SPE-171531-MS

Characterizations of Disproportionate Permeability Reduction of ParticleGels through Fractures

Abdulmohsin Imqam and Baojun Bai, Missouri University of Science and Technology; Chunming Xiong,Research Institute of Petroleum Exploration and Development, CNPC;Mingzhen Wei, Missouri University of Science and Technology; Mojdeh Delshad andKamy Sepehrnoori The University of Texas at Austin

Copyright 2014, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Asia Pacific Oil & Gas Conference and Exhibition held in Adelaide, Australia, 1416 October 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). Contentsof 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 reflectany position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the writtenconsent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations maynot be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

The primary objective of particle gel treatment is to significantly reduce water flow through high-permeability channels without damaging oil production zones. The ability of gels to reduce permeabilityto water much more than permeability to oil is a critical aspect of the success of water control in bothproduction wells and in-depth fluid diversion conformance control. This work investigates factorsaffecting particle gel placement through fractures and determines the extent to which particle gels canreduce water permeability more than oil permeability within a fracture. Experimental models weredesigned to study the effect of the particle gel size, particle gel strength, fracture width, and oil viscosityon the disproportionate permeability reduction (DPR). Five-foot tubes with two internal diameters wereused to represent a fracture with two different widths. PPGs were injected first into the fractures, followedby alternating floods of water and oil. During the gel injection, the resistance factors (Fr) increased as thegel particle size, gel strength, and fracture width increased. Results obtained from the alternating floodsshow that the DPR increased as the oil viscosity, particle size, gel strength, and fracture width increased.Gel shrinkage, gel strength, and gel dehydration were found to contribute significantly to this phenom-enon. The permeability reduction factor to water increased, becoming 100 to 1700 times greater than thepermeability reduction factor to oil. The injection pressure for different water cycles increased as morecycles were performed. These increases, however, were not significant when observed for different oilcycles. The experimental results show that when a second water cycle was injected to displace oil, theresidual resistance factor for water (Frrw) in the second cycle was significantly less than the precedingFrrw values. This finding indicates that the gel experienced a significant breakdown during the first oilcycles. Additional oil cycles were performed, and the Frrw decreased during each new brine cycle,indicating further gel breakdown.

IntroductionControlling water production to improve oil recovery in mature oil fields has become a primary task foroil companies. Decreasing water production not only increases oil recovery efficiently, but also extends

the life of reservoirs. A decrease in water productionalso decreases the environmental pollution associ-ated with water production. High-permeabilitystreaks, caves, wormholes, fractures, and channelsinside reservoirs are the main sources of severefluid-channeling problems, particularly in matureoil reservoirs. Water flows easily through these fea-tures, leaving large amounts of unrecovered oil inunswept areas. Many methods and materials havebeen proposed not only to reduce water production,but also to improve oil recovery. Chemical methodsare becoming more prevalent, especially when theprimary cause of water production is a result ofheterogeneities in reservoirs. Gel treatments arecommonly applied to improve conformance andcontrol water and gas channeling through reservoirs. Several different types of commercial gels arefrequently used to control water production, including polymers with a cross linker, preformed bulk gels,partially preformed gels, colloidal dispersion gels (CDGs), preformed particle gels (PPGs), temperaturetriggered microgels (known as Bright Water), pH-sensitive microgels, and non-toxic soft sizecontrolledmicrogels (known as STARPOL). The main differences between these gels are their size, swelling ratio,and swelling time.

Placing gels throughout target zones significantly decreases water permeability and minimizes waterflow into the well. However, if the reservoir produces oil through these zones, gel permeability will notdecrease significantly. This phenomenon has been examined previously, and many studies have beenconducted to evaluate gel performance in the presence of oil production (Liang et al., 1993; Tai Liang,1995; Liang and Seright, 1997; Grattoni et al., 2001; Willhite et al., 2002; Nguyen et al., 2004; Seright,2006; Sydansk and Seright, 2007; Seright, 2009; Seright et al., 2009). To the best of our knowledge, noneof these or any previous studies used PPG as a conformance material in their investigations, nor studiedthe performance or mechanism of PPG extrusion and placement in fracture systems. The first of only twoexisting studies of PPG extrusion was conducted by Zhang and Bai (2011), who investigated the effectof PPG extrusion through fractures on the injectivity and plugging efficiency when the fracture width wasless than the gel particle size. The second study was conducted by Imqam et al. (2014), who investigatedPPG propagation during extrusion through conduits, examining the factors affecting particle gel injectionand placement when the conduit opening size is larger than, equal to, and smaller than the swollenparticles. These two PPG studies, however, were confined to open fractures/conduits and emphasized gelextrusion through fractures/conduits and its effect on water flow in the absence of oil production.

