Robust Reservoir Characterisation of UAE Heterogeneous Carbonate Reservoirs (original) (raw)
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A New Approach of Reservoir Description of Carbonate Reservoirs
Proceedings of SPE International Petroleum Conference and Exhibition in Mexico, 2002
This study is conducted to test and evaluate the use of current methods of reservoir characterization, namely the permeability-porosity correlation, the J-function, and the Reservoir Quality Index (RQI) concepts, for reservoir description of heterogeneous carbonate formations. These approaches were compared with a new technique developed in this paper for improved reservoir description of carbonate reservoirs. This technique is called the Characterization Number (CN) technique and it is based upon considering fluid, rock, rock-fluid properties and flow mechanics of oil reservoirs. To compare these reservoir characterization techniques, measurements of porosity, absolute permeability, oil and water relative permeability and irreducible water saturation for 83 actual core samples extracted from eight different wells for a new oil reservoir in the U.A.E. are obtained. These experimental data are used first to develop a permeabilityporosity correlation. Then, the J-function and the RQI concepts along with the newly developed CN approach are applied and evaluated for reservoir description of the UAE carbonate reservoir under investigation. The results show that the Reservoir Quality Index concept is capable of identifying the flow units while the J-function concept is quiet poor. Also, a more refined identification of flow units is obtained by using the newly-developed Characterization Number. This improved description for the Characterization Number approach may be attributed to the consideration of rock/fluid properties of flowing fluid(s) and flow dynamic conditions of its containing formation.
Reservoir Characterization and Rock Typing of Carbonate Reservoir in the Southeast of Iraq
Iraqi Geological Journal
Flow unit and reservoir rock type identification in carbonates are difficult due to the intricacy of pore networks caused by facies changes and diagenetic processes. On the other hand, these classifications of rock type are necessary for understanding a reservoir and predicting its production performance in the face of any activity. The current study focuses on rock type and flow unit classification for the Mishrif reservoir in Iraq's southeast and the study is based on data from five wells that penetrate it. Integration of several methods was used to determine the flow unit based on well log interpretation and petrophysical properties. The flow units were identified using the Quality Index of Rock and the Indicator of Flow Zone. The Winland correlation was used to determine the pore throat size. The Lucia classification was based on fabric rock number, and cluster analysis detects rock types using well log data within the Mishrif Formation. Four rock types have been specified b...
Hydraulic flow units for reservoir characterization: A successful application on arab-d carbonate
IOP Conference Series: Materials Science and Engineering, 2018
The characterization of carbonate formations is challenging as compared to sandstones, yet carbonate reservoirs hold over 60% of the world's hydrocarbon reserves. Carbonate reservoirs exhibit a high level of heterogeneity at every scale; from core to field. To be able to manage heterogeneity for reservoir modelling, the formation has to be discretized into a few rock types, each of which having somewhat similar flow properties. Recently, the interest in extending the rock-typing approaches is increasing with the aim to identify the potential layers in complex lithology like carbonates. The approach becomes more rigorous if the geological description is coordinated with petrophysical data, an approach that has been followed in this study. The hydraulic flow units in Arab-D formation were identified and interpreted using both geological facies and petrophysical data. All three methods; histogram analysis, normal probability plot and least-squared regression were utilized to determine the optimum number of hydraulic flow units across Arab-D carbonate formation. Published routine core analysis data from ten wells of Arab-D formation was analyzed and six optimum hydraulic flow units were identified. The average porosity and average permeability of each hydraulic flow unit was then computed. The results were found to be in good agreement with the geological facies data of the Arab-D formation, thus validating the identified flow units.
Estimation of Permeability From Well Logs Using Resistivity and Saturation Data
Spe Formation Evaluation, 1997
This study is conducted to test and evaluate the use of current methods of reservoir characterization, namely the permeability-porosity correlation, the J-function, and the Reservoir Quality Index (RQI) concepts, for reservoir description of heterogeneous carbonate formations. These approaches were compared with a new technique developed in this paper for improved reservoir description of carbonate reservoirs. This technique is called the Characterization Number (CN) technique and it is based upon considering fluid, rock, rock-fluid properties and flow mechanics of oil reservoirs. To compare these reservoir characterization techniques, measurements of porosity, absolute permeability, oil and water relative permeability and irreducible water saturation for 83 actual core samples extracted from eight different wells for a new oil reservoir in the U.A.E. are obtained. These experimental data are used first to develop a permeabilityporosity correlation. Then, the J-function and the RQI concepts along with the newly developed CN approach are applied and evaluated for reservoir description of the UAE carbonate reservoir under investigation. The results show that the Reservoir Quality Index concept is capable of identifying the flow units while the J-function concept is quiet poor. Also, a more refined identification of flow units is obtained by using the newly-developed Characterization Number. This improved description for the Characterization Number approach may be attributed to the consideration of rock/fluid properties of flowing fluid(s) and flow dynamic conditions of its containing formation.
