estim - combined stimulation and sand control (english)
TRANSCRIPT
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8/18/2019 ESTIM - Combined Stimulation and Sand Control (English)
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30 Oilfield Review
Combined Stimulation and Sand Control
Specialized fracturing treatments in conjunction with gravel packing create highly conductive propped fractures that yield
sustained production increases and control fines migration in weakly consolidated reservoirs. This “frac-packing” method,
which became increasingly popular in the past 10 years, bypasses formation damage and eliminates many productivity
impairments that are common in conventional cased-hole gravel packs.
Frac pack
60%
Viscous-slurry pack
12%
High-ratewater pack
0
5
10
15
Dimensionlessskin
20
25
30
Gravelack
Frac pack
llllllllllllllllllll
1992
2002
> Fracturing for sand control. Initial frac-pack results in the early 1990s indicated improved productivity compared with conventional gravel packing (left ).As a result, frac packing now represents more than 60% of the US sand-control market (top right ), and companies providing stimulation services investheavily in research and development. These investments included construction of purpose-built vessels with high-volume mixing equipment, high-pressurepumps and sophisticated monitoring systems, such as the Schlumberger Galaxy stimulation vessel (center ).
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Syed Ali
David Norman
David Wagner
ChevronTexaco
Houston, Texas, USA
Joseph Ayoub
Jean Desroches
Sugar Land, Texas
Hugo MoralesHouston, Texas
Paul Price
Rosharon, Texas
Don Shepherd
Saudi Aramco
Abqaiq, Saudi Arabia
Ezio Toffanin
Beijing, China
Juan Troncoso
Repsol YPFMadrid, Spain
Shelby White
Ocean Energy
Lafayette, Louisiana, USA
For help in preparation of this article, thanks to ErnieBrown and Leo Burdylo, Sugar Land, Texas, USA; MehmetParlar and Colin Price-Smith, Rosharon, Texas; PedroSaldungaray, Jakarta, Indonesia; and Ray Tibbles, KualaLumpur, Malaysia.
ClearFRAC, CoilFRAC, DataFRAC, FIV (Formation IsolationValve), MudSOLV, PropNET, QUANTUM, SandCADE andScalePROP are marks of Schlumberger. Alternate Path,AllPAC and AllFRAC are marks of ExxonMobil; this technol-
ogy is licensed exclusively to Schlumberger.
Summer 2002 3
Hydraulic fracturing in high-permeability reser-
voirs to stop sand production is an accepted well-
completion technique. Today, one of the first
decisions during development planning for fields
that produce sand is whether or not to frac
pack—a combination of fracture stimulation and
gravel packing. More than a decade of success
proves that compared with conventional gravel
packing, this technique significantly improves
well productivity (previous page).
Frac packing as a percentage of sand-control
treatments and in terms of total jobs is growing
steadily. Use of this technique increased tenfold—
from fewer than 100 jobs per year during the early
1990s to a current rate of almost 1000 each year. In
West Africa, about 5% of sand-control treatments
are frac packs, and operators frac pack at least 3%
of the wells in Latin America.
Advances in stimulation design, well-
completion equipment, treatment fluids and
proppants continue to differentiate frac packing
from conventional gravel packing and fracturing.
US operators now apply this sand-control methodto complete more than 60% of offshore wells.
Shell used the term frac pack as early as 1960
to describe well completions in Germany that
were hydraulically fractured prior to gravel
packing.1 In current usage, frac packing refers to
tip-screenout (TSO) fracturing treatments that
create short, wide fractures and gravel packing
of sand-exclusion screens, both in a single oper-
ation. The resulting highly conductive propped
fractures bypass formation damage and alleviate
fines migration by reducing near-wellbore pres-
sure drop and flow velocity.
An early application of frac packing occurredduring 1963 in Venezuela, where producing com-
panies performed small fracturing treatments
using sand and viscous crude oil and then circu-
lated screens into place downhole through sand
remaining inside the casing.2 This approach
proved successful, but was not applied in other
areas until almost 30 years later.
In the ensuing years, operators used various
fracturing techniques to address drilling and
completion damage that often extends deep into
high-permeability reservoirs. These small “slug
fracture,” or “microfracture,” treatments were
designed to address formation damage that acids
or solvents would not remove and that reperfo
rating could not bypass, especially when perfora
tion-tunnel stability was questionable in weakly
consolidated sands.
Interest in frac packing resurfaced in the early
1980s when operators began to fracture high
permeability formations using TSO techniques.
Wider propped fractures yielded sustained pro
duction increases in the Prudhoe Bay and Kuparuk
fields on the North Slope of Alaska, USA, and in
chalk formations of the North Sea. These results
attracted the attention of producers in othe
areas and prompted evaluation of TSO fracturing
for sand control.
Interest in frac packing increased after 1985
driven by activity in the Gulf of Mexico, where
many conventional gravel packs do not achieveadequate productivity. Induced formation dam
age from drilling or completion fluids, cement fil
trate, overbalanced perforating and fines
migration contribute to unsatisfactory results, as
does mechanical skin damage created by the
redistribution of stresses after drilling.
Formation collapse and sand influx as a result o
incomplete gravel packing around screens o
unpacked perforations also restrict production.
Frac packing reduces pressure drops caused
by formation damage and completion restric
tions, which commonly are represented by a
dimensionless value called skin.5 Unlike gravepacking, frac-pack skin decreases as wells pro
duce and treatment fluids are recovered, and
productivity tends to improve over time
Consequently, the trend among operators is to
apply this technique in most of the wells that
require sand control.
1. McLarty JM and DeBonis V: “Gulf Coast Section SPEProduction Operations Study Group—TechnicalHighlights from a Series of Frac Pack TreatmentSymposiums,” paper SPE 30471, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, October 22–25, 1995.
2. Liebach RE and Cirigliano J: “Gravel Packing inVenezuela,” presented at the Seventh World PetroleumConference, Mexico City, Mexico, 1967, ProceedingsSection III: 407–418.
3. Smith MB, Miller WK and Haga J: “Tip ScreenoutFracturing: A Technique for Soft, Unstable Formations,”paper SPE 13273, presented at the SPE Annual TechnicalConference and Exhibition, Houston, Texas, USA,September 16–19, 1984; also in SPE Production Engineering 2, no. 2 (May 1987): 95–103.
Hannah RR and Walker EJ: “Fracturing a High-Permeability Oil Well at Prudhoe Bay, Alaska,” paperSPE 14372, presented at the SPE Annual TechnicalConference and Exhibition, Las Vegas, Nevada, USA,September 22–25, 1985.
Martins JP, Leung KH, Jackson MR, Stewart DR andCarr AH: “Tip Screenout Fracturing Applied to theRavenspurn South Gas Field Development,” paperSPE 19766, presented at the SPE Annual TechnicalConference and Exhibition, San Antonio, Texas, USA,October 8–11, 1989; also in SPE Production Engineering 7, no. 3 (August 1992): 252–258.
Reimers DR and Clausen RA: “High-PermeabilityFracturing at Prudhoe Bay, Alaska,” paper SPE 22835,presented at the SPE Annual Technical Conference andExhibition, Dallas, Texas, USA, October 6–9, 1981.
Martins PJ, Bartel PA, Kelly RT, Ibe OE and Collins PJ:“Small, Highly Conductive Hydraulic Fractures Near
Reservoir Fluid Contacts: Applications to Prudhoe Bay,”paper SPE 24856, presented at the SPE Annual TechnicalConference and Exhibition, Washington, DC, USA,October 4–7, 1992.
Martins JP, Abel JC, Dyke CG, Michel CM and Stewart G:“Deviated Well Fracturing and Proppant ProductionControl in Prudhoe Bay Field,” paper SPE 24858, pre-sented at the SPE Annual Technical Conference andExhibition, Washington, DC, USA, October 4–7, 1992.
4. Carlson J, Gurley D, King G, Price-Smith C and Walters F:“Sand Control: Why and How?” Oilfield Review 4, no. 4(October 1992): 41–53.
Mechanical skin consists of localized formation damageresulting from redistribution of in-situ stresses after theremoval of rock during the drilling process, especially inextremely permeable reservoirs. Formation stressesoriginally supported by drilled material concentrate near the borehole wall, compressing or crushing the rock
matrix within a cylindrical ring around the wellbore. Thiseffect restricts pore throats and reduces near-wellborepermeability, potentially trapping fine particles thatmigrate toward the well during production.
For more about mechanical skin damage: Morales RH,Brown E, Norman WD, BeBonis V, Mathews MJ, Park EIand Brown R: “Mechanical Skin Damage in Wells,”paper SPE 30459, presented at the SPE Annual TechnicaConference and Exhibition, Dallas, Texas, USA, October22–25, 1995; also in SPE Journal (September 1996): 275–281
5. Negative skin indicates stimulation; positive skin indi-cates damage.
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In the Gulf of Mexico, frac packing became
increasingly popular beginning in the late 1980s.