The purpose of the current work was to examine, in depth, the effect of several factors, such as particlesize, gel strength, and fracture width, on DPR properties, gel extrusion, and placement through fracturesystems. Alternating injections of both brine and oil were used to determine the extent to which PPGs canreduce water permeability more than oil permeability within a fracture.

Experimental MaterialsPreformed Particle Gel (PPG)Super-absorbent polymer (SAP) was used as a PPG sample. PPG is comprised primarily of potassium saltswith crosslinked polyacrylic acid / polyacrylamide copolymer. Typical characteristics of this PPG arelisted in Table 1.

Two sizes of particle gels, 2030 and 100120 mesh size, were selected for the experiments. Table2 illustrates the size distribution of the PPG before swelling, as determined by a sieving test.

Table 1Typical Characteristics of SAP

Properties Value

Absorption Deionized Water (g/g) 200

Apparent Bulk Density (g/l) 540

Moisture Content (%) 5

pH Value 5.56.0 (/ 0.5; 1 % gelin 0.9% NaCl)

Specific Gravity (Bulk Density) 0.60.7 gm/ml

Table 2Size Distribution of Particle Gel

Sieves (mesh) Size (microns)

2030 850600

100120 150125

2 SPE-171531-MS

Brine Concentrations and Oil ViscositiesSodium chloride (NaCl) with four concentrations (0.05, 0.25, 1, and 10 wt% NaCl) was used to preparethe swelling gels. The brine concentration was selected carefully according to both the swelling ratio andthe gel strength; the high-salinity brine resulted in high gel strength and a low swelling ratio, as presentedin Table 3. Two oils with viscosities of 37 and 195cp were used in the study.

TubesIn this experiment, stainless steel tubes with internal diameters of 0.12 inches and 0.069 inches were usedto represent fractures. These tubes were originally 20 ft long and were cut into 5 ft in lengths.

Experimental SetupFig. 1 presents the experimental apparatus, which consisted of a syringe pump used to inject brine, gel,and oil through the accumulator into a fracture model. The fracture model was essentially five long tubeswith two different internal diameters. A check valve was used at the inlet of the fracture model to ensurethat no back flow of gel occurred when pressure was released from the pump. A 0.5-micron filter wasinstalled at the outlet of the tube to ensure that no gel washout occurred during either the brine or the oilinjection process. Pressure sensors were connected at both the inlet and the outlet to measure thedifferential pressure across the gel.

Experimental ProceduresFirst, we obtained the effects of brine concentrations (gel strength), particle size, and fracture width on thegel extrusion and DPR behavior through fractures. PPGs with mesh sizes of 2030 swollen in 0.05%,0.25%, 1%, and 10% brine solution were extruded through tubes with internal diameters of 0.069 inches.From high to low, nine flow rates, 3.0246, 2.2684, 1.5123, 0.7561, 0.3781, 0.3025, 0.1512, 0.0756, and0.0151ml/min, were used to extrude the PPG. Stable PPG injection pressures were achieved and resistancefactors determined for each flow rate. Then, a filter was installed at the outlet, and PPG was injected againand compressed through the tube until the injection pressure reached 100 psi. The same type of brine usedto prepare the swollen PPG then was injected. Oil with a 37 cp viscosity was injected after each injected

Table 3PPG Swelling Ratio and Strength Measurements

NaCl (%) Swelling Ratio Gel Concentration, wt% Storage Moduli, Pa

0.05 165 0.60 515

0.25 80 1.25 657

1 50 2.0 870

10 25 4.0 1300

Figure 1Schematic diagram of PPG placement in fractures

SPE-171531-MS 3

brine concentration. Residual resistance factors for both water and oil were determined during theexperiments.

