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SPE-169107-MS Preformed Particle Gel Extrusion through Open Conduits during Conformance Control Treatments
Abstract
This paper was prepared for presentation at the SPE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, USA, 12–16 April 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohi bited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Millimeter-sized (10 um~mm) preformed particle gels (PPGs) have been used successfully as conformance control agents in more than 5,000 wells. They help to control both water and CO 2 production through high-permeability streaks or conduits (large pore openings), which naturally exist or are aggravated either by mineral solutions or by a high injection pressure during the flooding process. This paper explores several factors that can have an important impact on the injectivity and plugging efficiency of PPGs in these conduits. Extensive experiments were conducted to examine the effect of the conduit's opening size and the PPG strength on the ratio of the particle size to the opening diameter, injectivity index, resistance factor, and plugging efficiency. Five-foot tubes with four internal diameters were designed to emulate the opening conduits. Three pressure taps were mounted along the tubes to monitor PPG transport and plugging performance. The results show that weak gel has less injection pressure at a large particle opening ratio compared to strong gel. PPG strength impacted injectivity more significantly than did particle opening ratio. Resistance factor increased as the brine concentration and conduit opening size increased. PPGs can significantly reduce the permeability of an open conduit and their plugging efficiency depends highly on the particle strength and the conduit's opening size. The particle size of PPG was reduced during their transport through conduits. Experimental results confirm that the size reduction was caused by both dehydration and breakdown. Based on the lab data, two mathematical models were developed to quantitatively calculate the resistance factor and the stable injection pressure as a function of the particle strength, particle opening ratio, and shear rate. This research provides significant insight into designing better millimeter-sized particle gel treatments intended for use in large openings, including open fractures, caves, worm holes, and conduits. Introduction Excess water production in oil fields is becoming a challenging economical and environmental problem as more reservoirs are maturing. An estimated average of three barrels of water are produced for each barrel of oil produced worldwide (Bailey et al., 2000). It is estimated that the total cost to separate, treat, and dispose of this water is approximately $50 billion per year (Hill et al., 2012). Water can flow into the wellbore as a result of either near-wellbore problems or reservoir-related problems (Seright et al., 2001). The mechanisms that contribute to this undesired water production must be fully understood before the appropriate treatment can be chosen. Water channeling, one of the primary reservoir conformance problems, is caused by reservoir heterogeneities that lead to the development of high-permeability streaks. These streaks include open fractures and fracture like features, such as caves, worm holes, and conduits (Smith et al, 2006). These high-conductivity areas inside the reservoir only occupy a small fraction of the reservoir but will capture a significant portion of injected water. As a result, large amounts of oil remain unswept as a large water flood will bypass oil-rich unswept zones/areas. Gel treatments have been proven to be a cost-effective chemical conformance control technology to reduce the fluid flow in these large opening features. The application of these technologies can not only control water production but also significantly increase the oil production and extend the economic life of a reservoir. Traditionally, in-situ bulk gels have been used for this purpose. However, preformed particle gels recently have attracted much attention because they can solve some of the problems associated with in-situ gel systems, such as the dilution and dispersion of the gelant, chromatographic separation of the gelant solution, and so on. (Chauveteau et al., 2001, 2003; Coste et al., 2000; Bai et al., 2007a, 2007b).
Supplementary resource (1)
... Resistance factor as a function of concentration and superficial velocity 8.6.1.3 Effect of Swollen Degree of Nanogels on Injection Pressure and ResistanceFactor (Fr) Like other particle gels, nanogels can swell when certain environmental parameters change, such as the temperature, brine salinity, and pH [Bai et al., 2013]. ...
... 6 illustrates the permeability results obtained for 30-mesh size PPG swollen in three different brine concentrations. The results indicated that the KGB increased as the brine concentration increased. ...
... 6: Fluid and petrophysical properties for homogeneous sandpack experiment. ...
... Swelling ratio is defined as the ratio of PPG particle volume after and before swelling. Bai [7] and Imqam et al. [11] reported a relationship for swelling ratio as a function of salinity based on laboratory measurements. They showed that the particles can swell very fast within 60 min and the final swelling ratio depends on salt concentration, with higher salt concentration leading to the smaller swelling ratio. ...
