Preventing Proppant Flowback

1. Copyright 2009, International Petroleum Technology Conference
This paper was prepared for presentation at the International Petroleum Technology Conference held in Doha, Qatar, 7–9 December 2009.
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Abstract
Flowback of proppant and formation sand often poses serious challenges to operating companies when these solids cause
equipment damage, costly and frequent cleanup treatments, and production decreases. These flowback problems are often
compounded in severity in wells with production of heavy oil and high water cuts. Once the proppant is produced out, there
is no mechanical means to keep the unconsolidated sand in the perforations or behind the casing in place. Similarly,
formation sand from the perforations not aligned with the propped fractures produces out freely during well production once
the proppant filling the perforation tunnels produces out.
To combat the proppant and sand-production problems and revive the production of wells that have been shut in because
of solids production, field trials of an on-the-fly coating, curable resin system were performed to determine whether this resin
system is a viable solid flowback control that can provide an effective means to establish screenless completions in this field.
This paper presents the results of these field trials involving the screenless completions using the on-the-fly, curable resin-
coating system in treating the proppant. Detailed descriptions of the completion procedures, challenges and difficulties, and
lessons learned during the course of these hydraulic-fracturing treatments are presented.
Field results indicate this on-the-fly, resin-coating treatment effectively stops the proppant and formation sand from
producing back while allowing the production rates to be maintained as designed. The process has drastically decreased the
number of solids-cleanout workovers in the treated wells compared to the offset wells in the same field in which the resin
treatments were not performed. The resin treatment provides a reliable and cost-effective alternative in marginal reservoirs,
eliminating the need for sand-control screens and providing access to other intervals, when needed, without wellbore
restrictions.
Introduction
The case studies discussed in this paper regard oil wells operated by CAPSA, Argentina. The producing formations in these
wells generally have high permeability, unconsolidated sand, and high water cut or water-oil ratio (WOR). Throughout the
past several years, the operator has applied gravel-pack completions in a limited number of wells to control production of
formation sand and fines with low success. The objective of this completion technique was to create a tight gravel pack in the
annulus between perforated casing and the sand screen, with the attempt to squeeze as much gravel out into the formation as
possible to control migration of formation sand and fines. Hydraulic-fracturing treatments using curable-coated proppant
were also performed to bypass near-wellbore damage and lower the drawdown as an attempt in minimizing flowback of
formation sand with production fluid. The production results, however, indicated that these completion methods were not as
successful as planned.
Wells completed with gravel pack using premium screens successfully stopped sand production from the formation, but
this type of completion significantly reduced fluid production because of high skin damage. For wells in which hydraulic
fracture treatments were performed, both frac sand and formation sand were observed to produce back, filling the wellbore.
Formation sand plagued the operator with decreased production and plugging of progressive cavity pumps (PCP), requiring
frequent workovers and downtime. Sand production prevented the operator from boosting the well production to desired
levels. In addition to the disappointing performance of these completions, the frequency of workovers required to clean out
proppant and formation sand in these wells averaged once every three to four months. As a result, the operator considered
field trials of a newly developed curable resin for controlling flowback of proppant and formation sand.
IPTC 13174
Preventing Proppant and Formation-Sand Production in High Water Cut,
Heavy-Oil Wells: A Field Study from Argentina
D. Daparo, L. Solis, E. Perez, CAPSA, C. Saravia, P.D. Nguyen, and J.C. Bonapace, Halliburton