The second objective of this study was to understand gel performance under a sequence of brine andoil cycles. PPGs with mesh sizes of 2030 swollen in 1% NaCl were extruded through a tube with adiameter of 0.12 inches using the nine different flow rates. Stable pressure was achieved for each gelinjection rate. After a filter was installed and the PPG was compressed, brine and oil cycles werealternated in sequence. Both brine and oil were injected through the tube model with seven flow ratesstarting from low to high: 0.0151, 0.0756, 0.1512, 0.3025, 0.3781, 0.7561, and 1.5123 ml/ min. Thissequence can be summarized in the following steps:

1. Concentration of 1% NaCl (first cycle) was injected with seven flow rates through PPG-filledtubes. Stable pressure was achieved for each flow rate, and the residual resistance factors for water(Frrw) were determined.

2. Oil with a 37 cp viscosity was injected to displace water inside the gel. Residual resistance factorsfor oil (Frro) were obtained for the seven flow rates.

3. Oil with a 195 cp viscosity was injected, and the Frro were again obtained for each flow rate.4. 1% NaCl brine (second cycle) was injected after the injection of oils with same flow rates, and

Frrw was calculated.5. After the second cycle of brine injection, oil with a 37 cp viscosity was injected again to obtain

the Frro.6. High-viscosity (195 cp) oil was injected, and the Frro were determined.7. Finally, 1% NaCl brine (third cycle) was injected in the same model with the same flow rates to

determine the Frrw.

The above seven steps were repeated using PPG with a mesh size of 100120 swollen in the same NaClconcentrations (1%).

Results and AnalysisData showing the effects of the gel particle size, gel strength, and fracture width on gel extrusions andplacements were obtained. These data include the PPG injection pressure, resistance factor, residualresistance factors, and results for the brine and oil cycles.PPG Injections and Residual Resistance Factor ResultsThis section presents and discusses the results obtained for the injection pressure and residual resistancefactors for the effects of gel strength, particle gel size, and fracture width.

Figure 2Stable pressures versus injection rate for different gel strengths and particle sizes

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Stabilized PPG Injection Pressure versus Injection Rate The stable pressure measurements obtainedduring the gel extrusion process were recorded and plotted against the PPG injection flow rate for eachdifferent gel strength and particle size. Fig. 2 a illustrates the stable injection pressure of the gels for gelstorage moduli of 515, 657, 870, and 1300 pa injected through a tube with an internal diameter of 0.069inches. Fig. 2 b presents the measurements taken for both 2030 mesh size and 100120 mesh sizeinjected through a fracture 0.12 inches wide. The results show that the stable injection pressure for eachflow rate increased as the gel strength and particle size increased. For instance, a particle gel with a100120 mesh size had a stable pressure of 65 psi at a gel injection rate of 3.0256 ml/min, while a particlegel with a 2030 mesh size had a stable pressure of 71 psi at the same injection flow rate. This increasein pressure occurred because larger particles are more resistant to flow through fractures than smallerparticles. This behavior, however, was most pronounced at low flow rates. This finding could imply thatat a high injection rate, the stable pressure for both particle sizes is an independent factor.

The stable pressure for all of the gel strengths and particle sizes increased significantly as the injectionrate increased. Though to an insignificant extent, the pressure continued to build up as the PPG injectionrate increased. The results also indicate that as the gel strength increased, reaching the stable pressure foreach injection rate required more time.

Resistance Factor Calculation PPG is a shear thinning or pseudo plastic material. The resistance factor(Fr) is used to measure PPG resistance to flow when it extrudes through fractures. Similar to the porousmedia experiment, Fr was estimated from the injectivity index and geometry of the fracture. It can bedefined as the ratio of the particle gel injection pressure drop to the brine injection pressure drop at thesame flow rate and can be calculated using the following equation:

(1)

where PPPG is the PPG injection pressure drop and Pbrine is the brine injection pressure drop beforePPG placement, which is determined using Poiseuilles law.

