Production Enhancement White Paper

HALLIBURTON

A Novel Approach for Enhancing Proppant

Consolidation: Laboratory Testing and Field

Applications

P.D. Nguyen, J.D. Weavez M. Parkez M. McCabe, M. Hoogteijfing, andM.J, van der Horst,

Hal#burton

During a hydraulic-fracturing treatment, proppant grains suspended in a viscous fluid are

pumped into fractures created by the fluid. When the pumping pressure is released, the proppant

remains in the fractures, holding them open and forming conduits for fluid flow into the

wellbore. If the proppant flows back into the wellbore, the width of the fracture channels will

decrease. The loss of proppant from the fractures limits the flow-channel conductivity, impairing

the effectiveness of the fracture treatment. Produced proppant also erodes production equipment,

necessitating costly repairs and frequent downtime. The economic loss potential that can result

from the inability to prevent proppant flowback has been a key factor responsible for the

abandonment of some field developments that require unmanned platforms or subsea

completions.

Proppant-flowback control is a widespread industry endeavor. Curable resin-coated proppant

(RCP) was introduced to the industry during the 1980s as a means to prevent proppant flowback.

Two general processes are used. The first method is the use of RCP for precoating proppant in a

manufacturing plant and partially curing the resin so that it can be conveniently stored and

transported to the use site without consolidation. The second method involves on-the-fly coating

of the proppant with an activated liquid resin system (LRS) as it is used during a fracture

treatment. For the treatment to be effective, the RCPs should consolidate, under downhole

conditions, into a long-lasting, high-strength permeable pack.

In hydraulic-fracturing applications, the primary purpose of the consolidated pack is to prevent

proppant flowback. An earlier study showed that a compressive strength of about 150 psi is

adequate to control proppant flowback in producing wells with moderate temperatures and

production rates) However, one can infer that the long-term success of a consolidated proppant

pack requires higher consolidation strength, coupled with flexibility to handle repeated stress

changes that occur during normal production operations at the reservoir temperature. One of the

targets of this study is to provide a hydraulic fracture completion that can control proppant

flowback at high temperatures and allow extremely aggressive flowback rates to remove the

fracturing fluid in minimal time, so that the production of hydrocarbons can begin. Many

techniques have been developed over the years in attempts to address these issues.

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Various screening and evaluation methods have concentrated on the suitability of RCPs for

proppant-flowback control in hydraulic fracturing. This paper describes the results of a study that

compares the consolidation performances of a commonly used RCP material and a new LRS

system under simulated treatment and downhole conditions of delayed/uneven fracture closures

and extended pump times that can be encountered during fracturing treatments. This paper

describes techniques that were developed for determining the cure kinetics of curable resins.

These techniques include differential scanning calorimetry (DSC), rock-mechanical property

measurements, and environmental scanning electron microscopy (SEM). Results of proppantflowback control and stress-load testing at high temperatures, as well as the results of the initial

field applications, are presented.

Failure Mechanisms

The limitations and failure mechanisms of RCPs have been extensively studied and well

documented. Vreeburg et al. has identified two types of proppant flowback that can occur when

RCPs are used; one is during the well-cleanup phase, and the other is after a long period of

proppant-free production) The early production-type scenario is thought to be caused by

insufficient bonding strength of the RCP. The factors affecting the strength of the RCP pack

include resin concentration, resin type, curing temperature, resin/fracturing fluid interaction

(under shear and temperature), and erosion of the resin from the proppant grains. The late

flowback of proppant mechanism was believed to be caused by damage to the consolidated RCP

resulting from the stress cycling that the proppant undergoes each time the well is shut in and put

back on production.

During a fracturing treatment at normally used proppant concentrations, the proppant grains are,

in general, not in contact (dispersed) while going downhole. In addition, the fluid and proppant

temperature is increasing during this time. When the proppant is placed in the fracture, it is

believed that some proppant grain-to-grain contact is required to form a consolidated pack. The

loss of consolidation strength with curing under low closure stress has been identified as a

potential failure mechanism) Some RCPs have been specially formulated to consolidate only

under high closure stress. Although this feature facilitates tubing cleanout after a premature

screenout, it can lead to reduced strength development of the RCP pack with delayed or uneven

closure of the formation.

