Gel Placement Research Articles

X-Ray Computed Microtomography Studies of Fluid Partitioning in Drainage and Imbibition Before and After Gel Placement: Disproportionate Permeability Reduction

Summary X-ray computed microtomography (XMT) was used to establish why pore-filling Cr(III)-acetate-HPAM gels reduced permeability to water much more than to oil. Our results suggest that permeability to water was reduced to low values because water must flow through gel itself, whereas oil pressing on the gel in Berea sandstone or porous polyethylene forced pathways by dehydration—leading to relatively high permeability to oil. In very permeable sandpacks, data from other researchers support ripping or extrusion mechanisms for creating oil pathways. Our XMT studies provide interesting insights into imbibition and drainage processes in water-wet and oil-wet porous media even before gel placement. Many of our observations were consistent with conventional wisdom. However, some were unexpected. Residual wetting-phase (water) saturations in Berea were surprisingly low-valued in small pores. We attribute this to surface roughness caused by clay coating on Berea's pore walls, which allowed efficient water drainage from small pores during oil injection.

Cleanup of Oil Zones After a Gel Treatment

SummaryA simple mobility-ratio model was used to predict cleanup times for both fractured and unfractured production wells after a gel treatment. The time to restore productivity to a gel-treated oil zone (1) was similar for radial vs. linear flow, (2) varied approximately with the cube of distance of gel penetration, (3) varied inversely with pressure drawdown, (4) varied inversely with the kw at Sor in the gel-treated region, and (5) was not sensitive to the final ko at Swr. Although ko at Swr (after gel placement) had no effect on the cleanup time, it strongly affected how much of the original oil productivity was ultimately regained.

Application of In-Depth Gel Placement for Water and Carbon Dioxide Conformance Control in Carbonate Porous Media

Abstract This paper presents the results of an investigation of the application of gel placement in an attempt to reduce the effective permeability of a carbonate porous medium to water and supercritical carbon dioxide, as encountered in the CO2 flooding of carbonate reservoirs. Three gel systems based on a high and a low molecular weight polyacrylamide polymer with chromium(III), as crosslinker, were used for this study. Since sodium lactate is commonly used for increasing gelation time at elevated temperatures, experiments were conducted by adding sodium lactate to the gel solution with a ratio of polymer to sodium lactate equal to one. The higher molecular weight polyacrylamide gel system was composed of 7,200 ppm Alcoflood 935 and 300 ppm Cr(III), while the other gel system tested was composed of 5% low molecular weight polyacrylamide (Alcoflood 254S) with a ratio of 1:12 chromium(III)-acetate to polymer as crosslinker. Experiments were conducted at 8,274 KPa and 40 °C with and without the presence of residual oil. Performance and stability of the above gel systems for reducing the permeability of the carbonate medium to the injected water and carbon dioxide was tested in a series of flow experiments by alternately injecting several pore volumes of water and carbon dioxide into the porous media in several cycles. The porous medium used was crushed carbonate with an initial permeability of over 9.86 µm2. For all experiments, the presence of Sor led to lower residual resistance factors (RRF). Nevertheless, RRFs were between 100 and a few thousands for all experiments conducted. The results obtained are a clear indication of the effectiveness of these gel systems for conformance control purposes during carbon dioxide flooding projects in carbonate reservoirs. Introduction From the pore-scale point of view, dense carbon dioxide is an ideal displacement fluid for many crude oils. Carbon dioxide gains miscibility with oil and is able to achieve very high recovery efficiencies at reservoir pressures near or above minimum miscibility pressure. However, even when pressure conditions for miscibility are met, this high microscopic sweep efficiency is not often observed in field tests. The combined effect of heterogeneity of the reservoir and the low viscosity of the injected carbon dioxide leads to the viscous fingering of carbon dioxide through fractures, channels, or high-permeable streaks in the reservoir. This causes early breakthrough of injected carbon dioxide into production wells, which reduces oil recovery efficiency. Different techniques have been investigated for reducing channelling through fractures or high-permeability zones. One such technique is in-depth gel placement. This process has been applied successfully in many reservoirs, resulting in fracture sealing, water and gas shut-off, and permeability modification. The objective of gel placement is to reduce fingering of the injected fluid through fractures or high-permeability zones of formation while minimizing gel penetration in hydrocarbon bearing regions of the reservoir. The main advantages of using gels over the other methods, such as cements or mechanical plugs, is their flexibility for pumping without a workover rig, high control of setting time, a deeper penetration into the formation, ease of cleaning, and an easy removal from the wellbore by water recirculation(1, 2).