Resistance Factor versus Superficial Velocity The resistance factor was calculated during the gel ex-trusion process against the velocity for each different gel strength and particle size. Fig. 3a and 3billustrates the resistance factor results obtained for different gel strengths and gel particle sizes, respec-tively. The PPG resistance factor increased as the gel strength and gel particle size increased. For example,at a velocity of 29 ft/day, the Fr of gel strengths 515, 657, 870, and 1300 pa were 74981, 158294, 208282,and 291595, respectively. The Fr determined for each PPG strength decreased sharply as the superficial

Figure 3Resistance factor calculated for both gel strength and gel particle size in a log-log scale

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velocity increased. For instance, the resistance factor for 100120 mesh size was 8750 at a velocity of 10ft/day. When the velocity was doubled, the resistance factor decreased substantially to 1683.

The data in Fig. 3 were fitted according to the power law equations. Table 4 lists the fitting equationsfor the resistance factors obtained for both effects. The elasticity index (n) measured for the effects of gelstrength were plotted against the storage moduli, as presented in Fig. 4. As the gel strength increased, thegel elastic value decreased.

Residual Resistance Factor to Brine and Oil Residual resistance factors were determined by dividingthe pressure drop of the injection of either brine or oil into the fracture after gel placement by the pressuredrop of the injection of either brine or oil into the fracture before gel placement.

Effect of Gel Strength on Disproportionate Permeability Reduction Fig. 5 a illustrates the Frrw de-termined for brine injected through different strength PPGs. The results indicate that the gel strength doesaffect the Frrw; the Frrw increased as the gel strength increased. As the gel strength increased from 515pa to 1300 pa, the increase in the Frrw became significant. After determining the Frrw, oil was injectedthrough the same internal diameter with the same velocity to obtain the Frro. Fig. 5 b depicts themeasurements of oil with a viscosity of 37 cp injected through swollen PPGs. The results indicate that thegel strength also affects the Frro; the Frro increased as the gel strength increased. For all of the gelstrengths, the Frro was less than the Frrw.

Effect of Opening Size on Disproportionate Permeability Reduction PPGs with a mesh size of 2030swollen in a 1% NaCl solution were used to observe the effect of the fracture width on the residualresistance factors. Fig. 6 a and b presents the results obtained from injecting a 1% NaCl solution and 37cp oil through gel placed in fractures 0.069 and 0.12 inches wide. These data suggest that Frrw and Frroincreased as the fracture widened. Frro was less than Frrw regardless of the fracture width.

Table 4Summary of Fitting Equations for Resistance Factor Measurements

Storage Moduli G (Pa) Particle Size (mesh) Fitting Equations Elasticity Index (n) R2

515 FR 490150 u 0530 0.530 0.986

657 2030 FR 955622 u 0.525 0.525 0.996

870 FR 1E06 u 0.50 0.50 0.988

1300 FR 1 E06 u 0.437 0.437 0.981

870 2030 FR 238927 u 0.829 0.829 0.997

100120 FR 22514 u 0.547 0.547 0.957

Figure 4Elasticity index as a function of gel strengths

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Results of Brine and Oil CyclesThis section discusses the results obtained from injecting different cycles of brine and oils throughgel-filled fractures. During these several cycles, the residual resistance factors to brine and oil for eachcycle were determined to evaluate PPG performance.

Seven velocities were used to inject brine, and the stable pressure was observed at each. Fig. 7aillustrates the Frrw determined for the two particle sizes as a function of superficial velocity. The Frrwfor both particle sizes decreased as the velocity increased. This decrease was significant at a low velocity.For example, the Frrw value at 100120 mesh size decreased from almost 200,000 to 50,000 as thevelocity increased from 10 to 50 ft/day. The results also suggest that the Frrw was greater for larger thanfor smaller particle sizes. The power law equation was used to fit data for the Frrw. The following areequations that fit well for the two particle sizes:

(2)

(3)

After the Frrw values were determined, oils with different viscosities (37 cp and 195 cp) were injectedconsecutively to determine the Frro. Figs. 7 b and c illustrate the Frro measurements for both particlesizes at different oil viscosities. Both figures indicate that the Frro determined for the two PPG mesh sizesdecreased as the superficial velocity increased. The change in particle size does not appear to have a

Figure 5Residual resistance factor for brine and oil as a function of both superficial velocity and gel strength

Figure 6Residual resistance factor for brine and oil as a function of both flow rate and fracture width