The confining stress acting on the proppant pack during the curing process is probably not

uniform because of variations in the formation in-situ stress and the formation rock-mechanical

properties. In addition, some formations may not completely close after treatments. Studies have

shown that some hydraulic fractures do not completely close during the first 24 hours after

hydraulic-fracture stimulation treatments, especially in the case of low-permeability formations.

In fact, Blauer and Holcomb reported that many reservoir rocks do not sufficiently close to

prevent proppant flowback and settling during the first 90 days after the fracturing operations.4

RCPs may not be effective when wells with multiple or large perforated intervals are treated.

Multiple fractures or parts of single fractures in high-stress zones can screen out during the

proppant stages. Depending on the stage of the fracturing treatment, they may not contain any

RCP and may contain uncoated proppant that can be produced back. Uncoated proppant can also

HESI301676
be produced back from a well that has been perforated over a relatively short interval if the

treatment was not properly designed, and buoyancy forces have transported the high proppantconcentration RCP stages away from the near-wellbore area.

Even when RCPs are placed as designed, failures can occur. Several factors that can affect RCP

consolidation strengths and ultimate performances have been identified.2’3’~’6 Loss of

consolidation strength has been identified with increased fluid pH, crosslinked carrier fluid

incompatibility, increased shearing, low and very high closure stress, and increased stress

cycling. These factors are now well recognized in the industry and are usually considered in job

design and candidate selection. A factor that is not usually considered is the effect of the cure

kinetics of the resin coat of the proppant on its ultimate consolidation.

Cure Kinetics and Closure Stress

An extensive study by Nguyen et al.7 has concluded that most, if not all, of the currently

available RCPs lose their ability to form consolidations with adequate strengths after being

exposed to extended pump times in water-based fracturing fluids and high temperatures. The

cure kinetics of RCPs were found to have an impact on the resulting consolidation strength after

curing. For an RCP to achieve maximum consolidation strength, the RCPs cure rate should be

slow enough that minimal curing (or hardening) occurs while the proppant is being pumped and

until the formation has started closing.

By contrast, the systems that use a liquid resin applied to the proppant as it is being placed in the

fracture have shown slower cure rates. These systems have achieved consolidation strengths that

are much higher than RCPs. The high strengths are achieved even when long periods of time

precede fracture closure and, in some cases, even when no closure stress is applied to the

proppant grains.

The later in the curing cycle that the RCP is brought into grain-to-grain contact, the lower the

ultimate consolidation strength that will be developed. Because the resin cure rate increases with

temperature, the higher the temperature in which the proppant is exposed before grain-to-grain

contact occurs, the lower the ultimate consolidation strength. In addition, fracturing-fluid

components can have a significant impact on the resin curing rate, and any test performed needs

to be conducted in the actual fluid system planned for the fracture treatment. The combination of

these effects of time before grain-to-grain contact, along with fluid effects and temperature, has a

dramatic effect on the ultimate consolidation strength of the proppant pack.

The resin systems with slower cure rates and those that require minimal closure stress for

consolidation can be expected to lose less consolidation strength in fracturing treatments with

long pump times and slow formation closure rates.

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Why LRS-Coated Proppant Outperforms RCPs

The LRS-treated system shows superior performance over RCPs because:

 ̄ Capillary action causes flow of the liquid resin, concentrating it between proppant

grains and resulting in greater concentration of resin at contact points.

LRS-treated proppant is tacky, and this tackiness promotes grain-to-grain contact. In

contrast, the RCPs, even when heated, are not as tacky, and have little grain-to-grain

contact without closure stress. LRS-treated proppant has a slower cure rate and is not

removed from the proppant surface during stirring (simulated pumping) because the

resin system has been specially formulated to preferentially coat proppants in gel.

Contrastingly, RCPs have faster cure rates, and the resin from some of these

proppants has been shown to be leached off into the fracturing fluids.

RCPs are partially cured to provide for storage and handling, and the portion of the

resin that is cured does not contribute to the ultimate consolidation strength. Only a

small fraction of the resin in RCP is curable, while all the resin in LRS is curable.