Amoco, now BP, performed five frac-pack com-
pletions in the Ewing Bank area during 1989 and
1990 by batch mixing up to 6 pounds of proppant
added (ppa) per gallon of treatment fluid.6 In
1991, ARCO, now BP, performed frac packing in
the South Pass area.7 Pennzoil, now Devon
Energy, used this technique in the Eugene Island
area.8 At about the same time, Shell began frac
packing inland wells from barges in Turtle
Bayou field, Louisiana, USA. Later, Shell
expanded the use of this technique in the North
Sea and to offshore wells in Borneo, and also to
onshore wells in Colombia, South America and
northwest Europe.9
Frac-packing success led to increased use,
and this technique soon became the preferred
sand-control method in the Gulf of Mexico,
where several thousand oil and gas leases lie in
water deeper than 3000 ft [914 m]. During 1992,
BP completed frac packs in Mississippi Canyon
Block 109, where water depths range from 850 to1500 ft [260 to 460 m].10 A few years later, Shell
and Chevron used frac packing to develop fields
in water up to 3000 ft deep.
Technology transfer and frac-packing success
in other areas, such as Indonesia, the North Sea,
the Middle East, West Africa and Brazil, are further
expanding the worldwide application of this tech-
nique. Operators plan to frac pack Gulf of Mexico
wells in more than 4000 ft [1220 m] of water, and
in the North Sea and offshore Brazil, intend to push
the frontier of frac packing into water as deep as
6000 ft [1830 m]. Fracture stimulation and frac
packing in high-permeability reservoirs now repre-
sent 20% of the fracturing market.
This article reviews the evolution of frac
packing and discusses developments in stimula-
tion fluids, proppants, downhole equipment,
design simulation, job execution and post-
stimulation evaluation. Case histories illustrate
application of this technique to enhance well
productivity while preventing proppant flowback
and sand production.
Tip-Screenout Fracturing
Gravel packs typically have some degree of
damage—positive skin—and rarely achieve low
skin values consistently. Frac-pack completions,
on the other hand, often result in higher produc-
tivity wells than gravel packs performed below or
above fracture-initiation pressure, either by
slurry packing or high-rate water packing
(HRWP).11
Evaluations of wells completed duringthe past 10 years with these sand-control tech-
niques show the dramatic impact of frac packing
on total completion skin (below).12
The permeability contrast between forma-
tions and propped fractures determines required
fracture length for optimal reservoir stimulation.
In lower permeability reservoirs, there is a large
permeability contrast, and therefore, greater
relative fracture conductivity.13 In high-permeability
reservoirs, there is less contrast, and the relative
conductivity of a narrow fracture is reduced by
several orders of magnitude. This negates the
value of fracture extension away from a well and
underscores the need for wide fractures because
conductivity is also directly proportional to
propped width.
Short, wide fractures stimulate well produc-
tivity even in high-permeability formations.
These highly conductive fractures alleviate sand
production associated with high flow rates, per-
foration collapse in weakly consolidated forma-
tions and fines migration in formations with
poorly sorted grain sizes by reducing near-
wellbore pressure drop and flow velocity. These
factors also defer critical stress conditions that
crush formation grains until a lower reservoir
pressure is reached.
Hydraulic fracturing in low-permeability, or
tight, formations creates narrow propped frac-
tures about 0.1 in. [2.5 mm] wide, extending
1000 ft [300 m] or more from a wellbore (next page,
top left).14
A TSO treatment generates proppedfractures with widths up to 1 in. [2.5 cm] or more
in soft-rock formations and wellbore-to-tip half-
lengths of about 50 ft [15 m], depending on for-
mation characteristics.15 For conventional
treatments, final proppant concentrations in
terms of fracture surface area are less than
2 lbm/ft2 [10 kg/m2]. This contrasts with 5 to
10 lbm/ft2 [24 to 49 kg/m2] concentrations for
TSO designs.
A propped fracture increases completion
radius and area open to flow. Compared with
radial inflow, the resulting bilinear flow pattern
reduces flow convergence and turbulence at theperforations, which enhances productivity. For
example, a propped fracture with a 50-ft half-
length and height of 22 ft [7 m] has 4000 sq ft
[372 m2] of surface area; a gravel-pack comple-
tion in a 9-in. borehole has a maximum surface
area of about 50 sq ft [5 m2] open to radial flow.
The effective completion radius for each of these
hypothetical frac-pack and gravel-pack comple-
tions is 50 ft and 4.5 in. [11.4 cm], respectively.
The tip of a hydraulic fracture is the final area
packed by proppant during conventional fractur-
ing of low-permeability, hard-rock formations. In
contrast, TSO designs limit fracture length, orextension, by achieving fluid-leakoff rates that
dehydrate the proppant slurry early in a treat-
ment. This dehydration causes proppant to pack
off near the peripheral edge, or tip, of a dynamic
fracture. The hydraulic fracture inflates like a bal-
loon as additional proppant-laden fluid is injected,
creating a wider, more conductive pathway as prop-
pant packs toward the well (next page, top right).
32 Oilfield Review
14
12
Frac pack High-ratewater pack
Viscous-slurrygravel pack
10
8
6
Dimensionlessskin
4
2
0
Picture to be added later
> Completion damage. Evaluation of sand-control completions performed in the Gulf of Mexico during the past 10 years show the dramatic impact of fracpacking on dimensionless skin, and therefore, well productivity and ultimatehydrocarbon recovery. Operators report average skins of 12 and 8 for gravel-pack completions performed by viscous-slurry and high-rate water pack(HRWP) techniques, respectively. Frac packing consistently delivers loweraverage skins, typically about 3.
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Summer 2002 33
6. McLarty and DeBonis, reference 1.
7. Hainey BW and Troncoso JC: “Frac-Pack: An InnovativeStimulation and Sand Control Method,” paper SPE 23777,presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 26–27, 1992.
8. Monus FL, Broussard FW, Ayoub JA and Norman WD:“Fracturing Unconsolidated Sand Formations OffshoreGulf of Mexico,” paper SPE 24844, presented at theSPE Annual Technical Conference and Exhibition,Washington, DC, USA, October 4–7, 1992.
Mullen ME, Stewart BR and Norman WD: “Evaluation ofBottom Hole Pressures in 40 Soft Rock Frac-PackCompletions in the Gulf of Mexico,” paper SPE 28532,presented at the SPE Annual Technical Conference andExhibition, New Orleans, Louisiana, USA, September25–28, 1994.
9. Wong GK, Fors RR, Casassa JS, Hite RH andShlyapobersky J: “Design, Execution, and Evaluation ofFrac and Pack (F&P) Treatments in Unconsolidated SandFormations in the Gulf of Mexico,” paper SPE 26563, pre-sented at the SPE Annual Technical Conference andExhibition, Houston, Texas, USA, October 3–6, 1993.
Roodhart LP, Fokker PA, Davies DR, Shlyapobersky J andWong GK: “Frac and Pack Stimulation: Application,Design, and Field Experience From the Gulf of Mexico
to Borneo,” paper SPE 26564, presented at the SPEAnnual Technical Conference and Exhibition, Houston,Texas, USA, October 3–6, 1993.
10. Hannah RR, Park EI, Walsh RE, Porter DA, Black JW andWaters F: “A Field Study of a Combination Fracturing/Gravel Packing Completion Technique on the Amberjack,Mississippi Canyon 109 Field,” paper SPE 26562, pre-sented at the SPE Annual Technical Conference andExhibition, Houston, Texas, USA, October 3–6, 1993; alsoin SPE Production & Facilities 9, no. 4 (November 1994):262–266.
11. Slurry-packing techniques use viscous polymer-basefluids to place high gravel concentrations, while HRWP techniques use lower gravel concentrations transportedin a less viscous fluid, usually brine.
Dynamic fracture
Fracture inflation
Annular opening
Cement
Perforation
Screen
Casing
Propped fracture
“External” proppant pack
Tip screenout
Proppant
> Tip-screenout (TSO) fracturing. In high-permeability reservoirs, fracturestimulations require fluid systems that leak off early in a treatment. Dehydra- tion of the slurry causes proppant to pack off at the fracture tip, halting fur- ther propagation, or extension (top ). As additional slurry is pumped, biwingfractures inflate and proppant packs toward the wellbore (middle ). A TSO treatment ensures wider fractures and improves conductivity by promoting
grain-to-grain contact in the proppant pack. This technique also generatesenough formation displacement to create an annular opening betweencement and formation that becomes packed with proppant. This “external”pack connects all perforations and further reduces near-wellbore pressuredrop (bottom ).
Low-Permeability Formations Bilinear Flow
Proppant Pack
Fracture with viscous fluid
Fracture with viscous fluid
Fracture with water
Fracture with water
High-Permeability Formations
Formation
Proppant embedment
> Fracture geometry. In low-permeability formations, viscous fracturingfluids generate long, narrow fractures; less viscous fluids, such as water,leak off quickly and create shorter fractures ( top left ). Hydraulic fractur-ing increases effective completion radius by establishing linear flow intopropped fractures and dominant bilinear flow to a wellbore (top right ). Inhigh-permeability formations, fracturing treatments create short, wide
propped fractures that provide some reservoir stimulation and mitigatesand production by reducing near-wellbore pressure drop and flowvelocity (bottom left ). In low-strength, or soft, formations, proppant con-centration after fracture closure must exceed 2 lbm/ft2 [10 kg/m2] toovercome proppant embedment in fracture walls (bottom right ).