2. 2 IPTC 13174
Well flow rates in this field were often choked back, thereby restricting production flow rates to minimize formation-
solids production. PCPs were also operated at low pump rates to minimize potential from being plugged by sand production.
The tendency of sand production in these wells is directly linked to their water-cut production. It has been shown that
water production impacts the tendency of sand production.1,2
A recent study performed by Wu et al. (2006) showed that the
effect of water cut on perforation failure and sand production is most significant for sandstones with high clay content.3
Production of solid particulates often results in:
• Plugging, choking, corrosion, or erosion of sand-control screens.
• Damage to PCPs.
• Frequent workovers.
• Loss of production.
Similar to formation sand production, proppant flowback poses a serious challenge to the operator because proppant
production damages downhole equipment or surface facilities. Production has to be stopped to clean out and dispose of the
produced proppant. Also, because of the flowback of proppant, the conductivity of the fracture is reduced, and consequently
so is the production potential of the well.4
Before hydraulic-fracturing treatments with liquid-curable resin (LCR)-coated sand, both LGZ and UGZ horizons
produce high levels of water, with 93 and 96% of water cut, respectively. It was determined that simultaneous production of
viscous oil and high water cut in the poorly consolidated formation caused formation sand to readily produce out of the pay
zones. This was one of the reasons that proppant coated with LCR was used in hydraulic-fracturing treatments to generate
highly conductive consolidated proppant packs with high consolidation strength in the propped fractures and perforation
tunnels, which acts as in-situ screens to lock both proppant and the formation sand in place. This paper presents the
descriptions and results of hydraulic-fracturing completions and remedial workovers that were performed in Diadema field in
south Argentina. It concentrates on all of these issues and provides a solution for formation solids flowback to help maintain
production and reduce the frequency of workovers often required in these wells.
Reservoir Description
The Golfo San Jorge (GSJ) basin is located in the southern region of Argentina, extending from the Atlantic Ocean to the
Andean foothills. This basin accounts for approximately one third of the total hydrocarbon production in Argentina. GSJ is a
Mesozoic extensional basin filled with Jurassic lacustrian and Cretaceous fluvial deposits with Tertiary compression and
wrenching superimposed on earlier extensional features. The majority of the oil and gas reserves are located in three
Cretaceous formations: El Trebol, Comodoro Rivadavia, and Mina El Carmen. The main hydrocarbon source is the lacustrian
shale of the mid to lower Cretaceous D-129 Formation.
The Diadema field is located 40 km northwest to the city of Comodoro Rivadavia, on the northern flank of GSJ basin
(Fig. 1). Two main production zones exist in this field, the El Trebol and Comodoro Rivadavia formations. El Trebol is a soft
and unconsolidated formation that has an average permeability of 500 mD and 35% porosity. For differentiation, this zone is
called Upper Garnet Zone (UGZ) and the thickness of the sand layers varies from 3 to 6 m. Their Young’s modulus varies
from 0.80 E+5 to 1.05 E+6 psi with Poisson’s ratios between 0.30 to 0.33. The average depth for this pay zone is 800 m. The
bottomhole static temperature of UGZ is ~110°F.
The Comodoro Rivadavia is a soft and unconsolidated formation with an average permeability of 350 mD and 28%
porosity. This zone is referred to as the Lower Garnet Zone (LGZ). The average thickness of the sands is about 3 m. Its
Young’s modulus varies from 0.67 E+5 to 0.851 E+5 psi with Poisson’s ratios from 0.33 to 0.35. The average depth for this
pay zone is 1100 m. The bottomhole static temperature of LGZ is ~125°F.
X-ray diffraction analysis obtained from formation-core samples revealed that these formations contain between 15 to
20% clays. The particle size analyses of formation sand show grain sizes ranging from 200 to 500 µm. An oil gravity of 23°
API is considered to be average in the basin; however, there are fields with gravity as low as 12° API. This is considered the
heaviest oil in GSJ basin. A summary of formation properties is shown in Table 1.

3. IPTC 13174 3
Fig. 1—Diadema field in southern Argentina.
Table 1—Formation Data
Well Well A (F1) Well A (F2) Well B Well C
Formation Comodoro Rivadavia Comodoro Rivadavia El Trebol El Trebol
Zone LGZ AB4 LGZ B UGZ 1b UGZ 1b
Depth, m 1176.5 to 78.5
1118.0 to 20.0
1135.0 to 37.5
1139.5 to 42.0
798.0 to 803.0 799.0 to 802.0
Interval thickness, m
Fluid reservoir, API
Water cut, %
Porosity, %
Permeability, mD
Reservoir pressure, psi
Young's modulus, psi E+5 to 0.82 E+5 — 0.85 E+5 to 1.05 E+6 —
0.33 to 0.36 — 0.30 to 0.33 —
Formation Sand and Proppant-Flowback Control
The following methods and materials have often been applied within the industry to prevent or minimize production of
proppant and formation sand during production of the well.

