Influences of Fracture Aperture on the Water-Shutoff Performance of Polyethyleneimine Cross-Linking Partially Hydrolyzed Polyacrylamide Gels in Hydraulic Fractured Reservoirs

Published: May 02, 2011

r 2011 American Chemical Society 2616 dx.doi.org/10.1021/ef200461m | Energy Fuels 2011, 25, 2616–2624

ARTICLE

pubs.acs.org/EF

Influences of Fracture Aperture on the Water-Shutoff Performance ofPolyethyleneimine Cross-Linking Partially Hydrolyzed PolyacrylamideGels in Hydraulic Fractured ReservoirsJin-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 Chemistryand 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 partiallyhydrolyzed polyacrylamide (HPAM) gel system. The major goals of this paper are to investigate the conventional applicationperformance of the PEI cross-linking HPAM gel system, including injectivity and sealing charactersic through core flowingexperiments. Results show that polymer gels formualted with a combination of 2.0 wt %HPAM (Mw = 8000 kDa) and 0.35 wt % PEIcan achieve the critical pressure gradient above 500 psi/ft on average and with a maximum at 1136.38 psi/ft through the core flowingexperiments 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 forthe chromium(III) acetate cross-linkingHPAM gel. A strong adhesive force of stretching 2 cmwidth rather than breakage in fractureprofile is observed after gel washout, showing that PEI/HPAM gels have strong and durable mechanical performance to withstandbrine flowing. Atomic force microscope (AFM) scanning results exhibit that disorderly cavities are distributed in the microstructureof dehydrated gels, seem like a honeycomb. Free water existing in the gel network can be easily removed through these cavities for geldehydrating. The evaluation of the basic application performance demonstrates that the PEI cross-linking HPAM gel is a promisingsealing agent for use in fractured reservoirs.

’ INTRODUCTION

Most of the current world oil production comes from maturefields. The chemical enhanced oil recovery (EOR) method stillplays an import role in mature oilfield development.1,2 Polymershave been employed to control the mobility of injected water inEOR applications over several decades.3�6 Polymer floodingneeds to be considered a mature technology and still the mostimportant EOR chemical method in sandstone reservoirs basedon the review of full-field case histories. On the progress, Castroand coauthors confirm that terpolymers have very promisingaspects for the viscosity reduction ofMexican crude oil.7 Also, thepotential of polymer flooding technology in heave oil reservoirs isreported more recently.8�10 Both lab and polite tests showpolymer flood technology to be a suitable and economicalEOR process for East Bodo, Lloydminster SS heavy oil poolwith the viscosity ranging from 600 to 2000 cP.11

Similar to the polymer flooding, injecting a polymer solutiontogether with a cross-linker, as a chemical method of EOR hasalso been widely used.12,13 The use of polymer gels was proposedfor conformance control application. Conformance control is atechnique to block the already well-swept layers of reservoir, inorder to mobilize pockets of unswept oil/gas. Cross-linkers suchas phenol-formaldehyde,14�16 chromium(iii) salt,17 polyethyle-neimine (PEI),18,19 etc. cross-linking with partially hydrolyzedpolyacrylamide (HPAM) or acrylamide-based copolymer canform a polymer gel in subterranean formation during a few hoursto several days. However, as to a high water-cut oil/gas well, theproduction will face a severe situation.

Especially for nature fractured reservoirs, water injection canbreak through quickly along the fractures and production will

face serious challenge with a high water cut and a decline on oil/gas production. The hydraulic fractured oil wells will face evenmore severe problems in the last production period because ofthe commonly large millimeter-sized aperture in the near well-bore than those of a naturally fractured oil well. Polymer of highconcentrations together with cross-linker formed gels are oftenused as water shutoff agents to curb the high water productionrate. Chromium(III) acetate cross-linking HPAM gel systemsare 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 fracturewidth. Gel washout in fractures can be reduced using secondarycross-linking reactions.21 Our previous study confirmed thatresorcinol/phenol-formaldehyde/HPAM secondary cross-linkinggel system shows wonderful gelation performance than can berecommended for water shut off in fractured reservoirs.22