Conversely, LRS efficiently contributes to the final consolidation strength even with

less resin.

LRS is formulated with additives that promote the removal of gelled fracturing-fluid film that

can sometimes impede grain-to-grain contact and consolidation.8

Experiments and Results

This section includes descriptions of the following parameters:

 ̄ Cure kinetics

 ̄ Effect of stirring and carrier fluid viscosity on consolidation

 ̄ Effects of suspending time and closure stress on consolidation strength

 ̄ Effects of resin concentration, cure time, and temperature

 ̄ SEM studies

 ̄ API conductivity testing

 ̄ Proppant flowback and stress-loading testing

Cure Kinetics

RCPs usually are coated with phenolic-type resins, therefore, these systems have similar

chemistry and cure kinetics. The RCP selected for use in this study uses a phenolic-based resin

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system for applications in high-temperature, high-closure stress applications and is commonly

used in the south Texas area. The LRS chosen for study is an epoxy-based resin system

specifically formulated for high-temperature application, but with a slow curing rate.

The cure kinetics of the neat resin used in RCP and LRS were measured at 225°F and 275°F with

DSC (Fig. 1). The results indicate that LRS had a much slower cure rate than RCP. At 225°F,

about 50% of the cure was completed within 75 minutes for both RCP and LRS. However,

approximately 3 11⁄2 hours were required for the RCP to complete 90% of its cure, compared to 6

11⁄2 hours for the LRS. At 275°F, approximately 20 minutes were required for both RCP and LRS

to complete 50% of the cure. However, 65 minutes were required for RCP to complete 90% of

its cure, compared to 130 minutes for LRS. These results are based on the thermal analysis of the

neat resin systems without any fluid components present.

Effect of Stirring and Carrier Fluid Viscosity on Consolidation

Proppant slurries (7 lb/gal) of 20/40-mesh, resin-precoated bauxite RCP and 20/40-mesh bauxite

coated with LRS (3% by weight) were prepared in a carboxymethylhydroxypropyl guar

(CMHPG) based fracturing fluid at a pH of 10.2. Proppant-laden slurries were stirred in a

consistometer at 175°F so that pumping conditions could be simulated to determine the effect

that pumping and temperature increase have on the ultimate consolidation strength of the treated

proppant. At 30-, 60-, and 90-minute time intervals, samples of proppants were collected and

packed with fluid in consolidation chambers (1 3/8-in. ID × 5 in. in length) and cured at 325°F for

3 hours with no closure stresses applied. After curing, the consolidated proppant packs were

pressed from the chambers and were cut to desired lengths for unconfined compressive strength

(UCS) measurements. UCS measurements were performed at room temperature.

Fig. 2 shows that LRS coated on the proppant was capable of remaining on the proppant without

being removed from the proppant grains to provide consistent consolidation strengths despite

extended stirring time. A slight reduction of consolidation strength was observed for the LRStreated proppant when the fully crosslinked fracturing-fluid system was used.

Under similar testing conditions as those of LRS-treated proppant, the RCP system resulted in

much lower consolidation strength after being stirred in the uncrosslinked CMHPG-based

fracturing fluid. No measurable consolidation strength was detected after the RCP was stirred in

the fully crosslinked fracturing-fluid system (Fig. 2).

Effects of Suspending Time and Closure Stress on Consolidation Strength

Proppant slurries (7 lb/gal) of 20/40-mesh, resin-precoated bauxite RCP and 20/40-mesh bauxite

coated with the LRS (3% by weight) were prepared in a CMHPG-based fracturing fluid at a pH

of 10.2. The proppant-laden slurry was kept in a bath at 175°F and was stirred with a paddle

mixer to maintain suspension. A control test was performed with RCP and LRS-treated proppant

slurries being stirred at room temperature (RT). Two samples of each were taken after 30 and 60

minutes stirring. The samples were packed into the consolidation chambers with the fracturing

fluid and cured at 325°F for 3 hours. One sample had no closure stress applied during curing

while the other had 500-psi closure stress applied. After curing, UCS measurements were

performed for consolidated proppant packs. The results are shown in Fig. 3.