4. 4 IPTC 13174
Forced Closure
Forced fracture closure5
is a technique used to close the fracture rapidly, trapping proppant in a uniform distribution. This
technique can potentially eliminate proppant flowback because the stresses exerted by the closing fracture walls help hold the
proppant in place. However, closure stress does not always hold proppants in place. Test results indicate that closure stress
can actually contribute to flowback. Fracture-closure stress is normally the mechanism relied on to hold proppant in place.
Unfortunately, many times it does not work effectively, resulting in proppant flowback.
Resin Precoated Proppants (RCPs)
RCPs were one of the first solutions to the problem of proppant flowback.6,7
The resin coatings around each grain react with
one another, allowing the grains to bond. This reaction creates a mass of permeable, consolidated proppant. However, the
bonded grains do not always have adequate strength, and consequently, proppant flowback with RCPs has been
documented.6,7
At low bottomhole temperatures or low closure stress, RCPs are known to be ineffective in forming proppant
packs with sufficient consolidation to handle the drag forces generated by fluid production.8
Fibers and Deformable Particulate
Fibrous materials9
and deformable particulate10
have been used in recent years to control proppant flowback. These solid
materials are mixed with proppant and become an intimate part of the proppant pack. A network is created between the
proppant and the fibrous strands. The main functions of the fibrous strands are to induce bridging at the perforations and
allow solid-free fluid to flow through. The use of deformable particulate requires that closure stress exist to apply on the
proppant-deformable particulate so the particles will adhere to one another by way of interembedment. Without the closure
stress, a stable pack can not be established. Although these materials reduce proppant flowback, they do not eliminate the
problem entirely and are usually accompanied by significant decreases in fracture conductivity.11
Surface Modification Agent (SMAs)
SMAs are water- and oil-insoluble, resinous materials that provide cohesiveness between proppant grains and do not harden
or cure under reservoir conditions. When these liquid additives are applied to proppant during a fracturing treatment, they
render proppant grains very tacky. These materials help enhance fracture conductivity by creating proppant packs having up
to 30% increased porosity and permeability.12,13
Flowback studies conducted with SMA-coated proppants indicate that the
coating renders proppant significantly more resistant to production; however, sufficient fluid-flow rates can initiate proppant
flowback.
Mechanical Screens
The primary function of the screens is to provide mechanical support to prevent the proppant or gravel placed in the
screen/wellbore annulus from flowing back into the wellbore. The gravel and proppant act as the primary filter to prevent
formation sand and fines production. Keeping the gravel or proppant in place will support the perforation tunnel and fracture
to maintain a conductive path and production. The screens can become damaged from fines plugging, scale buildup,
corrosion, or erosion caused by producing formation fines and sand.14,15
The installation of sand screens will restrict the
wellbore diameter. If a refracturing treatment is required, the screen might need to be removed or the producing intervals
might require reperforating before the recompletion can be performed.
Frac-Pack Completion
Frac-pack completion is designed to access reservoirs with high-permeability formations by combining propped fractures and
a gravel pack to bypass near-wellbore damage and to retain formation sand, respectively. Tip screenout helps generate short
and thick proppant-packed fractures toward the wellbore. A tip screenout is achieved when proppant at the leading edge of
the fracture stops moving and therefore prevents further fracture extension. The annulus between wellbore wall and sand
screen is tightly packed to maximize connectivity with propped fractures and to prevent development of void spaces. The
width of the fracture is further increased by continued injection of the fracture fluid, providing an increased proppant packing
inside the fracture. Propped-fracture operations that use sand-control screens have been successful in frac-pack treatments.
However, screens employed in these applications increase well completion costs and are known to fail with time.14,15
Liquid Curable Resin Systems
A new family of LCR systems was introduced for handling proppant flowback problems after hydraulic-fracturing
treatments.16
The LCRs are designed to (1) minimize the interaction between the resin and the carrier fluid system, and (2)
minimize the logistical problems on location. The LCR selected for treating the proppant used in the wells for this study is a
low-temperature, two-component, epoxy system designed for a temperature range of 70 to 225°F. Unlike the RCPs, the LCR
system is 100% curable. It was formulated with a proprietary additive to help with the removal of crosslinked-gel coating on
the proppant to enhance the contact between proppant grains, thus increasing consolidation of the proppant pack even without
applied closure stress. As a result, even under low or no closure-stress conditions, high consolidation strength of the coated
proppant pack can still be developed. In addition to the ability to provide consolidation strength, this resin is also formulated

