SPE 165174

Effectively Controlling Proppant Flowback to Maximize Well Production: Lessons Learned from Argentina P.D. Nguyen, J.C. Bonapace, and G.F. Kruse, Halliburton; L. Solis and D. Daparo, CAPSA

Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE European Formation Damage Conference and Exhibition held in Noordwijk, The Netherlands, 5–7 June 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract Flowback of proppant and formation sand often poses serious challenges to operating companies. These solids can cause equipment damage, costly and frequent cleanup treatments, and production decreases. Various mechanisms were found that destabilize the proppant pack, causing the proppant to produce back with the production fluid. Since 2005, curable resin systems for coating proppant on-the-fly during hydraulic fracturing completions and remedial proppant treatments of propped fractures have been applied in Argentina to provide an effective means for proppant flowback control and screenless completions in various basins.

Evaluation of these applications has helped determine that optimum concentrations of resin coatings on the proppant in either primary or remedial treatments are necessary to maximize the bonding between proppant grains to lock the grains in place while minimizing any reduction of the proppant pack conductivity. Additives included in the liquid resin systems permit good consolidation properties in the proppant pack, allowing it to effectively handle the shear forces of high production rates and multiphase flow and the effect of stress cycling as the well undergoes producing and being shut in.

Field results indicate that on-the-fly resin coating on proppant and remedial treatments effectively stops the proppant from producing back while allowing the well production rates to be maximized as designed. These processes have drastically decreased the number of solids cleanout workovers in the treated wells compared to the offset wells in the same field where resin treatments were not performed. These resin treatments provide a reliable and cost-effective alternative in marginal reservoirs, eliminating the need for sand screens and providing access to other intervals when deemed necessary without wellbore restrictions.

Introduction Flowback of formation solid particulates during well production often results in the following:

• Plugging, choking, or erosion of sand-control screens. • Damage to downhole equipment. • 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 (Nguyen et al. 2006). Also, because of the flowback of proppant, the conductivity of the fracture is reduced and, consequently, so is the production potential of the well.

Several operators are actively involved in the three main basins in Argentina. These basins include Austral, Golfo de San Jorge (GSJ), and Neuquina. This paper discusses the implementation of liquid curable resin (LCR) systems by the four major operators in fracture treatments of their oil and gas wells. There are different objectives among the operators who have applied various curable resin systems to control flowback of formation sand and/or proppant. For example, an operator switched from using plain white fracturing sand to resin precoated proppant (RCP) so that an electrical submersible pump (ESP) could be used to produce the well at higher production flow rates. While using untreated white sand, the operator

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produced wells with progressive cavity pumps (PCPs) and had to maintain the well production at low flow rates to minimize flowback of the propping agent. The success of using RCP encouraged this same operator to consider using a LCR that can be coated on the proppant on-the-fly during the hydraulic fracturing treatment as an alternative system in case RCP was not available.

For another operator, the use of RCP was not an option because of the persistent failure of RCP in controlling proppant flowback. During the past several years, this same operator experienced limited success when applying gravel-pack completions in multiple wells to control production of formation sand and fines. Hydraulic fracturing treatments using curable-coated proppant were also performed to bypass near-wellbore (NWB) damage and lower the drawdown as an attempt to minimize 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 a 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 fracturing sand and formation sand were observed to produce back, filling the wellbore. Formation sand plagued the operator with decreased production and plugging of PCPs, 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 applied LCR for controlling flowback of proppant and formation sand.

The producing formations in the GSJ basin are known for high permeability, unconsolidated sand, and high water cut or water-oil ratio (WOR). 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 (Vaziri et al. 2002). This was one of the reasons that the operator in this basin treated proppant with LCR during hydraulic fracturing treatments to generate highly permeable proppant packs with high consolidation strength in the propped fractures and perforation tunnels, which acted as in-situ screens to hold the proppant and formation sand in place.

Rather than using RCP or treating the proppant with LCR on-the-fly during the hydraulic fracturing treatment, another operator applied a low-viscosity curable resin treatment as a preventive measure by treating the proppant that had been placed in the fracture with this resin soon after the hydraulic fracturing treatment to help ensure the proppant material stayed in place.