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The RCP consolidated packs, if measureable, provided very low consolidation strengths even

when closure stress was applied to the proppant packs during cure. On the other hand, proppant

coated with LRS still provided excellent consolidation results even after being subjected to long

stirring times at 175°F and when no closure stresses were applied during curing.

These results indicate that using RCP in the treatment of hot wells with bottomhole temperatures

(BHTs) around 325°F would not result in successful proppant-pack consolidation, while the LRS

should perform well.

Effects of Resin Concentration, Cure Time, and Temperature

The consolidation strength of the LRS-treated proppant can be significantly improved if the

amount of resin coating on the proppant (Fig. 4) and the cure time (Fig. 5) are increased. This

LRS system was designed to handle high temperatures, therefore, not much fluctuation in

consolidation strength was observed between 250°F and 325°F cure temperatures. The proppant

packs were cured without applying closure stresses.

Despite having no closure stress applied during curing at 325°F and only a small fraction of resin

(1%) coated on the proppant (Fig. 4) as compared to that of the RCP (4%), significant

consolidation strength can still be obtained for the proppant packs treated with LRS system. This

result is explained by the mobility of the liquid resin and by capillary forces. The liquid resin is

pulled to the grain-to-grain contact points by capillary forces providing localized high resin

concentration and consolidation strength. In contrast, much of the resin coated on RCP has

already been cured, with only a very small amount of resin available for additional curing after

grain-to-grain contact is made. Almost none of the partially cured phenolic resin is fluid enough

to be pulled by capillary action to the contact points of proppant grains.

SEM Studies

An environmental scanning electron microscope was useful in studying the consolidation of

resin-treated proppant. It permits visual observation of the resin distribution on the proppant

grains and at the contact points. SEM examination of consolidated samples that have been taken

to failure generally indicate that the number and size of resin footprints that remain correlate

nicely with compressive-strength measurements.

SEM photomicrographs were taken to better understand the progressive loss in consolidation

strength with increasing exposure to temperature and stirring before the onset of closure with the

RCP. Slurries of RCP and 20/40-mesh bauxite coated with the LRS system were stirred for 0

min, 30 min, and 60 min at 175°F and then cured under a 500-psi closure stress at 325°F for 3

hours, after which SEM photomicrographs were taken of the proppant packs.

Figs. 6 to 8 are the photomicrographs for RCP. These photos reveal the lack of area and number

of contact points between grain-to-grain in cured samples of RCP. The DSC data indicates that

the loss in consolidation strength of RCP is most likely a result of the resin curing before good

grain-to-grain contact is achieved, as indicated in Figs. 1 to 3.

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Figs. 9 to 11 are the photomicrographs taken under the same conditions for 20/40-mesh bauxite

proppant coated with the LRS system. The photomicrographs show that for these coated

proppants, the number and area of contact points did not decrease. These photomicrographs

reveal why losses in consolidation strength upon exposure to temperature before application of

closure were observed in the RCP but not in LRS-treated proppant. At these conditions, the RCP

has faster cure rates than LRS-treated proppant, and with extended pump times or delays in the

onset of closure stress, these conditions can result in considerable loss of consolidation strength

for RCP.

API Conductivity Testing

API conductivity testing included sample preparation and test cell assembly, a fracture

conductivity test, and conductivity results.

Sample Preparation and Test Cell Assembly

Formation core samples are shaped to fit the modified API linear flow cell. The exact cell design

was described in detail in API Recommended Practice 61 (RP61). The design creates a surface of

10 in.2 for contact area for proppant. The core wafers were used in the test cell to represent the

fracture faces in contact with the proppant.

Assembly progressed in sequence, with the bottom piston and core placed first. Next, the

proppant was loaded onto the bottom core at a 2-1b/ft2 concentration. The top core was placed

onto the proppant pack and was set with the top piston. The test cells were then placed into a

press where closure stress could be applied and the reservoir temperature could be controlled.

Test temperature can be controlled up to 350°F. Closure stress can be controlled up to 15,000

psi.