SPE-171531-MS 7

significant effect on the Frro when compared to the first cycle of brine. For the oil with a viscosity of 37cpinjected with a velocity of 10 ft/day, the Frro measurements for both 2030 mesh and 100120 meshparticle sizes was 4900 and 3400, respectively. The results also indicate that the Frro decreased as the oilviscosity (at the same given particle size) increased. The power law equation was used to fit the resultsobtained for the Frro values. The Frro for the different oil viscosities and particle sizes are describedusing Equations 4, 5, 6, and 7:

Residual resistance factor equations for 37 cp:

(4)

(5)

Residual resistance factor equations for 195 cp:

(6)

(7)

The water loss (dehydration) from PPG and the injection pressure were both obtained during theprocess of injecting 37cp oil through 2030 mesh. Fig. 8 illustrates that a significant gel breakdownoccurred during the oil injection process. Oil was injected at a constant flow rate of 0.3025 ml/min. Thedifferential pressures (stable pressure) across the gel and the water loss from the gel were measured. Thepressure began to build during the early stages of oil injection, eventually reaching 53 psi before fallingand finally fluctuating between 3 and 7 psi. When compared to the first water cycle injection process, thedifferential pressure at the same flow rate (0.3025ml/min) was 29 psi. This significant drop in pressuresuggests that gel could fail during the oil injection process.

Cumulative water loss data from the gel during the oil injection process were collected. Fig. 8 showsthat the cumulative water loss from the gel began to build rapidly until the cumulative oil injected reachedapproximately 150s ml. The cumulative water loss then began to level off at 14 ml. We continued to injectoil until observing a stable pressure across the gel to ensure that no more water loss would occur.

Comparison between Frro and Frrw Obtained from First Cycle for 2030 Mesh Size Fig. 9 depictsthe comparison of the first cycle of 1% brine with the first cycle of two oil viscosities to identify the extentto which gel can reduce permeability to water more than to oil.

Figure 7Frrw and Frro determined for the first cycles as a function of both particle size and superficial velocity

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The results show that the residual resistance factor was much lower during oil injection than duringwater injection. At a velocity of 10 ft/day, the Frrw to water was 653414, and the Frro for oil with aviscosity of 195cp was 930, which means that the Frro decreased by around 700 times. A number ofreasons may exist for this phenomenon; some of the reasons observed in our experiments will be explainedin the Discussion section.

Brine and Oil Reinjection Measurements After the first cycles of brine and oil injections were com-pleted, we continued to inject multiple cycles of brine and oil through the same gel sizes. Fig. 10 a showsthe results obtained for the second brine cycles. The Frrw measurements observed during the second waterinjection cycle were almost the same for both particle sizes. For instance, the Frrw measurements forparticle sizes 2030 and 100120 were 544.5 and 726, respectively, at the same velocity (964 ft/day). Inthis example, the oil may have dehydrated both particle sizes to the same extent. The effect of differentparticle sizes on the Frrw was not significant after oil was injected through the gel. The following Frrwmeasurements were taken during the second water injection cycle for both particle sizes:

(8)

(9)

Comparing Equations (2) and (3) with (8) and (9), respectively, indicates that the residual resistancefactor for brine decreased substantially after the oil injection cycle was complete.

Figure 8PPG breakdown during two-phase flow in a fracture 0.12 inches wide

Figure 9Comparisons between Frrw and Frro during the first cycle of flooding

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Fig. 10 b and c provides a comparison of the Frro determined during the first and second oil injectioncycles, respectively. The results obtained during the second oil injection cycle for both oil viscositiessuggest a decrease in the Frro, even when compared to the first cycle. This decrease indicates further gelbreakdown, thus continuously increasing the gels permeability during oil injection. For example, the Frrodetermined for oil with a viscocity of 37 cp at the same velocity (100 ft/day) decreased almost two timesless than the Frro measured during the first oil injection cycle. The Frro was 407 for the first oil injectioncycle and 203 for the second. Frro measurements were taken during the second oil injection cycle for bothoil viscosities, as follows:

Residual resistance factor for 37 cp:

(10)

Residual resistance factor for 195 cp:

(11)

The effect of oil viscosity on the Frro was noticeable when comparing Equation (6) with Equation (4)and Equation (11) with Equation (10). The Frro with a high oil viscosity was less than the Frro with alow oil viscosity for both cycles. These results indicate that gel has great potential for success in heavyoil field applications.