5. IPTC 13174 5
to provide elasticity, which is beneficial to effectively handle the repeated stress-strain cycles that occur during normal
production operations.
Fig. 2 shows the coating of LCR on 12/20-mesh white sand after the coated sand was cured and removed from the pack
chamber for consolidation measurement. The bonding between grains, illustrated by the footprints at the contact points, helps
establish the consolidation strength for the proppant pack to withstand stress load or high shear. This consolidation strength
(i.e., unconfined compressive strength) corresponds proportionally with the concentration of LCR coated on the proppant
(Fig. 3). The capillary pressure between grains pulls the liquid resin to the contact points, thus helping prevent resin from
occupying the pore spaces. Fracture conductivity testing17
shows that coating LCR on the proppant actually improves the
conductivity of the proppant pack (Fig. 4). Several factors contributed to this increase in conductivity. The tackiness of LCR
coating alters the proppant pack density by increasing intergrain friction, thus providing higher porosity within the pack. LCR
not only bonds the proppant grains to each other, but also bonds to the fracture faces. This bonding distributes the point-
source load of proppant across the formation face, thus reducing the spalling effect and the amount of formation fines
intruding into the proppant pack.
Fig. 2—12/20-mesh sand was coated with LCR and cured at 120°F for 24 hours. SEM pictures illustrate the footprints and bonding
between sand grains after the consolidated sand core was subjected to unconfined compressive-strength measurement.
Fig. 3—Effect of LCR concentration on consolidation strength of 12/20-mesh sand pack after curing at 125°F without applying
closure stress.

6. 6 IPTC 13174
Fig. 4—Fracture conductivity values obtained at various closure stresses for 20/40-mesh ceramic proppant, with and without
coating with LCR.
A consolidated, permeable proppant pack can be used as an effective in-situ screen for controlling formation sand from
producing into the wellbore. Because not all perforations are aligned with the propped fractures, the formation sand from
these non-aligned perforations could be the major source of formation sand producing back with the production fluid. As
formation sand continues to produce back, void spaces or caverns could be present behind the casing/cement, undermining
wellbore integrity. Therefore, it is imperative that these non-aligned perforations (along with the voids behind the casing) are
packed with proppant that has been coated with LCR during the hydraulic-fracturing treatment. Once consolidated, the
consolidation of the coated proppant pack transforms it into a highly permeable, competent solid mass, acting as in-situ
screen to withstand high drawdown pressure of viscous, two-phase fluid, and to prevent production of formation sand and
fines.
Field Implementation
The operator decided that recompleting the problem wells with a conventional gravel-pack completion would not be
economical and effective. The choking effect of gravel packs and sand screens severely reduced the productivity index in
several wells in which gravel-pack completions were previously applied. Therefore, screenless fracturing treatments were
considered for recompleting these wells.
Table 2 summarizes the well parameters involved in the treatments. The treatments of these wells basically involved
hydraulic-fracturing treatment procedures with tip screenout and squeeze-pack designs similar to those of conventional frac-
pack techniques, except that no sand screen was installed in the wellbores. The objectives of these screenless fracturing
treatments were:
• Generate fractures to lower flow velocity during production by increasing cross-sectional flow area.
• Bypass near-wellbore damage and enhance wellbore communication with as many pay intervals as possible.
• Lock the frac sand in place, preventing these particulates from producing back to maintain fracture conductivity.
• Minimize formation sand and fines from intruding into the proppant pack to damage its conductivity.
• Establish “in-situ screen” to prevent production of formation sand and fines from perforations that were not aligned
with propped fractures.
• Increase or maintain well productivity.
Table 3 details the procedures for the well preparation and sequences of the hydraulic-fracturing treatment. The treatment
involved the following steps:
1. Perform a breakdown test.
2. Perform a mini-fracturing treatment and analysis.
3. Perform the main fracturing treatment.