Fracture Conductivity Test

Water was used as the flowing fluid for conductivity measurements. Conductivity measurements

were taken several times over a period of at least 48 hours at the desired stress levels to get a

stable value. When a stable value was achieved, the stress was increased to the next level or the

test was terminated.

Conductivity Results

The results of API conductivity testing indicated that at low concentrations of LRS treated on the

bauxite proppant, the conductivity of the proppant pack was higher than that of the untreated

proppant at both low and high stress loads. At high resin concentrations (- 3% by weight), the

proppant pack conductivity was still higher than that of the untreated proppant at low stress loads

and became only slightly lower at high stress loads (Fig. 12).

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Proppant Flowback and Stress Loading Testing

Proppant flowback and stress loading testing included API cell setup, a single stress test, stress

loading, and test results.

API Cell Setup

An API conductivity cell was prepared with 3 lb/ft2 of 20/40-mesh bauxite proppant, placed

between two Ohio core wafers, resulting in a average proppant pack width of 0.:23 to 0.:27 in. The

proppant was coated with the LRS before being placed in the cell. Before the cell was closed, :2%

KC1 solution was added to help ensure good heat transfer. The cell was placed into the press and

the required stress was applied. Subsequently, the cell was heated to 300°F. The proppant pack

width was calculated by measuring the heights of the two pistons. On the inlet and outlet side,

displacement transducers were mounted on the top piston to monitor movement of the proppant

pack.

Single Stress Test

After the curing time, the filter was removed from the outlet of the cell, leaving a 0.3-in.

perforation opening. Pressure was measured constantly over the 5-in. length of the proppant

pack. Tap water was flowed through the pack after being heated in a 155-ft coil of 3/4-in. tubing

through an oil bath. The flow was increased when the pressure differential over the 5-in. pack

had stabilized. Proppant production is indicated when the displacement transducers move

significantly. Fig. 13 illustrates the equipment setup involved in the testing.

Stress Loading

After the proppant was cured at the desired stress and temperature conditions, the stress was

increased by 1,000 psi. When the proppant pack was stable, the filter was removed and the

proppant was ready for testing. If no proppant production occurred at maximum pump rate, 3.3

L/min, the stress was again increased by 1,000 psi. This process was repeated until proppant

production was observed.

Test Results

To obtain a clear picture of the behavior of the coating in combination with the proppant,

numerous tests were conducted. The stress during these tests ranged from 1,000 to 3,000 psi. The

curing time, time at desired temperature, and closure stress were set for 4 hours or 16 hours.

Table 1 shows the tests conducted at the single stress, while Table 2 shows the tests conducted

with stress cycling.

The results of the tests at the closure stresses of 1,000 and 3,000 psi, single stress tests showed

no proppant production at maximum achievable velocity (- 22 cm/sec). Fig. 14 shows no

indication of proppant production; the stress remains stable and without displacement movement.

In the event of proppant production, up to 50% of the placed proppant pack may produce through

the 0.3-in. perforation in seconds. This situation is demonstrated in Fig. 15, which shows sudden

proppant production occurring after 53 minutes.

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When a stress load was applied to the proppant pack, the pack width decreased approximately

0.02 in. per each addition of 1,000-psi closure stress. The results after 4 hours of curing show a

decrease in the flow rate at which proppant production occurs compared to the tests where no

stress load was performed. The same tests were conducted after 16 hours curing. The fluid flow

rates at which proppant production occurred are significantly higher compared with 4 hours

curing. The stress load from 1,000 to 2,000 psi resulted in no proppant production (Table 2).

Field Applications

A field with deep, hot, and highly productive wells

developing a fracturing stimulation process that:

2.

3.

4.

provided a significant challenge for

Provided excellent stimulation in production

Minimized shut-in time before fracturing fluid recovery operations

Permitted maximum cleanup rate

Yielded little or no proppant flowback production

Typical wells in this field have BHTs greater than 325°F with fracture closure stresses up to

approximately 12,000 psi. Because using force closure or aggressive flowback procedures on

these wells as soon as the fracturing treatment was over was desirable, the common practice of

using RCP materials and shutting the wells in for several hours after the fracturing treatment was

not acceptable. The quicker the fracturing fluid is removed from the well, the quicker the well

can be put on production. As a result of these criteria, the selection of curable resin system for

controlling the proppant flowback has a small window of opportunity. These criteria include:

The resin-treated proppant must cure slowly enough at expected temperatures and remain

in suspension mode long enough to be removed from the wellbore with the flowback in

case of premature screenout.

