Production Improvement by Proppant Consolidation Applying Liquid

Resins On-the-Fly during Hydraulic Fracturing: Case History from

Burgos Basin - Oscar Araujo, Levi Rodriguez, and Elias Lopez, Halliburton; Leonel

Bailon, PEMEX

September 9–13 2012, Mexico City, Mexico

Abstract

Proppants that are factory coated with a partially cured resin, generally referred to as

curable resin-coated proppants (CRCPs), have been used in the industry to reduce

proppant flowback and to improve fracture conductivity. A more recent methodology is to

coat proppants on location using liquid-resin systems (LRSs). This method uses a

specific type of hydrophobic material to place a curable resin coating on the proppants

and has often been used in the industry specifically to prevent post-fracturing proppant

flowback. The proppants are coated on-the-fly on location with the proper concentration

of LRS material. This technology has also proven to both initially increase and better

sustain fracture conductivity over time. The use of liquid resins for proppant coating in

the Burgos basin (primarily gas producers) to enhance and maintain fracture

conductivity in several fields has shown to lead to better well performance than when

using the factory-coated CRCPs.

Production data from a LSR-treated well after four years of production is presented and

compared to a well with similar petrophysical characteristics completed in the same

productive block in the same formation using the same volume of a CRCP-type proppant

(60% production increase for the LSR proppants).

The similar conditions initially present in these wells forcefully supports the superior

behavior of LRSs compared to conventional CRCPs when placed using identical

treatment designs.

Introduction

The Burgos basin stratigraphic column (Fig. 1) includes sediments from the Paleocene

trend with thickness up to 30 ft. The producing trends include, from west to east, the

Jurassic-Cretaceous, Paleocene-Eocene, Wilcox-Queen City, Jackson-Yegua,

Oligocene Frio-Vicksburg, and Miocene. Most of the production comes from clastic

Paleocene in the western portion to Miocene in the east.

Fig. 1—Burgos basin location and stratigraphic column.

The fields in subject are Arcabuz and Velero, where the productive formation is Wilcox-4

and Wilcox-3 for the Arcabuz field and Paleocene midway and PM-10 for the Velero

field.

These fields require a large number of wells be drilled to be economically feasible. Most

of the wells are drilled to depths of 9,500 to 10,000 ft and often encounter challenges of

lost circulation and high-pressure zones. The wells are completed mainly using 3 1/2-

and 4 1/2-in. cemented tubingless completions and are then hydraulically fracture

stimulated.

In fracturing operations, proppant is carried into fractures created and extended by the

force of hydraulic pressure applied to subterranean rock formations. Proppant

suspended in a viscosified fracturing fluid is carried outwardly away from the wellbore

within the fractures as they are created and extended with continued pumping. On

discontinuing of pumping, the proppant remains in the fractures, holding the separated

rock faces in an open position and forming a conduit for flow of hydrocarbons or

formation fluids back to the wellbore.

The loss of conductivity of the propped hydraulic fractures can be caused by factors

such as diagenesis, stress cycling, fines migrations, partial crushing, embedment, or

proppant flowback. The result is production reduction, and additionally any proppant

flowback also causes tubing erosion, safety-valve erosion, disposal problems, and

increased costs. Extra equipment and operational costs are required for wells that

produce back proppant. In fact, the development of fields that, for economic reasons,

require special completions and several rig-equipment interventions, have been inhibited

because of the potential of proppant flowback. In most instances, the near wellbore

fracture conductivity will decrease because proppant is produced during the cleanup

after a fracturing treatment, and requires special equipment and operators to be

available to handle the material that is produced to surface. However, loss of long-term

fracture conductivity has also been shown to be related to geochemical reactions, which

occur at the proppant/fracture interface, resulting in proppant degradation and mineral

recrystallization in the pore spaces (Luna et al. 2008). Substantial work has been

conducted in the industry to explain, predict, and reduce the problems related to these

effects.