In view of environment protection, low toxic PEI cross-linkinga copolymer of acrylamide and t-butyl acrylate (PAtBA) as watershutoff gels are widely reported in recently years. In the pastdecade, such a gel system has been used successfully for variouswater shutoff applications. Both lab study and pilot tests demon-strated that this gel can achieve a wonderful water shutoffeffect even in several hardness-fractured reservoirs at hightemperatures.23,24 On the basis of the advantage of the gelsystem, the gelation performance of PEI cross-linking HPAMat low temperature, 40 �C, has also been investigated in our

Received: March 25, 2011Revised: May 2, 2011

2617 dx.doi.org/10.1021/ef200461m |Energy Fuels 2011, 25, 2616–2624

Energy & Fuels ARTICLE

previous study.25 Results show that this gel system can achievelonger 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 shutoffperformance of the PEI cross-linking HPAM gel system throughcore flowing experiments to optimize its field application.

’EXPERIMENTAL SETUP AND PROCEDURE

Materials and Gel Preparation. The commercial materialsemployed in these studies included HPAM, with a high Mw of 8000 kDa

and degree of hydrolysis less than 10 mol %. The concentration of activepolymer in the as-supplied sample was analyzed to be 99.5 wt %; cross-linker 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 thesimulation water, were AR grade.

HPAM and PEI were dissolved in a saline solution furnished as 4900mg/L NaCl, 50 mg/L CaCl2, and 50 mg/L MgCl2 to prepare a gelantsolution with a total dissolved solids (TDS) value of 5000 mg/L. Theconcentration of polymer and cross-linker were kept constant at 2 and0.35 wt %, respectively in all experiments. The original gelant solutionhas a viscosity of 409 mPa.s and will be sealed in bottle and placed in anoven to investigate the gelation performance. All experiments were set ata temperature of 65 �C.

Strength code and apparent viscosity measurement methods were allused in this paper to get the accurate gelation time and gel strength,respectively. The gel viscosity was measured through Brookfield visc-ometer DV-III. The strength code method is used to monitor thedynamic gel strength.26 The experimental result of the test formulationshows in Figure 1.

This shows that the gelation time is about 10 h according to theinflection point method on the viscosity vs time curve.27 In later observa-tion, the final gel strength can reach code I after 2 days. This means that theoriginal gelant solutions (code A) changed to a state of no deformation onthe 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 andto give a clear understanding of the gel behavior through fracturedreservoirs. Figure 2 shows a schematic diagram of the used experimentalflood apparatus.

(1) Fractured Core Preparation. Several authors have given somereferences on fractured core preparation for evaluation the performance ofvariousworking fluids, including polymer, polymer gels, drilling/completion

Figure 1. Viscosity increment curve of test gel at a temperature of65 �C. (note) The gelant solution was formulated with a combination of2.0 wt % HPAM and 0.35 wt % PEI. The TDS was furnished bycombining 4900 mg/L NaCl, 50 mg/L CaCl2, and 50 mg/L MgCl2.

Figure 2. Schematic diagram of core flowing experimental equipment.



fluid, etc. Abbasy and coauthors28 have evaluated the performance ofthree water swellable materials (WSMs) for fracture shut-off throughsynthetic fractured cores with a lengthwise gradient fracture. Figure 3shows a diagram of the synthetic core dimensions and its physicalappearance. There are no fillings placed in the fracture to simulate theaperture. It seems a novel core fracturing method.

The influences of fracturing and fracture inclination on rockpermeability and oil recovery by water flood and polymer floods wereinvestigated by Shedid.29 The cores obtained from Hafiet Mountainwere uniformly cut along the axis. A graphical representation offracture orientation in different carbonate core samples is shown inFigure 4.