Gel treatment is a cost-effective method for oilfield conformance control. Traditionally, in-situ gels formed by the reaction of polymer and crosslinker at reservoirs have been used widely to control conformance. However, a newer trend is to apply preformed particle gels (PPGs) for this purpose because they are formed at surface facilities before injection and they overcome some distinct drawbacks inherent in in-situ gelation systems, such as lack of control over the gelation time, gelling uncertainty due to shear degradation, chromatographic fractionation or change of gelant compositions, and dilution by formation water. PPGs are characterized as having robust gel chemistries and as being highly insensitive to petroleum reservoir environments and interferences. They can resist temperatures up to 120 ºC (250 ºF) and are compatible with any kind of formation water. In this paper, we describe and discuss our extensive laboratory and field experiences with the widely applied and successful PPG technology. Highlights of illustrative PPG field applications and results are presented. An overview of what over a decade of experience in applying the PPG technology has taught us is discussed. This includes a discussion of classifying and distinguishing conformance problems and treatments, attributes of good candidate wells, requirements that must be met in candidate wells, gel treatment elements that must be implemented successfully to achieve success, and the guidelines as to where PPG conformance treatments are applied most successfully.
Preformed particle gel (PG) has been successfully synthesized and applied to control excess water production in some mature water-flooded oilfields in China. Investigations show that PG is strength- and size-controlled, environment-friendly, stable over long periods of time, and very likely capable of overcoming some drawbacks inherent in gel treatments based on in-situ gelling. Its thermostabilization is not sensitive to reservoirs minerals and formation water salinity. To support its future applications, this paper describes experiments that investigate the mechanisms for PG propagation through porous media.
Visual observations in etched-glass micro-models demonstrate that PG propagation exhibits six patterns of behavior: direct pass, adsorption and retention, deform and pass, snap-off and pass, shrink and pass, and trap. Which pattern is dominant is related to the diameter ratio of swollen PG and pore throat, PG strength and the driving force.
In macroscopic scale, PG propagation through porous media can be described by three patterns: pass, broken and pass, and plug. Which kind of pattern is dominant can be determined by pressure change with time at different tap, particle size of effluent and residual resistance factor at different segment of a core.
Measurements from core-flooding and micro-model experiments show that a swollen PG particle can pass through a pore throat whose diameter is smaller than its diameter due to the elasticity and deformability of swollen PG. PG strength is a principle parameter to determine the diameter ratio of a PG particle and a pore throat that PG can pass through a porous medium.
A PG particle can move through a porous medium only if a driving pressure gradient is higher than a threshold pressure gradient. The threshold pressure depends on PG strength, the diameter ratio of particle and average pore size.
Further work will investigate the potential for PG to improve oil recovery and the optimization method to design PG treatments.
Water plays an essential role in the recovery of oil and gas. Managing subsurface water conformance can maximize hydrocarbon production and reduce operating costs. However, unchecked water can decrease hydrocarbon production, reduce oil and gas recovery, increase costs substantially, and lead to possible well abandonment.
In the life of a well it is natural that water will eventually enter into the production stream. It is important to identify the water’s source and reason for the intrusion, and how it is interacting with the wellbore. This knowledge can be used to create an integrated customized solution that fits the needs of the well. An indepth understanding of the reservoir can avoid water problem areas in new infield drilling by the use of advanced navigation and directional systems.
Water management is essential to maximizing returns on investment and in controlling costs. There are a variety of technologies available for near-wellbore control and reservoir water conformance. Understanding of the water mechanism followed by proper application is key to reducing excess water production.
In many successful conformance control treatments, large volumes of gels were extruded through fractures during placement. The pressure gradient for gel extrusion depends strongly on fracture width and gel composition. Extrusion experiments directly measure gel properties in fractures, but they are both expensive and time-consuming. In this work, we investigated whether using rheology measurements to assess gel properties in fractures might prove a good substitute for the extrusion experiments, at a much more reasonable cost. The rheology behavior of the gels tested showed a strong parallel to the results obtained from previous gel extrusion experiments. However, for a given aperture (fracture width or plate-plate separation), the pressure gradients measured during the gel extrusion experiments were much higher than anticipated from rheology measurements. Extensive experiments established that wall slip and first normal stress difference were not responsible for the pressure gradient discrepancy. Steady shear and oscillatory shear data were collected with a rheometer using both smooth and rough parallel-plate geometries and employing various gap heights. Wall-slip effects were present with smooth plates but negligible with rough plates.