Unfortunately, variations in the formation’s in-situ stress and its mechanical properties

can lead to nonuniform fracture closure. One possibility is the formation of open

channels around proppant bridges. Fluid velocity in these channels can be extremely

high and can increase the tendency of proppant mobility and flowback in this region. An

incompletely closed fracture allows proppant to move freely (in suspension or migrating

intermittently) if it is not trapped between the fracture walls. As a result, when the fluid

flows back, any free-moving proppant can be brought back to the wellbore and

consequently lead to the loss of fracture conductivity (Al-Ghurairi et al. 2006).

This paper provides a brief overview of the causes of loss of conductivity, along with the

methods that have been applied to curtail the problem and their shortfalls. The

mechanical properties and conductivity-enhancement characteristics of LRSs are

presented. The use of liquid resins for proppant coating in the Burgos basin, which has

been applied to enhance and maintain conductivity in several fields, has shown to have

better performance than the use of factory-coated CRCP proppants. Laboratory results,

case histories, and recommendations are discussed.

Past and Present Methods to Enhance and Maintain Conductivity and

for Proppant-Flowback Control

An obvious method to enhance and maintain conductivity, including stopping flowback

from a well that is experiencing proppant production, is to reduce the velocity rate to a

point where the production is again proppant-free. This method is not a true cure and

has negative financial consequences for the well owner. A better approach is to prevent

proppant from being produced when flowing at desired production rates. A key to

enhance and maintain conductivity and also prevent proppant flowback lies in the proper

design of the treatment, as previously mentioned. The combination of a propped fracture

with sand-control screens has been successfully applied for frac-and-pack applications.

Screens, however, add additional cost to the completion of the well and are known to fail

with time in conventional sand-control applications.

Fiber particles also have been used in attempts to overcome proppant flowback by

incorporating the fibrous material into the proppant fracturing fluid. The fibers are

believed to bridge across constrictions and orifices in the proppant pack to form a mat or

framework that holds the particulate in place, thereby limiting particulate flowback.

Fibers of sufficient length and stiffness are required to form this mat. One disadvantage

of this method is the tendency of stiff and long fibrous ends to break because of their

small diameter. Glass fibers in particular tend to break into small fragments when

sheared by the pumping equipment. Broken fiber fragments produce a weakened

framework in the fracture. These fragments and fibers can be produced with the

fracturing fluid and can cause plugging problems.

Other approaches that have been investigated and used are methods to improve the

internal resistance of the particles that comprise the pack. Inclusion of different sizes or

angular grains increases the resistance to flowback but, at the same time, reduces the

effective conductivity of the proppant pack. This method has had little field application.

Curable resin coatings, both precoated and coated on-the-fly during a treatment, have

had wide application and are discussed in more detail in the next section.

Factors Affecting Fracture Conductivity

Several factors affect the conductivity of a propped fracture and ultimately the

productivity of a well. As mentioned, diagenesis, stress cycling, fines migrations,

embedment, partial crushing, proppant flowback, and the migration of fines onto the

proppant pack after a hydraulic treatment have been recognized as some of the main

factors affecting fracture conductivity. The latter occurs when flocculation of the fines

creates larger particles that result in pack plugging. Infiltration of fines into a pack in

effect reduces the conductive width of the fracture and provides a source of fines that

can migrate upon stress cycling. Fines can be a product of the proppant breakdown

under closure stress or they can come from the formation that is in contact with the

proppant bed. Fines migration is often related to unconsolidated formations; however, it

can also come from hard rocks if the fracture face crushes under the load of the

proppant (Soriano et al. 2007).

Stress Cycling

Closure stress on the pack will increase as the drawdown of bottomhole pressure

increases; closure stress will subsequently decrease if a well is shut-in. Conductivity

studies are often performed by cycling the closure stress and flow rates to simulate

flowing wells at different drawdown pressures. Generally, there is a significant loss of

conductivity each time stress is increased until the pack is well-stabilized. As higher

closure stress loads are applied to the proppant packs during production, proppant

crushing as well as proppant embedment onto the formation can continue to contribute

to loss of conductivity. This type of testing is often used with soft formations to induce

fines movements from the formation into the pack (Fig. 2).

(a) (b)

Fig. 2—(2a Left) stress changes within formation and proppant pack cause conductivity

reduction; (2a right) the effect of production cycling is shown. (2b Left) base proppant,

(2b center) proppant after 10 cycles at 8,000 psi, and (2b right) proppant after 20 cycles

at 8,000 psi. Notice the obvious crushed fines (near the bottom) and damaged proppant

(circled in right photo).

