-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
1/18
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.
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
2/18
Autumn 2001 6
> A fit-for-purpose CT Express coiled tubing unit performing a selective fracturing treatment in Medicine Hat, Alberta, Canada.
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
3/18
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).
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
4/18
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).
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
5/18
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.
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
6/18
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.
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
7/18
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.
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
8/18
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%.
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
9/18
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).
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
10/18
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.
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
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.
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
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.
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
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.
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
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.
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
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.
-
8/2/2019 01-Isolate and Stimulate Individual Pay 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.
-
8/2/2019 01-Isolate and Stimulate Individual 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.
-
8/2/2019 01-Isolate and Stimulate Individual Pay Zones
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.