This paper presents the descriptions and results of hydraulic fracturing completions and remedial treatments involved in the applications of these curable resin systems that were performed in Argentina. Detailed descriptions of completion procedures, the challenges, and lessons learned during their treatments are discussed.

Reservoir General Description

Neuquina Basin. Located in west-central Argentina, the Neuquina basin contains Late Triassic to Early Cenozoic strata that were deposited in a back-arc tectonic setting (Fig. 1). Extending over a total area of 66,900 square miles, the basin is bordered on the west by the Andes Mountains and on the east and southeast by the Colorado basin and North Patagonian Massif. The sedimentary sequence exceeds 22,000 ft in thickness, comprising carbonate, evaporite, and marine siliclastic rocks. Compared to the western part of the basin, the central Neuquina is deep and less structurally deformed. The Neuquina basin is a major oil and gas production area for conventional and tight sandstones and could be an early site for shale gas development in South America. Production formations are Lotena, Tordillo, Quintuco, and Agrio for oil production, while Molles, Lajas, and Mulichinco are gas reservoirs.

GSJ Basin. The GSJ basin is located in the southern region of Argentina, extending from the Atlantic Ocean to the Andean foothills (Fig. 1). This basin presently 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 Middle to Lower Cretaceous D-129 formation.

Austral Basin. The Austral basin is located at the southern part of Argentina, extending from Magallanes province, in Chile, continuing over Argentina, and up to the Atlantic Ocean (Fig. 1). It is bordered by the South American Plate between the “Macizo del Deseado” craton and the Río Chico-Dugness arch. It is also bordered by the Patagonian Andes Mountains and the Malvinas basin. The basin covers an area of 230,000 km2, with approximately 85% belonging to Argentina, and the remainder to Chile. The sedimentary column can reach a maximum thickness of 8,000 m. The main oil reservoir is the Springhill formation, while the Magallanes formation is the gas reservoir.

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Fig. 1—General locations of major reservoir basins in Argentina.

LCR Systems A family of LCR systems was introduced for handling proppant flowback problems after hydraulic fracturing treatments (Nguyen and Weaver 2003). This includes both a resin system designed for primary treatments in which the resin is directly dry-coated on the proppant on-the-fly during the hydraulic fracturing treatment, and a resin system designed for remedial treatments in which a lower-viscosity resin is applied to treat the proppant that has already been placed inside the fractures.

For primary treatment, this resin system 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 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.

Fig. 2—12/20-mesh sand was coated with LCR and cured at 120°F for 24 hr. Scanning electron microscope (SEM) photographs illustrate the footprints and bonding between sand grains after the consolidated sand core was subjected to unconfined compressive-strength (UCS) measurement.

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Application of LCR during Fracturing Treatments. 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 provided sufficient mixing to create a homogeneous, activated resin blend immediately before use. The mixed LCR was then injected into the bottom of the sand screw, which had its bottom end installed inside the sand hopper. The auger action of the sand screw helped to spread the resin onto the dry proppant as it moved from the sand hopper up the sand screw and into 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 precoating maximized the coating effectiveness of resin onto the dry proppant and minimized the chemical interaction between the resin and the fracturing fluid.

Fig. 3 provides a schematic layout of equipment involved during the fracturing treatment and coating of LCR on the proppant.

Fig. 3—Fracturing equipment layout for the treatment using LCR to dry-coat proppant on-the-fly.

Proppant Remedial Treatment. A combination of coiled tubing (CT), consolidating fluids, and a pressure-pulsing tool offers a viable solution to the proppant flowback problem after the proppant has been placed in the fracture (Nguyen et al. 2007). This process involves using CT or jointed pipe coupled with a pressure-pulsing tool to enhance the successful placement of a relatively low-viscosity consolidating treatment fluid into the NWB region of propped fractures. This low-viscosity consolidating treatment fluid can be formulated from one of the LCR systems, based on the bottomhole temperature (BHT) of the well. In addition, the treatment process moves fines and debris away from the NWB proppant pack region, which helps to restore and maintain conductivity between the fracture and the wellbore.