Proppant Embedment—Brinell Hardness Number

The interface area (where the proppant pack contacts the formation face) carries the

overburden load, and stresses might not be well-distributed in this area. It is believed

that most damage to conductivity occurs in this region. Examination of the formation

core faces after conductivity measurements reveals insight into the embedment of

proppant into the core material. Very soft formation material can be imbedded one or

two proppant grains deep; while, on hard rock, only minor embedment is observed; the

size and distribution of embedment footprints provide some quantification of this effect

(Weaver et al 2006).

Whole-core testing indicates that, because the rock is relatively soft (low Young’s

modulus (YM)), it is prone to proppant embedment (Figs. 3 through 5). Fig. 3 illustrates

that the embedment in formation at 5,000-psi closure stress will have about 0.20 grain

diameters of embedment, while the embedment in formation at 10,000-psi closure stress

can have an entire grain diameter of embedment.

Fig. 3—Embedment effect from closure stress.

Fig. 4—Proppant embedment simulations for various YM vs. closure stresses.

Fig. 5—Proppant embedment observed after fracture conductivity testing.

Proppant Diagenesis

Clean proppant packed into hydraulically created fractures in formations of high

temperature and stresses undergo rapid diagenesis type reactions that may result in

dramatic reductions in pack porosity. It has been discovered that dissolution-mediated-

compaction reactions accelerated from a few centuries (normally expected with

diagenesis) to a fraction of a year as the temperature is increased, resulting in

decreased porosity (15 to 25% of starting porosity) and this would contribute to

underperformance of hydraulic-fracture stimulation treatments; this effect is believed to

be a contributor to accelerated production-rate decline.

Proppant Flowback

When proppant produces out of the fracture along with the produced fluids, fracture

conductivity diminishes with time and closure stress (Fig. 6) as the fracture width

decreases; thereby creating a choking effect that causes the potential production of the

well to decline. The use of resin-coated proppants (CRCPs) to reduce the back

production of proppant led to the discovery that resin coating could provide significant

improvements in conductivity performance.

Fig. 6—(Left) ceramic proppant exposed to closure stress and temperature in a solution

of 2% KCl. At right, the same proppant type exposed to same conditions but coated with

surface modification agents (SMAs), one type of a LRS.

CRCP Problems

CRCP was first introduced to the industry during the 1970s as a means to prevent

proppant flowback. CRCPs are pre-coated on the proppant before delivery to location,

or a resin material can be coated on-the-fly during a fracturing treatment (LSR). CRCPs

have been used in areas where proppant back production proved to be a problem or

where the risk of proppant back production was considered to be too great. CRCPs may

not be substituted for regular proppant during a job because the reactive resin can affect

the fracturing fluid chemistry and the added cost can become prohibitive.

Because of their higher costs, CRCPs are most often used as a tail-in for the last 20 to

40% of the proppant placed during a fracturing treatment. Although sometimes

successful, in many applications, the results of this method of treatment can be

disappointing. For wells with multiple intervals or large perforated intervals that are

treated with multiple fractures present, or parts of a single fracture in high-stress zones

can screenout early during the proppant stages that do not contain any CRCP, and this

uncoated sand can be produced back. Uncoated proppant can also be produced back

from a well that has been perforated over a relatively short interval if the treatment was

not properly designed and the high-proppant-concentration CRCP stages have been

transported away from the near-wellbore area because of buoyancy forces; uncoated

proppant may have earlier been deposited very near the wellbore and later coated

proppant could not displace it. CRCP tail-ins have, however, been successfully used in

horizontal wells with transverse fractures and short perforated intervals.

Loss of permeability has been reported to occur after treatments that used 100%

CRCPs. Proppant flowback has been reported after an initial proppant-free production

from wells that were fractured using CRCP. The cause of this proppant flowback was

identified as failure of resin bonds between the proppant grains caused by stress cycling

of the wells during production operations. Results obtained from an earlier study

revealed that high consolidating strength in the proppant bed is not always necessary to

prevent proppant flowback. Therefore, an alternative approach that provides an effective

and versatile solution was needed.