However, the most mainstream of fractured core preparing method isto cut the core into two identical halves lengthwise, and then, a spacerwith a certain width is placed between the halves to simulate the width ofthe fracture.30 The spacer filled fracture cannot represent the realaperture. The fracture aperture can strongly control effective perme-ability in the open natural fracture system. Effective fracture permeabilityis approximately a cubic function of fracture. That is a 100 μm diameterfracture will have about 1000 times the effective permeability of a 10 μmdiameter fracture. Similar to this fracture preparing method, Salimi andAlikarami31 recommend a nonfilling fracture method to evaluate thefluid loss during well drilling and completion. The below empiricalequations were proposed to calculate the fracture width (fractureaperture):

Kf ¼ hfWf3

12A

WhereKf is effective permeability of the fracture, A is cross sectional areaof the core, hf is fracture length in cross profile, and Wf is fractureaperture (opening fracture); hf is often equal to D (the outside

diameter). By substitution of A = πD2/4, the following equation forcalculating of the fracture width is listed:

Kf ¼ Wf3

3πD

Supplementary equation

Kt ¼ Km þ Kf

Where Kt is the effective permeability of whole fractured core (bothfracture and core matrix) and Km is the effective permeability of corematrix (before fracturing). The real aperture (Wf) of a fractured core canbe calculated through above equations. This method can be used tocalculate themicrometer-sized fracture aperture due to the doublemedia(fracture and rock matrix) seepage characteristics. However, as tomillimeter-sized fractures, very little fluid can enter into the rock matrixfor flowing. Therefore, the aperture cannot be directly calculatedthrough above equations. In our experiments, the gel performanceevaluation only investigated in simulated hydraulic fracturing cores oflow rock matrix permeability. We know that most of oil well with lowpermeability zones will experience hydraulic fracturing to achieve highoil production. So proppant together with sand can enter into the soonopened millimeter-sized fracture to make the fracture saturated withartificial materials during fracturing. Therefore, the simple space fillingmethod 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 atmo-sphere, this aims at obtaining an accurate porosity value. Andthen, the basic parameters including length, diameter, and dryweight are measured in this section.

(2) Each core sample was vacuumized for almost 20 h andsaturated with brine (the same TDS as gelant solution). Thecore was then inserted into the core holder and flooded withbrine at constant rate of 1.0 ml/min until steady-state condi-tions were well-established and brine permeability was calcu-lated 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 fractureprofile using epoxy resin. The simulated fracture aperturedepends on the grain size and ulking thickness. The two halveswere packed with adhesive tape and immersed into the previousbrine for later experiments. The primary fractured core prepar-ing procedure was shown in Figure 5. The petrophysical proper-ties of synthetic core samples are shown in Table 1.

In the core fracturing section, a few ceramsite samples were placed onthe core profile only fixed at six points. This aims at simulating a lowspace filling factor for hydraulic fractured reservoirs. In view of this, thefractured core can be treated as nonfilling ones. We know that as forfracture reservoirs, several fillings more or less existed in the fractures,especially for hydraulic fractured reservoirs. If the polymer gel can showwonderful water shut-off performance in these low space filling factorfractures, then more wonderful performance can be achieved in thehigher space filling factor fractures due to the additional resistancecaused by the fillings. In fact, as to hydraulic fractured reservoirs, the sandfillings even can show a high space filling factor of 50%.

(2) Methods and Procedures. (2.1) Critical Pressure Gradient. Thecritical pressure (Pc) is an important factor to evaluate the property ofmatured gel which can reflect the sealing strength in porous media orfracture; it is related to the polymer viscosity, cross-linking density, andadsorption/retention ability. Theoretical, it can be described using therelationship between stress state and deformation. The high strength gelcan show wonderful stress tolerance ability and can also bring a high

Figure 3. Synthetic cores with a gradient fracture: (a) dimensions and(b) physical appearance.28

Figure 4. Fracture orientations of different core samples.29



degree of deformation. Therefore, when brine flows at a constant flowrate through the gel saturated core/or fracture, the injection pressure willcontinuously increase to a maximum value, then only when the shearstress bearing of the matured gel becomes greater than the friction forceproduced in porous media/or fracture can the flow of gel be promoted.Usually, the critical pressure (breakthrough pressure) is defined as thethreshold pressure when the first drop of brine water flows out.