These resin systems allow the activator to be premixed with the resin so that they can be injected as a single component, which helps ensure that, wherever the proppant pack is treated, consolidation will occur without the uncertainty often encountered with other externally catalyzed consolidation systems. Rather than an instant cure, as often occurs with externally acid-catalyzed resin systems, curing of the low-viscosity LCR occurs slowly. This allows complete placement of the resin into the proppant pack and complete displacement of the excess resin from the pore spaces within the pack to maximize its permeability (Fig. 4) before the resin can cure to a point at which placement is prohibited.

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Fig. 4—SEM micrographs of a sand pack taken at various locations of a treated pack showing the footprints of contact points and pore spaces between sand grains.

The two low-viscosity LCR components (i.e., resin and activator) are metered together on-the-fly using a static mixer to

form a homogeneous mixture just before being injected down hole using CT or jointed pipe, which places the treatment into the perforated interval to treat the proppant NWB in the fractures. The application of this consolidation system mainly involves the following steps:

1. Injecting a volume of preflush fluid for cleaning and conditioning the proppant pack. 2. Injecting a volume of low-viscosity LCR treatment fluid to coat the proppant and establish consolidation between

grains. 3. Injecting a volume of post-flush fluid to displace the excess resin from occupying the pore spaces within the matrix

of the proppant pack, thereby minimizing the damage to the pack permeability.

Remedial Treatment Design and Procedure. The chemical treating fluids used in this process, when properly deployed, were found to offer no obstruction to the wellbore or completion and were suitable to be placed in multiple intervals in one treatment operation. The process is depicted in Fig. 5 and is described as follows:

1. The well is cleaned out and any fill is removed to below the bottom-most producing interval. 2. A pressure-pulsing tool is installed on the bottom of a typical CT (or jointed pipe) bottomhole assembly (BHA). 3. The CT is deployed into the well to the bottom-most producing interval. 4. A preflush displacement fluid is pumped through the pulsing tool and into the producing interval. This cleans the

proppant surface and prepares it to receive the LCR. The CT annulus is closed during this process (Fig. 5a). 5. The BHA is moved upward across each producing interval in the wellbore, and the preflush treatment is repeated

(Fig. 5b). 6. Once at the top of all producing intervals, the LCR is pumped through the pulsing tool, directly adjacent to the

producing interval being treated. The pulsing action is essential and necessary to aid in flushing away debris or fines in the pack and to help ensure proper distribution of the LCR (Fig. 5c).

7. The CT is run back down the hole, and the consolidation step is replicated at each producing interval down to the bottom-most interval (Fig. 5d).

8. Once at the bottom of the well again, a final post-flush fluid is displaced and injected through the pulsing tool and into the producing interval to remove excess LCR from plugging the pore spaces of the proppant pack (Fig. 5e).

9. This process is repeated as the CT is withdrawn, until it reaches the uppermost producing interval (Fig. 5f). 10. The CT is removed from the well, with the CT annulus still closed (Fig. 5g).

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11. A cleanup solution is injected through the CT to clean and prevent the equipment from contamination with LCR residue.

12. The well remains shut in for a period of time, depending on the BHT of the well, from 2 to 48 hr.

(a) Inject preflush (b) Move CT across perfs (c) Inject curable resin (d) Move CT across perfs

(e) Inject post-flush (f) Move CT across perfs (g) Pull out of hole (POOH) Fig. 5—Treatment process uses a combination of CT, resin consolidation, and pulsing tool technologies to provide remedial solutions for controlling proppant flowback.

Field Implementation Since the introduction of LCR systems in Argentina in 2005, more than 240 hydraulic fracturing treatments have been performed with these resin systems. The fracturing treatments were performed in both oil and gas reservoirs that include formations of sandstone, dolomite, limestone, and tuffaceous sand, between the depths of 1,640 and 10,663 ft. Approximately 95% of the wellbores at the perforated intervals of the fracture-treated wells were vertical or slightly deviated, and only 5% were horizontal.