Post-Stimulation Performance

The importance of fracture conductivity and its effects on well productivity are well-

understood in the petroleum industry (Al-Ghurairi et al. 2006). Post-treatment

performance in many wells seems to suggest that the effective fracture length can be

different than expected (or predicted by the design simulations). The shorter effective

fracture lengths might be the result of fluid-cleanup issues or loss of fracture conductivity

caused by fluid residue, such as filter cake, or formation embedment of proppant.

Although solids-free high-rate gas production has been achieved in the majority of wells

for which the strategy has been implemented, a reduction in fracture conductivity in the

form of positive skin has been detected from pressure-buildup tests conducted on a

number of fractured wells. Part of this detrimental effect results in all likelihood from

partial perforation effects, given that the interval from which a fracture is initiated is

usually perforated in high-YM rock and limited to 60 to 120 ft in tight formations. Through

extensive industry testing, it is well-known that the combination of CRCP and fibers can

reduce fracture conductivity in treated wells.

Fig. 7 shows a pressure and derivative plot of a build-up period corresponding to a

typical response of a hydraulically fractured well using CRCP. The pressure derivative

signature does not indicate a clear fracture response, usually represented by a linear

flow followed by a bilinear flow.

Fig. 7—Derivative response of hydraulically fractured well using CRCP.

LRSs

It has been demonstrated by lab testing and field trials that there is benefit to be gained

through the use of LRSs. Previous work has suggested that these techniques could

reduce the potential damage associated with formation material entering the proppant

pack. In addition, studies have shown that applying surface modifying agents (SMA)

using relatively low resin concentrations and LRS with traditional resin concentration to

proppant resulted in a proppant of higher porosity and pack permeability over a wide

range of stresses (Soriano et al. 2007). Another benefit of using these materials on

proppant is that they minimize the loss of conductivity associated with the formation

mechanical properties by stabilizing the formation surface at the interface. Three

different types of proppant were used on these evaluations: bauxite, intermediate-

strength proppant, and economical lightweight ceramic proppant. Conductivity values

obtained from these tests clearly showed the benefits of coating proppants with LRS

(Fig. 8).

Some parts of the family of LRS products were introduced for handling proppant-

flowback problems after hydraulic-fracturing treatments. These systems are designed to

minimize the chemical interference between the resin and fracturing fluid and also

minimize the logistical problems on location. Additives included in the LRS facilitate the

displacement of fracturing fluid from the proppant grain surfaces and replacing it with the

resin coating. Some application methods place the resin coating on the proppant before

the proppant is added to the fracturing fluid. This new system includes:

A low-temperature, two-component epoxy system designed for a temperature

range of 70 to 225ºF.

A high-temperature, two-component epoxy system designed for a temperature

range of 200 to 350ºF.

A high-temperature, one-component furan system designed for a temperature

range of 300 to 550ºF.

Fig. 8—Photomicrographs of a widely used CRCP (left) and proppant coated using LRS

(right). Both samples were handled identically and tested to completion. Resin-contact

footprints correlate closely to compressive strength. Note the lack of contact footprints

on the CRCP. With LRS, capillary action causes flow of the liquid resin after grain

contact, resulting in greater concentration of resin at contact points for increased

durability.

The LRS has a delayed cure time, and its consolidation strength helps reduce the

amount of proppant being produced back to surface during cleaning and production

stages. All the resin components are preblended, so only the preblended solutions are

brought to the site. As long as the individual components are separated, they should

remain stable for many months. The two components are metered together on-the fly

through a static mixer to form a homogeneous mixture before being coated directly onto

the proppant in the sand screws. Several field cases have already been published,

showing successful results from using these LRS for conductivity enhancement and

proppant-flowback control (Fig. 9) (Soriano et al. 2007).

Fig. 9—Comparison of conductivity (md-ft) using CRCP and LRS with regard to closure

stress, demonstrating LRS showed better performance and conductivity.