Accordingly, the critical pressure gradient (PL) is widely used for gelevaluation and defined as the critical pressure in per unit length ofplugging segment.21 The equation is written as follows:

PL ¼ PcL

(2.2) Water Residual Resistance Factor. The water residual resis-tance factor (Frrw) or water permeability reduction factor is defined asthe resistance to flow of water injected behind a polymer/or polymer geltreatment.32 It provided a quantitative indication about the reduction ofwater permeability, which could be useful to control the water fingeringdue to water injection after polymer/or polymer gel treatment.

Frrw ¼ λwiλwa

¼ KwiμwaKwaμwi

¼ Kwi

Kwa

Where λwi and λwa are water mobility ratios initially and after polymer/or polymer gel treatment, respectively. Kwi and Kwa are water relativepermeability 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 aimsat understanding the process for gel withstanding brine flowing.

’RESULTS AND DISCUSSIONS

All gelant formulated in the brine was described in theprevious paragraph. The pressure gradient was sensitive to initialviscosity of gelant but not sensitive to injection rate, and a lowinjection rate is beneficial for gel washout reduction.21 Hence, aconstant low injection rate of 1.0 ml/min was employed for all

gelant injecting experiments. A stabilized pressure gradientduring gelant placement in all fractured cores averaged around38.156 psi/ft (Table 2). The near wellbore treatment distance ofa common water shut-off gels is usually around 9.8�16.4ft(3�5m), For a well of 5 m treated radius, the injection pressureof this PEI/HPAM gel system is only 625.76 psi. Therefore, therewill be no difficulty in injecting such a gelant in these fracturedreservoirs. All lines are cleaned after gelant injected into thefractured core, and then, the core flow setup was shut in to allowthe gel to mature at a temperature of 65 �C. A bottle containingthe same formulation was also left in the oven for monitoring ofthe dynamic gel strength. The bottle test shows that a gel withcode I was formed after 2 days of aging. Then, brine at constantflow rate of 1.0 ml/min was injected into the sealed fracturedcore for pressure and permeability monitoring. More details arediscussed in the next section.Determination of Critical Pressure Gradient. Experimental

results show that all fractured cores achieved a high criticalpressure gradient above 500 psi/ft on average and a maximum of1136.38 psi/ft.

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)

4�7 0.086 6.090 2.524 30.85 9.40 1.32 123.18 10082.14

4�8 0.102 6.230 2.520 29.74 9.24 1.60 125.76 10305.05

4�9 0.182 6.120 2.520 30.27 9.24 2.81 147.84 9939.04

3�3 0.120 6.144 2.518 32.29 9.88 1.86 131.13 5106.99

3�5 0.150 6.158 2.536 31.96 9.94 2.34 69.30 8391.68

4�2 0.200 6.210 2.518 31.08 9.61 3.13 149.05 5237.68

4�5 0.152 6.630 2.442 28.18 8.75 2.46 41.03 5957.19

5�3 0.080 6.026 2.492 34.87 10.25 1.20 258.52 5238.67

4�10 0.156 6.110 2.524 30.03 9.18 2.41 217.18 10278.07

Table 2. Injection Characteristics of PEI Cross-LinkingHPAM Gels in Fractured Cores

core code stabilized pressure (psi) pressure gradient (psi/ft)