12. Mullen ME, Norman WD and Granger JC: “ProductivityComparison of Sand Control Techniques Used forCompletions in the Vermilion 331 Field,” paper SPE27361, presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 7–10, 1994.
Monus et al, reference 8.
Fletcher PA, Montgomery CT, Ramos GG, Miller ME and
Rich DA: “Using Fracturing as a Technique forControlling Formation Failure,” paper SPE 27899, pre-sented at the SPE Western Regional Meeting, LongBeach, California, USA, March 23–25, 1994; also in SPE Production & Facilities 11, no. 2 (May 1996): 117–121.
Hannah et al, reference 10.
Papinczak A and Miller WK: “Fracture Treatment Design to Overcome Severe Near-Wellbore Damage in aModerate Permeability Reservoir, Mereenie Field,Australia,” paper SPE 25379, presented at the SPE AsiaPacific Oil & Gas Conference and Exhibition, Singapore,February 8–10, 1993.
Stewart BR, Mullen ME, Howard WJ and Norman WD:“Use of a Solids-Free Viscous Carrying Fluid in FracturingApplications: An Economic and Productivity Comparisonin Shallow Completions,” paper SPE 30114, presented at the SPE European Formation Damage Conference, TheHague, The Netherlands, May 15–16, 1995.
13. Fracture conductivity is a measure of how easily producedor injected fluids flow within a propped hydraulic fracture.
14. Hydraulic fracturing begins with injection of a proppant-free fluid stage, or pad, at pressures above formationbreakdown stress to initiate a crack in the rock andcool-down the near-wellbore region. This pad stage cre-ates two fracture “wings” 180 degrees apart that propa-gate in the preferred fracture plane (PFP). The PFP liesin the direction of maximum horizontal stress, perpendicular to the least horizontal rock stress. Proppant-ladenfluid stages follow to generate a required geometry—height, width and length—and pack the biwing fracturewith proppant. Proppants ensure that a conductive pathway remains open after fluid injection stops anddynamic fractures close.
15. Hanna B, Ayoub J and Cooper B: “Rewriting the Rulesfor High-Permeability Stimulation,” Oilfield Review 4,no. 4 (October 1992): 18–23.
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Fracture conductivity and reservoir stimula-
tion do not account for all of the resulting pro-
ductivity increase. Another factor is elimination
of flow restrictions through the perforations.
Aggressive frac packing opens a dynamic frac-
ture up to 2 in. [5 cm] wide across all or most of
the completion interval. The principles of rock
mechanics dictate that the amount of subsurface
movement required to generate wide TSO
fractures also must create an annular opening
outside of the cement sheath. This opening then
is packed with proppant to form a ring, or “halo,”
around the wellbore.
This “external” pack provides a more effec-
tive hydraulic connection between propped frac-
tures and all the perforations, which further
reduces pressure drop across completion inter-
vals. Computer simulations indicate that perfora-
tions that are not aligned with propped fracture
can contribute up to 50% of fluid flow into a well-
bore in high-permeability formations (below).16
The proppant halo is a key factor in frac-pack
success and the basis for screenless completionsthat control sand without mechanical screens
and internal gravel packs (see “Emerging
Technologies,” page 45 ).
Frac packing is a frontline defense against
sand production, and properly designed TSO
fracturing treatments are vital to the success of
this important well-completion technique.
Conventional cased-hole gravel packs often
experience progressive loss of productivity, but
production from properly designed and executed
frac packs tends to improve over time as treat-
ment fluids are recovered and wells clean up.17
Treatment Execution
Initially, operators performed frac packing in mul-
tiple steps—a TSO fracturing treatment followed
by wellbore cleanout, installation of sand-exclu-
sion screens and separate gravel-packing opera-
tions.18 However, high positive skins and limited
productivity indicated damage between the
propped fracture and internal gravel pack. Frac
packing was simplified into a single operation to
further improve well production and reduce oper-
ational costs.19 The TSO fracturing treatment now
is pumped with screens in place. Gravel packing
of screen assemblies is accomplished at the end
of a treatment.
Like conventional gravel packing, fluids and
proppants for frac packing are injected through
tubing and a gravel-pack packer with a service
tool in squeeze or circulating configuration (right).
However, to withstand higher pressures during
TSO fracturing, service companies adapted stan-dard gravel-packing assemblies. Modifications
include increased metal hardness, larger cross-
sectional flow areas and minimizing sudden
changes in flow direction to reduce metal erosion
by fluids and proppants.
Squeeze configuration is used for most frac-
pack treatments, especially in wells with produc-
tion casing that cannot handle high pressures.
Circulating position provides a path for fluid
returns to surface through the tubing-casing
annulus, or communication—a “live” annulus—
to monitor pressure at surface independent of
friction in wellbore tubulars, depending on
whether the annular surface valve is open or
closed. Friction pressures generated by pumping
proppant-laden slurry through tubing and com-
pletion equipment often mask true downhole
pressure responses when monitoring treating
pressure on the tubing.
34 Oilfield Review
100
Flow
throughfracture,%
0100 1000
Permeability, mD
10,000
20
40
60
80
Unaligned perforations
Propped fracture
> Perforation contributions. Inflow is not limited to the propped fracture cross-sectional area and perforations aligned, or connected, with the fracture wings.Computer simulations indicate that unaligned perforations contribute almost50% of the inflow from high-permeability formations, underscoring the impor- tance of TSO fracturing and creation of an external pack.
QUANTUMgravel-pack packer
Mechanical fluid-losscontrol device
Washpipe
Screens
Perforations
Screens
Perforations
Ball seat
Ball valve
Fluid flow
Crossover ports
Service tool
Annular BOP
Annulus surface valveand pressure gauge
Circulating ports
Temperature andpressure gauge
Bottom packer
> Downhole tools. In gravel packing and fracpacking, a service tool directs fluid flow througha gravel-pack packer and around the screenassembly. Squeeze configuration is establishedby closing the annular blowout preventer (BOP)and the tubing-casing annulus surface valve
(left ), or by closing the ball valve downhole(right ). Shutting in the annulus with the downholeball valve open allows bottomhole pressure to bemonitored independent of friction in the tubing.Closing the downhole valve prevents fluid returns to surface and protects weak casing from highpressures; pressure also can be applied to theannulus to offset high pressure in the tubing.Mechanical devices such as flapper valves or the FIV Formation Isolation Valve system preventexcess fluid loss into formations after the service tool is retrieved.
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Summer 2002 35
Early service tools used a conventional check
valve, which prohibited pressure declines from
being observed after fracturing. More recent
designs of QUANTUM gravel-pack packer tools
eliminate the check valve, replacing it with an
improved downhole ball valve that allows pres-
sure fluctuations to be monitored in real time dur-
ing treatments when the ball valve is open. A live
annulus allows more accurate evaluation
of treatments.20
Frac packing usually begins in squeeze con-
figuration. After tip screenout occurs, establish-
ing circulating configuration ensures complete
packing of the screens and grain-to-grain prop-
pant contact. The service tool then is shifted to
clean out excess slurry by pumping fluid down
the annulus and up the tubing. The amount of
upward movement required to shift some service
tools pulls reservoir fluids into a wellbore. This
swabbing effect can bring formation sand into
perforation tunnels before a fracture is com-
pletely packed or reduce conductivity between
fractures and the internal gravel pack, which canlimit frac-pack productivity.
Set-down service tools, such as the
QUANTUM gravel-packing system, close the
downhole ball valve and shift tool configuration
with upward movement. This type of tool also is
used for deep completions and treatments con-
ducted from floating rigs or drillships.
In addition to a variety of reservoir conditions
and of fracturing and gravel-packing requirements,
treatment execution must address the complexity
of completing multiple zones and long intervals.
Even the best frac-pack designs end in failure if
excess fluid loss into formation causes proppantbridges to form between screens and casing,
restricting or blocking annular flow. Annular prop-
pant packoff, or bridging, results in early treatment
termination, low fracture conductivity and an
incomplete gravel pack around screens.
Placing proppant with sand-exclusion screens
in place requires close attention to annular clear-
ances. As frictional pressure increases, there is
potential for fluid from slurry in the screen-casing
annulus to pass through the screens into the
washpipe-screen annulus. Fluid bypass worsens
as the slurry dehydrates, and proppant concentra-
tion increases to an unpumpable state, causingproppant to bridge in the screen-casing annulus.
Annular blockage near the top of a comple-
tion interval prevents continued fracturing of
deeper zones or zones with higher in-situ stress
and inhibits subsequent packing of the screens.
Even a partial flow restriction in the annulus
increases frictional pressure drop, restricts rate
distribution and limits fracture-height growth
across the remainder of the completion interval.
Annular voids below a proppant bridge increase
the likelihood of screen failure from erosion by
produced fluids and fine formation sand.
For homogeneous reservoirs where pay inter-
vals are less than 60 ft [18 m] thick, fracture-
height growth typically covers the entire zone. In
longer intervals, the probability of complete frac-
ture coverage decreases, and risk of proppantbridging increases dramatically. Long intervals
can be split into stages and treated separately.
