ARTICLE pubs.acs.org/EF
Influences of Fracture Aperture on the Water-Shutoff Performance of Polyethyleneimine Cross-Linking Partially Hydrolyzed Polyacrylamide Gels in Hydraulic Fractured Reservoirs Jin-Zhou Zhao,†,‡ Hu Jia,*,†,‡ Wan-Fen Pu,‡ and Ran Liao†,§ †
State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, ‡School of Petroleum Engineering, and §School of Chemistry and Chemical Engineering, Southwest Petroleum University, Chengdu 610500, People’s Republic of China ABSTRACT: In previous study, we have discussed the gelation performance of the polyethyleneimine (PEI) cross-linking partially hydrolyzed polyacrylamide (HPAM) gel system. The major goals of this paper are to investigate the conventional application performance of the PEI cross-linking HPAM gel system, including injectivity and sealing charactersic through core flowing experiments. Results show that polymer gels formualted with a combination of 2.0 wt % HPAM (Mw = 8000 kDa) and 0.35 wt % PEI can achieve the critical pressure gradient above 500 psi/ft on average and with a maximum at 1136.38 psi/ft through the core flowing experiments with apertures ranging from 0.080 to 0.200 cm. The pressure gradient and brine permeability reduction factors (Frrw) are also attractive. The gradient pressure is inline with expectations of the gradient pressure predicting curve obtained by Seright for the chromium(III) acetate cross-linking HPAM gel. A strong adhesive force of stretching 2 cm width rather than breakage in fracture profile is observed after gel washout, showing that PEI/HPAM gels have strong and durable mechanical performance to withstand brine flowing. Atomic force microscope (AFM) scanning results exhibit that disorderly cavities are distributed in the microstructure of dehydrated gels, seem like a honeycomb. Free water existing in the gel network can be easily removed through these cavities for gel dehydrating. The evaluation of the basic application performance demonstrates that the PEI cross-linking HPAM gel is a promising sealing agent for use in fractured reservoirs.
’ INTRODUCTION Most of the current world oil production comes from mature fields. The chemical enhanced oil recovery (EOR) method still plays an import role in mature oilfield development.1,2 Polymers have been employed to control the mobility of injected water in EOR applications over several decades.36 Polymer flooding needs to be considered a mature technology and still the most important EOR chemical method in sandstone reservoirs based on the review of full-field case histories. On the progress, Castro and coauthors confirm that terpolymers have very promising aspects for the viscosity reduction of Mexican crude oil.7 Also, the potential of polymer flooding technology in heave oil reservoirs is reported more recently.810 Both lab and polite tests show polymer flood technology to be a suitable and economical EOR process for East Bodo, Lloydminster SS heavy oil pool with the viscosity ranging from 600 to 2000 cP.11 Similar to the polymer flooding, injecting a polymer solution together with a cross-linker, as a chemical method of EOR has also been widely used.12,13 The use of polymer gels was proposed for conformance control application. Conformance control is a technique to block the already well-swept layers of reservoir, in order to mobilize pockets of unswept oil/gas. Cross-linkers such as phenol-formaldehyde,1416 chromium(iii) salt,17 polyethyleneimine (PEI),18,19 etc. cross-linking with partially hydrolyzed polyacrylamide (HPAM) or acrylamide-based copolymer can form a polymer gel in subterranean formation during a few hours to several days. However, as to a high water-cut oil/gas well, the production will face a severe situation. Especially for nature fractured reservoirs, water injection can break through quickly along the fractures and production will r 2011 American Chemical Society
face serious challenge with a high water cut and a decline on oil/ gas production. The hydraulic fractured oil wells will face even more severe problems in the last production period because of the commonly large millimeter-sized aperture in the near wellbore than those of a naturally fractured oil well. Polymer of high concentrations together with cross-linker formed gels are often used as water shutoff agents to curb the high water production rate. Chromium(III) acetate cross-linking HPAM gel systems are commonly used for water shutoff in fracture reservoirs.20 The fracture aperture can seriously affect the gel sealing effect. The gel’s resistance to washout increases with decreased fracture width. Gel washout in fractures can be reduced using secondary cross-linking reactions.21 Our previous study confirmed that resorcinol/phenol-formaldehyde/HPAM secondary cross-linking gel system shows wonderful gelation performance than can be recommended for water shut off in fractured reservoirs.22 In view of environment protection, low toxic PEI cross-linking a copolymer of acrylamide and t-butyl acrylate (PAtBA) as water shutoff gels are widely reported in recently years. In the past decade, such a gel system has been used successfully for various water shutoff applications. Both lab study and pilot tests demonstrated that this gel can achieve a wonderful water shutoff effect even in several hardness-fractured reservoirs at high temperatures.23,24 On the basis of the advantage of the gel system, the gelation performance of PEI cross-linking HPAM at low temperature, 40 °C, has also been investigated in our Received: March 25, 2011 Revised: May 2, 2011 Published: May 02, 2011 2616
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Energy & Fuels previous study.25 Results show that this gel system can achieve longer gelation time than that of commonly used chromium(III) acetate cross-linking HPAM gel systems at 40 °C. In this paper, we will further study the major water shutoff performance of the PEI cross-linking HPAM gel system through core flowing experiments to optimize its field application.