Candidate Selection: Case History

The selected candidate wells were two similar wells (Well A and B) drilled out about 40

m from one another at the surface with 200 m of subsurface spacing. The tight-gas wells

were in a low-permeability formation. The goal of the operator was to use the similar

wells to compare production results using LRS instead of RPC on one of the wells.

Well A and Well B both had synchronized Formations W-3 and W-4.

Levels of W-3 and W-4 shared similar petrophysical characteristics.

They belong to the same productive block.

They shared similar initial pressure and reservoir conditions.

There was little structural difference between Formation W-3 and W-4 of both

wells.

Well A was an S-type, off-track well, while Well B was vertical.

Hydraulic-Fracturing Design

Well A was fractured using ceramic 20/40-mesh proppant, with the last part a

factory-coated CRCP.

Well B was fractured using ceramic 20/40-mesh proppant, with the last part on-

the-fly coated with LRS.

Equal volume of treatment was used for both wells.

Fig. 10 shows the first logs for the deeper W-4 (shown first) formations and Fig. 11

shows the lower part of the W-3 formations of Wells A and B.

Well A (Formation W-4) Well B (Formation W-4)

Fig. 10—Logs for the W-4 formations.

Well A (Formation W-3) Well B (Formation W-3)

Fig. 11—The lower part of W-3 formations of Wells A and B.

Fracture-Treatment Design: Case History

Several sensitivity runs were made to optimize the treatments on Wells A and B in the

W-4 and W-3 formations, respectively. The simulation runs showed that perforating the

deeper interval (W-4) from 10,282.8 to 10,315.6 ft and in the lower formation (W-3)

interval from 9,682.56 to 9,715.36 ft would generate a better fracture geometry, avoiding

fracture growth, thus increasing the risk of premature screenout caused by the presence

of high-stress sections. The main treatment design started with 400,000 lbm of 20/40-

mesh intermediate-strength proppant (ISP) and 85,000 gal of 30-lbm crosslinked gel,

designed to achieve approximately between 165 and 200 m of fracture half-length.

After analyzing the minifrac, it was decided to adjust the pumping plan to a 20% PAD

volume and a rate of 32 bbl/min. During the PAD, 20 sacks of 20/40-mesh sand were

pumped at 1 to 2 lbm/gal as a slug to evaluate if near-wellbore problems were present;

no adverse pressure response was observed when this sand slug reached the

perforations. A net increase of about 250 psi was observed through the main course of

the proppant stages entering the fracture, reaching a maximum proppant concentration

of 8 lbm/gal. During wellbore displacement, the rate was reduced to assist closure of the

fracture. A total of 100% of the operational program was completed.

The first 85% of the proppant, which included the 1- to 7-ppa stages, was not coated

with CRCP or LRS; the remaining 15% of ceramic proppant at the tail end, used CRCP

or LRS, was applied in Well A. The proppant treated with 3% LRS was during the latter

part of the 7-ppg and all the 8-ppg stages on Well B (Figs. 12a and 12b).

Fig. 12a—Well B wellbore diagram.

Fig. 12b—LRS treatment chart data for Well B.

Field Implementation

The actual fracturing treatment was split into stimulation of W-4 zone and W-3 zones,

using essentially similar designs that all placed 400,000 lbm of 20/40-mesh ceramic ISP.

In all cases, the last 50,000 lbm at the end of the proppant ramp were replaced with

CRCP and or treated with LRS. Pad volume was, on average, about 25,000 gal based

on the results of fluid-efficiency data collected during the minifrac.

The treatments were 100% successfully executed, as per the scheduled design of each

well and each formation. All 400,000 lbm of 20/40-mesh ISP (including 50,000 lbm

CRCP on Well A and coated on-the-fly with LRS on Well B in both W-4 and W-3

formations) was displaced into the formation. A maximum surface-treating pressure of

8,730 psig and a maximum rate of 32 bbl/min were attained, as shown in Table 1.

The information in Table 1 shows all parameters, from the design to the actual treatment

of the two-each fracture jobs performed on Wells A and B. Well A was stimulated with an

CRCP during last 500 sacks of ceramics proppant. Well B was stimulated with an LRS

during last 500 sacks of 20/40-mesh ceramic proppant.

