Permeability Modification Simulator Studies of Polymer-Gel-Treatment Initiation Time and Crossflow Effects on Waterflood Oil Recovery

1993 ◽  
Vol 8 (03) ◽  
pp. 221-227 ◽  
Author(s):  
Hong W. Gao ◽  
Ming-Ming Chang ◽  
Thomas E. Burchfield ◽  
Min K. Tham
Keyword(s):  
Oil Recovery ◽  
Treatment Initiation ◽  
Initiation Time ◽  
Polymer Gel ◽  
Gel Treatment ◽  
Permeability Modification

Large-Volume Foam-Gel Treatments to Improve Conformance of the Rangely CO2 Flood

1999 ◽  
Vol 2 (01) ◽  
pp. 14-24 ◽  
Author(s):  
T.L. Hughes ◽  
F. Friedmann ◽  
D. Johnson ◽  
G.P. Hild ◽  
A. Wilson ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Large Volume ◽  
Fractured Reservoirs ◽  
Gas Injection ◽  
Cost Effective ◽  
Fracture Network ◽  
Polymer Gel ◽  
Sweep Efficiency ◽  
Gel Treatment ◽  
Incremental Oil Recovery

Summary Large-volume foam-gel treatments can provide a cost-effective method to achieve in-depth conformance improvement in fractured reservoirs. The applicability and cost effectiveness of the approach depends on the availability of a cheap source of gas, the efficiency with which the foam can be placed into the high permeability thief zone(s), and the effectiveness of the gelled foam barrier in diverting reservoir drive fluids to improve oil recovery. This paper reviews progress in the application of large-volume CO2-foam-gel treatments to improve conformance in the Rangely Weber Sand Unit (RWSU), Colorado. During the period November 1996-November 1997 three large-volume foam-gel treatments were successfully placed into the Rangely reservoir. The first 36?400 bbl treatment, implemented November 1996, increased the pattern oil rate from 260 barrels of oil per day (BOPD) in March 1997 to ±330 BOPD in August 1998; a conservative estimate of incremental oil recovery is ±40?000 bbl by the end of August 1998. The second 43?450 bbl treatment, implemented August-September 1997, increased the pattern oil rate from ±430 BOPD in March 1998 to ±470 BOPD in August 1998; post-treatment, the pattern oil rate data is described by a linear regression with slope, +56 BOPD but it is too early to make a firm estimate of incremental oil recovery. The third 44?700 bbl treatment, implemented October-November 1997, increased the pattern oil rate from ±330 BOPD in May 1998 to ±375 BOPD in July-August 1998; a linear regression of the post-treatment data gives a positive slope but again it is too early to estimate incremental oil recovery. Some general features in the pattern production response given by the three foam-gel treatments were observed. First, each of the treatments induces a stabilization in the pattern oil rate which, for treatments I and II, is accompanied by a decrease in the pattern gas rate. Second, the first positive oil rate response given by each of the treatments is observed 6-8 months after treatment execution and is dominated by the response at producer wells lying to the west/southwest and/or east/southeast of the treated injector well. For a given treatment volume, the cost of a foam-gel treatment at Rangely is 40%-50% below the average cost of polymer gel treatments. As the foam is injected at a higher rate, the total pump time required for a 40?000 bbl foam-gel treatment is similar to a 20?000 bbl polymer gel treatment. Early during pumping treatments II and III, we attempted to increase the CO2 content of the foam from 80 to 85 vol?%; this resulted in a wellhead pressure which was too close to the CO2 pressure limit necessitating a decrease in foam injection rate. Thus, in optimizing foam-gel treatment cost, there is a balance between maximizing the content of the inexpensive CO2 phase and minimizing total pump time. For Treatments II and III, the cost of the liquid phase formulation was reduced by decreasing the concentrations of surfactant and buffer. The implementation and evaluation of three large-volume foam-gel treatments at Rangely indicates that the foam-gel approach provides a cost-effective method to achieve in-depth conformance improvement in fractured reservoirs. Introduction A recent survey1 indicated that the proportion of U.S. EOR production recovered by gas injection has increased from 18% to 41% during the period 1986-1996. A major contribution to this trend has been the strong increase in the number of miscible carbon dioxide (CO2) projects which now account for > 70% of the total number of ongoing gas injection projects in the U.S. The Rangely CO2 flood began in 1986; currently, there are 372 active producer wells and 300 active injector wells, 259 of which are injecting CO2 using the water-alternating-gas (WAG) process. In the application of gas injection to heterogeneous reservoirs, oil recovery efficiency can be limited by poor conformance as an increasing proportion of the injected gas flows through higher permeability thief zones and/or fractures. The importance of conformance improvement has long been recognized at Rangely. The main problem being addressed is poor CO2 conformance due to preferential flow through the natural fracture network leading to premature gas breakthrough at the associated producers. This process increases operating costs and reduces oil recovery. The objective of the Rangely Conformance Improvement Team (CIT) is to improve conformance in order to reduce operating costs and increase the oil recovery to >1 billion bbl (>50% OOIP) compared to the current 815 million bbl (43% OOIP). A number of mechanical methods and chemical treatments have been employed to improve conformance at Rangely. While dual injection strings and selective injection equipment (SIE) have been used for improved injection profile control, chemical treatments using polymer gels2 and CO2 foam3 have been used to improve volumetric sweep efficiency and oil recovery. During the period 1994-1997, 49 injector wells were treated by placing a MARCIT™ gel4 into the fracture network.5 While these treatments have improved local sweep efficiency and oil recovery, economics limit the maximum treatment volume per injector well to 15?000-20?000 bbl. Certain regions of the Rangely reservoir require considerably larger treatment volumes to reduce the permeability of a larger volume of the fracture network and improve conformance in a larger volume of the well pattern.