’ EXPERIMENTAL SETUP AND PROCEDURE Materials and Gel Preparation. The commercial materials employed in these studies included HPAM, with a high Mw of 8000 kDa
Figure 1. Viscosity increment curve of test gel at a temperature of 65 °C. (note) The gelant solution was formulated with a combination of 2.0 wt % HPAM and 0.35 wt % PEI. The TDS was furnished by combining 4900 mg/L NaCl, 50 mg/L CaCl2, and 50 mg/L MgCl2.
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and degree of hydrolysis less than 10 mol %. The concentration of active polymer in the as-supplied sample was analyzed to be 99.5 wt %; crosslinker PEI, with a molecular weight of 20 kDa, was furnished as a 50 wt % aqueous solution. Deionized water was obtained in own laboratory. Inorganic salts NaCl, MgCl2, and CaCl2, which were used to prepare the simulation water, were AR grade. HPAM and PEI were dissolved in a saline solution furnished as 4900 mg/L NaCl, 50 mg/L CaCl2, and 50 mg/L MgCl2 to prepare a gelant solution with a total dissolved solids (TDS) value of 5000 mg/L. The concentration of polymer and cross-linker were kept constant at 2 and 0.35 wt %, respectively in all experiments. The original gelant solution has a viscosity of 409 mPa.s and will be sealed in bottle and placed in an oven to investigate the gelation performance. All experiments were set at a temperature of 65 °C. Strength code and apparent viscosity measurement methods were all used in this paper to get the accurate gelation time and gel strength, respectively. The gel viscosity was measured through Brookfield viscometer DV-III. The strength code method is used to monitor the dynamic gel strength.26 The experimental result of the test formulation shows in Figure 1. This shows that the gelation time is about 10 h according to the inflection point method on the viscosity vs time curve.27 In later observation, the final gel strength can reach code I after 2 days. This means that the original gelant solutions (code A) changed to a state of no deformation on the gel surface upon inversion (code I) after 2 days of aging. Core Flowing Experiments. Core flowing experiments were conducted to assess the performance of PEI/HPAM gel systems and to give a clear understanding of the gel behavior through fractured reservoirs. Figure 2 shows a schematic diagram of the used experimental flood apparatus. (1) Fractured Core Preparation. Several authors have given some references on fractured core preparation for evaluation the performance of various working fluids, including polymer, polymer gels, drilling/completion
Figure 2. Schematic diagram of core flowing experimental equipment. 2617
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diameter). By substitution of A = πD2/4, the following equation for calculating of the fracture width is listed: Kf ¼
Wf 3 3πD
Supplementary equation Kt ¼ Km þ Kf Figure 3. Synthetic cores with a gradient fracture: (a) dimensions and (b) physical appearance.28
Figure 4. Fracture orientations of different core samples.29 fluid, etc. Abbasy and coauthors28 have evaluated the performance of three water swellable materials (WSMs) for fracture shut-off through synthetic fractured cores with a lengthwise gradient fracture. Figure 3 shows a diagram of the synthetic core dimensions and its physical appearance. There are no fillings placed in the fracture to simulate the aperture. It seems a novel core fracturing method. The influences of fracturing and fracture inclination on rock permeability and oil recovery by water flood and polymer floods were investigated by Shedid.29 The cores obtained from Hafiet Mountain were uniformly cut along the axis. A graphical representation of fracture orientation in different carbonate core samples is shown in Figure 4. However, the most mainstream of fractured core preparing method is to cut the core into two identical halves lengthwise, and then, a spacer with a certain width is placed between the halves to simulate the width of the fracture.30 The spacer filled fracture cannot represent the real aperture. The fracture aperture can strongly control effective permeability in the open natural fracture system. Effective fracture permeability is approximately a cubic function of fracture. That is a 100 μm diameter fracture will have about 1000 times the effective permeability of a 10 μm diameter fracture. Similar to this fracture preparing method, Salimi and Alikarami31 recommend a nonfilling fracture method to evaluate the fluid loss during well drilling and completion. The below empirical equations were proposed to calculate the fracture width (fracture aperture): Kf ¼
