Using the Modified Resistivity–Porosity Cross Plot Method to Identify Formation Fluid Types in Tight Sandstone with Variable Water Salinity

It is generally difficult to identify fluid types in low-porosity and low-permeability reservoirs, and the Chang 8 Member in the Ordos Basin is a typical example. In the Chang 8 Member of Yanchang Formation in the Zhenyuan area of Ordos Basin, affected by lithology and physical properties, the resistivity of the oil layer and water layer are close, which brings great difficulties to fluid type identification. In this paper, we first analyzed the geological and petrophysical characteristics of the study area, and found that high clay content is one of the reasons for the low-resistivity oil pay layer. Then, the formation water types and characteristics of formation water salinity were studied. The water type was mainly CaCl2, and formation water salinity had a great difference in the study area ranging from 7510 ppm to 72,590 ppm, which is the main cause of the low-resistivity oil pay layer. According to the reservoir fluid logging response characteristics, the water saturation boundary of the oil layer, oil–water layer and water layer were determined to be 30%, 65% and 80%, respectively. We modified the traditional resistivity–porosity cross plot method based on Archie’s equations, and established three basic plates with variable formation water salinity, respectively. The above method was used to identify the fluid types of the reservoirs, and the application results indicate that the modified method agrees well with the perforation test data, which can effectively improve the accuracy of fluid identification. The accuracy of the plate is 88.1%. The findings of this study can help for a better understanding of fluid identification and formation evaluation.

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

10.5194/egusphere-egu21-664 ◽

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

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 km2. 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.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.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.

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Reservoir characteristics and control mechanism of resistivity low-contrast oil pays in Chang 8 tight sandstone of Longdong West area, Ordos Basin

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-021-01195-1 ◽

2021 ◽

Author(s):

Ze Bai ◽

Maojin Tan ◽

Yujiang Shi ◽

Gaoren Li ◽

Simon Martin Clark

Keyword(s):

Control Mechanism ◽

Ordos Basin ◽

Water Salinity ◽

Formation Water ◽

Tight Sandstone ◽

Low Contrast ◽

Reservoir Characteristics ◽

The Difference ◽

Formation Water Salinity ◽

And Control

AbstractLog interpretation and evaluation of tight sandstone reservoir in Chang 8 Member of Longdong West area, Ordos Basin, China, are facing great challenges due to the co-development of normal oil pay and resistivity low-contrast oil pay. To better guide the exploration and development of oil resources in this area, the reservoir characteristics and control mechanism of resistivity low-contrast oil pay were studied. Firstly, the reservoirs were divided into resistivity low-contrast oil pay (RLP) and normal oil pay (NP) based on the relative value of the apparent resistivity increase rate. Then, the difference of reservoir characteristics between RLP and NP is analyzed by comparing a series of experimental data and real logging data in those two reservoir types. Finally, the control mechanism of RLP was studied from reservoir micro-factors and regional macro-factors, respectively. It is found that the chlorite and illite are the most abundant clay minerals in RLP and NP, respectively. Compared with NP reservoir, the average porosity of RLP is better, but the pore space is mainly composed of micropores, which lead to smaller average pore throat radius and poor pore structure. The high irreducible water saturation and high formation water salinity reduced the reservoir resistivity from micro-aspect. Besides, the difference of hydrocarbon expulsion capacity of source rock and the regional difference of formation water salinity controlled the distribution of RLP and NP. Comprehensive consideration of the reservoir micro-factors and regional macro-factors is important to carry out effective logging interpretation and evaluation.

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

The APPEA Journal ◽

10.1071/aj85023 ◽

1986 ◽

Vol 26 (1) ◽

pp. 242 ◽

Cited By ~ 4

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.

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Logging Characteristics and Identification Methods of Low Resistivity Oil Layer: Upper Cretaceous of the Third Member of Qingshankou Formation, Daqingzijing Area, Songliao Basin, China

Geofluids ◽

10.1155/2017/2915646 ◽

2017 ◽

Vol 2017 ◽

pp. 1-13 ◽

Cited By ~ 1

Author(s):

Congjun Feng ◽

Murray Gingras ◽

Mengsi Sun ◽

Bing Wang

Keyword(s):

Water Saturation ◽

Thick Layer ◽

Water Layer ◽

High Amplitude ◽

Production Test ◽

Tight Sandstone ◽

Low Resistivity ◽

The Third ◽

Irreducible Water Saturation ◽

Low Amplitude

This study focuses on low resistivity thick layer sandstone in the X~XII groups of the third member of Qingshankou Formation at Daqingzijing oilfield, along with comprehensive data of logging, core, oil test, and production test. Based on the current data, we characterized the logs of low resistivity thick-layer sandstone, quantitatively identified calcareous sandstone and low resistivity reservoir, predicted the reservoir thickness, and further explored the causes of low resistivity reservoir of the region. The resistivity of thick layer sandstone in the X~XII groups of Qingshankou Formation can be classified into low amplitude logfacies, middle amplitude logfacies, and sharp high amplitude logfacies. Sharp high amplitude logfacies sandstone is the tight sandstone of the calcareous cementation. Low amplitude logfacies sandstone is water layer. For the middle amplitude logfacies sandstone, water layer or oil-water layer can be identified with the identification standard. Low amplitude structure, high clay content, high irreducible water saturation, and high formation water salinity are attributed to the origin of low resistivity oil layer.

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

10.30632/t60als-2019_nnn ◽

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

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

Mehran University Research Journal of Engineering and Technology ◽

10.22581/muet1982.2004.15 ◽

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).

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