scholarly journals Experimental evaluation and tomographic characterization of polymer gel conformance treatment

2020 ◽  
Vol 75 ◽  
pp. 65
Author(s):  
Mina Kalateh-Aghamohammadi ◽  
Jafar Qajar ◽  
Feridun Esmaeilzadeh
Keyword(s):  
Pore Space ◽  
Ct Images ◽  
Water Salinity ◽  
Water Production ◽  
Polymer Gel ◽  
Formation Water ◽  
High Permeability ◽  
Conformance Control ◽  
Formation Water Salinity ◽  
Excessive Water

Excessive water production from hydrocarbon reservoirs is considered as one of major problems, which has numerous economic and environmental consequences. Polymer-gel remediation has been widely used to reduce excessive water production during oil and gas recovery by plugging high permeability zones and improving conformance control. In this paper, we investigate the performance of a HPAM/PEI (water-soluble Hydrolyzed PolyAcrylaMide/PolyEthyleneImine) polymer-gel system for pore space blockage and permeability reduction for conformance control purpose. First, the gel optimum composition, resistance to salt and long life time are determined using bottle tests as a standard method to specify polymer-gel properties. Then the performance and stability of the optimized polymer-gel are tested experimentally using coreflood tests in sandpack core samples. The effects of different parameters such as gel concentration, initial permeability of the cores, and formation water salinity on the final permeability of the cores are examined. Finally, the gel flow-induced local porosity changes are studied in both a sandpack core and a real carbonate sample using grayscale intensity data provided from 3D Computed Tomography (CT) images in pre- and post-treatment states. The results show that the gel system has a good strength at the middle formation water salinity (in the range of typical sea water salinity). In addition, despite a higher performance in high permeability cores, the gel resistance to degradation in such porous media is reduced. The CT images reveal that the initial porosity distribution has a great influence on the performance of the gel to block the pore space.

A NEUTRON-INDUCED GAMMA-RAY SPECTROSCOPY LOGGING METHOD FOR DETERMINING FORMATION WATER SALINITY

2019 ◽  
Author(s):  
Lili Tian ◽  
Feng Zhang ◽  
Quanying Zhang ◽  
Qian Chen ◽  
Xinguang Wang ◽  
...  
Keyword(s):  
Gamma Ray ◽  
Water Salinity ◽  
Formation Water ◽  
Gamma Ray Spectroscopy ◽  
Formation Water Salinity

scholarly journals Thermal Stability and Compatibility of Surfactants in Presence of Formation Water Salinity under Reservoir Conditions

2020 ◽  
Vol 39 (4) ◽  
pp. 826-830
Author(s):  
Muhammad Khan Memon ◽  
Ubedullah Ansari ◽  
Habib U Zaman Memon
Keyword(s):  
Thermal Stability ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Gas Injection ◽  
Surfactant Solution ◽  
Water Salinity ◽  
Formation Water ◽  
Reservoir Temperature ◽  
Gas Mobility ◽  
Formation Water Salinity

In the surfactant alternating gas injection, the injected surfactant slug is remained several days under reservoir temperature and salinity conditions. As reservoir temperature is always greater than surface temperature. Therefore, thermal stability of selected surfactants use in the oil industry is almost important for achieving their long-term efficiency. The study deals with the screening of individual and blended surfactants for the applications of enhanced oil recovery that control the gas mobility during the surfactant alternating gas injection. The objective is to check the surfactant compatibility in the presence of formation water under reservoir temperature of 90oC and 120oC. The effects of temperature and salinity on used surfactant solutions were investigated. Anionic surfactant Alpha Olefin Sulfonate (AOSC14-16) and Internal Olefin Sulfonate (IOSC15-18) were selected as primary surfactants. Thermal stability test of AOSC14-16 with different formation water salinity was tested at 90oC and 120oC. Experimental result shows that, no precipitation was observed by surfactant AOSC14-16 when tested with different salinity at 90oC and 120oC. Addition of amphoteric surfactant Lauramidopropylamide Oxide (LMDO) with AOSC14-16 improves the stability in the high percentage of salinity at same temperature, whereas, the surfactant blend of IOSC15-18 and Alcohol Aloxy Sulphate (AAS) was resulted unstable. The solubility and chemical stability at high temperature and high salinity condition is improved by the blend of AOSC14-16+LMDO surfactant solution. This blend of surfactant solution will help for generating stable foam for gas mobility control in the methods of chemical Enhanced Oil Recovery (EOR).

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.

Field Performances, Effective Times, and Economic Assessments of Polymer Gel Treatments in Controlling Excessive Water Production From Mature Oil Fields

2020 ◽  
Vol 143 (8) ◽  
Author(s):  
Munqith Aldhaheri ◽  
Mingzhen Wei ◽  
Ali Alhuraishawy ◽  
Baojun Bai
Keyword(s):  
Fractured Reservoirs ◽  
Descriptive Analysis ◽  
Naturally Fractured Reservoirs ◽  
Oil Fields ◽  
Water Production ◽  
Polymer Gel ◽  
Rock Formations ◽  
Water Cut ◽  
Matrix Rock ◽  
Excessive Water