7. IPTC 13174 7
Summary of Well Parameters
Well Well A (F1) Well A (F2) Well B Well C
Casing data
5 1/2 in. 15.5 lbm/ft
K-55
5 1/2 in. 15.5 lbm/ft
K-55
5 1/2 in. 15.5 lbm/ft
K-55
5 1/2 in. 15.5 lbm/ft
K-55
2 7/8 in. 6.5 lbm/ft
J-55
2 7/8 in. 6.5 lbm/ft
J-55
2 7/8 in. 6.5 lbm/ft
J-55
2 7/8 in. 6.5 lbm/ft
J-55
zone, m 1176.5 to 78.5
1118.0 to 20.0
1135.0 to 37.5
1139.5 to 42.0
798.0 to 803.0 799.0 to 802.0
Number of perf
intervals
Perf interval length, m
Zone Length, m
Table 3—Procedure Sequence for Preparing and Performing Treatment
Step Wellbore Preparation
Perforate production interval (in case of new completion).
2 Perform swabbing test as per completion program.
3 Determine if perforated interval produces sand or fines, also take data of oil and water cut.
4 Stabilize the well by circulating one bottomhole with 2% KCl brine.
-treatment Preparation
1 Ensure good conditions of packer and plug used in swabbing test. If it is permissible, use the same tools for frac treatment.
2 Blenders, pumps, and lines must be verified to be free of proppant and debris from previous operations.
3
All rig tanks, lines, choke manifold, and pumps (rig mud pumps and transfer pumps) are cleaned. All lines and valves must be pumped
through to ensure cleanliness.
4 Spot the frac equipment and rig up frac equipment. Install a relief valve and backside pressure valve in the treating line.
5 Ensure frac equipment is properly grounded.
6 Mobilize frac materials and record onsite inventory.
7 Perform prejob equipment quality-assurance test including a loop test for the flowmeter and bucket test for liquid additives.
8 Test packer and 5.5-in. plug with 4,000 psi. Record this test in the frac van.
9 Place three sacks of sand above pin of plug to protect it from LCR and facilitate fishing operations after frac.
10 Pressure test the surface lines. Set the pop-off valve. Set the pump trips.
1
Hold the prejob procedure and safety meeting with all operator and service personnel. Ensure all personnel on location are aware of
job procedures and safety concerns and that everyone knows their assignment.
2 Prime all pumps and fill the line to the wellhead.
3 Perform a final check to ensure that all valves are open that should be and that all valves are closed that should be.
4 Perform a breakdown test.
5 Perform a mini-frac test or step-down test according to previous agreement with well operator and company person.
6
On completion of pumping the mini-frac test, shut in and monitor pressure decline (ensure fracture has closed). Shut down the frac-
pumping equipment. Do not bleed off pressure during this shut-in period.
7
Once mini-frac pressure decline is complete, re-evaluate the prejob design and optimize the treatment as dictated by the mini-frac
results. The redesign process normally takes between one and two hours.
8
Perform the main fracturing treatment based on the information obtained from mini-frac analysis.
Displace the frac sand with 300 gal of crosslinked fluid and finish with lineal gel.
9 Shut in the well for 24 hours to allow the treated proppant pack to build consolidation strength, this is due to low BHT (150°F average).
10
Important, after frac neither move packer nor circulate unless premature screenout occured.
Demobilize frac spread to facilities.
11 Unset packer. Reverse out and circulate with 2% KCl brine.
12 Clean out LCR-coated sand. Prepare all equipment to perform production test to evaluate sand-control treatment.
13 Perform swabbing test to evaluate if there is no flow back of proppant.
14 Stabilize well and fish plug. POOH packer and plug.
15 Place the well on production and evaluate the well.