 ̄ It must provide sufficient consolidation strength to handle initial flowback after two

hours of shut in.

General Fracturing Treatment Descriptions

Multiple fracturing treatments were applied in each well through separate perforated zones for

drainage of the reservoir. Fracturing treatments were performed down the casing. Fluid

efficiency tests (FETs) were pumped before every fracturing treatment, followed by a rate stepdown test to determine perforation friction and porosity. Before the fracturing treatment began, a

fluid efficiency, leakoff number of psi/min, and ISIP were evaluated to determine pad size.

Average pad sizes for the treatments were 45%, using 45,000 gallons of fluid. Approximately

75% of the fracturing treatments had proppant slugs of 1 to 1.75 lb/gal pumped during the pad

volume. Normally, proppant slugs were pumped depending on the size of job in relation to the

amount of friction observed in the step-down test. So it varied from well to well. Typically, a

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slug of 1 lb/gal for 1,500 lb and another slug of 1.75 lb/gal for 2,000 lb were pumped during the

pad.

Typical treatment had a pump rate of about 35 bbl/min and used about 300,000 lb of bauxite.

Typical proppant concentrations were from 2 to 8 lb/gal, and were ramped or stair-stepped

during the job.

Zones were isolated with composite bridge plugs, then coiled-tubing drilling was performed

following the last fracturing treatment. When the plugs were drilled, the well was put on

production.

Application of Liquid Resin System

At the well site during the fracturing treatment, liquid-additive pumps continuously transferred

the individual components of the two-component resin system from their respective containers

and mixed them together. The mixing of the two components, a liquid resin and a liquid

hardener, transformed these components into a homogenous activated resin mixture. The

amounts of individual components were metered in proportion with the desired pump rate and

the proppant rate being used during the treatment. This mixed resin was then applied directly to

the proppant before being delivered to the blender tub. The concentration of resin for coating on

the proppant was about 3% based on the weight of proppant.

Placing the resin on the proppant before adding it to the blender tub has been determined to be a

key component of this system, because it helps ensure that proppant surfaces are uniformily

coated before contact by the water-based fracturing fluids. This method improves the resincoating efficiency, reducing the impact of dispersed resin on the fracturing fluid. Because the

objective was to eliminate proppant flowback under the most severe conditions, it was

considered paramount that all the proppant pumped into the fracture be resin-coated. This

requirement eliminates potential proppant convection issues and multiple fracture problems.

Flowback and Cleanup Procedures

After the fracture stimulation treatment, the wells were subjected to shut-in for 2 hours before

flowback was initiated. The typical procedure called for the flowback to begin at no more than

50 bbl/hr for the first few hours and be ramped up afterward until gas was produced. If an

unexpected screenout occurs during the fracturing stimulation treatment, the pumping process is

suspended and the well is allowed to flow back to the disposal containers. The timeliness of this

flowback procedure helps to minimize post-screenout cleanup involving various processes such

as the use of coiled tubing to remove the resin-treated proppant suspended inside the wellbore.

A thorough cleanup procedure was applied to pumping equipment, blender tub, and flow lines,

as the LRS-treated proppant was being displaced to the disposal container.

The Use of Tagging Agent Tracers

To help determine which fracturing treatment for a well fractured with multiple stages was

responsible for producing proppant back to the surface during the flowback, cleanup, or during

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production, a known concentration of various chemicals was mixed with the resin system used to

coat the proppant. These chemicals then became a permanent part of the proppant that is encased

with hardened resin. Analyses for these chemical agents provided a convenient way to

differentiate individual fracturing treatments on the well. If the proppant flowed back to the

surface during the flowback, cleanup, or well production, a small sample of this proppant was

collected and analyzed to determine exactly from which zone or fracturing treatment it was

produced.