To explain the discrepancy, we noted that the aperture for gel flow (for mobile gel wormholing through concentrated immobile gel within the fracture) was much narrower than the width of the fracture. Considering the shear-thinning properties of the gels, two models were developed using shell momentum balances. The first model explained why the pressure gradient for gel extrusion varied inversely with the square of the fracture width rather than inversely with fracture width. In particular, the relationship depends on the power-law index of the material. The second model correlated pressure gradient, shear stress, flow rate, and shear rate to bridge the gap between gel rheology in fractures versus in a rheometer.
Injecting preformed particle gel (PG) as a fluid-diverting agent to reduce water production is an attractive new procedure designed to minimize some of the risks inherent in gel treatments based on in-situ gelling. The objectives of this paper are: (1) understand how to control PG properties by changing gelant compositions and their fraction when synthesized; (2) determine where PG can be applied and how reservoir conditions affect PG properties; and (3) outline candidate well criteria and the proper injection procedures by illustrating several field applications.
Based on laboratory experiments, the following results will show that: (1) PG strength and swelling capacity can be controlled by adjusting gelant compositions; (2) certain additives can improve PG stability at elevated temperatures (120°C); (3) increasing temperature will increase the swelling ratio and the swelling rate of PG, and increasing salinity will reduce the swelling capacity of PG and will increase PG strength; (4) the swelling capacity of PG is insensitive to pH; (5) PG is insoluble in water, but absorbs it, swelling up to 20–200 times of its original size. It is strength- and size-controlled, environment-friendly and not sensitive to reservoir minerals and formation water salinity.
Three examples from more than 200 operations were selected to show how to choose candidate wells and how to operate the injection procedures.
PG can be used as a conformance control agent to correct permeability heterogeneity for those reservoirs with fractures or channels, both of which are widely found in mature water-flooding oilfields in China.
This paper investigates washout of mature Cr(III)-acetate-HPAM gels from fractures. After gel placement, the pressure gradient for gel washout during brine or oil flow was similar to the pressure gradient observed during gel placement. The mechanism of gel failure involved the displacement of relatively mobile gel from wormholes. Generally, only a small fraction of the gel (<5%) was displaced during the washout process. Resistance to washout can be increased by injecting a more concentrated gel. However, this approach exhibits significantly higher pressure gradients during gel placement.
The presence of a constriction in a fracture inhibited gel washout during the first pulse of brine flow after gel placement. However, during subsequent brine flow, gel erosion occurred upstream of the constriction to the same extent as downstream. The extrusion, leakoff, and washout behavior in fractures in strongly oil-wet polyethylene cores were similar to those in strongly water-wet Berea sandstone.
Gel washout can be reduced by controlling gel placement rate. A Cr(III)-acetate-HPAM gel placed in a 0.04-in. wide fracture at 826 ft/d was about five times more resistant to washout than a gel placed at 4,130 ft/d. Gel washout can also be reduced using secondary crosslinking reactions. Post-placement reaction with Cr(III) acetate increased resistance to washout for a resorcinol-formaldehyde-HPAM gel by a factor from two to three.
During steady state flow after first breaching the gel, a Cr(III)-acetate-HPAM gel reduced permeability to water (within the fracture) moderately more (2.5 to 4.7 times) than that to oil. Disproportionate permeability reduction in fractures was most evident at low flow rates.
This paper describes a straightforward strategy for diagnosing and solving excess water production problems. The strategy advocates that the easiest problems should be attacked first and diagnosis of water production problems should begin with information already at hand. A listing of water production problems is provided, along with a ranking of their relative ease of solution.