hf Wf 3 12A
Where Kf is effective permeability of the fracture, A is cross sectional area of the core, hf is fracture length in cross profile, and Wf is fracture aperture (opening fracture); hf is often equal to D (the outside
Where Kt is the effective permeability of whole fractured core (both fracture and core matrix) and Km is the effective permeability of core matrix (before fracturing). The real aperture (Wf) of a fractured core can be calculated through above equations. This method can be used to calculate the micrometer-sized fracture aperture due to the double media (fracture and rock matrix) seepage characteristics. However, as to millimeter-sized fractures, very little fluid can enter into the rock matrix for flowing. Therefore, the aperture cannot be directly calculated through above equations. In our experiments, the gel performance evaluation only investigated in simulated hydraulic fracturing cores of low rock matrix permeability. We know that most of oil well with low permeability zones will experience hydraulic fracturing to achieve high oil production. So proppant together with sand can enter into the soon opened millimeter-sized fracture to make the fracture saturated with artificial materials during fracturing. Therefore, the simple space filling method cannot directly reflect the real fracture. The fractured core preparation procedure was as follows: (1) The synthetic core samples were oven dried to remove the residual water due to the long time immersion in the atmosphere, this aims at obtaining an accurate porosity value. And then, the basic parameters including length, diameter, and dry weight are measured in this section. (2) Each core sample was vacuumized for almost 20 h and saturated with brine (the same TDS as gelant solution). The core was then inserted into the core holder and flooded with brine at constant rate of 1.0 ml/min until steady-state conditions were well-established and brine permeability was calculated using Darcy’s law. (3) All the core samples were cut along the axis for fracturing. Then, ceramsite of different grain size was adhered to the fracture profile using epoxy resin. The simulated fracture aperture depends on the grain size and ulking thickness. The two halves were packed with adhesive tape and immersed into the previous brine for later experiments. The primary fractured core preparing procedure was shown in Figure 5. The petrophysical properties of synthetic core samples are shown in Table 1. In the core fracturing section, a few ceramsite samples were placed on the core profile only fixed at six points. This aims at simulating a low space filling factor for hydraulic fractured reservoirs. In view of this, the fractured core can be treated as non- filling ones. We know that as for fracture reservoirs, several fillings more or less existed in the fractures, especially for hydraulic fractured reservoirs. If the polymer gel can show wonderful water shut-off performance in these low space filling factor fractures, then more wonderful performance can be achieved in the higher space filling factor fractures due to the additional resistance caused by the fillings. In fact, as to hydraulic fractured reservoirs, the sand fillings even can show a high space filling factor of 50%. (2) Methods and Procedures. (2.1) Critical Pressure Gradient. The critical pressure (Pc) is an important factor to evaluate the property of matured gel which can reflect the sealing strength in porous media or fracture; it is related to the polymer viscosity, cross-linking density, and adsorption/retention ability. Theoretical, it can be described using the relationship between stress state and deformation. The high strength gel can show wonderful stress tolerance ability and can also bring a high 2618
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Figure 5. Diagram for fractured core preparing: (A) core fractured, (B) ceramsite adhered to the core profile, (C) packed core.