scholarly journals Application of Polymer Based Nanocomposites for Water Shutoff—A Review

Fuels ◽  
2021 ◽  
Vol 2 (3) ◽  
pp. 304-322
Author(s):  
Velima Obino ◽  
Upendra Yadav
Keyword(s):  
Thermal Stability ◽  
Oil Recovery ◽  
Experimental Studies ◽  
High Water ◽  
Polymer Gel ◽  
Polymer Hydrogels ◽  
Undesirable Characteristic ◽  
Gel Treatment ◽  
Reservoir Conditions ◽  
Thermal Stability Of

One highly undesirable characteristic of mature assets that inhibits oil recovery is high water production. Polymer gel treatment is a popular conformance improvement technique applied in this regard due to its cost effectiveness and proved efficiency. Despite this popularity, optimum performance of polymer hydrogels in water shut off is inhibited by excessive aggregation, difficulty in controlling gelation, and their instability at high temperature and high salinity reservoir conditions. To address these shortcomings, research on the application of nanoparticles (NPs) in polymer hydrogels to manage thermal stability and salinity sensitivity has significantly increased in the recent past. By incorporating metal-based NPs, silica or graphene at nanoscale; the gel strength, storage modulus, salinity tolerance and thermal stability of commonly used polymers have been greatly enhanced. In this paper, the advances in experimental studies on polymer-based nanocomposites are discussed and field experiences from adoption of polymer composites reviewed.

Polymer Gelled Technology to Improve Sweep Efficiency in Enhanced Oil Recovery: A Literature Review

2015 ◽  
Vol 1113 ◽  
pp. 690-694 ◽  
Author(s):  
Norfarisha Achim ◽  
Nur Hashimah Alias ◽  
Nurul Aimi Ghazali ◽  
Miradatul Najwa Muhd Rodhi ◽  
Tengku Amran Tengku Mohd ◽  
...  
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Polymer Gels ◽  
Fluid Injection ◽  
Potential Candidate ◽  
Polymer Gel ◽  
Excellent Performance ◽  
Sweep Efficiency ◽  
Enhance Oil Recovery ◽  
Permeability Modification

This article is an overview of the use of polymer gelled technology to improve sweep efficiency in enhanced oil recovery. Recent progress use polymer types, Polyacrylamide and polysaccharide to be applied in enhanced oil recovery (EOR). A lot of researchers concluded that polymer gel stability must be maintained to ensure excellent performance in sweep efficiency. The application of polymer gels in permeability modification to improve volumetric sweep efficiency of fluid injection processes showed fruitful efforts as it can be a potential candidate to enhance oil recovery as compared to other technologies.

scholarly journals On estimating optimal regime for treatment initiation time based on restricted mean residual lifetime