Conventional methods (e.g., cement, mechanical devices) normally should be applied first to treat the easiest problems— i.e., casing leaks and flow behind pipe where cement can be placed effectively and for unfractured wells where impermeable barriers separate water and hydrocarbon zones. Gelant treatments normally are the best option for casing leaks and flow behind pipe with flow restrictions that prevent effective cement placement. Both gelants and preformed gels have been successfully applied to treat hydraulic or natural fractures that connect to an aquifer. Treatments with preformed gels normally are the best option for faults or fractures crossing a deviated or horizontal well, for a single fracture causing channeling between wells, or for a natural fracture system that allows channeling between wells. Gel treatments should not be used to treat the most difficult problems—i.e., three-dimensional coning, cusping, or channeling through strata with crossflow.
This paper introduces a new diverting agent that has been developed to control water production in high salinity, high temperature reservoirs. Several dry gels have been crushed and sieved to obtain different cuts of gel particles. The dry powdered gel particles swell in water to give a stable suspension. The swollen pre-gelled (PG) particles do not dissolve in water and can move inside the porous media. Results presented here include test pilots and laboratory experiments. PG particles have been successfully used in two recent pilot tests in Shengli Oilfield, China. Micromechanisms of particle motion and oil mobilization have been studied through transparent glass micromodels experiments. Core tests have also been conducted to verify the selective placement of the particles. According to the experimental laboratory results we can conclude that the mechanisms responsible for the enhancement of oil production are the following:
After swelling and under a high pressure gradient (near the wellbore), the pre-gel particles can deform to pass through small pore throats, ensuring displacement of the residual oil. When the pressure gradient is too small (away from the wellbore) the particles plug the pore throats changing the flow pattern inside the reservoir.
In addition, as the gelation is accomplished before the injection, the PG particle technique overcomes some of the most important problems which can be encountered by classic gel treatments: lack of control of the gelation time, lack of control of the stability of the gel formed or ungelation due to adsorption, dilution or degradation of the polymer or pH change. Furthermore, due to these specific characteristics, this process can be used in oilfield environment that would prevent the in-situ gelation of a classical gelant solution.
High water cuts during waterflood operations are a major problem encountered in mature reservoirs. Areas of the reservoir that are fractured, either naturally or hydraulically, are excellent pathways for floodwater to bypass oil-bearing pore spaces. Gel placement within fractured zones of the reservoir is a technique that has been employed to decrease water production. In order to utilize this technique more effectively, the improvement of gel placement and its performance within fractures must be investigated.
For the purposes of this study, two experimental setups are developed. Initially an acrylic fracture model is developed in order to obtain qualitative information about flood fluid penetration into the placed gel. The rupture pressure of the HPAM-Cr (III) [hydrolyzed polyacrylamide-chromium (III) acetate] gel system is observed for 1x, 2x?and 3x?gel systems (multiplier refers to chromium concentration) within the fractures. The rupture pressures observed are generally higher for gel systems with greater chromium concentration. The acrylic setup also allows for visual observation of the gel's performance and behaviour during water injection. Water penetration is dominated by one major channel. Smaller channels are often observed to either branch off from the dominant channel or smaller side channels would connect and join the flow path of the major channel.
Secondly, Berea sandstone slabs are cut and an experimental setup is built in order to study two main mechanisms for improved gel placement. The application of Cr (III) acetate pre-flush and overload are investigated in order to determine their effect on gel performance within fractures. Both techniques compensate for the amount of chromium lost to the matrix via molecular diffusion and the integrity of the gel is maintained. This allows for significant fracture blockage without having to place performed gel or placing the gel ant with leak-off in order to achieve a stable gel.
Introduction
Many reservoirs currently under production suffer from excessive water production. Water could be supplied either by a natural water source (e.g. aquifer) and/or because of waterflooding. Waterflooding is normally used in order to displace any remaining oil in the reservoir matrix after the primary stages of oil production. Presence of high permeability zones in the reservoir provides pathways for water to bypass oil-bearing regions and break through into the production wells. Areas of the reservoir that are fractured, either naturally or hydraulically, are excellent pathways for floodwater to penetrate and consequently bypass oil-bearing pore spaces.