General Field Test Results

Highly effective fracture stimulation was achieved and aggressive cleanup procedures were

successfully practiced with this resin system with only a 2-hour shut-in time after treatment,

significantly minimizing time before commercial well production could begin.

Conclusions

Based on laboratory testing and field application, the following conclusions can be reached:

A newly developed resin system has been field-proven to permit aggressive well cleanup

procedures to be used after fracture stimulation. This system can improve time to market

for hot, high-rate wells significantly.

 ̄ A new resin system that permits coating of proppant just before blending with the

fracturing fluid can minimize chemical interferences with fracturing fluid.

 ̄ The slow curing rate of the new resin system can allow maximum consolidation strength,

but sufficient early strength to permit flowback to begin with very short shut-in time.

 ̄ Additives included in the liquid resin facilitate the removal of crosslinked fracturing fluid

from the proppant grains.

 ̄ Resin-coating of the entire proppant stage helps eliminate the possibility for uncoated

proppant being produced back.

 ̄ A series of chemical tracers that are included within the liquid resin can enable operators

to diagnose from where proppant is produced in wells that have multiple fracture

treatments.

SI Metric Conversion Factors

psi × 6.894 757 E+00

°F (°F-32)/1.8

lbm/U.S, gal × 1.198 264 E+02 = kg/m3

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lbm × 4.535 924 E-01

gal × 3.785 412 E-03

= kg

3

=m

References

1. Murphey, J.R. et al.: "Proppant Flowback Control," paper SPE 19769 presented at the 1989

SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8-11 October.

Norman, L.R. et al. : "Applications of Curable Resin-Coated Proppants," Production

Engineering (November 1992) 343-9.

Vreeburg, R.J. et al.: "Production Backproduction during Hydraulic Fracturing--a New

Failure Mechanism for Resin-Coated Proppants," JPT (October 1994) 884-9.

Blauer, R.E. and Holcomb, D.L.: "The Detection, Simulation, and Reservoir Performance

Impact of Slowly Closing Fractures," paper SPE 37404 presented at the 1997 SPE

Production Operations Symposium, Oklahoma City, Oklahoma, 9-11 March.

Cleary, M.P. and Fonseca, A.A: "Proppant Convection and Encapsulation in Hydraulic

Fracturing: Practical Implications of Computer and Laboratory Simulations," paper SPE

24825 presented at the 1992 SPE Annual Technical Conference and Exhibition, Washington,

DC, 4-7 October.

Almond, S.W., Penny, G.S., and Conway, M.W.: "Factors Affecting Proppant Flowback with

Resin-Coated Proppants," paper SPE 30096 presented at the 1995 European Formation

Damage Conference, The Netherlands, 15-16 May.

Nguyen, P.D. et aL: "New Guidelines for Applying Curable Resin-Coated Proppants," paper

SPE 39582 presented at the 1998 International Symposium on Formation Damage Control,

Lafayette, Louisiana, 18-19 February.

Todd, B.L. et al. : "Resin Compositions and Methods of Consolidating Particulate Solids in

Wells with or without Closure Pressure," U.S. Patent 6,311,773, November 6, 2001.

Table lmTests Conducted at Single Closure Stress

Closure Stress Curing Time Flowback Velocity ~p

(psi) (hr) (Yes/No) (cm/s) (psi)

1,000 4 No 20.8 11.0

1,000 16 No 20.1 12.1

3,000 4 No 22.0 16.6

3,000 16 No 22.8 23.5

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Table 2mTests Conducted with Stress Loading

Closure Stress

During Cure

(psi)

1,000

1,000

1,000

1,000

1,000

Flowback Curing Flowback Velocity Ap

Stress Time (Yes/No) (cm/s) (psi)

(psi) (hr)

2,000 4 Yes 3.7 1.5

2,000 16 No 18.3 17.3

3,000 16 No 19.4 26.0

4,000 16 No 20.8 34.8

5,000 16 No 19.2 39.5

,ooi

~ 8o /

~- ~o

0

0 1 2 3 4 5 6 7 8 9 10

Time, hr ~

--e~225°F RCP --I-.. 275°F RCP --~--225°F LRS 275°F LRS °s

.... z

Fig. 1--Comparison of conversion or cure rates of resin coated on RCP and high-temperature LRS system.