Biometrics ◽  
2021 ◽  
Author(s):  
Xin Chen ◽  
Rui Song ◽  
Jiajia Zhang ◽  
Swann Arp Adams ◽  
Liuquan Sun ◽  
...  
Keyword(s):  
Treatment Initiation ◽  
Residual Lifetime ◽  
Initiation Time ◽  
Optimal Regime ◽  
Mean Residual Lifetime

Design of in-Depth Conformance Gel Treatment to De-Risk ASP Flooding in a Major Carbonate Reservoir

2021 ◽  
Author(s):  
Mohammed T. Al-Murayri ◽  
Abrahim A. Hassan ◽  
Deema Alrukaibi ◽  
Amna Al-Qenae ◽  
Jimmy Nesbit ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Oil Recovery ◽  
Significant Risk ◽  
High Viscosity ◽  
Carbonate Reservoir ◽  
High Permeability ◽  
Laboratory Design ◽  
Gel Treatment ◽  
Viscosity Polymer ◽  
Chromium Acetate

Abstract Mature carbonate reservoirs under waterflood in Kuwait suffer from relatively low oil recovery due to poor sweep efficiency, both areal and microscopic. An Alkaline-Surfactant-Polymer (ASP) pilot is in progress targeting the Sabriyah Mauddud (SAMA) reservoir in pursuit of reserves growth and production sustainability. SAMA suffers from reservoir heterogeneities mainly associated with permeability contrast which may be improved with a conformance treatment to de-risk pre-mature breakthrough of water and chemical EOR agents in preparation for subsequent ASP injection and to improve reservoir contact by the injected fluids. Design of the gel conformance treatment was multi-faceted. Rapid breakthrough of tracers at the pilot producer from each of the individual injectors, less than 3 days, implied a direct connection from the injectors to the producer and poses significant risk to the success of the pilot. A dynamic model of the SAMA pilot was used to estimate in the potential injection of either a high viscous polymer solution (~200 cp) or a gel conformance treatment to improve contact efficiency, diverting injected fluid into oil saturated reservoir matrix. High viscosity polymer injection scenarios were simulated in the extracted subsector model and showed little to no effect on diverting fluids from the high permeability streak into the matrix. Gel conformance treatment, however, provides benefit to the SAMA pilot with important limitations. Gel treatment diverts injected fluid from the high permeability zone into lower permeability, higher oil saturated reservoir. After a gel treatment, the ASP increases the oil cut from 3% to 75% while increasing the cumulative oil recovery by more than 50 MSTB oil over ASP following a high viscosity polymer slug alone. Laboratory design of the gel conformance system for the SAMA ASP pilot involved blending of two polymer types (AN 125SH, an ATBS type polymer, and P320 VLM and P330, synthetic copolymers) and two crosslinkers (chromium acetate and X1050, an organic crosslinker). Bulk testing with the polymer-crosslinker combinations indicated that SAMA reservoir brine resulted in not gel system that would work in the SAMA reservoir, resulting in the recommendation of using 2% KCl in treated water for gel formulation. AN 125 SH with S1050 produce good gels but with short gelation times and AS 125 SH with chromium acetate developed low gels consistency in both waters. P330 and P320 VLM gave good gels with slow gelation times with X1050 crosslinker in 2% KCl. Corefloods with the P330-X 1050 showed good injectivity and ultimately a reduction of permeability of about 200-fold. A P330-X 1050 was recommended for numerical simulation studies. Numerical simulator was calibrated by matching bulk gel viscosity increases and coreflood permeability changes. Numerical simulation indicated two of the four injection wells (SA-0557 and SA-0559) injection profile will change compared to water. Overall injection rate was reduced by the conformance treatment and was the corresponding oil rate. Total oil production from the center pilot production well (SA-0560) decreased with gel treatment but ultimately increased to greater rates

Understanding the Plugging Performance of HPAM-Cr (III) Polymer Gel for CO2 Conformance Control

SPE Journal ◽  
2020 ◽  
Author(s):  
Xindi Sun ◽  
Baojun Bai ◽  
Ali Khayoon Alhuraishawy ◽  
Daoyi Zhu
Keyword(s):  
Pressure Gradient ◽  
Low Permeability ◽  
Far Field ◽  
Polymer Gel ◽  
Co2 Flooding ◽  
High Permeability ◽  
Conformance Control ◽  
Gel Treatment ◽  
Plugging Performance ◽  
Breakthrough Pressure