To date, several wells have been hydraulically fractured using LRS with ceramic

proppant. This paper will next show Well C that was also treated with LRS at the end of

the proppant concentration, in the 9 to 10 lbm/gal stages, resulting in a long and

sustainable term of production.

Fracture Parameters Well-A_W-4 Well B_W-4 Well-A_W-3 Well-B_W-3

Design Real Design Real Design Real Design Real

Frac fluid (lbm) ZrCMHG

30 ZrCMHPG

30 ZrCMHPG

30 ZrCMHPG

30 ZrCMHPG

30 ZrCMHPG

30 ZrCMHPG

30 ZrCMHPG

30

Pad (%) 23 24 22 23 24 25 23 26

Carrier fluid (gal) 85,000 87,315 88,530 84,784 87,000 83,205 84,880 82,824

BH proppant concentration (lbm/gal)

1 to 8 1 to 8 1 to 7 1 to 8 1 to 7 1 to 8 1 to 7 1 to 8

Ceramic 20-40-mesh + RPC/LRS (Klbm)

350/50 347/57 350/50 343/50 350/50 350/58 350/50 350/51

Rate average (bbl/min) 28 32 32 32 30 30 32 32

Pressure average (psi) 4,154 6,564 7,136 6,566 6,853 6,574 6,760 6,459

Maximum pressure (psi)

4,657 8,493 7,891 8,730 7,775 7,138 7,453 8,926

ISIP (initial/final) (psi) 3,075 4,346 4,701 4,628 4,492 4,474 4,525 4,497

Fracture proppant length (m)

167 182 163 178 204 159 194 170

Fracture height (m) 51 53.2 65 62 47 63 65 59

Width average (in.) 0.5 0.802 0.63 0.72 0.8 0.83 0.61 0.7

Conc. areal average (lbm/ft

2)

1.74 2.57 2.08 1.95 2.45 1.89 2.05 1.51

Conductivity average (md-ft)

2327.3 6393 4141 4282 8777 7711 4160 4690

FCD 74.57 214 155 146.5 130 147 130 168

Table 1—Fracture results.

Well C: Case from Velero Field—Midway PM-10 Formation

This well was fracture stimulated sometime after production results from the Wilcox

formation were reviewed. Also a tight-gas well with very low permeability, it showed

initial post-stimulation gas rate production of 4.9 MMscf/D, and 4.1 MMscf/D established

after one week. During the operation, the resin was applied during the last 80,000 lbm of

20/40-mesh ceramic proppant. Fig. 13 shows well log information and a diagram of the

completions for Well C. Fig. 14 shows the pumping data during the hydraulic fracture

treatment on Well C, and the calculated pressure increase caused by added fluid friction

after the point marked, but the BH pressure calculation rise resulted from the error

introduced into that calculation by not allowing for the increased friction effect. Table 2

shows fracture stimulation results.

Fig. 13—Processed logs and wellbore configuration.

Fig. 14—Hydraulic fracturing treatment data for Well C.

Fracture Parameters Design Actual

Frac fluid, lbm Zr CMHPG 30-25 Zr CMHPG 30-25

PAD (%) 25 26

Carrier fluid (gal) 89,200 88,550

BH proppant concentration (lbm/gal) 1-10 1-10

Ceramic prop 20/40-mesh + LRS (Klbm) 450/80 450/80

Rate average (bbl/min) 35 35

Pressure average (psi) 4558 4830

Maximum pressure (psi) 4908 6068

ISIP (Initial/final) (psi) 2756 2760

Fracture propp length (m) 164 166

Fracture height (m) 62 56

Width average (in) 0.52 0.40

Conc. areal average (lbm/ft2) 2.54 2.60

Conductivity average (md-ft) 2810 2880

FCD 32.80 33.42

Table 2—Fracturing stimulation treatment results.

Fig. 15 shows the forecast production pre- and post-fracture stimulation for Well C. The

figure shows a forecast prefracture scenario with 1.1 MMpcd, Pwf = 2,600 psi, DP =

1,680 psi at 10/64 in. Also, it shows the forecast for production after the treatment

varying the choke; 3.40 MMpcd, Pwf 4,127 psi DP=153 psi at 14/64 in. Xf=150 m and

4.40 MMpcd, Pwf 4,127 psi, DP = 200 psi at 16/64 in. Xf = 150 m.

Fig. 15—Post-treatment simulated results for Well C.