This requires more downhole equipment, such as
two stacked frac-packing assemblies, and addi-
tional installation time, but increases frac-pack-
ing effectiveness (see “Conventional and
Alternate Path Screens,” next page ).
Alternate Path technology is also available to
gravel pack and frac pack longer intervals (right).
AllFRAC screens use hollow rectangular tubes, or
shunts, welded on the outside of screens to pro-
vide additional flow paths for slurry. Exit ports
with carbide-strengthened nozzles located alongthe shunt tubes then allow fluids and proppant to
exit below annular restrictions, which allows
fracturing and annular packing to continue after
restrictions form in the screen-casing annulus.
AllFRAC screens for frac packing use slightly
Screen
Basepipe
Fracture
Shunttubes
Nozzle
Casing
Shunt tubes
Perforations Screens
Annularproppant bridge
Void
Nozzle
> Alternate Path technology. Proppant bridges, ornodes, that form in the screen-casing annulus,commonly as a result of slurry dehydration orpremature fracture screenout in zones withlower in-situ stress, cause early treatment termi-nation. In wells with conventional sand-exclusionscreens, this limits fracture height and frac-packefficiency. Alternate Path technology uses shunt tubes with strategically located exit nozzleswelded on the outside of conventional screens(top and middle ). Shunt tubes provide a flow pathfor slurry that bypasses annular restrictions to
allow continued treating of lower intervals andpacking of voids around the screens (bottom ).
16. Burton RC, Rester S and Davis ER: “Comparison ofNumerical and Analytical Inflow Performance Modellingof Gravelpacked and Frac-Packed Wells,” paper SPE31102, presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 14–15, 1996.
Guinot F, Zhao J, James S and d’Huteau E: “ScreenlessCompletions: The Development, Application and FieldValidation of a Simplified Model for Improved Reliability
of Fracturing for Sand Control Treatments,” paper SPE68934, presented at the SPE European FormationDamage Conference, The Hague, The Netherlands,May 21–22, 2001.
17. Stewart BR, Mullen ME, Ellis RC, Norman WD and MillerWK: “Economic Justification for Fracturing Moderate to High Permeability Formations in Sand ControlEnvironments,” paper SPE 30470, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,Texas, USA, October 22–25, 1995.
18. Monus et al, reference 8.
19. Hannah et al, reference 10.
20. Mullen et al, reference 8.
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larger shunt tubes than AllPAC screens for gravel
packing to accommodate higher injection rates
for fracturing.
Shunt tubes provide conduits for slurry to
bypass collapsed hole and external zonal isola-
tion packers as well as annular proppant gravel
bridges at the top of intervals or adjacent to
higher permeability zones with high fluid leakoff.
If annular restrictions form, injection pressure
increases and slurry diverts into the shunt tubes,
the only open flow path. This ensures fracture
coverage and complete gravel packing around
screens across an entire perforated interval.
Conventional and Alternate Path Screens
In the late 1990s, Saudi Aramco chose frac pack-
ing to control sand in oil wells about 200 km
[124 miles] southeast of Riyadh, Saudi Arabia
(below).21 This new field in the Central Province
encompassed two heterogeneous Permian-age
reservoirs comprising high-permeability sand-
stones at 8700 to 9000 ft [2650 to 2740 m] that
are interbedded with shale and siltstone.The deeper B reservoir was a high-quality
sandstone interbedded with thin, low-permeabil-
ity siltstone. Reservoir thickness varied from 20
to 65 ft [6 to 20 m]. Well tests indicated perme-
ability from 0.5 to 2 darcies; air-derived core per-
meabilities were 3 to 4 darcies. The A reservoir
was a sequence of slightly more heterogeneous
individual sandstones between lower permeabil-
ity siltstone strata. This overlying reservoir was
up to 200 ft [61 m] thick with net pay up to 75 ft
[23 m]. Permeabilities from well tests were 0.1 to
2.5 darcies; air-derived core permeabilities were
about 2 darcies.
A well completed without sand-control mea-
sures produced for less than six months before
sand influx and suspected perforation collapse
stopped production. If completion practices
induced a significant pressure drop downhole, it
would be difficult to control sand at oil rates and
wellhead pressures that met production targets
while allowing wells to flow naturally into exist-
ing facilities 50 km [31 miles] away. Frac packing
satisfied well-completion requirements for both
the A and B reservoirs.
Long completion intervals necessitated differ-
ent frac-packing techniques for each reservoir(next page, top). Saudi Aramco used conventional
screens in the B reservoir where pay zones were
less than 60 ft thick. For longer perforated inter-
vals in the A reservoir, the operator chose
AllFRAC Alternate Path screens with three shunt
tubes, each designed for 6 bbl/min [1 m3 /min], to
achieve required injection rates (next page, bottom).
Wells with an oil-water contact near the bot-
tom perforations required close control of frac-
ture height to avoid early water breakthrough. In
other wells, perforations extended over long
intervals and individual zones were spaced far
apart. Engineers selected a stacked-screen com-
pletion to meet frac-packing objectives in these
wells. Dividing the productive interval into two
sections allowed Saudi Aramco to optimize treat-
ment designs for each zone and avoid fracturing
into water-bearing zones.
Typically, these frac-packing treatments
included the pad, an initial low-concentration
stage with 0.5 lbm/gal [0.06 kg/L], or pounds of
proppant added (ppa) per gallon of fracturing
fluid, and additional proppant stages ramped up
to 3, 6 or 9 ppa [0.36, 0.72 or 1 kg/L]. In a few
wells, 9-ppa stages were pumped successfully.
Higher proppant concentrations were difficult to
place in more permeable zones, but placing 3 and6 ppa in the formation yielded good results.
Saudi Aramco and Schlumberger modified ini-
tial fracturing designs based on minifracture
analysis using the Schlumberger DataFRAC frac-
ture data determination service (see “Design and
Implementation,” page 38 ). Fracture-closure
stress, fluid-leakoff coefficient and fracture
height from these pretreatment injectivity tests
helped ensure that the main treatments achieved
a tip screenout. The operator adjusted pad and
proppant stages as needed and accounted for
high fluid leakoff in the B sand by increasing
the maximum injection rate to 18 bbl/min[2.9 m3 /min]. Engineers also restricted pump
rates to 16 bbl/min [2.5 m3 /min] for the A-reser-
voir Alternate Path completions to limit friction
pressure in the shunt tubes.
The operator performed post-treatment
hydrochloric [HCl] acid jobs on some wells to
reduce cleanup time. Other wells cleaned up
within two months without acid treatments.
Overall well productivity continued to improve as
treatment fluids were recovered. Experience from
the first wells helped optimize frac-packing pro-
cedures. Saudi Aramco reduced polymer concen-
trations in treatment fluids and includedslow-release encapsulated breakers to optimize
fracture placement and post-treatment cleanup.
36 Oilfield Review
21. Shepherd D and Toffanin E: “Frac Packing UsingConventional and Alternative Path Technology,” paperSPE 39478, presented at the SPE InternationalSymposium on Formation Damage Control, Lafayette,Louisiana, USA, February 18–19, 1998.
Riyadh
Welllocations
Saudi Arabia
EUROPE
AFRICA
SAUDI ARABIA
IRAN
IRAQ
SUDAN
ERITREA
EGYPT
YEMEN
OMAN
UAER
e
d
S e a
T h e
G u
l f
A r a b i a
n S
e a
0
0 300 600 900 km
200 400 600 miles
> Sand-control completions onshore. In the late 1990s, Saudi Aramco beganfrac packing new oil-well completions in central Saudi Arabia about 200 km[124 miles] southeast of Riyadh. These frac packs controlled sand influx andreduced downhole pressure drop, allowing the wells to flow naturally intofacilities 50 km [31 miles] away under existing intake-pressure conditions.
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Summer 2002 37
0
Gamma Ray, API Depth, ft
8800
8850
8900
8950
9000
9050
Resistivity, ohm-m
200 2 3
Perforations
Flapper valve
Washpipe
Tubing
Bottompacker
Conventional
Gravel-packpacker
< B-sand completions. A typical well log indi-cates a maximum pay interval of about 65 ft withclosely spaced perforations in the B reservoir(left ). Relatively short perforated intervals allowedSaudi Aramco to install a single completion andfrac pack these lower sands using standardscreens (right ).
0
Gamma Ray, API Depth, ft
8800
8850
8750
8900
8950
9000
Resistivity, ohm-m
100 2 3
Perforations
Tubing
Gravel-packpacker
Flapper valve
Gravel-packpacker
Flapper valve
packer
< A-sand completions. A typical well log showsperforations across a 180-ft [55-m] interval of theA reservoir (left ). Saudi Aramco performed twoseparate treatments using a stacked-screenassembly to frac pack these longer intervals(right ). Standard screens were used for the low-est zone, which was shorter. AllFRAC screenswith shunt tubes were installed to complete the
longer upper zone.
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The initial group of wells included five com-
pletions with conventional screens in the B
reservoir and five completions in the A reservoir
with AllFRAC screens that successfully treated
intervals up to 200 ft. Two completions in the A
reservoir used stacked-screen assemblies.
