Effect of Formation Water Salinity on Interfacial Tension of Reservoir Fluids

2021 ◽  
pp. 108700
Author(s):  
Bastian Sauerer ◽  
Mohammed Al-Hamad ◽  
Shouxiang Mark Ma ◽  
Wael Abdallah
Keyword(s):  
Interfacial Tension ◽  
Water Salinity ◽  
Formation Water ◽  
Formation Water Salinity

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).

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>

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.

FRESHWATER INFLUX IN THE GIPPSLAND BASIN: IMPACT ON FORMATION EVALUATION, HYDROCARBON VOLUMES, AND HYDROCARBON MIGRATION

1986 ◽  
Vol 26 (1) ◽  
pp. 242 ◽  
Author(s):  
K. Kuttan ◽  
J.B. Kulla ◽  
R.G Neumann
Keyword(s):  
Water Saturation ◽  
Water Salinity ◽  
Production Test ◽  
Formation Water ◽  
Aquifer System ◽  
Using Data ◽  
Saline Formation ◽  
Freshwater Aquifers ◽  
Formation Water Salinity ◽  
Gippsland Basin

The recognition and quantitative evaluation of hydrocarbon zones in the Gippsland Basin is complicated by the presence of a freshwater aquifer system. This aquifer system has been verified and documented using data obtained from wireline logs. The presence of freshwater aquifers below the hydrocarbon sands leads to (i) difficulty in distinguishing the hydrocarbon zones from the water sands using well logs, and (ii) difficulty in determining accurate water saturation values used in estimating hydrocarbon volumes.Water saturations calculated from logs require the input of a formation water salinity. In conventional log analysis the formation water salinity in the hydrocarbon zones is assumed to be the same as that of the underlying water sands. In reservoirs in the Gippsland Basin underlain by freshwater aquifers, calculated water saturations using the salinities of the water sands are inconsistent with capillary pressure, Repeat Formation Tester (RFT*-Schlumberger), and production test data. All available evidence suggests that the formation water salinities within the hydrocarbon zones are significantly greater than in the freshwater aquifers. The water saturations derived using the higher salinity values lead to the calculation of greater hydrocarbon volumes.The occurrence of saline formation waters within the hydrocarbon zones leads to the interpretation that significant volumes of hydrocarbon were emplaced prior to the formation of the freshwater aquifer system. Subsequent freshwater influx did not flush the emplaced hydrocarbons.

Formation water salinity and macro-components’ composition for Bazhenov, Achimov and Georgiev formations from the results of water extract analysis

2018 ◽  
pp. 100-110
Author(s):  
E. S. Kazak ◽  
N. A. Haritonova ◽  
A. V. Kazak
Keyword(s):  
Water Extract ◽  
Laboratory Analysis ◽  
Water Salinity ◽  
Reliable Estimate ◽  
Formation Water ◽  
Salt Composition ◽  
Shale Formations ◽  
Before And After ◽  
Formation Water Salinity ◽  
First Time

The paper presents for the first time a reliable dataset on formation water salinity and salt composition for tight shale formations of Bazhenov, Achimov and Georgiev suites. The data were obtained in the result of laboratory analysis of aqueous extracts from rock samples before and after its hydrocarbon extraction (cleaning). Based on the experimental data a thermodynamic modeling of solution-mineral equilibrium was performed followed by Na/Cl, Ca/SO4, Mg/SO4, Ca/Cl, Ca/HCO3, Fe/SO4 correlation analysis. The results shown that concentrations of certain macro-components, including Ca, Mg, Fe, hydrocarbonate and sulfate ion in pore solutions cannot be reliably determined using aqueous extract data. At the same time a reliable estimate nominal salinity of formation water could be provided using the obtained data. The paper concludes that a reliable study of macro-components’ chemical composition in formation waters of tight shale formations requires laboratory analysis of non-extracted rock core samples with maximal preservation of water content.

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