4�7 8.70 43.59

4�8 8.70 42.61

4�9 8.70 43.38

3�3 4.35 21.61

3�5 7.25 35.93

4�2 8.70 42.75

4�5 7.25 33.37

5�3 7.25 36.71

4�10 8.70 43.45



We know that some fiberglass and other composite materialcan be added to a single gel system for performance improvment;this is confirmed both in lab and field application.21,34 Forinstance, the CPS gel has been successfully applied in an Australiaoilfield. CPS is a gel based on a copolymer of PAtBA cross-linkingwith PEI and laden with insoluble solids such as silica flour,calcium carbonate, or cement.35 The higher pressure gradientsfor gel combined with 0.1�0.2% fiberglass can provide 220 psi/ftin a 0.04 in. (0.1 cm) wide fracture.21 Our results suggest that thesingle PEI/HPAM mature gels could provide perfect elasticdeformation ability and mechanical strength to effectively shut-off such fractured reservoirs with apertures ranging from 0.080 to0.200 cm. And we also find that the fracture aperture versus criticalpressure gradient curve (Figure 6) shows in an arc shape. Thecritical pressure gradient increased with increase of the fractureaperture when the fracture aperture was below 0.120 cm, contra-rily, which dramatically decreased with the increase of the fractureaperture. It seems that there existed a “critical fracture width” forthe PEI/HPAM gels in this fracture aperture range. Large fractureaperture can have a negative impact on the gel sealing effect. This isconsistent with the results of Sydansk et al. For instance, a 0.1 cmaperture 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 highstrength 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 havesufficient strength for the successful treatment of many wells innumerous producing provinces (e.g., the Wyoming Big Hornbasin and the Texas Permian Basin), a need still exists forstronger 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 canprovide about 163 psi/ft critical pressure gradient, which ishigher than the result of 37 psi/ft critical pressure gradient inthe same aperture fracture using chromium(III)/acetate/HPAMgel given by Sydansk et al.33 Would the PEI/HAPM gel showmore superiority than the commonly used chromium(III)/acetate/HPAM gels of the approximate formulations?The previous study shows that the highMw commercialHPAM

(Ciba Alcofood 935) used in the experiments of Sydansk et al.has a nominal Mw of 5000 kDa and 5�10 mol % hydrolyzation.

The polymer concentration is 1.5 wt %, which has a similar Mw

and hydrolyzing degree with our materials. However, the activeconcentration of Ciba Alcofood 935 polymer was analyzed onlyto be 92 wt%. In fact, the active polymer concentration is 1.38 wt%.This may indicate that the polymer concentration plays a key roleon the effect of critical pressure gradient, which may not dependon whether a gel for PEI or chromium(III)/acetate cross-linking.Without doubt, the test gel in our experiment necessarily canshow higher pressure gradients compared to a 1.38 wt %HPAM gel.Determination of Frrw and Pressure Gradient.After exceed-

ing the critical pressure gradient, cycles of brine were injectedinto the fractured cores. The automatic acquisition systemperiodically collects experimental data including pressure, accu-mulated volumes of brine, and calculated water relativelypermeability.The experimental results are summarized in Figure 7, except

for core 4�2 due to the breakage of this fractured core. The Frrwvalues of test cores range from 200 to 15 000 during the total ofnear 15 FV (fracture volumes) brine injection. Most of the coreflooding experiments shows that a small peak existed in the priorperiod of brine injection. This is obviously found in core 4�7,3�5, and 4�10, after 5, 6, and 7 FV brine injection, respectively.The significant increase in the pressure gradient indicates that thegel effectively blocks brine flowing through the fracture. After thegel treatment, the injected brine has to flow through a fracturefilled with matured gel with a very low permeability. The presentstudy shows that the PEI/HPAM gel can show wonderfuldurable mechanical strength. As in a fractured reservoir, toachieve a 5�7 FV water injected usually needs several years. Itmeans that the gel treated reservoirs have long validity for watershut-off. The slope increment phase to reach the peak also candemonstrate that the PEI/HPAM gel is provided with thecommon high absorbing water ability for a super absorbentpolymer (SAP). With increasie of the brine injection, the waterabsorbing ability of the polymer gels reach a saturated balancestate, then the mechanical strength correspondingly increased toa peak.The peak indicates the time associated with gel failure and

washout, for most fractured cores, both Frrw and pressuregradient curves drop suddenly after the small peak followed withseveral leaps. For instance, the curves of core 3�5, 4�10, and4�7 are qualitatively similar with obvious leaps. It means that theimposed pressure difference due to the injected brine exceeds thethreshold pressure of the gel network. The wormholes orrelatively small channels may be formed in the gel in this phase.20