Abstract Polymer bulk gels have been widely applied to mitigate excessive water production from mature oil fields by correcting the reservoir permeability heterogeneity. This paper reviews water responses, effective times, and economic assessments of injection-well gel treatments based on 61 field projects. Eight parameters were evaluated per the reservoir type using the descriptive analysis, stacked histograms, and scatterplots. Results show that water production generally continues to increase after the treatment for undeveloped conformance problems. Contrarily, it typically decreases after the reactive gel treatments target developed conformance issues. For the developed problems, gel treatments do not always mitigate the water production where the water cut may stabilize or increase by 17% in 22% of instances. In addition, they often do reduce water production but not dramatically to really low levels where the water cut stays above 70% and reduces by only 10% in most cases. Gel treatments are economically appraised based only on the oil production response, and both water responses (injection and production) are not considered in the evaluation. They have a typical payout time of 9.2 months, cost of incremental oil barrel of 2 $/barrel, and effective time of 1.9 years. In addition, they have better water responses and economics in carbonates than in sandstones and in unconsolidated and naturally fractured reservoirs than in matrix-rock formations. The current review strongly warns reservoir engineers that gel treatments are not superior in alleviating the water production and candidates should be nominated based on this fact to achieve favorable economics and avoid treatment failures.

RELATIONSHIP BETWEEN FORMATION WATER SALINITY AND BIOGENIC COALBED METHANE: BLACK WARRIOR BASIN, ALABAMA (USA)

2016 ◽  
Author(s):  
Tyler Gilkerson ◽  
◽  
Jack C. Pashin ◽  
Tracy M. Quan ◽  
Thomas H. Darrah ◽  
...  
Keyword(s):  
Coalbed Methane ◽  
Water Salinity ◽  
Formation Water ◽  
Black Warrior Basin ◽  
Formation Water Salinity

Analysis of main controlling factors and identification method of Jurassic low resistivity reservoir in Huanxian area, Ordos Basin

2021 ◽  
Author(s):  
Jingzhe Guo ◽  
Lifa Zhou
Keyword(s):  
Apparent Resistivity ◽  
Ordos Basin ◽  
Controlling Factors ◽  
Water Salinity ◽  
Formation Water ◽  
Low Resistivity ◽  
Reservoir Fluid ◽  
Oil Resources ◽  
The Ordos Basin ◽  
Formation Water Salinity

<p>The Ordos Basin is located in the central and western part of China, which is rich in oil resources in Mesozoic strata. Huanxian area is located in the west of the Ordos Basin, covering an area of about 3000 km<sup>2</sup>. With the wide distribution of Jurassic low resistivity reservoir, it is difficult to identify reservoir fluid by logging, which restricts the efficient promotion of oil resources exploration and development in this area to a certain extent.</p><p>Based on the basic geological law, this study makes full use of the data of oil test conclusion, production performance and formation water analysis to deeply analyze the genesis of low resistivity reservoir in this area. The average formation water salinity of Jurassic in Huanxian area is 63.5g/l. Through the correlation analysis of mathematical methods such as fitting and regression, the formation water salinity and reservoir apparent resistivity show a good negative correlation in the semi logarithmic coordinate, and the correlation coefficient is 0.78. Therefore, it is considered that the main controlling factor for the widespread development of low resistivity reservoir in this area is the high formation water salinity. Irreducible water saturation, clay mineral content and nose bulge structure amplitude are the secondary controlling factors for the development of low resistivity reservoir in this area, and their correlation coefficients with apparent resistivity are 0.23, 0.25 and 0.31, respectively.</p><p>On the basis of clarifying the genesis of Jurassic low resistivity reservoir in Huanxian area, the comprehensive identification of reservoir fluid type by logging is carried out. For the whole area, there are obvious differences in geological characteristics, so conventional methods such as cross plot method of acoustic time difference and apparent resistivity can not effectively identify reservoir fluid. According to the main controlling factors of reservoir apparent resistivity, the salinity of formation water is combined with apparent resistivity and resistivity index of reservoir respectively to establish the cross plot. Using these two kinds of cross plot, the accuracy of reservoir fluid type identification is 62.9% and 88.6% respectively. This method can meet the accuracy requirements of reservoir fluid identification, realize the rapid identification of reservoir fluid types in the whole area, and provide technical support for efficient exploration and development of Jurassic low resistivity reservoir in this area.</p>

A Novel Branched Polymer Gel System with Delayed Gelation Property for Conformance Control

SPE Journal ◽  
2021 ◽  
pp. 1-11
Author(s):  
Tao Song ◽  
Qi Feng ◽  
Thomas Schuman ◽  
Jie Cao ◽  
Baojun Bai
Keyword(s):  
Gelation Time ◽  
Polymer Gels ◽  
Environmental Concerns ◽  
Water Production ◽  
Polymer Gel ◽  
Conformance Control ◽  
Branched Polymer ◽  
Chelating Ability ◽  
Hydrolyzed Polyacrylamide ◽  
Gel System

Summary Excessive water production from oil reservoirs not only affects the economical production of oil, but it also results in serious environmental concerns. Polymer gels have been widely applied to decrease water production and thus improve oil production. However, traditional polymer gels such as partially hydrolyzed polyacrylamide (HPAM)/chromium (III) gel systems usually have a short gelation time and cannot meet the requirement of some conformance control projects. This paper introduces a novel polymer gel system of which crosslinking time can be significantly delayed. A branched polymer grafted from arginine by the surface initiation method is synthesized as the backbone, chromium acetate is used as the crosslinker, and no additional additives are used for the gel system. The results show that the gelation time of this system can be delayed to 61 days at 45°C and 20 days at 65°C because of the rigid structure of the branched polymer and the excellent chromium (III) chelating ability of arginine. The polymer gels have been stable for more than 150 days at 45 and 65°C. Coreflooding and rheology tests have demonstrated that this branched polymer has good injectivity and shear resistance in high-permeabilityrocks.

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