8. 8 IPTC 13174
Application of LCR
Fig. 5 provides a schematic layout of equipment involved during the fracturing treatment and coating of LCR on the
proppant. The proppant in all of the fracturing treatments was treated with LCR using a concentration of 3% (volume by
weight of proppant) throughout all the proppant stages, rather than coating only in the tail-in portion of the proppant. The
reasons for using this 100% coating were: (1) uncertainty about where untreated proppant and treated proppant were placed
near the wellbore and (2) to help ensure that all the perforations, including those not aligned with the propped fractures, were
filled with LCR-coated proppant.
The liquid resin and the hardener were delivered to the well location in separate containers. They were transferred into the
LCR containers and metered in proportion with the desired fluid and proppant rate pumped during the treatment. These
individual components were then pumped through a static mixer, which provides sufficient mixing to create a homogeneous,
activated resin blend. The mixed LCR was then injected to the bottom of the sand screw, which had its bottom end installed
inside the sand hopper. The auger action of the sand screw helps to spread the resin onto the dry proppant as it is moved
from the sand hopper to the blender tub. Once dropped into the blender tub containing the fracturing fluid, the coated
proppant was mixed into the fracturing fluid before the slurry mixture was pumped downhole. This direct pre-coating
maximizes the coating effectiveness of resin onto the dry proppant and minimizes the chemical interaction between the resin
and the fracturing fluid.
An aggressive breaker schedule was applied to ensure that early gel breaking would allow the proppant grains to obtain
grain-to-grain contact before the resin began to cure. The proppant pack required a 20-hr curing time to allow the resin to
cure properly at reservoir temperature after the treatment was executed.
Fig. 5—Fracturing equipment layout for the treatment using LCR to dry-coat proppant on-the-fly.
Case Histories
A total of four hydraulic-fracturing treatments were performed in three wells. All of the treatments were successfully
performed as per design without premature screenout. The fracturing treatment was performed through 2 7/8-in. tubing. The
fracturing fluid was designed for temperature application from 110 to 130°F. The low gel loading required help to minimize
gel residue and maximize conductivity in the proppant pack. The average pad size for the wells was around 4,000 gallons
(i.e., between 45 to 55% of total volume). The fluid system used was 25-lbm/Mgal guar polymer and borate crosslinker, with
an average pumping rate of 14 bbl/min.
The producing intervals were typically perforated with 4 shots/ft and 90° phasing, to obtain a 0.4-in. perf diameter and
32-in. perf length. White 12/20-mesh sand was used as proppant to ensure high permeability in the proppant pack. The ramp-
up concentrations of frac sand started from 1 to 7 lbm/gal and the last sand stage was often maintained for four to five
minutes to maximize packing and conductivity of the propped fractures near the wellbore. The average intended proppant
amount was 16,000 lb per frac stage. Tables 4 and 5 provide summaries of fluid, proppant, and treatment parameters applied
during the mini-frac and main-pack treatments.
The workover rig moved in and prepared the well by cleaning out the wellbore, reperforating the target interval (if
needed), and setting tubing. After the treatment and curing time, drill pipe coupled with drill bit was used to drill out the
consolidated proppant remaining inside the wellbore. Afterward, the well was swab tested to determine production rates and
to help design downhole production equipment.

9. IPTC 13174 9
Table 4—Minifrac Data
Well
Diagnostic pumping SDRT SDRT SDRT
Not performed
Fluid WaterFrac 25# WaterFrac 25# WaterFrac 25#
Injected volume, gal 3,600 4,100 2,900
Pump rate, bbl/min 14 15.3 14.3
Wellhead pressure, psi 1940 1160 1390
ISIP, psi 690 204 640
Fracture gradient, psi/ft 0.62 0.49 0.68
Perf friction, psi 0 0 78
NWB friction, psi 370 87 205
Total friction, psi at bbl/min 370 at 14 87 at 15.3 283 at 14.4
Closure stress, psi 1830 1700 1375
Closure grad, psi/ft 0.48 0.45 0.52
Closure time, [min 2.15 3 0.5
Fluid efficiency, % 23 27.2 4
Table 5—Fracturing Data
Well Well A (F1) Well A (F2) Well B Well C
BHST, °F 128 126 110 110
Fracture gradient, psi/ft 0.67 0.57 n/a n/a
PAD, % 46 47 55 51
Pump rate, bbl/min 14.9 14.9 14.3 14.2
Wellhead pressure, psi 2160 1646 1825 2170
Fracture fluid Guar (Borate) Guar (Borate) Guar (Borate) Guar (Borate)
Injected volume, gal 8,700 9,800 7,350 8,900
Operation time, min 14 16 12 15
Proppant type Sand Sand Sand Sand
Proppant size, mesh 12/20 12/20 12/20 12/20
Total proppant in Fm, sks 175 189 142 154
Max proppant conc, lbm/gal 6 6 7 6.5
Screenout No No Yes(induced) Yes
Shut-in time, hr 24 24 24 24
Date Nov-07 Nov-07 Sep-08 Nov-08