The fracturing carrier fluid was designed for bottomhole static temperatures (BHSTs) ranging from 90 to 250°F, including mostly borate-crosslinked hydroxypropyl guar, zirconate-crosslinked carboxymethylhydroxypropyl guar, and, occasionally, with just linear gel. Fig. 6 shows the percentage of each carrier fluid system applied in each basin based on the total number of performed fracturing treatments. For viscosifying gel fluids, low gel loading was used to help minimize gel residue and maximize conductivity of the proppant pack. Liquid gel concentrate (LGC) was used extensively in preparing the fracturing carrier fluid for the fracturing treatments. The LGC products are highly concentrated forms of the fully hydrated gel prepared offsite. In preparation of the fracturing fluid, the LGC was diluted with water to achieve the appropriate gel loading.

Both fracturing sand and intermediate-strength bauxite were used as propping agents, with particle sizes including 12/20-, 16/30-, and 20/40-mesh. Details of proppant amounts pumped in each basin are shown in Fig. 7. Table 1 provides a summary of fluid, proppant, and treatment parameters that were applied in each basin as per its operators during the fracturing treatments.

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Fig. 6—Breakdown of various fracturing carrier fluids applied in all of the fracturing treatments in each basin.

Fig. 7—Amounts of proppant pumped based on the total number of fracturing treatments in each basin.

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TABLE 1—SUMMARY OF RESERVOIR AND FRACTURING TREATMENT PARAMETERS

Treatment Parameters Operator A— Neuquina Basin

Operator B— GSJ Basin

Operator C— GSJ Basin

Operator A— Austral Basin

Number of fracturing treatments performed 52 105 31 17

Number of fracturing treatments per well 2 3 to 4 1 to 2 1

Fracture depth (m) 550 to 1800 585 to 2880 730 to 1370 1610 to 2830

BHST (°F) 95 to 165 108 to 235 110 to 140 170 to 245

Fracture gradient (psi/ft)] 0.53 to 1.05 0.50 to 0.89 0.48 to 0.56 0.55 to 1.15

Young’s modulus (psi) 3.5 to 4.5 E+6 0.80 to 1.05 E+6 0.67 to 0.85 E+5 3.5 to 4.5 E+6

Pad volume (%) 33 to 54 12 to 22 36 to 65 27 to 48

Pump rate (bbl/min) 14 to 45 (>75% Fracturing treatments < 20 bbl/min)

12 to 25 (93% Fracturing treatments < 20 bbl/min)

12 to 16 (42% Fracturing treatments < 14 bbl/min)

15 to 28 (60% Fracturing treatments < 20 bbl/min)

Wellhead pressure (psi) 1,000 to 5,400 1,350 to 5,800 700 to 2,200 2,600 to 6,700 Max proppant concentration (lbm/gal) 6 to 8 7 to 8 9 to 10 8 to 9

Fracturing fluid Low-temp borate gel (98%) Mid-temp borate gel (92%)

Low-temp borate gel (100%)

Mid-temp borate gel (89%)

Proppant type White sand (98%) White sand (80%) and intermediate-strength

bauxite (20%) White sand (100%) Intermediate-strength

bauxite (95%)

Proppant size (mesh) 12/20 (56%) and 16/30 (40%)

12/20 (2%), 16/30 (11%), and 20/40 (67%) 12/20 (100%) 16/30 (18%) and 20/40

(82%) Post-fracture shut-in time 4 to 8 hr (90%) 2 to 8 hr (55%) and

Forced closure (20%) 24 hr (100%) 4 to 12 hr (76%)

The main fracturing treatment was commonly preceded by a mini-fracturing treatment. The step-rate tests were only

performed when excess friction pressure was observed. Depending on the preference of the operators in the basin, nearly 80% of the fracturing treatments were performed as a single treatment per well. However, the other 20% were performed with multistage (two or more) treatments per well on the same day. Operator B in the GSJ basin could perforate a specific interval and perform a single fracturing treatment for this perforated interval; several fracturing treatments would be performed per well. In contrast, Operator C in this same basin often grouped several perforated intervals (i.e., three to five intervals) together in a fracture treatment.

The fracturing fluid was generally pumped down tubing. The average pad size for the wells was between 15 and 65% of the total fluid volume. Pump rates applied in the fracturing treatments ranged from 12 to 45 bbl/min; however, more than half of the fracturing treatments were performed with pump rates less than 20 bbl/min. Fig. 8 shows various ranges of pump rates that have been applied in the basins based on the total number of fracturing treatments.