Table 1. Petrophysical Properties of Synthetic Core Samples Used in These Experiments core code
fracture aperture (cm)
L (cm)
D (cm)
φ (%)
PV (cm3)
FV (cm3)
Km (mD)
Kt (mD)
47
0.086
6.090
2.524
30.85
9.40
1.32
123.18
10082.14
48
0.102
6.230
2.520
29.74
9.24
1.60
125.76
10305.05
49
0.182
6.120
2.520
30.27
9.24
2.81
147.84
9939.04
33
0.120
6.144
2.518
32.29
9.88
1.86
131.13
5106.99
35 42
0.150 0.200
6.158 6.210
2.536 2.518
31.96 31.08
9.94 9.61
2.34 3.13
69.30 149.05
8391.68 5237.68
45
0.152
6.630
2.442
28.18
8.75
2.46
41.03
5957.19
53
0.080
6.026
2.492
34.87
10.25
1.20
258.52
5238.67
410
0.156
6.110
2.524
30.03
9.18
2.41
217.18
10278.07
degree of deformation. Therefore, when brine flows at a constant flow rate through the gel saturated core/or fracture, the injection pressure will continuously increase to a maximum value, then only when the shear stress bearing of the matured gel becomes greater than the friction force produced in porous media/or fracture can the flow of gel be promoted. Usually, the critical pressure (breakthrough pressure) is defined as the threshold pressure when the first drop of brine water flows out. Accordingly, the critical pressure gradient (PL) is widely used for gel evaluation and defined as the critical pressure in per unit length of plugging segment.21 The equation is written as follows: Pc PL ¼ L (2.2) Water Residual Resistance Factor. The water residual resistance factor (Frrw) or water permeability reduction factor is defined as the resistance to flow of water injected behind a polymer/or polymer gel treatment.32 It provided a quantitative indication about the reduction of water permeability, which could be useful to control the water fingering due to water injection after polymer/or polymer gel treatment. λwi Kwi μwa Kwi ¼ ¼ Frrw ¼ λwa Kwa μwi Kwa Where λwi and λwa are water mobility ratios initially and after polymer/ or polymer gel treatment, respectively. Kwi and Kwa are water relative permeability initially and after polymer/or polymer gel treatment, respectively. The water viscosity is not changed in the hole process, thus μwa is equal to μwi. (2.3) Atomic Force Microscope (AFM) Analysis. The AFM method is used to investigate the microstructure of residual mature gel and aims at understanding the process for gel withstanding brine flowing.
’ RESULTS AND DISCUSSIONS All gelant formulated in the brine was described in the previous paragraph. The pressure gradient was sensitive to initial viscosity of gelant but not sensitive to injection rate, and a low injection rate is beneficial for gel washout reduction.21 Hence, a constant low injection rate of 1.0 ml/min was employed for all
Table 2. Injection Characteristics of PEI Cross-Linking HPAM Gels in Fractured Cores core code
stabilized pressure (psi)
pressure gradient (psi/ft)
47
8.70
43.59
48
8.70
42.61
49
8.70
43.38
33 35
4.35 7.25
21.61 35.93
42
8.70
42.75
45
7.25
33.37
53
7.25
36.71
410
8.70
43.45
gelant injecting experiments. A stabilized pressure gradient during gelant placement in all fractured cores averaged around 38.156 psi/ft (Table 2). The near wellbore treatment distance of a common water shut-off gels is usually around 9.816.4ft (35m), For a well of 5 m treated radius, the injection pressure of this PEI/HPAM gel system is only 625.76 psi. Therefore, there will be no difficulty in injecting such a gelant in these fractured reservoirs. All lines are cleaned after gelant injected into the fractured core, and then, the core flow setup was shut in to allow the gel to mature at a temperature of 65 °C. A bottle containing the same formulation was also left in the oven for monitoring of the dynamic gel strength. The bottle test shows that a gel with code I was formed after 2 days of aging. Then, brine at constant flow rate of 1.0 ml/min was injected into the sealed fractured core for pressure and permeability monitoring. More details are discussed in the next section. Determination of Critical Pressure Gradient. Experimental results show that all fractured cores achieved a high critical pressure gradient above 500 psi/ft on average and a maximum of 1136.38 psi/ft. 2619
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Figure 6. Relationship curve of fracture aperture with critical pressure gradient.