Characterization of Partially Formed Polymer Gels for Application to Fractured Production Wells for Water-Shutoff Purposes

Summary A laboratory study characterized partially formed chromium(III)-carboxylate/acrylamide-polymer (CC/AP) gels for water shutoff in fractures. These partially formed gels showed much lower effective viscosities during placement than comparable fully formed gels. During placement, leakoff rates through fracture faces were low for gelants and partially formed gels. During the first brine injection after gel placement, the pressure gradient required to breach the gel increased with the increasing polymer concentration. Most gel remained in the fracture and did not wash out. During brine flow through "wormholes" in the gel, stabilized residual-resistance factors (Frr) were large and increased with increasing polymer concentration.

Water Shutoff in Gas Wells: Proper Gel Placement Is the Key to Success

Summary The objectives of water-shutoff treatments in gas wells suffering from water influx are to reduce water production and, at the same time, increase gas-production rates and producible gas reserves. Several field treatments, conducted under the umbrella of a research project focused on water abatement in gas wells, have demonstrated that a sequential gel/gas-injection technique in fractured gas reservoirs was successful in reducing water production and increasing gas production. Further efforts focused on improving gel placement in both fractured and matrix reservoirs to improve the treatment efficiency. Injectivity of the gelant was improved for injection into matrix reservoirs by either reducing the concentration of the highmolecular-weight polymer in the gelant formulation or by using a low-molecular-weight polymer. Gel placement was improved by displacing the gelant away from the near-wellbore region with semistable foam rather than with gas. Such displacement allows for improved gas production after the gel treatment. Laboratory-scale simulations were used to history match the coreflood results to calibrate the gelation and overdisplacement options in the simulations. Field-scale simulations demonstrated the merits of the proper gel-placement technique using a foam to displace the gelant away from the wellbore in matrix and fractured reservoirs. Optimized gel formulations in combination with the new over-displacement technique provide a treatment alternative for combatting 3D coning situations. This overdisplacement technique can also minimize the startup problems experienced in fractured gas reservoirs after gel treatments.

Gel Placement Key to Success for Water Shutoff in Gas Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 89403, "Water Shutoff in Gas Wells: Proper Gel Placement Is the Key to Success," by F. Wassmuth, SPE, K. Green, and L. Hodgins, Alberta Research Council, prepared for the 2004 SPE/DOE Symposium on Improved Oil Recovery, Tulsa, 17-21 April.

Use of X-ray computed microtomography to understand why gels reduce relative permeability to water more than that to oil

X-ray computed microtomography (XMT) was used to investigate why gels reduce relative permeability to water more than that to oil in strongly water-wet Berea sandstone. XMT allows saturation differences to be monitored for individual pores during various stages of oil, water, and gelant flooding. The method also characterizes distributions of pore size, aspect ratio, and coordination number for the porous media. We studied a Cr(III) acetate–HPAM gel that reduced permeability to water (at S or) by a factor 80–90 times more than that to oil (at S wr). In Berea, the gel caused disproportionate permeability reduction by trapping substantial volumes of oil that remained immobile during water flooding (i.e., 43.5% S or before gel placement versus 78.7% S or after gel placement). With this high trapped oil saturation, water was forced to flow through narrow films, through the smallest pores, and through the gel itself. In contrast, during oil flooding, oil pathways remained relatively free from constriction by the gel.

Characterizing Disproportionate Permeability Reduction Using Synchrotron X-Ray Computed Microtomography

Summary X-ray computed microtomography was used to investigate why gels reduce permeability to water more than that to oil in strongly water-wet Berea sandstone and in an oil-wet porous polyethylene core. Although the two porous media had very different porosities (22% vs. 40%), the distributions of pore sizes and aspect ratios were similar. A Cr(III)-acetate-HPAM gel caused comparable oil and water permeability reductions in both porous media. In both cores, the gel reduced permeability to water by a factor 80 to 90 times more than that to oil. However, the distributions of water and oil saturations (vs. pore size) were substantially different before, during, and after gel placement. This paper examines the mechanism for the disproportionate permeability reduction in the two porous media.