Fig. 8—Ranges of pump rates applied in the fracturing treatments based on their total number of treatments.

Both RCP and the on-the-fly LCR were used to solve proppant flowback problems. Fig. 9 shows the concentrations of

LCR used for treating the fracturing sand or proppant in each basin.

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Fig. 9—Concentrations of LCR coated on proppant material during fracturing treatment in each basin. In the middle of 2007, Operator B began using RCP to enhance production from its wells. Before that year, this operator

had used white fracturing sand as propping material and produced the wells with a PCP. After a couple months, when the wells produced with a reduction of proppant flowback to a manageable level, the PCP was replaced with an ESP, with the intention to increase the production flow rate. The use of RCP permitted the operator to handle higher production flow rates. This operator also used LCR as an alternative for RCP in case there was a shortage of this resin precoated material. In general, Operator A did not find much difference in terms of proppant flowback control performance between RCP and LCR. This operator has not performed a single workover intervention in the wells that have used LCR, even several years after the fracturing treatments.

Operator B generally applied RCP for the entire fracturing treatment if the total required proppant was less than 30,000 lbm. However, in most cases, this operator used RCP as tail-in proppant in less than 50% of the total proppant used to help minimize costs. The operator used RCP to help ensure minimum risk and operative issues related to removing RCP from the wellbore in case of screenout, knowing that, to form a consolidated pack, RCP requires both temperature and closure stress.

For Operator C, overcoming formation sand production was the main objective; whereas, proppant flowback control was secondary. This operator also applied RCP in fracturing treatments to solve both formation sand production and proppant flowback problems. However, the use of RCP was not as successful as this operator had expected. The operator determined that LCR provided much better results in terms of controlling both formation sand production and proppant flowback.

Operator C, in the GSJ basin, coated most of the proppant used in its fracturing treatments with LCR throughout all of the proppant stages. However, other operators typically coated only in the tail-in portion of the proppant (i.e., between 10 and 30%) (Fig. 10). The reasons this operator coated most of the proppant were (1) uncertainty about where untreated proppant and treated proppant were placed NWB and (2) to help ensure that all the perforations, including those not aligned with the propped fractures, were filled with LCR-coated proppant.

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Fig. 10—Amounts of proppant coated with LCR during fracturing treatments in each basin.

Post-Fracture Treatment Results Except for a few premature screenouts, more than 95% of the fracturing treatments were successfully performed as per design. The treatment applications of LCR-coated proppant have provided an excellent solution for proppant flowback problems compared to the use of RCPs or any other additives that have been applied in the area. LCR-coated proppant drastically reduced the number of wells with proppant flowback, allowing the operators to maintain the well production at high drawdown without losing production because of well shutdown and/or workovers. In fact, the number of workovers was significantly lowered in wells that were treated with LCR compared to those treated with RCPs.

Operator C. Overall, the production profiles of wells completed with screenless fracturing treatments using LCR showed that oil production from their 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.

The treatments of LCR in the remaining wells successfully locked the proppant in place. In addition to keeping the sand in place, the use of LCR-coated fracturing sand permitted the consolidated sand pack to function as an in-situ screen to successfully prevent the formation sand from producing back. These on-the-fly resin treatments drastically reduced or 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. 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.

Low-Viscosity Liquid Resin in Remedial Treatment. This process was applied by Operator B in the GSJ basin and Operator D in the Neuquina basin.

Operator B. Operator B applied a low-viscosity LCR to treat the proppant that had already been placed in the fractures of

the four wells completed in the GSJ basin. Two of the treatments were considered remedial treatments (Wells A and B), and the other two treatments were considered preventive (Wells C and D).

Well A. A total of six hydraulic fracturing treatments were previously performed in the multistage stimulation of this gas

well, in which the proppant was coated with a surface modification agent (SMA) for fines-migration control and to enhance propped fracture conductivity. During the initial well flowback, a mistake was made by allowing the well to produce at a very high flow rate. This high flow rate caused the proppant in the first two zones (i.e., Fracturing Stages 1 and 2) to produce back with the production fluid. A remedial treatment using CT to place low-viscosity LCR was performed on these two zones. This remedial treatment successfully solved the proppant flowback problem in this well.