10. 10 IPTC 13174
Well A—This well was drilled and completed in August of 2007. For zone LGZ AB4, the perforations were shot in intervals
from 1176.5 to 1178.5 m, and zone LGZ B, the perforations were shot in intervals from 1118.0 to 1120.0 m, from 1135.0 to
1137.5 m, and from 1139.5 to 1142.0 m (Fig. 6). The well produced large amounts of formation sand during the production
test. As a result, the operator shut in the well to select an alternative method to complete the well, allowing it to produce sand
free. Table 6 shows production rates of oil and water in Well A from each zone before fracturing treatments.
In November of 2007, a hydraulic-fracturing treatment using LCR-coated sand was performed in zone LGZ AB4 (Fig. 7).
Similarly, zone LGZ B, covering all three perforated intervals, was also fractured with LCR-coated sand (Fig. 8). Because of
this fracturing treatment, sand production has not been observed and well intervention has not been applied. Table 7
summarizes the fluid production for Well A from December 2007 to January 2009 and Fig. 9 provides production profiles of
the well.
Well B—This well was completed in May of 2006 with a bottomhole depth at 906 m. Perforations were shot in intervals
from 853.0 to 857.5 m and from 798.0 to 803.0 m (Fig. 10). Initial production tests did not show sand production. However,
two workover interventions were performed to clean out formation sand, plugging the PCP within a month after the well was
put on production. The well was shut in until September 2006 when a well cleanout was carried out and a hydraulic-
fracturing treatment was performed with sand coated with a curable resin for interval 798.0 to 803.0 m. After the fracturing
treatment, the well was tested and small amounts of sand were observed producing back. A plug was set at 845 m and the
well was allowed to produce mainly from the fractured interval. Table 6 shows production rates of oil and water in Well B
before fracturing treatments.
In December of 2007, a workover was performed to cleanout formation sand, plugging the PCP. Sand was tagged at a
depth of 837 m. In January 2008, a new workover was performed to clean out formation sand, plugging the PCP, and to wash
and clean out sand from the wellbore. The well was then shut in. In June 2008, the plug set at 845 m was drilled out and the
well was put on production from both perforated intervals. In September 2008, a workover was performed to clean out sand
from the wellbore. A plug was again set at 845 m and a hydraulic-fracturing treatment using LCR-coated sand was performed
for interval 798.0 to 803.0 m (Fig. 11). Since this fracturing treatment, one workover intervention was performed because of
broken tubing. However, sand production has not been observed. Table 7 summarizes the fluid production for Well B from
October 2008 to June 2009 and Fig. 12 provides production profiles of the well.
Well C—This well was completed in June 2006 with a bottomhole depth at 885 m. Perforations were shot in intervals from
799.0 to 802.0 m (Fig. 13). A hydraulic-fracturing treatment was performed with sand coated with a curable resin. The well
was produced with a mechanical pump. Table 6 shows production rates of oil and water in Well C before fracturing
treatments.
In September 2006, a workover was performed to cleanout formation sand in the wellbore from 840 to 885 m. The
extraction system was changed to a progressive cavity pump. In November 2006, a well intervention was necessary to check
on the extraction system (which did not show any problem) but tagged the sand fill at 848 m. In February 2007, a workover
was performed because of a problem in the PCP and to clean out sand fill from 814 to 849 m. In March 2007, a workover
was performed to check on the PCP and formation sand was cleaned out from 816 to 863 m. In May 2007, the well was shut
in because the well stopped producing. In September 2007, a workover revealed several problems in rotor and stator of the
extraction system. Sand was washed and cleaned out from wellbore from 790 to 856 m. The operator changed the extraction
system to a jet pump. In December 2008, a hydraulic-fracturing treatment using LCR-coated sand was performed in the
perforated interval. The well has been producing sand-free since this frac treatment (Fig. 14). Table 7 summarizes the fluid
production for Well B from November 2008 to June 2009 and Fig. 15 provides production profiles of the well.
Table 6—Prefrac Production
Well BOPD BWPD % Water Cut Comment
Table 7—Post-Frac Production
Well A Well B Well C
3
624 1203 2075
Water cumulative, m
3
10429 3995 1423
Total cumulative, m
3
11053 5198 3498
Water cut, % 94 77 41
Days production 332 240 198
Sand production (Yes/No) No No No

11. IPTC 13174 11
Fig. 6—Well A—Log charts and perforation depths.
Fig. 7—Well A—First fracturing treatment (F1) in zone LGZ AB4.