Treatments were pumped through 9000 ft of 3-in.
outside diameter (OD) tubing at surface injection
pressures below 10,000 psi [69 MPa] and pump
rates of 14 bbl/min [2.2 m3 /min] to 18 bbl/min.
The operator performed well tests by flowing
through surface facilities or with downhole pro-
duction logging tools to evaluate 12 frac-packing
treatments on the first 10 completions in this
field (left). Except for two, these frac-pack
completions yielded low completion skin and
good sand control in formations with up to
3-darcy permeability.
A positive frac-pack skin is caused by inade-
quate connectivity between propped fractures
and wellbores, incomplete zone coverage or fail-
ure to achieve a high-conductivity TSO fracture. If
these conditions produce a completion skin of 8or more, well productivity may be no better than
that of a conventional gravel pack. Achieving
optimal frac-pack performance, as in the case of
these Saudi Aramco wells, requires detailed pre-
liminary designs, careful proppant and fluid
selection, accurate pretreatment injectivity test-
ing and treatment optimization as needed.
Design and Implementation
During the initial design of frac-packing treat-
ments, completion engineers determine required
fracture geometry based on reservoir conditions,
rock properties and barriers to fracture-heightgrowth. Fracture length and, more importantly for
high-permeability formations, fracture width
enhance well productivity. Operators select an
optimal TSO fracture design by maximizing the
net present value (NPV) from enhanced well pro-
ductivity (left).22
Proppant selection —The type of proppant
chosen to keep fractures open and form a granular
filter is an important design consideration. Frac-
packing success is due, in part, to larger proppant
sizes than those commonly used in gravel packing.
High concentrations of large, spherical proppants
minimize embedment and offset the effects of tur-bulent flow in propped fractures.
Operators use various grain sizes and
proppant types, including natural sand, custom-
sieved sand, resin-coated sand and intermediate
or high-strength man-made ceramic proppants,
depending on formation stress and fracture-
closure pressure. Proppants for frac packing
should accomplish four fracturing objectives:
38 Oilfield Review
20
Well
Dimensionlessskin
0
-5
10
15
5
1
11
3
0
2
20
5
3 3
1
-1
2 3 4 5 6 7 8 9 10
> Frac-pack performance. Saudi Aramco has frac packed 23 wells in the Cen- tral Province of Saudia Arabia and published results from an initial group of10 wells completed with 12 frac packs. In Wells 6 and 7, the operator usedstacked-screen assemblies and divided the completion intervals into twostages to optimize treatment designs and avoid fracturing into an underlyingwater-bearing zone. Premature screenout and early treatment termination inWells 2 and 5 contributed to high skins and poor productivity, confirming thatfracture conductivity and connectivity with the wellbore are critical factors.Eight wells had skins below those expected in conventional gravel packs and typical frac packs.
3.520
2030
4050
6070 6
7
8
9
Propp
ant c
oncen
tratio
n, lbm
/ft2
Fracture half-length, ft
Optimal
10
11
3.53
3.54
3.55
3.56
Netpresentvalue(NPV),millionsofdollar
s
3.57
3.58
3.59
3.60
> Frac-pack economics. Optimal fracture half-length and width maximize netpresent value (NPV). In this example, the optimal fracture length and width, orproppant concentration, are 30 ft [9 m] and 7 lbm/ft2 [34 kg/m2], respectively.Discounted operating costs and incremental income are expressed in pre-sent-day value. Completion and stimulation investments and discounted oper-ating costs are subtracted from discounted incremental income to arrive at the NPV for a treatment. Incremental income increases for longer and widerfractures, but at some point increasing costs for larger treatments yielddiminishing returns.
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Summer 2002 39
• provide an effective permeability contrast
• control sand influx and fines migration
• minimize proppant embedment in soft rock
•maintain fracture conductivity without
proppant crushing.
In the past, gravel-packing considerations
dominated proppant selection.23 Gravel packs
require gravel, or sand, sized to prevent forma-
tion particles and fines from invading the annular
pack. The widely accepted Saucier rule dictates
that sand, or gravel, particles be five to six times
the mean particle diameter of formation grains.24
Fracture permeability and conductivity improve
as proppant sizes become larger, but production
of formation sand grains and fine particles that
reduce pack permeability also increases. Frac
packs require proppants sized to optimize frac-
ture permeability.
In the early 1990s, operators began evaluat-
ing larger sizes of stronger proppants to increase
fracture permeability and relative conductivity in
high-permeability reservoirs.25 For example,
larger 20/40-mesh proppants were used used forfrac packing instead of smaller 40/60-mesh prop-
pants often required for gravel packing. 26
Experience indicated that proppant sizes dictated
by gravel-packing criteria could be increased to
next larger size for frac packing.
Saucier criteria for sizing proppants in relation
to formation grain size were relaxed in frac-pack
designs because the large flow area of hydraulic
fractures mitigates formation failure and sand
influx. Balancing the mechanisms of sand produc-
tion—flow velocity, proppant particle sizes and
fluid properties—allows operators to increase
fracture conductivity and improve frac-packperformance by using larger proppant sizes.
Completing deeper wells with high fracture-
closure stresses led operators to use more man-
made ceramic proppants because they are
stronger and their consistent spherical shape
reduces embedment, which also increases frac-
ture conductivity (above right). The majority of
frac packs use ceramic 20/40-mesh intermedi-
ate-strength proppant (ISP) when reservoirs have
good pressure support and closure stresses are
not excessive.
Fluid selection —After evaluating reservoir
characteristics, engineers choose an optimalfluid for combined stimulation and gravel pack-
ing. The polymer-based hydroxyethylcellulose
(HEC) fluids used in gravel packing, hydroxypropyl
guar (HPG) fracturing fluids with a borate
crosslinker for additional viscosity, and more
recently, viscoelastic surfactant (VES) fracturing
fluids, all are applicable. Frac-packing fluids must
have a variety of properties.27
Fluid selection depends primarily on TSO frac-
turing criteria. Unlike massive hydraulic fracture
stimulations in low-permeability formations, a
low leakoff rate, or high fluid efficiency, is less
desirable for frac packing. In fact, a somewhat
inefficient fluid helps achieve tip screenout andpromote grain-to-grain proppant contact from
fracture tip to wellbore.
However, frac-packing fluids also must
maintain sufficient viscosity to create wide
dynamic fractures and place high proppant con-
centrations that ensure adequate conductivity
after fracture closure.28 After tip screenout, fluid
systems transport proppant in the low-shear
environment of a wide dynamic fracture, but also
must suspend proppant under higher shear rates
in tubing, around screen assemblies, through
the perforations and during fracture initiation
and propagation.Fluid viscosity should break easily to minimize
formation and proppant-pack damage after treat-
ments. Optimal fluids need to be compatible with
formations and chemicals such as polymer break-
ers; they must also produce low friction and clean
up quickly during post-treatment flowback. To max-
imize retained fracture conductivity, operators
exercise great care with viscosity breakers o
acid treatments after frac packing to optimize
post-treatment cleanup for maximum productiv
ity and hydrocarbon recovery. Finally, frac-pack
ing fluids should be safe, cost-effective and easy
to mix, especially in offshore applications.
22. Morales RH, Norman WD, Ali S and Castille C: “OptimumFractures in High Permeability Formations,” paper SPE36417, presented at the SPE Annual TechnicalConference and Exhibition, Denver, Colorado, USA,October 6–9, 1996; also in SPE Production & Facilities 15no. 2 (May 2000): 69–75.
23. Monus et al, reference 8.
24. Saucier RJ: “Considerations in Gravel Pack Design,”Journal of Petroleum Technology 26, no. 2 (February1974): 205–212.
25. Hainey BW and Troncoso JC: “Frac-Pack: An InnovativeStimulation and Sand Control Technique,” paper SPE23777, presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 26–27, 1992.
26. Naturally occurring sand and man-made ceramic prop-
pants are specified according to sieve analysis based onparticle-size distributions and percentage of particlesretained by screens with standard U.S. mesh sizes.
27. Hainey and Troncoso, reference 25.
28. Morales RH, Gadiyar BR, Bowman MD, Wallace C andNorman WD: “Fluid Characterization for Placing anEffective Frac/Pack,” paper SPE 71658, presented at theSPE Annual Technical Conference and Exhibition, NewOrleans, Louisiana, USA, September 30–October 3, 2001.
1000
Permeab
ility,darcies
0 2 4 6 8 10 12
Closure stress, 1000 psi
100
10
30/50 Ceramic
20/40 Natural sand
40/60 Natural sand
20/40 ISP ceramic
20/40 Ceramic
> Proppant specifications. In the mid-1990s, operators began using larger,stronger and more conductive proppants in frac-pack completions. Man-made ceramic materials have since become the proppant of choice in the USGulf of Mexico to maintain fracture conductivity at higher closure stress indeeper formations. For example, switching from smaller 40/60-mesh sand(green) to a larger intermediate-strength 20/40-mesh ceramic proppant (yel-
low) increases proppant permeability and fracture conductivity by a factor ofsix in laboratory tests at 2000 psi [13.8 MPa] of closure pressure (inset ). Anintermediate-strength proppant (ISP) is priced competitively with custom-sieved natural sands.
