

treatment fluids and proppant in existing or

bypassed pay intervals at little or no additional

cost because decreased fluid volumes and elimi-

nation of redundant operations reduce mobiliza-

tion, equipment and material charges.

CoilFRAC treatments are useful for fracturing

bypassed single or multiple zones, protection of

casing and completion equipment, and for

development of coalbed methane reserves. This

technique is also valuable in settings where

chemical inhibition, reservoir flow-conformance

modifications, water-control or sand-contro

methods may be required. Schlumberger has

pumped more than 12,000 CoilFRAC fracture

stimulations in more than 2000 wells. Coiled tub

ing-conveyed treatments can now be performed

in vertical, high-angle and horizontal wells with

measured vertical depths up to 12,200 ft [3720 m]

Pumping rates can range from 8 to 25 bbl/min

[1.3 to 4 m3/min] with 5 to 12 ppa of proppant.

Coiled tubing-conveyed fracturing was originally developed for multilayered shallow-gas

reservoirs in Canada and further developed in the

USA (above). These CoilFRAC treatments, how

ever, are being refined in applications around the

world, from Indonesia, Argentina and Venezuela

to Mexico and now Algeria.

The largest total volume of proppant placed in

a single wellbore was 850,000 lbm [385,555 kg

for a well treatment in northern Mexico. A well in

southeast New Mexico, USA, was the first hori

zontal well to be fracture stimulated using a

CoilFRAC Mojave tool. Two separate zones a

9123 and 9464 ft [2781 and 2885 m] measureddepth were treated. The deepest CoilFRAC job to

date was recently performed at 10,990 ft [3350 m

for Sonatrach in Algeria. The progress to date in

selective stimulations has been impressive

Continued research and field experience are

expected to further extend the range of application

and reach of this innovative technique. MET

> CoilFRAC screenless completion results in Duri field, Indonesia.

> Ongoing CoilFRAC operations in Medicine Hat,Alberta, Canada.

01-isolate and stimulate individual pay zones

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