12. 12 IPTC 13174
Fig. 8—Well A—Second fracturing treatment (F2) covering all perforated intervals in zone LGZ B.
Fig. 9—Production profile in Well A before after fracturing treatments.

13. IPTC 13174 13
Fig. 10—Well B—Log charts and perforation depths
Fig. 11—Fracturing treatment in Well B.

14. 14 IPTC 13174
Fig. 12—Production profile in Well B before and after fracturing treatment.
Fig. 13—Well C—Log charts and perforation depths.

15. IPTC 13174 15
Fig. 14—Fracturing treatment in Well C.
Fig. 15—Production profile in Well C before and after fracturing treatment.

16. 16 IPTC 13174
Post-Treatment Results
Overall, the production profiles of wells completed with screenless fracturing treatments using LCR showed that oil
production from these wells remained similar to pretreatment levels. Because water injection was applied to sweep the oil as
part of the oil-enhanced recovery process in this field, oil production was induced by water production. The amount of oil
recovered was directly tied to the amount of water produced back. This water produced later in the life of a waterflood is
coproduced with oil because of the fractional flow characteristics in the reservoir porous rock. Earlier studies have shown that
water production in unconsolidated formations can enhance the production of formation solids.3
The treatments of LCR in the remaining wells successfully locked the proppant in place. LCR concentration was 3%
(volume by weight of proppant) to ensure high consolidation strength for the treated proppant that was essentially located
near the wellbore and was required to withstand the high shear exerted on the sand during well production. In addition to
keeping the sand in place, the use of LCR-coated sand permitted the consolidated sand pack to function as in-situ screen to
successfully prevent the formation sand from producing back. These on-the-fly resin treatments drastically reduced or
practically eliminated the frequent cleanout operations or workovers often required in these wells before the LCR treatments.
Because all the wells were previously perforated at 4 shots/ft and 90° phasing, more than half of the generated
perforations were not aligned with the propped fractures. Without sand-control mechanisms, these perforations could become
primary sources for formation sand and fines production. Therefore, it is important that these perforations be completely
cleaned out during wellbore cleanup as part of the wellbore preparation before the screenless fracturing treatment so that they
can completely be filled with LCR-coated proppant. Once the LCR-coated proppant fills up the perforations not aligned with
the propped fractures, the permeable consolidated proppant pack will help lock the formation in place and prevent the
formation particulates from producing back along with the production fluid.
Lessons Learned and Recommendations
A. Coating Proppant throughout All Stages
Lessons learned from other areas that have applied LCR were carried over to the frac treatment here in Diadema field.
Because of the relative length of the perforated interval, the proppant involved in these treatments was coated throughout all
proppant stages. Evidence has indicated that even with a single, short-perforated interval, the first proppant injected into the
fractures can also be the first proppant produced back.11,14
B. Cleaning Out Sand from Perforations and Wellbore
Before performing the fracturing treatment, a thorough clean-up of perforations and wellbore was performed to ensure that no
restriction could prevent LCR-coated proppant from entering and packing all of the perforations, including those not aligned
with the propped fractures and/or void spaces that might be existing behind the casing. This simple procedure greatly
enhanced the success of the entire treatment.
C. Perforation Phasing
To minimize the production of sand from the unconsolidated formations, perforations should be shot at 180° phasing (and
parallel to the maximum horizontal stress). This part of the well completion helps reduce the number of perforations that are
not aligned with the propped fractures.
Conclusions
Based on the lessons learned and obtained results from these well treatments, the following conclusions have been made:
• With careful planning, screenless fracturing treatment provides an effective method for controlling flowback of
proppant and formation sand to maintain well production without disruption (i.e., workovers) caused by solid
particulate production.
• Properly cleaning out of solids from the perforations and the wellbore greatly enhances the success of the fracturing
treatment by allowing the LCR-coated proppant to completely fill and pack all perforations and voids behind the
casing and transforming the consolidated pack into a high-strength, permeable mass to handle high drawdown and the
effect of stress-strain cycles during well operations.
• Screenless fracturing treatment using LCR-coated proppant is an economical and viable completion method for wells
with mature reservoirs, unconsolidated formations, high water cut, and heavy-oil production. These have been
common issues in the Gulf of San Jorge Basin in the south of Argentina.
Acknowledgements
The authors thank the management of CAPSA and Halliburton for the permission to publish this paper.

17. IPTC 13174 17
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