Comparing the Frrw Obtained for All Three Brine Cycles Fig. 11 compares the results from the first,second, and third water cycles for the same particle size. A third water cycle was injected after the secondoil cycles. The Frrw measurements taken during the third brine cycle indicate a slight decrease whencompared to the Frrw measured during the second brine cycle. For instance, at a velocity of 10 ft/day, theFrrw for the second cycle was 127052; it decreased slightly to 108902 during the third cycle. Acomparison of all three water cycles indicates that Frrw decreased substantially after the first oil injection.The Frrw for both the second and third cycles were very similar. These measurements indicate furtherparticle gel breakdown but to a lesser extent than during the second cycle. The Frrw measurementobtained during the third water injection cycle was:

(12)

Injection Pressures over DPR Processes The alternative injection pressures for both brine and oil wererecorded during their injection through the gel-filled fracture. Fig. 12 illustrates the injection pressure forcycles of 1% NaCl and 195 cp oil through PPG with a size of 2030. These injection pressures built upduring the flooding cycles. The results also indicate that the injection pressure for water increased as more

Figure 10Frrw and Frro determined for the second cycles as a function of both particle size and superficial velocity

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cycles of water were performed. These injection pressure increases, however, were insignificant atdifferent oil cycles. The injection pressure recorded during the first water cycle peaked at approximately2227 psi, while after a cumulative volume of 700 ml of oil was injected, the pressure dropped slightly to2135 psi. Sequential cycles of brine, oil, and brine were injected with almost the same volume into PPG.After injecting 700 ml, the pressure peaked at approximately 2590 psi for the second brine cycle, 2290psi for the second oil cycle, and 2860 psi for the third water cycle.

DiscussionThe study presented in this paper investigated the behavior of PPG extruded through a fracture duringtwo-phase flow. The DPR mechanisms have been investigated extensively by several researchers. Table5 summarizes the DPR mechanisms, gels, and investigators in the relevant literature. The following is asummary of the mechanisms observed during PPG placement inside a fracture.

Mechanism 1 in Table 5 considers gels that swell when they come into contact with brine and shrinkwhen they come into contact with oil. In their visualization studies, Liang et al. (1995) did not observeany volume changes in the gel at atmospheric pressure. They conducted the same experiment at 1500 psiand still found no significant macroscopic changes during alternating exposures of the gels to brine, oil,and compressed CO2. However, we observed a different trend for PPG. In visualization studies with PPGat atmospheric pressure, we observed significant volume changes in the gel. In brine, dry gel swelled to

Figure 11Frrw determined for the different 1% brine cycles

Figure 12Injection pressure over oil and water flood cycles

SPE-171531-MS 11

many times its original size, which helps to increasethe residual resistance factor for water. However,when we placed swollen particle gel in a glasscontainer filled with oil for three weeks, the gelvolume decreased dramatically to half of its originalPPG volume. This shrinkage of the gel particle sizevolume allows oil to move easily through gel andcauses the residual resistance factor to oil to de-crease compared to water.

Many researchers have investigated the effect ofcapillary forces and gel elasticity (Mechanism 5).Al-Sharji et al. (1999) found that the flow of waterand oil through gel was controlled by the elasticityof polymer gels. Our results for the flow of oil andwater through PPG showed the same trend. Wefound that the flow of oil through gel had a different elasticity index than the flow of water through gel.The effect of dehydration (Mechanism 8) was observed when the first cycle of oil was injected throughPPG (see Fig. 8). The pressure began to decrease substantially during the oil injection process. Theexperimental data suggest that the oil dehydrated the PPG by displacing water from the gel structures andcreating new flow channels inside the gel.

In this study, gel strength was established as an important factor/mechanism for PPG that greatlyaffects the DPR. Results obtained from rheometer measurements, as shown in Fig. 13, suggest that gelstrength measurements taken after the oil and water flowed through PPG also affected the DPRmechanism. The results indicate that the gel strength for oil was much less than for water; consequently,gel with less strength has a lower residual resistance factor than gel with high strength.