The Effect of Fluid Leakoff on Gel Placement and Gel Stability in Fractures

Summary Chromium acetate-hydrolyzed polyacrylamide gel systems are applied in fractured reservoirs for conformance control. A portion of the gelant leaks off into the adjoining matrix during placement of the gelant in the fracture. This paper describes an experimental study on the effect of fluid leakoff on the performance of a gel treatment. The stability of a gel that is placed in a fracture and is subjected to a pressure gradient was also investigated. Physical models of a fracture were developed to conduct displacement experiments. The models were fractured Berea sandstones designed to permit leakoff of the gelant into the matrix on the sides of the fracture. A polyacrylamide-chromium acetate gelant was injected into the fracture under conditions in which there was leakoff and no leakoff into the matrix. A gel did not form, and the gelant was easily displaced from the fracture by subsequent brine injection when the gelant was placed without leakoff. When the gelant was placed with leakoff, a gel formed in the fracture after placement and provided significant flow resistance. It is hypothesized that the lack of gelation in the absence of leakoff was caused by diffusion of chromium from the fracture to the matrix. Diffusion reduced the chromium concentration in the gelant to levels at which gelation would not occur when the gelant was placed without leakoff. It was discovered that gels that were formed in a fracture ruptured when a brine pressure was applied at the inlet. The pressure where rupture occurred was determined for gels placed in tubing of various lengths and diameters. The rupture pressure was proportional to a length/diameter ratio.

Applications of Polymer Gel for Establishing Zonal Isolations and Water Shutoff in Carbonate Formations

SummaryIn this paper, we present the results of successful applications of polymer gels to control water production in Mexico. We discuss three case studies that used a systematic methodology to correctly diagnose near-wellbore water channeling behind the casing. The methodology uses diagnostic plots based on the historical behavior of the water/oil ratio (WOR) as a function of time. These include correlation with information from original cement bond logs (CBL's), oxygen-activated logs during production to effectively determine the origin of the water, and saturation logs to determine the water levels independent of the salinity of the water produced.In addition, we present successful applications of polymer gels to re-establish zonal isolations in the three case studies previously mentioned. We discuss gel placement and present the procedure followed in each case, evaluate a water injectivity test followed by a temperature log taken before gel placement to determine the height propagation of the water, and anticipate potential zone damage of adjacent producing intervals during gel placement. In one case, a new interval completed perforating through the gel with excellent results. Another case involved a zone abandonment with gel, in which positive pressure was tested with 35 and 70 kg/cm2 wellhead pressure at 2500 m. In all cases, the advantages of gel treatments over common cement squeezes are discussed.Finally, we present the treatment results, including the analysis of pressures recorded during gel placement and the oil and water production before and after treatment.

Gel Placement in Porous Media: Constant Injection Rate

In this paper we analyse advective transport of polymers, crosslinkers and gel, taking into account non-equilibrium gelation, gel adsorption and crosslinker precipitation. In absence of diffusion/dispersion the resulting model consists of hyperbolic transport-reaction equations. These equations are studied in several steps using mainly analytical techniques. For simple cases, we obtain explicit travelling wave solutions, whereas for more complicated cases we rely on analytical techniques to analyse the problem qualitatively. Finally, a numerical solution for the full system of equations is obtained. The results developed in this study can be used to validate numerical solutions obtained from commercial simulators.

Design Strategies For Improved Conformance Using Polymer Gels

Abstract The possibility of using polymer gels for improved conformance in the treatment of producer wells has been evaluated using computer simulation. A radial model was built and used to test a variety of immiscible displacement conditions. The tests included water influx in a layered clastic reservoir with and without segregation between layers, simultaneous water and gas coning in a uniform carbonate reservoir, and simultaneous water and gas channelling in a fractured carbonate reservoir. The gel placement was modelled by altering the permeability, or the relative permeability, of the affected blocks according to experimentally determined values. Reverse coning was also evaluated for the case of simultaneous water and gas coning. This preliminary design work has proved that utilization of polymer gels in producers is favoured in clastic reservoirs when there is segregation between layers. It also proved that gels have little value when implemented in a uniform carbonate reservoir producing under high water/oil ratio. Gel placement extended production well life by significantly reducing water/oil ratios and gas/oil ratios, but cumulative oil production did not increase in proportion to well life. Injection of a plugging agent around the perforations can be detrimental to oil production if the plug is too large. Finally, reverse coning was found to be more effective than gel placement for the case of simultaneous water and gas coning. Introduction The concept of increasing conformance through the injection of polymer gels has been the topic of extensive research and numerous reviews. Water coning in oil wells has been the main focus of earlier research but gas coning is becoming of increasing interest. Recently, water coning in gas wells has also attracted attention. Although the problem focusses on producer wells, most of the successful treatments documented in the literature were applied on injectors. Reservoir conditions, gel properties and placement protocols influence how effectively gel treatments reduce water coning(1, 2). Although success has been demonstrated both in the laboratory and in the field, no one is in a position to claim a good understanding of why gels work so well in some situations and not in others(2). The majority of gels used today are either polyacrylamides(3, 4) or polysaccharides. However, simple polymer injection was considered for controlling water influx in horizontal wells placed in heavy oil reservoirs(5). Other technologies include use of nitrogen(6), starch biopolymers(7), silicates(8), surfactant and alcohol Blends(9), small particle cement(10), to name only a few of the recent applications. Of particular interest is the work that aims at selective relative permeability alteration so that water influx to the production wells is hindered. The technology can be applied to both oil and gas wells(11, 12). Recently, the combination of foams and gels seems to provide hope for extended use of gel technology(13, 14). Coupled with the laboratory findings, extensive field results have been presented by Marathon Oil(4), Phillips Petroleum(15), etc., where the effectiveness of gel technology has been mainly demonstrated for treatment of injector wells in waterflood scenarios of fractured reservoirs.