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Fluids based on HEC have many preferred
frac-packing characteristics, but also several
drawbacks. Systems based on HEC exhibit
increased friction pressures compared with
delayed crosslinked HPG or VES fluids, and fric-
tional losses become significant in deeper wells
or smaller diameter tubulars. In addition, prop-
pant transport characteristics for HEC fluids are
not as good as those of crosslinked HPG or VES
fluids. High temperatures cause HEC fluids to thin,
and viscosity is not as high at low shear rates.
High-viscosity crosslinked HPG systems leave
some polymer residue, but maximize fracture-
height growth in moderate- to high-permeability
formations. They also perform well in longer
intervals and transport higher proppant concen-
trations for greater fracture conductivity.
Pumping pressures increase with HPG systems,
but service companies can used a delayed
crosslinker to reduce tubular friction.
Delayed-crosslink HPG fluids start at a lower
viscosity and require less hydraulic horsepower
to pump downhole. Prior to reaching the perfora-tions, temperature in the wellbore and fluid pH
cause the viscosity of these fluids to increase in
order to achieve low fluid-leakoff rates. The
majority of frac packs are pumped with
crosslinked or delayed-crosslink HPG fluids.
Viscoelastic ClearFRAC polymer-free fracturing
fluids, introduced in the mid-1990s, use a VES liq-
uid-gelling agent to develop viscosity in light
brines. This type of fluid provides low friction pres-
sures while pumping, enough viscosity at low
shear rates for good proppant transport, adequate
leakoff rates to ensure tip screenout and high
retained permeability for better fracture conduc-tivity. Field data also indicate that fracture con-
finement using VES fluids is better than with
conventional fracturing fluids, which is an advan-
tage when frac-packing near water-bearing zones.
These VES systems mix easily and do not
require additives such as bactericides, breakers,
demulsifiers, crosslinkers, chemical buffers or
delayed-crosslink agents. Systems based on VES
also are not susceptible to bacterial attack. If
wells must be shut in for extended periods before
flowback and cleanup, solids-free ClearFRAC flu-
ids are recommended to avoid precipitation of
damaging polymer materials.Fluids based on HEC and VES systems mini-
mize formation damage in zones with low to mod-
erate permeability, but high leakoff rates and
deeper invasion often result in slower recovery of
treatment fluids.29 Adding enzyme or oxidizing
breakers to frac-packing fluids reduces formation
damage and improves well cleanup. Slow-release
40 Oilfield Review
Shearrate,sec
1
Viscosity,cp
0 10 20 30 40100
1000
10,000
45 ppt
40 ppt
35 ppt
Fluid shear
Time, min
Fracture extension Tip screenout0.1
1
10
100
1000
> Fluid viscosity versus typical shear rate (blue) in laboratory tests.Under frac-packing conditions of fracture extension and tip screenoutin an Amoco, now BP, Matagorda Island field in the US Gulf of Mexico,a 35-ppt crosslinked HPG fracturing fluid (green) exhibited adequateviscosity behavior, while 40- and 45-ppt systems (red and gold, respec- tively) had unneccessarily high viscosities.
70
60
50
40
30
Gasrate,MMscf/D
20
10
0
1 2 3 4Well
5 6 7
50 ppt 35 ppt
> Improving frac-pack productivity. Production from frac-pack completions ina field of the Gulf of Mexico Matagorda Island area doubled after Amoco,now BP, began using an optimized 35-ppt crosslinked HPG fluid (Wells 5–7)instead of an initial fluid system with 50-ppt polymer concentration (Wells 1–4).Well 7 also had a high productivity ratio, but output was limited by small pro-duction tubing.
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Summer 2002 4
encapsulated breakers deposited in the proppant
pack allow higher breaker concentrations to be
used without sacrificing fluid efficiency.
In addition to fluid leakoff and friction pres-
sure considerations, shear rate and temperature
are critical in selecting frac-packing fluids and
polymer concentrations.30 The first frac-pack
treatments were performed using the same HEC
fluid systems as gravel-packing operations. Later,
a shift to more conventional fracturing fluids
occurred because of increasing temperature
requirements and the need to maximize fracture
conductivity in high-permeability formations.
Initially, selection criteria for these fluids
were similar to those of conventional fracturing
applications in which narrow hydraulic fractures
in consolidated, low-permeability formations cre-
ate high shear rates with low fluid-leakoff rates.
These factors result in breakdown of fluid viscos-
ity and less cooling of formations, and greater
polymer concentrations are required to maintain
viscosity throughout a treatment. The use of
higher polymer concentrations carried over intofracturing and frac-packing designs for high-
permeability reservoirs.
In frac packing, however, fractures are wider
with lower fluid velocities and shear rates.
Pretreatment fluid injection also decreases for-
mation temperature near the wellbore. Pumping
large volumes of treatment fluid decreases heat
transfer from a reservoir, resulting in cooler tem-
peratures inside a fracture. Failure to consider
these effects results in use of higher polymer
concentrations than actually required. This
increases the potential for formation damage and
decreases the likelihood of a tip screenout.For example, because of differences in shear
rate, a crosslinked fluid with a polymer loading
of 20 lbm/1000 gal (ppt) [2.4 kg/m3] of base
fluid can have the same viscosity in a high-
permeability formation as a 40-ppt [4.8-kg/m3]
fluid in a low-permeability formation. Proper fluid
selection and specification dramatically increase
frac-packing efficiency and well productivity.
In 1996, Amoco, now BP, completed four
Matagorda Island wells in the western Gulf of
Mexico by frac packing.31 The reservoir tempera-
ture was 300ºF [150ºC], so the operator chose a
high-viscosity 50-ppt [6-kg/m3] crosslinked HPGfluid that was also used in fracture-stimulation
treatments for low-permeability reservoirs.
Production from these frac-pack completions was
comparable to that of gravel-packed wells. The
operator attributed the relatively poor perfor-
mance to lack of tip screenout because of
improper fluid design.
The operator and Schlumberger evaluated the
effects of shear rate on fluid properties in orderto remedy poor performance (previous page,
top).32 Based on the results of this investigation,
frac-pack treatments on the next three wells
used a 35-ppt [4.2-kg/m3] fluid. Fluid efficiency
decreased because of lower viscosity, allowing
better slurry dehydration, which achieved desired
TSO results. Average daily production from these
wells doubled compared with the initial four
wells (previous page, bottom).
Pretreatment testing —Laboratory testing
and history matching of previous treatments pro-
vide insight into stress profiles and the perfor-
mance of treatment fluids, but in-situ formationproperties vary significantly in high-permeability
unconsolidated reservoirs. After developing
preliminary stimulation designs, engineers per-
form a pretreatment evaluation, or minifracture,
to quantify five critical parameters, including
fracture-propagation pressure, fracture-closure
pressure, fracture geometry, fluid efficiency
and leakoff.33
This procedure consists of two tests, a stress
test and a calibration test, performed prior to the
main treatment to determine specific reservoir
properties and establish the performance charac-
teristics of actual treatment fluids in the payzone. A stress, or closure, test determines mini-
mum in-situ rock stress, which is a critical refer-
ence pressure for frac-pack analysis and
proppant selection (above).
A calibration test involves injecting actual frac-
turing fluid without proppant at the design
treatment rate to determine formation-specific
fluid efficiency and fluid-loss coefficientsFracture-height growth can be estimated by tag
ging proppants with radioactive tracers and
running a post-treatment gamma ray log
A pressure-decline analysis confirms rock prop
erties and provides data on fluid loss and
fluid efficiency.
An integral part of pretreatment testing is live
annulus monitoring and real-time measurements
from downhole quartz gauges to obtain pressure
responses independent of frictional pumping pres
sures. Accurate analysis using DataFRAC services
ensures that the current frac-pack design and sub
sequent treatments achieve wide fractures with atip screenout for optimal results.
Surface data from pretreatment tests com
bined with bottomhole injection pressures are
history matched using a computer simulator
such as the SandCADE gravel-pack design and
evaluation software, to calibrate the fracturing
model and finalize treatment design. Calibrated
data from DataFRAC analysis are also used to
assess stimulation effectiveness during post
treatment evaluations.
29. Monus et al, reference 8.
30. Morales et al, reference 28.
31. Norman WD, Mukherjee H, Morales HR, Attong D,Webb TR and Tatarski AM: “Optimized Fracpack DesignResults in Production Increase in the Matagorda IslandArea,” paper SPE 49045, prepared for presentation at
the SPE Annual Technical Conference and Exhibition,New Orleans, Louisiana, USA, September 27–30, 1998.
32. Morales et al, reference 28.
33. Monus et al, reference 8.
Bottomholepressure
Time
Increasinginjection
rate
Constantinjection
rate
Constantflowback
Shut in Constantinjection rate
Net pressure
Fracture closure pressure
Instantaneous shut-inpressure (ISIP)
Fracture-extensionpressure
Reboundpressure
Pressurefalloff
> Pretreatment minifracture testing. Stress, or closure, tests involve injecting low-viscosity, nondam-aging fluid at increasing rates to initiate a fracture and determine the pressure required to propagate,or extend, fracture length. Fracture-closure pressure is determined by monitoring pressure declineduring a slow, constant-rate flowback.