We know that some fiberglass and other composite material can be added to a single gel system for performance improvment; this is confirmed both in lab and field application.21,34 For instance, the CPS gel has been successfully applied in an Australia oilfield. CPS is a gel based on a copolymer of PAtBA cross-linking with PEI and laden with insoluble solids such as silica flour, calcium carbonate, or cement.35 The higher pressure gradients for gel combined with 0.10.2% fiberglass can provide 220 psi/ft in a 0.04 in. (0.1 cm) wide fracture.21 Our results suggest that the single PEI/HPAM mature gels could provide perfect elastic deformation ability and mechanical strength to effectively shutoff such fractured reservoirs with apertures ranging from 0.080 to 0.200 cm. And we also find that the fracture aperture versus critical pressure gradient curve (Figure 6) shows in an arc shape. The critical pressure gradient increased with increase of the fracture aperture when the fracture aperture was below 0.120 cm, contrarily, which dramatically decreased with the increase of the fracture aperture. It seems that there existed a “critical fracture width” for the PEI/HPAM gels in this fracture aperture range. Large fracture aperture can have a negative impact on the gel sealing effect. This is consistent with the results of Sydansk et al. For instance, a 0.1 cm aperture fracture core needs twice the pressure gradient (88 psi/ft) of a 0.2 cm aperture fracture core (37 psi/ft) for gel fist breaching. Therefore, as to high aperture fracture reservoirs (>0.2 cm), a high strength water shut-off agent is more needed. These problems are often faced in the oil/gas industry. Although currently available water shut-off polymer gels have sufficient strength for the successful treatment of many wells in numerous producing provinces (e.g., the Wyoming Big Horn basin and the Texas Permian Basin), a need still exists for stronger gels when encountering fractures with large apertures (>0.15 cm) and/or large drawdown pressures.33 However, the PEI/HPAM gel in a 0.2 cm aperture fracture can provide about 163 psi/ft critical pressure gradient, which is higher than the result of 37 psi/ft critical pressure gradient in the same aperture fracture using chromium(III)/acetate/HPAM gel given by Sydansk et al.33 Would the PEI/HAPM gel show more superiority than the commonly used chromium(III)/ acetate/HPAM gels of the approximate formulations? The previous study shows that the high Mw commercial HPAM (Ciba Alcofood 935) used in the experiments of Sydansk et al. has a nominal Mw of 5000 kDa and 510 mol % hydrolyzation.