Figure 13Particle gel strength measurements as a function of oil andbrine flow

Table 5Summary of Mechanisms Proposed for Disproportionate Permeability Reductions

No Mechanism Gel Investigators

1 Gel swells in water but shrinks inoil

Cr(III)-acetate-HPAM; Xanthangum-Cr(III) gels;polyacrylamide polymers; PPG

Liang et al.; Dawe and Zhang;Gales et al.;Sparlin and Hagen;Imqam et al.

2 Wall effects polyacrylamide polymers; waterand oil based gels

Zaitoun et al.; Liang and Seright;Liang et al.

3 Gravity affects gel locations inpores

Glyoxal / cationic polyacrylamide(CPAM)

Liang et al.

4 Gels change rock wettability Nonionic polyacrylamide (PAM);resorcinol-formaldehyd; Cr3(chloride)-xanthan;Cr3(acetate)-polyacrylamide;colloidal silica

Zaitoun et al.; Liang et al

5 Effect of capillary forces and gelelasticity

Cr (III)-acetate-HPAM; bulkpolymer gel; PPG

Liang and Seright; Al-Sharji et al.;Imqam et al.

6 Segregated pathway theory Polymer; water and oil based gels;HPAM & crosslinker

White et al.; Liang and Seright;Nilson et al.

7 Lubrication effect PAM and polysaccharidepolymers; polyacrylamidepolymers

Zaitoun and Kohler; Sparlin andHagen

8 Gel dehydration PPG; acetate/HPAM Imqam et al; Dawe and Zhang;Willhite et al

9 During brine injection, polymerleaches from the gel andsignificantly decreases thebrine mobility

Cr (III)-acetate-HPAM Liang and Seright

10 Pore blocking by gel droplets water and oil based gels Liang and Seright

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ConclusionWe fully investigated the characterization of disproportionate permeability reduction during our experi-ments. The following conclusions were drawn specifically for particle gel mechanisms and placement inclosed-fracture systems:

The particle gel injection pressure increased as the particle size, gel strength, and flow rateincreased but decreased as the fracture width increased.

Elasticity indices (n) were successfully obtained and fitted as a function with gel strength. Theresults indicated that as the gel strength increased, the gel elastic value decreased.

The results also indicated that the greater the gel strength, the more time is needed to achieve astable pressure for each injection rate. Additionally, wider fractures require less time to reach astable pressure than do narrower fractures for each injection flow rate.

The Frro was always much less than the Frrw during all alternating water and oil floods. The DPRalso increased with increases in the oil viscosity, particle size, gel strength, and fracture width.

The first oil injection (first cycle of oil) can significantly degrade the gel properties. This findingexplains why the residual resistance factor Frrw obtained from the second brine cycle decreasedsignificantly compared with the Frrw obtained from the third brine cycle.

The injection pressure for different water cycles increased as more water cycles were performed.However, these injection pressure increases were not significant at different oil cycles.

A different disproportionate permeability reduction mechanism of the particle gel was investi-gated. The gel strength greatly affected the DPR and is an important parameter that should beconsidered.

AcknowledgmentThe authors would like to express their gratitude to the Research Partnership to Secure Energy forAmerica (REPSA) and the U.S. Department of Energy for their financial support for this project. Theauthors also would like to express their appreciation for the support of the High Ministry of Education inLibya.

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14 SPE-171531-MS

Characterizations of Disproportionate Permeability Reduction of Particle Gels through FracturesIntroductionExperimental MaterialsPreformed Particle Gel (PPG)Brine Concentrations and Oil ViscositiesTubesExperimental SetupExperimental ProceduresResults and AnalysisPPG Injections and Residual Resistance Factor ResultsStabilized PPG Injection Pressure versus Injection RateResistance Factor CalculationResistance Factor versus Superficial VelocityResidual Resistance Factor to Brine and OilEffect of Gel Strength on Disproportionate Permeability ReductionEffect of Opening Size on Disproportionate Permeability ReductionResults of Brine and Oil CyclesComparison between Frro and Frrw Obtained from First Cycle for 2030 Mesh SizeBrine and Oil Reinjection MeasurementsComparing the Frrw Obtained for All Three Brine CyclesInjection Pressures over DPR ProcessesDiscussionConclusionAcknowledgmentReferences