Blocking the high permeable thief zones and diverting water towards the unswept regions of the reservoir has been proposed and used by oil producers as a viable remedy for this problem. In-depth gel placement is the most widely used technique for blocking high permeable zones of reservoirs. This technique has been implemented through many field trials around the world and researchers have successfully determined the mechanisms governing this process in porous media.
Although gel placement in fractures is a common practice in the field, the mechanisms controlling the performance of this technique in fractures are not well understood. This has created a challenging opportunity for researchers to study the detailed mechanisms of gel placement and performance in fractures.
We investigated how different types of gels reduce permeability to water and gases in porous rock. Five types of gels were studied, including (1) a "weak" resorcinol-formaldehyde gel, (2) a "strong" resorcinol-formaldehyde gel, (3) a Cr(III)-xanthan gel, (4) a Cr(III)-acetate-HPAM gel, and (5) a colloidal-silica gel. For all gels, extensive coreflood experiments were performed to assess the permeability-reduction characteristics and the stability to repeated water-alternating-gas (WAG) cycles. Studies were performed at pressures up to 1,500 psi using either nitrogen or carbon dioxide as the compressed gas. We developed a coreflood apparatus with an inline high-pressure spectrophotometer that allowed tracer studies to be performed without depressurizing the core. We noted several analogies between the results reported here and those observed during a parallel study of the effects of gel on oil and water permeabilities.
This work constructed transparent fracture models to visually track swollen preformed-particle-gel (PPG) propagation through open fractures and water flow through PPG placed in the fractures. During injection, PPG propagated like a piston along a fracture and a gel pack was formed in the fracture. When water broke through the particle-gel pack after PPG placement, several channels were created that discharged water from the outlet while water was being injected. Investigation of factors that influence PPG injectivity and plugging efficiency revealed that PPG injectivity increases with fracture widths and flow rates but decreases with brine concentrations (on which the PPG swelling ratio depends). PPG can reduce the permeability for the fractures with different widths to the same level. Full-factorial experimental design analysis was performed to rank the influence of injection rate, fracture width, and PPG swelling ratio on pressure response, resistance factors, and injectivity.
An experimental study of shear stability of several high-molecular-weight polymers used as mobility control agents in EOR projects has been performed in well-controlled conditions. The shearing device was made of a capillary tube with ID of 125 μm, through which polymer solution was injected at controlled rate. The set-up enables a precise measurement of the shear rate to which the polymer macromolecule is submitted. The degradation rate was measured by the viscosity loss induced by the passage into the capillary tube. The shear rate was gradually increased up to 106 sec-1 while checking degradation rate at each stage.
Different commercial EOR polymer products were submitted to the test with polyacrylamide backbone and different substitution monomer groups. All macromolecules behave as flexible coils in solution. The parameters investigated were: Molecular weight (between 6 and 20x106)Nature of substitution group (Acrylate, ATBS/sulfonate, nVP/Vinyl-Pyrrolidone)Salinity
Polymer shear degradation increases with molecular weight and salinity, but decreases with the presence of Acrylate, ATBS and nVP. All results can be interpreted in terms of chain flexibility. The highly flexible polyacrylamide homopolymer is the most sensitive to shear degradation. Introduction of acrylate groups in the polymer chain induces some stability because of the rigidity provided by charge repulsion, which vanishes in the presence of high salinity (due to the screening of acrylate negative charges). ATBS and VP groups, which are larger in size, provide significant chain rigidity thus better shear stability. It is also shown that some very-high molecular-weight polymers, after passing the shearing device, attain a final viscosity lower than lower-molecular-weight products with the same chemical composition. This factor has to be taken into account in the final choice of a polymer for a given field application.
As a comparison, although less popular today than two decades ago, xanthan gum, which behaves like a semi-rigid rod, is shown to be much less sensitive to the shear degradation test than the coiled polyacrylamides.