Summary With the demand for conformance control in carbon dioxide (CO2) flooding fields, hydrolyzed polyacrylamide-chromium [HPAM-Cr (III)] polymer gel has been applied in fields for CO2 conformance control. However, the field application results are mixed with success and failure. This paper is intended to understand the HPAM-Cr (III) polymer gel plugging performance in CO2 flooding reservoirs through laboratory experiments and numerical analysis. We conducted core flooding tests to understand how the cycles of CO2 and water affect the HPAM-Cr (III) polymer gel plugging efficiency to CO2 and water during a water-alternating-gas (WAG) process. Berea Sandstone cores with the permeability range of 107 to 1225 md were used to evaluate the plugging performance in terms of residual resistance factor and breakthrough pressure, which is the minimum pressure required for CO2 to enter the gel-treated cores.We compared the pressure gradient from the near-wellbore to far-field with the gel breakthrough pressure, from which we analyzed under which conditions the gel treatment could be more successful. Results show that HPAM-Cr (III) polymer gel has higher breakthrough pressure in the low-permeability cores. The polymer gel can reduce the permeability to water much more than that to CO2. The disproportionate permeability reduction performance was more prominent in low-permeability cores than in high-permeability cores. The gel resistance to both CO2 and brine significantly decreased in later cycles. In high-permeability cores, the gel resistance to CO2 became negligible only after two cycles of water and CO2 injection. Because of the significant reduction of pressure gradient from near-wellbore to far-field in a radial flow condition and the dependence of breakthrough pressure on permeability and polymer concentration, we examined hypothetical reservoirs with no fractures, in which impermeable barriers separated high- and low-permeability zones and in which the gel was only placed in the high-permeability zone. We considered two scenarios: CO2 breaking through the gel and no CO2 breakthrough. No breakthrough represents the best condition in which the gel has no direct contact and can be stable in reservoirs for long. In contrast, the breakthrough scenario will result in the gel’s significant degradation and dehydration resulting from CO2 flowing through the gel, which will cause the gel treatment to fail.

scholarly journals Experimental Investigation of Chemical Flooding Using Nanoparticles and Polymer on Displacement of Crude Oil for Enhanced Oil Recovery

2020 ◽  
Vol 2020 ◽  
pp. 1-10
Author(s):  
Imran Akbar ◽  
Hongtao Zhou ◽  
Wei Liu ◽  
Muhammad Usman Tahir ◽  
Asadullah Memon ◽  
...  
Keyword(s):  
Fluid Flow ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Petroleum Industry ◽  
Chemical Flooding ◽  
Polymer Gel ◽  
Core Flooding ◽  
High Concentration ◽  
Remaining Oil ◽  
Water Cut

In the petroleum industry, the researchers have developed a new technique called enhanced oil recovery to recover the remaining oil in reservoirs. Some reservoirs are very complex and require advanced enhanced oil recovery (EOR) techniques containing new materials and additives in order to produce maximum oil in economic and environmental friendly manners. In this work, the effects of nanosuspensions (KY-200) and polymer gel HPAM (854) on oil recovery and water cut were studied in the view of EOR techniques and their results were compared. The mechanism of nanosuspensions transportation through the sand pack was also discussed. The adopted methodology involved the preparation of gel, viscosity test, and core flooding experiments. The optimum concentration of nanosuspensions after viscosity tests was used for displacement experiments and 3 wt % concentration of nanosuspensions amplified the oil recovery. In addition, high concentration leads to more agglomeration; thus, high core plugging takes place and diverts the fluid flow towards unswept zones to push more oil to produce and decrease the water cut. Experimental results indicate that nanosuspensions have the ability to plug the thief zones of water channeling and can divert the fluid flow towards unswept zones to recover the remaining oil from the reservoir excessively rather than the normal polymer gel flooding. The injection pressure was observed higher during nanosuspension injection than polymer gel injection. The oil recovery was achieved by about 41.04% from nanosuspensions, that is, 14.09% higher than polymer gel. Further investigations are required in the field of nanoparticles applications in enhanced oil recovery to meet the world's energy demands.

Increased Oil Recovery by Permeability Modification in High Perm Contrast Slim Tubes

2014 ◽  
Author(s):  
Scott Jackson ◽  
John Fisher ◽  
Robert Fallon ◽  
Joseph Norvell ◽  
Edwin Hendrickson ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Permeability Modification ◽  
Increased Oil Recovery
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