It seems that cyclical brine flowmakes some new paths into thebulk gel; therefore, during the next injected fracture volumes,brine flow tends to move through the newmore permeable pathsinstead of the low permeable gel bulk. This leads to pressuregradient drop and shows several leaps. However, in the later stageof brine injection, the pressure gradient levels off to a plateau(core 4�8, 4�9, and 5�3). Perhaps, stable wormholes areformed in these cores, and the polymer gels adhered to thefracture profile can provide the steady pressure gradient forthe continuous brine injection. The whole process of pressuregradient decreased with an increasing fracture aperture, rangingfrom 20 to 230 psi/ft, and shows a similar trend to that of Frrw.Core 4�9 with an aperture of 0.182 cm can provide the stabilizedpressure gradient only around 20 psi/ft after 9.5 FV brineflooding; contrarily, low fracture aperture cores 4�8, 3�5, and4�10 with the fracture width, respectively, of 0.102, 0.15, and

Figure 6. Relationship curve of fracture aperture with critical pressuregradient.



0.156 cm provide the stabilized pressure gradient around 210,195, and 90 psi/ft, respectively. The pressure gradient values for a0.102 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 anaperture of 0.04 in. (≈0.102 cm). The curve indicates that the

Figure 7. Water residual resistance factor (Frrw) and pressure gradient versus accumulated brine flux of the test fractured cores.



pressure gradient has a perfect linear relation with HAPM con-centration for a chromium(III)/acetate cross-linking gel. About210 psi/ft pressure gradient will be obtained when extending thestraight 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—notby whether the cross-linker is chromium(III)/acetate or PEI. Thisfinding may be of great signifiance for better understanding of thesealing 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, theresidual 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 fractureprofile, and the threadiness gel is rather hairchested, whichdemonstrates that the PEI/HPAM gels can achieve wonderful

washout ability. Also, wormholes are observed after the end ofexperiments. Figure 9 shows that the cylindric channels dis-tributed in an arbitrary direction.This behavior is caused by gel dehydrated process.21 Dehy-

drated gel was formed during the brine injection to compress thegel network. With the continuously brine injection, the dehy-drated gel becomes increasingly concentrated and less mobileand the fresh gels (not too much dehydrated gel) was output.The leaps phenomenon in most of the curves may be theevidence for the process of wormholes forming. From theobservation of the narrow channel, it seems that only a smallfraction 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 inFigure 10. The AFMphotos are obtained through themeasurementof the hysteretic angle due to the acting force produced during gelsample interacting with needle. The color difference represents thedifferent hysteretic angle values and shows the superficial differencesof gel sample. From the observation of a 3D photo, the gel structureis full of sags and crests, and it seems like a honeycomb. Forcomparison of the 2D structure, the light color irregurlar circles actas the sags and crests part showing in the 3Dphoto. The thickness ofthe light color circle is approximately 0 μm. In the AFM test, onlythe existingmica plate and gel two substance, we can deduce that thesunk part (light color circles) is the mica plate surface and thenumerous light color irregular circles should be the porosity of thedehydrated gel. The width of the porosity is clearly around 0.5 to1μm.Thismay be caused by the innate character of thePEI/HPAMgels. As to PEI/HPAM gel system, the gelation mechanism can beexplained as imine nitrogen from PEI attacking the carbonyl carbonattached to the amide group as shown in Figure 11.Wemake a hypothesis that the gelationmechanism for attacking

the carbonyl carbonmay be attacked again to a slight displacementby the mechanical force of continuous brine flowing. The physicalextrusion results in the anisotropic gel network and nonuniformdistribution cross-linking density which can lead to the partially

Figure 8. Threadiness shape of the washed out gel in fracture profile.