The Anton Irish field was discovered in 1945, unitized in 1950 for a produced gas pressure maintenance project and converted to a waterflood in 1969. In 1997 CO2 flooding began and currently accounts for about 85% of the unit production. Presently, the entire field produces around 6,500 BOPD; 36.5 MMCFPD of recycled CO2, and 69,200 BWPD. Over the years of flooding, various conformance problems have been identified and many attempts have been made to address these problems with limited to no success. In 2003 a new program was initiated to re-evaluate the problems and design better solutions. This paper will outline the diagnostic efforts that were undertaken, discuss the basic findings of that effort, review the resulting solutions that were designed to resolve these problems, and show the results of this work.
New size-controlled microgels formed by crosslinking polymers under shear flow are very promizing for various applications in oil production. Indeed, when produced by using a proper polymer/crosslinker system and under the conditions needed to obtain the desired properties, these microgels should be quasi-ideal products. They are expected to control water mobility at long distances from the wells to improve sweep efficiency and reduce selectively permeability to water for water production control. For this latter application, injecting stable, preformed microgels eliminates the risks inherent to in-situ gelling which is a technique now recognized as being very difficult to control. This paper reports the results of new lab experiments conducted to complete our theoretical description of the crosslinking-under-shear process and to test the properties of these microgels in porous media. The actual properties of these microgels are compared to theoretical predictions. The results provide new theoretical insights into microgel formation and show that such microgels 1) have sizes measured directly by Photon Correlation Spectroscopy which are satisfactorily predicted by our model 2) adsorb quasi-irreversibly, forming adsorbed layers having a thickness equal to two times their viscometric radius of gyration, thus, are capable of controlling permeability more efficiently than the polymer alone 3) can be injected in porous media without any plugging tendency 4) have small internal rigidity as suggested by elastic modulus measurements and thus, they should be ideal disproportionate permeability modifiers 5) have viscosity higher than polymers in the dilute regime and extremely high in the semi-dilute regime, and 6) are stable, showing no tendency to re-form larger microgels when ageing, in presence of a suitable stabilizer.
When gels are used for conformance control in reservoirs, a need exists to determine how much gel should be injected in a given application and where that gel is distributed (i.e., placed) in a naturally fractured reservoir. These parameters depend critically on the properties of gels in fractures. This paper describes an investigation of how Cr(III)-acetate-HPAM gels propagate and dehydrate (i.e., lose water through leakoff) during extrusion through fractures. These studies included fractures with lengths from 0.5 to 4 ft, and heights from 1.5 in. to 12 in., and gel injection fluxes from 129 to 33,100 ft/d.
Based on the experimental results, a model was developed to quantify gel propagation and dehydration during extrusion through fractures. The model indicated that to maximize gel penetration along fractures in field applications, the highest practical injection rate should be used.
Additional tests indicated that significant advantages could be realized for gels made using polymer with the highest available molecular weight. In addition to being potentially more cost-effective, these gels may penetrate deeper into a fracture system than gels made with lower molecular weight polymers.
A laboratory study was conducted to characterize water-shutoff polymer gels that are injected in the partially formed (partially matured) state into fractures (or other high permeability anomalies) that are in direct contact with production wells. Partially formed (<8-hr-old) 1X (0.5% polymer) chromium(III)-carboxylate/acrylamide-polymer (CC/AP) gels showed much lower (as much as 100 times less) effective viscosities (17 to 30 cp) during placement in a 1-mm-wide fracture than "fully formed" (>15-hr-old) gels with the same chemical composition. Thus, partially formed gels exhibit substantially higher injectivities and lower placement pressures. This feature is of major importance during field applications where pressure constraints limit rates and volumes during gel injection. For gelants and partially formed gels that were 5 hours old or less, the rates of gelant leakoff through fracture faces were very low [about 0.013 ft3/ft2/d (ft/d)]. Thus, field applications that inject relatively small volumes of gelant or partially formed gels will generally experience small gelant leakoff distances, and the leakoff substance will not significantly inhibit oil from entering the fractures.
