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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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