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The polymer concentration is 1.5 wt %, which has a similar Mw and hydrolyzing degree with our materials. However, the active concentration of Ciba Alcofood 935 polymer was analyzed only to be 92 wt %. In fact, the active polymer concentration is 1.38 wt %. This may indicate that the polymer concentration plays a key role on the effect of critical pressure gradient, which may not depend on whether a gel for PEI or chromium(III)/acetate cross-linking. Without doubt, the test gel in our experiment necessarily can show higher pressure gradients compared to a 1.38 wt % HPAM gel. Determination of Frrw and Pressure Gradient. After exceeding the critical pressure gradient, cycles of brine were injected into the fractured cores. The automatic acquisition system periodically collects experimental data including pressure, accumulated volumes of brine, and calculated water relatively permeability. The experimental results are summarized in Figure 7, except for core 42 due to the breakage of this fractured core. The Frrw values of test cores range from 200 to 15 000 during the total of near 15 FV (fracture volumes) brine injection. Most of the core flooding experiments shows that a small peak existed in the prior period of brine injection. This is obviously found in core 47, 35, and 410, after 5, 6, and 7 FV brine injection, respectively. The significant increase in the pressure gradient indicates that the gel effectively blocks brine flowing through the fracture. After the gel treatment, the injected brine has to flow through a fracture filled with matured gel with a very low permeability. The present study shows that the PEI/HPAM gel can show wonderful durable mechanical strength. As in a fractured reservoir, to achieve a 57 FV water injected usually needs several years. It means that the gel treated reservoirs have long validity for water shut-off. The slope increment phase to reach the peak also can demonstrate that the PEI/HPAM gel is provided with the common high absorbing water ability for a super absorbent polymer (SAP). With increasie of the brine injection, the water absorbing ability of the polymer gels reach a saturated balance state, then the mechanical strength correspondingly increased to a peak. The peak indicates the time associated with gel failure and washout, for most fractured cores, both Frrw and pressure gradient curves drop suddenly after the small peak followed with several leaps. For instance, the curves of core 35, 410, and 47 are qualitatively similar with obvious leaps. It means that the imposed pressure difference due to the injected brine exceeds the threshold pressure of the gel network. The wormholes or relatively small channels may be formed in the gel in this phase.20 It seems that cyclical brine flow makes some new paths into the bulk gel; therefore, during the next injected fracture volumes, brine flow tends to move through the new more permeable paths instead of the low permeable gel bulk. This leads to pressure gradient drop and shows several leaps. However, in the later stage of brine injection, the pressure gradient levels off to a plateau (core 48, 49, and 53). Perhaps, stable wormholes are formed in these cores, and the polymer gels adhered to the fracture profile can provide the steady pressure gradient for the continuous brine injection. The whole process of pressure gradient decreased with an increasing fracture aperture, ranging from 20 to 230 psi/ft, and shows a similar trend to that of Frrw. Core 49 with an aperture of 0.182 cm can provide the stabilized pressure gradient only around 20 psi/ft after 9.5 FV brine flooding; contrarily, low fracture aperture cores 48, 35, and 410 with the fracture width, respectively, of 0.102, 0.15, and 2620
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Figure 7. Water residual resistance factor (Frrw) and pressure gradient versus accumulated brine flux of the test fractured cores.
0.156 cm provide the stabilized pressure gradient around 210, 195, and 90 psi/ft, respectively. The pressure gradient values for a 0.102 cm aperture fracture is inline with expectations with the
results of a pressure gradient predicting curve given by Seright.20 The experiment was conducted in the fracture cores with an aperture of 0.04 in. (≈0.102 cm). The curve indicates that the 2621
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Energy & Fuels pressure gradient has a perfect linear relation with HAPM concentration for a chromium(III)/acetate cross-linking gel. About 210 psi/ft pressure gradient will be obtained when extending the straight line to the 2 wt % HPAM concentration in x-axis. From the result of the previous section, we further believe that the strength of the gel is dominated by the polymer concentration—not by whether the cross-linker is chromium(III)/acetate or PEI. This finding may be of great signifiance for better understanding of the sealing properties for other kinds of acrylamide based polymer gels. The PEI cross-linking HPAM gels still have strong adhesive force in fracture profile after nearly 10 to 15 FV brine, the residual gel even can stretch 2 cm rather than breaking (Figure 8), this still shows wonderful elasticity and toughness. The adhesion state gels are uniformly distributed in the fracture profile, and the threadiness gel is rather hairchested, which demonstrates that the PEI/HPAM gels can achieve wonderful
Figure 8. Threadiness shape of the washed out gel in fracture profile.
Figure 9. Formed wormholes (channels) in fractured profile.