Well B. This mature oil well was fractured with four separate hydraulic fracturing treatment stages. During well tests, the

fracture in the last zone (i.e., Fracturing Stage 4) was observed to produce proppant. The operator applied a remedial

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treatment process involving CT to place a low-viscosity LCR to address the problem. After the treatment, the operator was able to test, evaluate, and produce the well without proppant flowing back.

Well C. This is a new oil and gas well in which three separate hydraulic fracturing treatments were performed with 20/40-

mesh white sand to create fractures in the three productive zones. Each fracture in these pay zones was tested and was found to produce injected fluid, gas, and fracturing sand. In fact, Fracture 1 produced more fracturing sand than the others. The operator applied remedial treatments for all three fractured zones with a low-viscosity LCR treatment (placed using CT) as a preventive treatment to help ensure that the fracturing sand stayed in place. After performing the treatment, each zone was tested again, and no fracturing sand was found to produce back.

Well D. This is a new oil well that had five productive intervals. Five separate hydraulic fracturing treatments were

performed with 20/40-mesh white sand to create fractures in these intervals. During testing, the first two fractures were found to produce proppant. The operator decided to treat all of these fractured intervals with a low-viscosity LCR using CT as a preventive measure of proppant flowback control. The well was tested after a curing period of the resin, and then was opened through a small orifice. When changing the orifice diameter from 8 to 12 mm, a higher drawdown pressure occurred, and the well produced a small amount of proppant; but, since then, it has produced proppant free.

Operator D. An oil well was fractured in October 2004 through four perforated intervals having a net interval of 66 ft.

The well has a BHT of 180°F and a bottomhole pressure of 3,129 psi at 8,202 ft measured depth (MD). Lightweight ceramic proppant (US 16/30-mesh) was used during the initial fracturing treatment. Initial oil production for this well was approximately 40 m3/day, with water cut of 60 to 98%. The proppant continued to produce back after the fracturing treatment. Three workovers were required to remove the proppant from the wellbore. Pump efficiency was drastically reduced, and oil production was decreased to 1 m3/day.

In December 2005, Operator D applied the remedial treatment method in this well. This involved the use of CT, a pressure-pulsing tool, and a low-temperature LCR treating fluid system. The treatment fluid included the preflushes (5 gal/ft), the low-viscosity LCR (2.5 gal/ft), and a post-flush (5 gal/ft). All of these fluids were commingled with nitrogen during placement because of low reservoir pressure. The liquid injection rate was 1 bbl/min, and the nitrogen gas rate was 800 scf/min. After the remedial treatment, the proppant flowback problem was completely resolved. The oil production rate steadily returned to 10 m3/day and then increased, while water cut maintained at around 80%.

Lessons Learned and Recommendations 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.

Cleaning Out Sand from Perforations and Wellbore. Before performing the fracturing treatment, a thorough cleanup of perforations and the wellbore was performed to help 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 could exist behind the casing. This simple procedure greatly enhanced the success of the entire treatment.

Fracturing Fluid Compatibility with LCR-Coated Proppant. Quality assurance/quality control (QA/QC) testing of LCR-coated proppant should be performed with the fracturing fluid that will be used in the fracturing treatment to help ensure the crosslinking time and break time follow the fracturing treatment design and schedule. This usually involves adjusting the pH or crosslinker concentration of the fracturing fluid. Because a short crosslinking time is desirable during the tail-in stages of LCR-coated proppant to enhance grain-to-grain contact between resin-treated proppant grains, lower crosslinker concentrations and higher breaker concentrations are applied to achieve complete breaking of the crosslinked gel.

Coating Proppant throughout All Stages. Because of the relative length of the perforated interval, the proppant involved in these treatments was coated throughout all proppant stages. Evidence indicates that, even with a single, short-perforated interval, the first proppant injected into the fractures can also be the first proppant produced back (Al-Ghurairi et al. 2006).