Post-Treatment Production Results

Wells A and B were shut-in for 12 hours after the fracturing treatment to allow the CRCP

or the LRS chemical to cure inside the formation. Well A was fractured with CRCP and

later showed better initial production by about 5%, but was dropping faster. Both wells

were in continuous production until Well A stopped production in May of 2010. Well B

has obtained a higher daily rate than well A of about 0.45 Bcf more gas accumulated

during the comparative point of 951 days (2.6 years) as of May 2010, and has continued

to produce.

After the required shut-in time, the Well B responded slowly because of the hydrostatic

column of fluid residing inside the completion and possibly some type of plugging. A

subsequent tag indicated a wellbore obstruction 1,900 ft above the top perforation. The

obstruction was cleaned out by jetting fluids with high-pressure coiled tubing (CT)

equipment. After that, a solids-free rate of 4.3 MMscf/D at a flowing wellhead pressure

(FWHP) of 2,800 psig was achieved after two days of cleanup of the sand (Figs. 16

through 19).

Fig. 16—Well A treated with CRCP, production history. As of February 2012.

Fig. 17—Well B treated with LRS, production history. As of February 2012.

Fig. 18—Cumulative production of two wells fracture stimulated and then put to

production at the same time.

Fig. 19—Well C cumulative production.

The most important achievement has been the slower decline rates of Wells B and C

that were treated with LRS, as well as witnessed by the two to four years of continuously

sustainable production. Most of the wells in this particular field have short production

lives when conventional fracturing methods are used. In other words, wells not treated

with LRS have shown the classic decline curve characterized by an initial high

production followed by a rapid decline normally associated with loss of fracture

conductivity, possibly from proppant diagenesis damage.

Conclusions

The following conclusions are a result of this work.

A plan was made to select twin wells in similar conditions drilled at the same

block and formation with similar levels of petrophysical characteristics in an effort

to compare the performance of CRCP and LRS.

The new LRS was successful in enhancing the productivity of Well B. Post-

stimulation results exceeded the operator’s expectations, achieving good

performance. Increasing the long-term proppant-pack conductivity on Well B

resulted in better and sustainable production compared to Well A completed with

CRCP.

The conditions of the compared wells allowed confirmation of better performance

of LRS compared to conventional proppant resin vs. CRCP, increasing the

proppant-pack conductivity of Well B.

The maintained production implies at least one and probably more among this

group: the reduction of the diagenesis effect, reduction of plugging caused by

fines production, and/or reduction of proppant flowback.

Minor drawdown of the formation pressure led to a sustainable rate of production

over time, assisting in conductivity enhancement.

Wells treated with LRS still have sustained productivity after 49 months (4.08

year), instead of the classic decline curve characterized by an initial high

production followed by a rapid decline normally associated with proppant

diagenesis and/or other damage to fracture conductivity.

Recommendations

The following items are recommended.

It is proposed to apply LRS on all of the proppant pumped downhole to achieve

even more sustainable production and better protection against diagenesis,

stress cycling, fines migrations, embedment, and proppant flowback.

The use of LRS throughout the entire treatment should be beneficial for

stimulation purposes on these kinds of applications.

The equipment setup and the on-the-fly proppant-coating process is undergoing

continued improvement to help ensure all pumped material is properly coated.

A second pressure-transient test should be conducted after flowing Well B for an

extended period of time to ascertain whether higher-than-expected well

performance is long-lasting, and to obtain more representative values of fracture

length and conductivity.

Improvements

Listed below are suggested improvements.

Use conductivity endurance additives to sustain production by reducing proppant

diagenesis, flowback, and fines migration if found in wells in this kind of field.

Optimize the use of fluids with systems to improve pumpability, proppant

transport, and retained conductivity while providing environmental benefits.

Use microemulsion surfactants to enhance fluid recovery by reducing capillary

pressure.

Acknowledgements

The authors thank all of the personnel involved in the execution of this operation, and

Halliburton management for their support and permission to publish this paper.

References

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