During first brine injection after gel placement and maturation in 1-mm-wide fractures, the pressure gradient required to first breach the gel increased significantly with increasing polymer concentration in the gel — ranging from roughly 5 psi/ft for 1X (0.5% polymer) partially formed gels to 99 psi/ft for 3X (1.5% polymer) partially formed gels. For 1X gels, the breaching pressure gradient was greatest (~9 psi/ft) when the gel was aged from 12 to 24 hours before injection. Prior to exceeding the breaching pressure gradient, no detectable brine flowed through the fracture. During the limited brine flow after gel placement, most (>90%) of the gel remained in the fracture and did not "washout." The stabilized residual resistance factors (permeability reduction factors) for the first brine flood through the fracture (following gel placement and maturation) ranged from 750 to 22,000 – increasing with increasing polymer concentration and gel strength. The large stabilized (final and equilibrium) residual resistance factors for brine flow through the gel-filled fracture resulted from the brine flow occurring through relatively small channels (wormholes) residing in the gel. For the 1X gel, the stabilized permeability reduction factors (for brine flow in a gel-treated fracture) were comparable for formulations injected in the gelant state, the partially formed state, and the "fully formed" state.
The CC/AP gels exhibited disproportionate permeability reduction during brine and oil flow through gelfilled fractures. During one experiment with the 1X gel, brine permeability in the fracture was reduced 166 times more than that for oil. In this case, brine was flooded first, followed by oil. For the 1X and 3X gels, the permeability reduction factor for oil flow remained constant (within experimental error) during four cycles of brine and oil injection. In contrast, the permeability reduction factor for brine decreased more than a factor of 10 during these cycles.
Using wide ranges of gel age, gel velocity, and fracture conductivity or tube diameter, Cr(III)-acetate-HPAM gels were studied as they extruded through fractures and tubes. Gels exhibited shear-thinning behavior in fractures and tubes that correlated with the gel superficial velocity and the fracture width or tube diameter. In fractures with sufficiently small widths, gels dehydrated during extrusion, thus reducing the rate of gel propagation. This effect was more pronounced as the fracture width decreased. Using the experimental results, a numerical study was conducted to compare placement of preformed gels and water-like gelants.
Typical gelled-polymer treatments to treat fractured rock consist of injecting in-line-mixed gelant into the reservoir for times usually much longer than the bulk gel time of the gelant. Flow experiments were conducted to determine the effect of shear on the flow properties of the gelant for durations greater than the bulk gel time. In-line-mixed gelant was injected through a 1,031-ftlong tube to simulate a fracture treatment. Flow resistance increased down the tubing to steady values indicating gelation of the flowing system. Similar flow experiments were conducted by injecting preformed gel through the tubing. Flow resistances decreased down the tubing to steady values, indicating breakdown of the gel structure. Steady flow resistances of the downstream sections were higher during the injection of in-line-mixed gelant compared to injection of preformed gel, and both were much lower than literature values determined where preformed gel was injected through short fractured rocks and short lengths of tubing. Gel samples underwent syneresis after they were formed during shear flow in the tubing and in a rheometer. Interpretations of flow-resistance data from the injection of in-line-mixed gelants and preformed gels in long tubing are presented.
Chromium acetate-hydrolyzed polyacrylamide gel systems are applied in fractured reservoirs for conformance control. A portion of the gelant leaks off into the adjoining matrix during placement of the gelant in the fracture. This paper describes an experimental study on the effect of fluid leakoff on the performance of a gel treatment. The stability of a gel that is placed in a fracture and is subjected to a pressure gradient was also investigated.
Physical models of a fracture were developed to conduct displacement experiments. The models were fractured Berea sandstones that were designed to permit leakoff of the gelant into the matrix on the sides of the fracture. A polyacrylamide-chromium acetate gelant was injected into the fracture under conditions in which there was leakoff and no leakoff into the matrix. A gel did not form and the gelant was easily displaced from the fracture by subsequent brine injection when the gelant was placed without leakoff. When the gelant was placed with leakoff, a gel formed in the fracture after placement and provided significant flow resistance. Lack of gelation in the absence of leakoff was caused by diffusion of chromium from the fracture to the matrix, reducing the chromium concentration in the gelant to levels where gelation would not occur.
It was discovered that gels that were formed in a fracture ruptured when a constant brine pressure was applied at the inlet. The pressure where rupture occurred was determined for gels placed in tubing of various lengths and diameters. The rupture pressure was proportional to a ratio of the length-to-diameter.
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