Early Screenout. It was the intention of the operator to prevent screenout from occurring, especially during coating of LCR with proppant during the tail-in stage. However, if the screenout occurred during the LCR-treating stage, forced closure was immediately applied to prevent coated proppant from being cured and forming a consolidated pack inside the wellbore. Cleaning out or reaming out of the consolidated pack inside the wellbore often required the use of a CT unit or workover rig, which required additional time and added complexity to the operation.

The resin-coating process can raise some concerns should premature screenouts occur during the fracturing treatment and the proppant slurry settles inside the wellbore. In this case, the well is flowed back as soon as possible so that tubing will not be necessary to clean out the wellbore. However, if the screenout occurs toward the end of the treatment, it is a desirable

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feature that helps ensure complete coverage of all perforations. When allowed to remain in the wellbore to semicure, the LCR-coated proppant pack can be cleaned out with tubing, preferably coupled with a drill bit or notched collar.

Forced Closure. A forced-closure method was applied to some of the fracturing treatments. Soon after the displacement stage was performed and after the treating iron was disassembled from the wellhead, the fracturing fluid was allowed to flow back. In most cases, the crosslinked fracturing fluid had not been completely broken. However, the principle of the forced-closure method is to enhance the closure of open fractures while the proppant is still being suspended in the fracturing fluid such that the fracture closure helps lock the proppant in place before it settles to the bottom of the fractures. This locking mechanism helps keep the fractures opened or “propped” instead of completely being closed, as in the case of proppant settled to the lower part of the fracture. Early flowback might help increase BHST to speed up the cure kinetic of coated proppant. In addition, the early flowback of fracturing fluid during forced-closure enhances the removal of gel residues, which are often thought to contribute to the conductivity reduction or permeability damage of proppant if allowed to remain too long inside the fracture.

To minimize the amount of proppant producing back during forced closure, the concentration of breaker is increased by 50 to 100% of the normal amount during the tail-in stage. This increase in breaker concentration promotes the breakdown of the crosslinked polymer fluid to enhance the grain-to-grain contact of the LCR-coated proppant and minimize the drag force during flowback of forced closure, especially with crosslinked fluid. The LCR-coated proppant grains are tacky in aqueous-based fluid; thus, their grain-to-grain contacts should help minimize their movement and flowback with the fracturing fluid, even though the curing of the LCR on the proppant has not been well-established.

Coating Proppant with Low Resin Concentrations. In terms of resin concentration, a LCR concentration of 1 to 2% (vol/wt) was often applied to coat the proppant, compared to a typical concentration of 3%, which was often required in other areas. Depending on the number of fractures and their interval lengths, concentrations of LCR in the range of 2 to 3% should be applied to attain high consolidation strength for the treated proppant that is essentially located NWB, allowing it to handle high shear exerted on the proppant during well production.

Shut-in Time for Curing. The well should be shut in after the fracturing treatment for at least 8 hr if the BHST of the well is 175°F or higher. A longer shut-in time is required if the BHST is less than 175°F. Insufficient shut-in time does not allow the resin-treated proppant pack to obtain sufficient consolidation strength to handle high production flow rates, especially for wells with a limited number of perforations.

An aggressive breaker schedule is recommended. The gel should be broken as quickly as possible to allow the proppant grains to obtain grain-to-grain contact before the resin hardens. If the gel is not broken before the resin hardens, the compressive strength of the pack will be very low. A forced-closure type breaker schedule or a ramped breaker schedule should be used. A general flowback recommendation is to begin flowback after the shut-in time at less than 1 bbl/min for the first few hours and then ramp up to the desired flow rate. However, well/reservoir conditions for each well should be reviewed to determine an appropriate flowback rate.

Conclusions

• With careful planning, liquid resin systems can be efficiently coated on the proppant during hydraulic fracturing treatments, or applied as part of remedial consolidating treatments, to transform the proppant placed in the fractures into consolidated, permeable packs for controlling proppant flowback.

• Proper coating and curing of liquid resin onto proppant allows the consolidated proppant to handle the high drawdown and the effects of stress-strain cycles during well shut-in and production.

• Application of liquid resins provides an effective method for controlling flowback of proppant and formation sand to maintain well production without disruptions caused by solids production.

Acknowledgments The authors thank Halliburton for permission to publish this paper.

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