Gel Treatments for Reducing Channeling in Naturally Fractured Reservoirs

Summary This paper considers some of the reservoir variables that affect the severity of channeling and the potential of gel treatments for reducing channeling through naturally fractured reservoirs. We performed extensive tracer and gel placement studies using two different simulators. We show that gel treatments have the greatest potential when the conductivities of fractures that are aligned with direct flow between an injector-producer pair are at least 10 times the conductivity of off-trend fractures. Gel treatments also have their greatest potential in reservoirs with moderate to large fracture spacing. Produced tracer concentrations from interwell tracer studies can help identify reservoirs that are predisposed to successful gel applications. Our simulation studies also show how tracer transit times can be used to estimate the conductivity of the most direct fracture. The effectiveness of gel treatments should be insensitive to fracture spacing for fractures that are aligned with the direct flow direction. The effectiveness of gel treatments increases with increased fracture spacing for fractures that are not aligned with the direct flow direction.

Prostaglandin E 2 cervical ripening without subsequent induction of labor

Objective: To determine whether outpatient administration of intracervical prostaglandin (PG) E 2 gel decreases the interval to delivery and duration of labor. Methods: A randomized, double-blind, placebo-controlled trial compared the intracervical placement of 0.5 mg PGE 2 gel with placebo in 61 pregnant women at 38 weeks’ or greater gestation with Bishop scores less than 9. Transvaginal cervical length, fetal fibronectin, and Bishop score were assessed before gel placement. Subjects were then allowed to go into spontaneous labor unless an indication for induction developed. Results: Thirty women were assigned to PGE 2 and 31 to placebo. There were no significant demographic differences between the groups and there were no differences in cervical length, fetal fibronectin status, or Bishop scores. Fifteen women in the PGE 2 group and five in the placebo group went into labor and delivered within the first 2 days after gel placement ( P = .007). The median interval to delivery was significantly shorter in the PGE 2 group, at 2.5 days, compared with placebo, at 7 days ( P = .02). Nulliparas in the PGE 2 group had a median interval to delivery of 2 days, compared with 7 days for nulliparas receiving placebo ( P = .03). Active phases of labor were significantly shorter in the PGE 2 group and for women with a negative fetal fibronectin test who received PGE 2. Conclusion: Outpatient administration of intracervical PGE 2 gel shortened intervals to delivery and shortened labor.

Polymer Gel Dehydration During Extrusion Through Fractures

Summary Some of the most successful water shutoff treatments in fractured reservoirs used relatively large volumes of Cr(III)-acetate-HPAM gel that extruded through fractures during the gel placement process. The gel can dehydrate during extrusion, and consequently, propagate at an unexpectedly low rate if the fracture conductivity or width is sufficiently small. This paper characterizes the dehydration phenomenon and its relation to gel extrusion. The findings are relevant to gel placement during field applications.

A cost-minimization analysis of intracervical prostaglandin E 2 for cervical ripening in an outpatient versus inpatient setting