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washout ability. Also, wormholes are observed after the end of experiments. Figure 9 shows that the cylindric channels distributed in an arbitrary direction. This behavior is caused by gel dehydrated process.21 Dehydrated gel was formed during the brine injection to compress the gel network. With the continuously brine injection, the dehydrated gel becomes increasingly concentrated and less mobile and the fresh gels (not too much dehydrated gel) was output. The leaps phenomenon in most of the curves may be the evidence for the process of wormholes forming. From the observation of the narrow channel, it seems that only a small fraction of the gel was displaced during the washout process. AFM Analysis. The residual gel (dehydrated gel) was collected for AFM analysis. The representative scanning photos show in Figure 10. The AFM photos are obtained through the measurement of the hysteretic angle due to the acting force produced during gel sample interacting with needle. The color difference represents the different hysteretic angle values and shows the superficial differences of gel sample. From the observation of a 3D photo, the gel structure is full of sags and crests, and it seems like a honeycomb. For comparison of the 2D structure, the light color irregurlar circles act as the sags and crests part showing in the 3D photo. The thickness of the light color circle is approximately 0 μm. In the AFM test, only the existing mica plate and gel two substance, we can deduce that the sunk part (light color circles) is the mica plate surface and the numerous light color irregular circles should be the porosity of the dehydrated gel. The width of the porosity is clearly around 0.5 to 1 μm. This may be caused by the innate character of the PEI/HPAM gels. As to PEI/HPAM gel system, the gelation mechanism can be explained as imine nitrogen from PEI attacking the carbonyl carbon attached to the amide group as shown in Figure 11. We make a hypothesis that the gelation mechanism for attacking the carbonyl carbon may be attacked again to a slight displacement by the mechanical force of continuous brine flowing. The physical extrusion results in the anisotropic gel network and nonuniform distribution cross-linking density which can lead to the partially
Figure 11. Transmutations of the amide group.
Figure 10. Microstructure of the dehydrated gel sample: (left) two-dimensional diagram, (right) three-dimensional diagram. 2622
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Energy & Fuels exorbitant cross-linking density (cross-linking point displacement) to promote gel network shrinkage. The shrinkage force in different directions lead to the strength of the network of gel enhanced to form a macromolecule network entity; however, another part (cross-linking points and polymer chains) will be breakage under the inner stress to produce various shapes of cavities (porosity). The partial cavities are rather compact. This also means that the dehydrated gel is bound to experience the severe physical extrusion and also may be the evidence for the bearing of anisotropic mechanical force. The cavities in the gel can provide convenience for gel dehydration. The free water existing in the gel network can be easily percolated, leaching through the cavities, when compressed by the continuous brine flow. Therefore, the entitative gel (dark part) can show even higher mechanical strength than before. This may be another reason for the wonderful adhesion force.
’ CONCLUSIONS The basic application performance evaluation demonstrates that the PEI cross-linking HPAM gel system is a promising system for water shutoff in fractured reservoirs. (1) The PEI/HPAM formulation gel in this study exhibits high mechanical performance for gel breaching. The critical pressure gradient is maximum to 1136.38 psi/ft in 0.0800.200 cm aperture fracture cores. (2) The brine permeability reduction factors (Frrw) of test fractured cores range from 200 to 15 000 in the whole process of brine flooding. The tendency of the curves of Frrw and pressure gradient matched well in most core flooding tests. (3) The polymer concentration is the most important factor to affect the washout properties (pressure gradients and resistance), not dependent on whether the cross-linker is chromium(III)/acetate or PEI. (4) The PEI cross-linking HPAM mature gels still show strong adhesive force of the stretching 2 cm width rather than breakage in fracture profile. The cavities are found in the microstructure of dehydrated gels which can be evidence for the experience of the strength physical extrusion of mature gels. We believe that this study not only gives a new understanding of the application performance of PEI cross-linking HPAM gels but also could give a new avenue in low toxic PEI cross-linking acrylamide based copolymers for better perfecting these gels for water shut-off in various complex reservoirs. ’ AUTHOR INFORMATION Corresponding Author
*Mailing address: Xindu Road No. 8, Zip Code: 610500, Department of State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation of Southwest Petroleum University, Chengdu, People’s Republic of China. Tel.: þ86-28-15902825270. E-mail: tiger-jia@ 163.com.
’ ACKNOWLEDGMENT This work was financially supported by State Development Program of Large Gas Fields and Coalbed Gas, China (No. 2008ZX05049-05-03). Special thanks to Fa-Yang Jin, Ke-Xing Li, Ji-Mao Li and Yong Guo for their assistance in core flowing
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experiments. The authors would like to thank the reviewers of this paper for many useful suggestions.
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