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Treatment design, particularly TSO fracture
stimulation, is critically important to successful
frac packing. If premature screenout or failure to
achieve a tip screenout results in insufficient
fracture width to overcome proppant embedment
in the formation, well productivity may, at best,
be equivalent to that of a conventional gravel
pack. Standard frac-packing practice is to
redesign treatments on-site after minifracture
testing and analysis are complete.
Treatment design —Previously, frac packs,
which sometimes failed because of premature
fracture screenout or early annular packoff,
were designed solely using hydraulic-fracturing
simulators that neglected gravel-packing and
completion equipment inside the wellbore, such
as crossover ports in gravel-pack packers, blank
pipe, screens and washpipe. With the SandCADE
simulator, engineers now specify tip-screenout
designs and simulate frac-packing treatments
using coupled wellbore and hydraulic-fracturing
simulators.34 This software also simulates slurry
flow including the effects of well inclination,gravel setting and bridging around screens, and
fluid flow through packer and screen assemblies.
The fracture simulator supports tip-screenout
designs in high-permeability formations. Inducing
gravel packoff in wellbores by deliberately reduc-
ing pump rate or shifting service tools to circulate
at the end of a treatment also can be modeled.
The SandCADE simulator also models fracturing
of multiple layers and shunt-tube flow (below).
Well-Completion Applications
Fracturing designs based on TSO technology,
larger proppant particle sizes, advances in frac-
turing fluids and improved treatment evaluation
combined with more robust and versatile pump-
ing equipment and downhole tools make frac
packs a viable completion alternative in many
wells. Experience from more than 4000 Gulf of
Mexico frac packs in formations with permeabil-
ities ranging from 3 mD to 3 darcies helps oil and
gas producers identify frac-pack candidate wells
(next page, left). Frac-packing well-completion
applications include the following:
• wells prone to fines migration and sanding
• high-permeability, easily damaged formations
• high-rate gas wells
• low-permeability zones requiring stimulation• laminated sand-shale sequences
• heterogeneous pay zones
• low-pressure and depleted reservoirs.35
Today, operators select sand-control methods
by determining first if conditions justify frac
packing. There are 11 major advantages to
frac packing:
• bypass formation damage
•increase completion radius and flow area
•reduce pressure drop and fluid velocity
•connect individual laminated zones
•re-stress borehole relaxation after drilling
• alleviate fines migration and sand production
•improve well productivity
•achieve consistent low-skin completions
•sustain increased production
•maintain completion longevity
•reduce the likelihood of sand-control failure.
Most wells requiring sand control benefit
from frac packing. Exceptions include locations
where high-pressure pumping equipment is
unavailable, wells with casing sizes that are less
than 5 in., wells with weak casing when there is
a risk of failure and loss of wellbore integrity or
completions with a possibility of fracture-height
growth into water or gas zones. Frac packing alsomay not be economical for low-rate wells,
water-source or injection wells that do not pro-
duce revenue directly, and reservoirs with
42 Oilfield Review
35603580360036203640366036803700
37803800382038403860388039003920
388039003920394039603980
40004020-0.1 0
Fracture widthat wellbore, in.
Fracture half-length, ft Fracture widthat wellbore, in.
Fracture half-length, ft
0.1 0 10
Depth,ft
Depth,ft
20 30 40 50 60 70 80 90
35603580360036203640366036803700
37803800382038403860388039003920
38803900392039403960398040004020
-0.1 0 0.1 0 10 20 30 40 50 60 70
Proppantconcentration,lbm/ft2
0–2
2–4
4–6
6–8
8–
1010–12
12–14
>14
> Modeling frac-packing treatments. The Schlumberger SandCADE simulator is the only commercially available software that accounts for completion andgravel-packing equipment. A hydraulic-fracturing simulator that calculates fracture geometry, proppant distribution in fractures, and two-dimensional fluidflow as boundary conditions is coupled to wellbore simulator, which models fluid and slurry flow in the screen-casing annulus and Alternate Path shunt tubes. A special feature simulates fracturing of multiple layers with or without shunt tubes. This example illustrates simultaneous frac packing of threezones. Without shunt tubes, the treatment places most of proppant in the middle zone (left ). Alternate Path screens ensure treatment of the entire comple- tion interval as well as more uniform fracture lengths and widths (right ).
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Summer 2002 43
limited reserves or homogeneous thick zones
where horizontal gravel packing in openhole is
more appropriate.36
In more prolific reservoirs, flow turbulence
associated with perforated casing restricts pro-
duction, so operators often drill and complete
openhole horizontal wells to optimize productiv-ity. Stand-alone screens, openhole gravel packs
or expandable screens are sand-control options
in these settings, especially for thick reservoir
sections. Frac packing in openhole completions is
the next logical step to provide long-term sand
control without sacrificing productivity.
Openhole Frac Packing
Widuri field, operated by Repsol YPF, lies off
shore in the Java Sea, Indonesia (above). Drilled
in an area scheduled for waterflooding, Well B
28 targeted a thin sandstone of the Talang Aka
formation at 3500 to 3600 ft [1067 to 1097 m
with 29% porosity and 1- to 2-darcy permeability.37 Original reservoir pressure was
1350 psi [9.3 MPa], but solution-gas drive and
weak aquifer support resulted in rapid depletion
to 600 psi [4 MPa]. Moderate consolidation and a
tendency to produce sand mandated sand-contro
completions. Initially, wells were completed as
cased-hole gravel packs. Because of lower reser
voir pressure, the operator planned cased-hole
frac packs for new wells.
34. Sherlock-Willis T, Romero J and Rajan S: “A CoupledWellbore-Hydraulic Fracture Simulator for RigorousAnalysis of Frac-Pack Applications,” paper SPE 39477,
presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 18–19, 1998.
35. Hannah et al, reference 10.
Ayoub JA, Kirksey JM, Malone BP and Norman WD:“Hydraulic Fracturing of Soft Formations in the GulfCoast,” paper SPE 23805, presented at the SPEInternational Symposium on Formation Damage Control,Lafayette, Louisiana, USA, February 26–27, 1992.
DeBonis VM, Rudolph DA and Kennedy RD:“Experiences Gained in the Use of Frac Packs inUltralow BHP Wells, U.S. Gulf of Mexico,” paper SPE
High-Permeability Reservoirs
Low-Permeability Reservoirs
Laminated Sand-Shale Sequences
Wellbore
Shale
Sand
Proppant
> Frac-pack applications. Frac packing is aviable completion alternative for many wells inreservoirs with sand-production tendencies.
In reservoirs with moderate to high permeabil-ity that are susceptible to drilling and completiondamage that extends deep into the formation,frac packing and wide TSO fractures connectreservoirs and wellbores more effectively.
For reservoirs with heterogeneous pay or lami-nated sand-shale sequences, frac packing pro-vides an effective hydraulic connection acrossmost of a completion interval. When perforated-interval length is limited, frac packing connectsmore pay with fewer perforations.
In low-permeability reservoirs, fracture exten-sion increases the wellbore drainage radius, andbilinear flow stimulates well productivity. In for-mations with low bottomhole pressures, fractur-ing bypasses perforating debris and damage,
mitigating the impact of overbalanced perforat-ing. Frac-pack completions also improve hydro-carbon recovery from low-pressure anddepleted reservoirs by minimizing completionskin across the pay interval, thus reducing draw-down and ultimate abandonment pressure.
MALAYSIA
Singapore
Jakarta
INDONESIA
BORNEOA n d a m a n S e a
T i m o r S ea
Widuri field
0
0 300 600 900 km
200 400 600 miles
ASIA
AUSTRALIA
Indonesia
> Openhole frac packing. Repsol YPF chose to frac pack an openhole com-
pletion located north of Jakarta, Indonesia, in the offshore Widuri field tomaximize well productivity.
27379, presented at the SPE International Symposium onFormation Damage Control, Lafayette, Louisiana, USA,February 7–10, 1994.
36. Ali S, Dickerson R, Bennett C, Bixenman P, Parlar M,Price-Smith C, Cooper S, Desroches J, Foxenberg B,Godwin K, McPike T, Pitoni E, Ripa G, Steven B, Tiffin Dand Troncoso J: “High-Productivity Horizontal GravelPacks,” Oilfield Review 13, no. 2 (Summer 2001): 52–73.
37. Saldungaray PM, Troncoso J, Sofyan M, Santoso BT,Parlar M, Price-Smith C, Hurst G and Bailey W: “Frac-Packing Openhole Completions: An Industry Milestone,”paper SPE 73757, presented at the SPE InternationalSymposium and Exhibition on Formation DamageControl, Lafayette, Louisiana, USA, February 20–21, 2002
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An unexpected low bottomhole pressure of
390 psi [2.7 MPa] resulted in complete fluid loss
while drilling the B-28 well. A high-pressure,
reactive shale above the pay zone required that
the operator set 7-in. casing to isolate this poten-
tially unstable section. Hole collapse caused this
casing string to be set high, leaving 70 ft [21 m]
of shale exposed after drilling deeper. Repsol YPF
suspended the well temporarily after attempts to
run a screen assembly failed.