This investigation was undertaken to compare the cost impact of prostaglandin E 2 gel delivered intracervically in an outpatient versus an inpatient setting. Eligible pregnant women with a singleton gestation that was beyond 37 weeks gestational age and who had an unfavorable cervix (Bishop score ≤4) received a single dose of 0.5 mg of prostaglandin E 2 intracervically as an outpatient or one or more doses as an inpatient the day before a scheduled induction of labor. After gel placement, the outpatient group was monitored for 2 hours with electronic fetal monitoring before being sent home, while the inpatient group was monitored for 2 hours in a labor and delivery unit and then sent to the maternity unit overnight. The outpatient (n = 40) and inpatient (n = 36) groups were not different in terms of maternal age, race, parity, gestational age, maternal weight, predose Bishop score, or inidcation for delivery. Patients in the outpatient group incurred significantly less costs ($3835.00 ± 2172.00 vs $5049.00 ± 2060.00) and time (74.4 ± 33.1 hours vs 100.3 ± 41.6 hours) in the hospital than did patients in the inpatient group, compared with those in the inpatient group, spent fewer total hours in the hospital (56.6 ± 19.3 vs 90.3 ± 41.0 hours) and had a lower hospital cost ($2891.00 ± 1236.00 vs $4704.00 ± 2100.00). The only difference between the nulliparous groups favored outpatient therapy because of less intrapartum expenses ($730.00 ± 405.00 vs $1036.00 ± 487.00). There were no differences between the inpatient and outpatient groups for the frequencies of failed inductions abnormal fetal heart rate patterns, and cesarean sections. No adverse maternal or neonatal effects with therapy were encountered in either setting. Substantial cost savings were found with prostaglandin E 2 therapy in an outpatient rather than an inpatient setting for patients who required an induction of labor and were candidates for outpatient cervical ripening.

Gel Placement in Fractured Systems

SummaryThis paper examines several factors that can have an important effect on gel placement in fractured systems, including gelant viscosity, degree of gelation, and gravity. For an effective gel treatment, the conductivity of the fracture must be reduced and a viable flow path must remain open between the wellbore and mobile oil in the reservoir. During placement, the gelant that "leaks off" from the fracture into the rock plays an important role in determining how well a gel treatment will reduce channeling. For a given volume of gelant injected, the distance of gelant leakoff is greater for a viscous gelant than for a low-viscosity gelant (other factors being equal).In one method to minimize gelant leakoff, sufficient gelation is designed to occur before the gelant leaves the wellbore. We investigated this approach in numerous experiments with both fractured and unfractured cores. We studied Cr(III)/acetate/hydrolyzed polyacrylamide (HPAM), resorcinol/formaldehyde, Cr(III)/xanthan, aluminum/citrate/HPAM, and other gelants and gels with various delay times between gelant preparation and injection. Our results suggest both hope and caution concerning the injection of gels (rather than gelants) into fractured systems. Tracer studies indicate that some gels can effectively heal fractures under the right circumstances. However, high resistance factors exhibited during placement could limit the ability to propagate certain gels deep into a fractured system unless the fractures are very conductive.

Why Do Gels Reduce Water Permeability More Than Oil Permeability?

Summary A capacity to reduce water permeability much more than oil permeability is critical to the success of gel treatments in production wells if zones cannot be isolated during gel placement. Although several researchers have reported polymers and gels that provide this disproportionate permeability reduction, the explanation for the phenomenon was unclear. In this paper, we examine several possible explanations for why some gels reduce water permeability more than oil permeability. Our experimental results indicate the disproportionate permeability reduction is not caused by gravity or lubrication effects. Results also indicate that gel shrinking and swelling are unlikely to be responsible for the phenomenon. Although wettability may play a role in the disproportionate permeability reduction, it does not appear to be the root cause for water permeability being reduced more than oil permeability. Results from an experiment with an oil-based gel suggest that segregation of oil and water pathways through a porous medium (on a microscopic scale) may play the dominant role in the disproportionate permeability reduction. However, additional work will be required to verify this concept.

A Study of Diversion Mechanisms by Reactive Water Diverting Agents

Summary High water saturations in producing zones of petroleum formations cause problems during both acidizing and production. Water diverting agents are designed to prevent some of these problems by selectively plugging watered-out strata. Reactive water diverting agents are oil-based fluids that provide selective plugging because they react with aqueous formation fluids to form permeability reducing gels. This study used laboratory formulated diverting agents to elucidate the plugging mechanisms that result from in-situ interfacial reactions and gel placement. Our results show the physical characteristics of the media and gels necessary to bring about effective plugging and also the conditions that typically prevent selectivity. Additionally, a simple treatment method called the injection/back-flow procedure is introduced, which helps achieve a highly selective diversion treatment.

Gel Placement in Production Wells

Summary Straightforward applications of fractional-flow theory and material-balance calculations demonstrate that, if zones are not isolated during gel placement in production wells, gelant can penetrate significantly into all open zones, not just those with high water saturations. Unless oil saturations in the oil-productive zones are extremely high, oil productivity will be damaged even if the gel reduces water permeability without affecting oil permeability. Also, in field applications, capillary pressure will not prevent gelant penetration into oil-productive zones. An explanation is provided for the occurrence of successful applications of gels in fractured wells produced by bottomwater drive. With the right properties, gels could significantly increase the critical rate for water influx in fractured wells.