Figure 9. Formed wormholes (channels) in fractured profile. Figure 11. Transmutations of the amide group.

Figure 10. Microstructure of the dehydrated gel sample: (left) two-dimensional diagram, (right) three-dimensional diagram.



exorbitant cross-linking density (cross-linking point displacement)to promote gel network shrinkage. The shrinkage force in differentdirections lead to the strength of the network of gel enhanced toform a macromolecule network entity; however, another part(cross-linking points and polymer chains) will be breakage underthe inner stress to produce various shapes of cavities (porosity).The partial cavities are rather compact. This also means that thedehydrated gel is bound to experience the severe physical extru-sion and also may be the evidence for the bearing of anisotropicmechanical force.The cavities in the gel can provide convenience for gel

dehydration. The free water existing in the gel network can beeasily percolated, leaching through the cavities, when compressedby the continuous brine flow. Therefore, the entitative gel (darkpart) can show even higher mechanical strength than before. Thismay be another reason for the wonderful adhesion force.

’CONCLUSIONS

The basic application performance evaluation demonstratesthat the PEI cross-linking HPAM gel system is a promisingsystem for water shutoff in fractured reservoirs.(1) The PEI/HPAM formulation gel in this study exhibits

high mechanical performance for gel breaching. Thecritical pressure gradient is maximum to 1136.38 psi/ftin 0.080�0.200 cm aperture fracture cores.

(2) The brine permeability reduction factors (Frrw) of testfractured cores range from 200 to 15 000 in the wholeprocess of brine flooding. The tendency of the curves ofFrrw and pressure gradient matched well in most coreflooding tests.

(3) The polymer concentration is the most important factorto affect the washout properties (pressure gradients andresistance), not dependent on whether the cross-linker ischromium(III)/acetate or PEI.

(4) The PEI cross-linking HPAM mature gels still showstrong adhesive force of the stretching 2 cm width ratherthan breakage in fracture profile. The cavities are foundin the microstructure of dehydrated gels which can beevidence for the experience of the strength physicalextrusion of mature gels.

We believe that this study not only gives a new understandingof the application performance of PEI cross-linking HPAM gelsbut also could give a new avenue in low toxic PEI cross-linkingacrylamide based copolymers for better perfecting these gels forwater shut-off in various complex reservoirs.

’AUTHOR INFORMATION

Corresponding Author*Mailing address: Xindu Road No. 8, Zip Code: 610500, Depart-ment of State Key Laboratory ofOil andGasReservoir Geology andExploitation of Southwest PetroleumUniversity, Chengdu, People’sRepublic of China. Tel.: þ86-28-15902825270. E-mail: [email protected].

’ACKNOWLEDGMENT

This work was financially supported by State DevelopmentProgram 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

experiments. The authors would like to thank the reviewers of thispaper for many useful suggestions.

’NOMENCLATUREPEI = polyethyleneimineHPAM = partially hydrolyzed polyacrylamidePAtBA = a copolymer of acrylamide and t-butyl acrylateTDS = total dissolved solidsMw = molecular weightkDa = 1000 DaKf = effective permeability of the fracture, cm2

A = cross sectional area of the core, cm2

hf = fracture length in cross profile, cmWf = fracture aperture (opening fracture), cmKt = effective permeability of whole fractured core (both fracture

and core matrix), cm2

Km = effective permeability of core matrix (before fracturing), cm2

mD = 10�3 darcyL = length of core sample, cmD = outside diameter, cmφ = rock porosity, percentPV = pore volume, cm3

FV = fracture volume, cm3

Pc = critical pressure, psiPL = critical pressure gradient, psi/ftdp/dl = pressure gradient, psi/ftFrrw = water residual resistance factor, zero dimensionµ = viscosity, cPAFM = atomic force microscope

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Documents

Influences of Fracture Aperture on the Water-Shutoff Performance of Polyethyleneimine Cross-Linking Partially Hydrolyzed Polyacrylamide Gels in Hydraulic Fractured Reservoirs