HESI301687
1,400

1,200

1,000-

800

600

4OO

2OO

0

RCP in RCP in LRC in LRC in

Uncrosslinked Crosslinked Uncrosslinked Crosslinked

~0 min ~30 min 1-160 rain 1-190 min

Fig. 2--Effect of stirring RCP and LRS-treated proppant at 175°F in uncrosslinked and crosslinked fracturing fluids, then

curing at 325°F on their consolidation strengths.

1,600

1,400 ~

._ 1,200

o. 1,000-

~ 800

 ̄ ~ 600-

400

200-

o,O

~0 min ~30 rain 1360 rain

Fig. 3--Effect of suspending RCP and LRS-treated proppant at room temperature and at 175°F in uncrosslinked fracturing

fluid, then curing at 325°F with and without closure stress, on their consolidation strengths.

HESI301688
8OO

2OO

2 3 z

Resin Concentration, Wt. %

Fig. 4--Effect of LRS concentration on consolidation strength of proppant pack after curing at 325°F in crosslinked

fracturing fluid without applying closure stress.

1,200

1,000

800

600

400

200

0

6

Cure Time, hr

U250°F BI325°F ]

24 48

Fig. 5--Effect of cure time and temperature on consolidation strength of LRS-treated proppant packs after stirring in

crosslinked fracturing fluid for 60 minutes and curing without applying closure stress.

HESI301689
Fig. 6--RCP after mixing in uncrosslinked fracturing

fluid without stirring, then curing at 325°F for 3 hours.

Fig. 9--LRS-treated proppant after mixing in

uncrosslinked fracturing fluid without stirring, then

curing at 325°F for 3 hours.

Fig. 7--RCP after being stirred for 30 minutes in

uncrosslinked fracturing fluid at 175°F, then cured at

325°F for 3 hours.

Fig. 10--LRS-treated proppant after being stirred for 30

minutes in uncrosslinked fracturing fluid at 175°F, then

cured at 325°F for 3 hours.

Fig. 8--RCP after being stirred for 60 minutes in

uncrosslinked fracturing fluid at 175°F, then cured at

325°F for 3 hours.

Fig. 11--LRS-treated proppant after being stirred for 60

minutes in uncrosslinked fracturing fluid at 175°F, then

cured at 325°F for 3 hours.

HESI301690
i 0,000

g,O00

8,000

7,000

6,o,oo

5,000

41000 31000

2,000

1,000

0

4,000 6,000 8,000 10,000

Closure Stress, psi

--=--1% ----2% :: 3%

Fig. 12--Effect of LRS concentration and closure stress on proppant pack conductivity.

Pipe Rheometer

3/4-in,

Flowback Schematic Setup

Water Cooler

Relief Valve

8

35 M 3/4-in, 35 M 3/4-in,

tubing in tubing in

heating bath heating bath

300 M 1/4-in, tubing

~ Drain Static Mixer

Relief Valve

Pulse

-- Fluid

Water Coo~er

B,PR.

Drain

Fig. 13--Equipment setup for testing proppant flowback and stress loading.

HESI301691
3,500

~o 2,500

c 2,000

._~

~: 1,500

~ 1,000

~. 500

0

Stress ~

Fbwrate ..................................................~, .... Displacement 1 .... J

Displacement 2 ~"

10 20 30 40 50 60 70 80

Time, rain

19.5

14.5

9.5

4.5

-0.5

9O

Fig. 14--Example of proppant flowback test without failure of the pack.

6,500.

6,000.

5,500

5,000

4,500

4,000

3,500.

3,000

2,500,

2,000

1,500

1,000

5OO

0

0

 ̄ 1-- Stress ...................................... ~.

I -- Flowrate r’mJ.

"1 -- Displacement I ............................... .~._..

1 -- Displacement 2 ............................. ~ .....

10 20 30 40 50

Time, rain

....... 59.5

....... 49.5

....... 39.5

....... 29.5

19.5

........ 9.5

-o.5

6O

Proppant production

Fig. 15--Example of proppant flowback test with failure of the pack.

HESI301692