After five months of waterflooding, reservoir
pressure increased enough to hold a water col-
umn and maintain hole stability. Repsol YPF
decided to attempt an openhole frac pack
because running 5-in. casing was too restrictive
for an internal gravel pack. This approach
presented several challenges, including openhole
stability, screen deployment, fracturing a long
high-permeability section, proppant slurry con-
tamination in exposed shale and annular packing
efficiency in a 70º inclined wellbore. Incomplete
packing and completion failures on other comple-
tions raised concerns about frac-packing effec-tiveness in high-angle wells.
Repsol YPF chose an innovative combination
of Alternate Path screens and a multizone (MZ)
isolation packer to avoid fluid contamination,
facilitate effective fracturing and ensure com-
plete packing of the long openhole section (left).
Two shunt tubes designed for pumping
15 bbl/min [2.4 m3 /min] extended through the
packer, across the reactive shale section and
the entire pay interval. The design incorporated
an inner washpipe that conveyed drilling fluid to
a drilling motor. This motor could rotate a bit
on the bottom of the assembly if required todeploy the completion equipment. An outer
shroud with holes protected screens from
damage in the openhole.
Elastomer cups on the MZ packer prevented
annular flow and diverted fluid to the shunt
tubes. Exit nozzles on the shunt tubes did not
begin until just above the screens to avoid any
injection across the shale. Slurry bypassed the
shale section, exiting through nozzles along the
screens to fill gaps in the pack below proppant
bridges that might form. This configuration
preserved fracture and proppant conductivity
by eliminating fluid contamination from the reac-tive shale.
Frac-pack execution went smoothly despite
concerns about the high-angle wellbore, multiple
competing fractures and excessive fluid leakoff
through 225 ft [69 m] of openhole interval with
47 ft [14 m] of high-permeability net sand.
44 Oilfield Review
Drilling bit
Drilling motor
AllFRAC screenswith nozzles
AllFRAC blank pipewithout nozzles
Reactive shale
MZ isolationpacker with
bypass shunts
Shunttubes
QUANTUMgravel-pack
packer
QUANTUMservice tool
Washpipe
> Widuri Well B-28 completion. Run as part of the completion assembly, a
multizone (MZ) isolation packer was located below the QUANTUM gravel-pack packer inside the 7-in. casing. Two large shunt tubes extending through the packer bypassed the reactive shale section. A protective shroud covered the AllFRAC screens and shunt tubes to prevent mechanical damage fromhole instability or assembly rotation to reach total depth. The shroud alsocentralized the screens for a more complete annular pack. To reach bottom, this assembly could ream and clean out the hole if necessary using a posi- tive-displacement motor and bit at the end of the screen assembly. An innerwashpipe conveyed fluid to the motor.
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Summer 2002 45
Treatment simulation indicated a final fracture
half-length of 18 ft [5.5 m] with a propped width
of 1 in.
Initial production of 2000 B/D [318 m3 /d] total
fluid with 500 B/D [79 m3 /d] of oil from an elec-
trical submersible pump exceeded operator
expectations. Post-treatment skin was not mea-
sured by pressure-buildup analysis, but a sensor
on the electrical submersible pump monitored
downhole flowing pressures, which indicated a
small pressure drop at the completion face.
Well performance was evaluated by calculat-
ing a productivity index (PI) based on net reser-
voir thickness from flowing bottomhole
pressures, reservoir pressure and production
rates (below). Well B-28 outperformed most
wells in the field and compared favorably with
wells completed by openhole horizontal gravel
packing. Considering the excessive fluid losses
during drilling, this level of productivity demon-
strates the feasibility of openhole frac packing as
a sand-control alternative in extremely perme-
able reservoirs with high mobility ratios.
Emerging Technologies
New developments continue in all aspects of frac
packing, from improved sand prediction and
treatment modeling, to new fluids that reduce
damage in both propped fractures and annular
packs. New placement techniques improve frac
packing by applying new downhole equipment or
eliminating subsurface hardware entirely. Fluid
additives that are in testing promise to minimize
production declines by reducing fines migration
and preventing scale deposition.
Frac-pack placement data generally indicate
creation of a fracture and subsequent tip screen-
out, but post-treatment pressure data often
indicate positive skin values and some remaining
damage, raising questions about the effective-
ness of propped fractures. More realistic models
have been developed to resolve discrepancies
between geophysical evaluations, well-log
interpretation, fracturing data from frac-packing
treatments and well-test pressure analysis
(right).38 Generating consistent solutions and
resolving discrepancies require measurement of
multiple parameters within a discipline, and inte-
gration across disciplines.
Differential stresses make uniform hydraulic
fracture diversion and complete coverage diffi-
cult in long intervals of heterogeneous forma-tions, even when Alternate Path technology is
used. This is particularly true if stress profiles
vary significantly when high-permeability zones
with lower stresses occur at the top of a long
interval. Preferential propagation of fractures in
zones with lower in-situ stresses results in sub-
optimal reservoir stimulation. Ocean Energy used an innovative technique in
the Gulf of Mexico to ensure uniform stimulation
and annular packing across long intervals in a
field in the Eugene Island area.39 The operato
pumped more than one pad-slurry sequence dur
ing a treatment without shutting down to
sequentially increase the resistance to fractureextension, or fracture stiffness, in each zone from
lowest to highest in-situ stress. As proppan
packed toward a well, fractures became more
difficult to propagate, and the next pad-slurry
sequence diverted into other zones of long
heterogeneous intervals.
In this application, AllFRAC screens improved
frac-pack treatment diversion across long
intervals. Multiple temperature gauges with
electronic memory placed strategically in the
washpipe monitored slurry diversion through
38. Ayoub JA, Barree RD and Chu WC: “Evaluation of Fracand Pack Completions and Future Outlook,” paper SPE38184, presented at the SPE European FormationDamage Conference, The Hague, The Netherlands,June 2–3, 1997; also in SPE Production & Facilities 15,no. 3 (August 2000): 137–143.
39. White WS, Morales RH and Riordan HG: “ImprovedFrac-Packing Method for Long HeterogeneousIntervals,” paper SPE 58765, presented at the SPEInternational Symposium on Formation Damage Control,Lafayette, Louisiana, USA, February 23–24, 2000.
Cased-hole frac-packaverage = 0.17
Specificproductivity
index(PI),B/D/psi/ft
0.00
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
1 2 3 4 5 B-28 6
Well
7 8 9 10 11 12
> Openhole frac-pack performance. Inflow-performance calculations yieldedaverage and maximum specific productivity index (PI) values of 0.17 and 0.39B/D/psi/ft [0.013 to 0.03 m3 /d/kPa/m] for 12 Widuri field cased-hole frac packs,respectively. Only two cased-hole wells in this field performed equal to orbetter than the Well B-28 openhole frac pack, which had a specific PI of 0.28B/D/psi/ft [0.021 m3 /d/kPa/m].
Welltest (T)
T1
T2
T3
F1
F2
L1 G1
L1
G1
F1
G1
L1 G1
F2
G2
Fractureplacement (F)
Interpretationand Simulation
Models
Model Results andMatching Solutions
Well logs (L)
Geology andGeophysics (G)
> Post-treatment evaluations. Solutions from geo-logical and geophysical modeling, well-log inter-pretation, fracture-placement evaluation and well test analysis are not unique. Various combinationsof input data—length of pay interval, reservoirpressure, porosity, permeability, and fracturelength, width or height—often generate multiplesolutions and different results from each model.Better simulation and interpretation software helpestablish a match among all of the different modelssuch as T2, F1, L1 and G1 in this depiction.
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shunt tubes to other zones (above). Temperature
decreases indicated fluid flow past a gauge, and
temperature increases corresponded to reduced
flow or no fluid movement at a gauge.
Temperature responses at the gauges confirmed
complete interval coverage and diversion of
treatment fluids into individual target zones. Net
pressure developed during the treatment indi-
cated a tip screenout.
Individually frac packing multiple zones in a
single wellbore is time-consuming and expensive.An alternative to stacked frac-pack completions
uses Alternate Path screens and MZ isolation
packers with bypass shunt tubes to complete
more than one zone in a single pumping operation
with the same gravel-pack packer (next page,
left). This diversion technique uses pressure drop
in the shunt tubes to control fluid flow. Changing
the number and length of shunt tubes going to
each zone controls pressure drop. Engineers vary
shunt-tube configurations to achieve the desired
rate distribution. This system potentially allows
up to three zones to be completed at reduced cost
and improved profitability.Operators often bypass many marginal, or
secondary, pay intervals. These zones may never
be exploited because of the mechanical risk of
extending the frac-pack interval length up or
down and the cost of mobilizing a rig to recom-
plete the well, especially offshore where the vast
majority of frac packs are performed. Recently,
new technologies have been introduced that
promise to speed routine application of
“rigless” completions.
Coiled tubing-conveyed fracturing technology,
including CoilFRAC stimulation through coiled
tubing service, is rapidly becoming a viable tool
for exploiting bypassed pay.40 This new technol-
ogy has been applied successfully onshore in
multilayered, low-permeability reservoirs, but
the next step is to take this technology offshore.
Accessing offshore wellbores in a workover envi-
ronment and placing a frac pack or screenlesscompletion in a new zone without using a costly
conventional drilling or workover rig opens up
countless fu