Carbonates and Evaporites, 2018
Reservoir permeability and other property variations were investigated in all nine zones of the Bangestan carbonate sequence in the Mansouri oil field located in the southwestern of Iran. The prepared permeability distribution models using RMS method indicated that there are two abnormal high-permeability zones located at the northwestern in Zone 2 and southeastern in Zone 6 of the reservoir. Core data analysis and petrographic thin-section study, electrofacies model, and fluid saturation measurements were used to verify the results of permeability models. Petrographically, the main constituents of the Bangestan carbonate sequence were wackestone and packstone facies. Based on five determined microfacies confirmed the environmental instability from open marine to semi-restricted lagoonal environments while understudied carbonate deposition. Diagenetic processes such as solution (pressure and chemical), dolomitization, and fracturing improved the reservoir quality. Electrofacies (EF) model was also done by gamma ray (GR), water saturation (Sw), acoustic log (DT), neutron porosity, and effective porosity (PHIE) data. Four EFs were determined and reservoir quality was decreased from EF-1 to EF-4. The results showed that the vuggy porosity abundances and electrofacies distribution, as the main controllers of the reservoir quality, are well coincident with the permeability model. The vuggy porosity type was found to be as a fabric selective pore and an individual character of rudist-rich zones. Fluid saturation data are consistent with the permeability model and related high reservoir quality and production zones. The detected anomalies of permeability in the model can be interpreted by three scenarios: (1) basement faults activities, (2) sedimentary environment changes, and (3) combinational effects of faults and sedimentary deposition. It is believed that the third scenario is more logic.
Analysis and application of classification methods of complex carbonate reservoirs
Journal of Geophysics and Engineering, 2018
There are abundant carbonate reservoirs from the Cenozoic to Mesozoic era in the Middle East. Due to variation in sedimentary environment and diagenetic process of carbonate reservoirs, several porosity types coexist in carbonate reservoirs. As a result, because of the complex lithologies and pore types as well as the impact of microfractures, the pore structure is very complicated. Therefore, it is difficult to accurately calculate the reservoir parameters. In order to accurately evaluate carbonate reservoirs, based on the pore structure evaluation of carbonate reservoirs, the classification methods of carbonate reservoirs are analyzed based on capillary pressure curves and flow units. Based on the capillary pressure curves, although the carbonate reservoirs can be classified, the relationship between porosity and permeability after classification is not ideal. On the basis of the flow units, the high-precision functional relationship between porosity and permeability after classification can be established. Therefore, the carbonate reservoirs can be quantitatively evaluated based on the classification of flow units. In the dolomite reservoirs, the average absolute error of calculated permeability decreases from 15.13 to 7.44 mD. Similarly, the average absolute error of calculated permeability of limestone reservoirs is reduced from 20.33 to 7.37 mD. Only by accurately characterizing pore structures and classifying reservoir types, reservoir parameters could be calculated accurately. Therefore, characterizing pore structures and classifying reservoir types are very important to accurate evaluation of complex carbonate reservoirs in the Middle East.
Journal of Chemical and Petroleum Engineering, 2024
This study is focused on identifying the formations, whether are they reservoir formations or not. The effective porosity and permeability evaluating of the oil reservoir is the most important methods to recognize the formations. In this study, the effective porosity and permeability of the Yamama formation in an oil field of southern Iraq can be calculated by applying, the neutron-density and the sonic logs. The calculated effective porosity of the formation ranged between (6%-17%), and the porosity in the joints was less than (0.04). The permeability in Yamama Formation calculated by three methods: Timur, Morris Biggs oil, and Schlumberger methods. By comparing the values of the permeability calculated by these methods, it was found that the methods of Timor and Schlumberger gave the same results, and also when the permeability calculated by these methods compared with the permeability of the cores, the method of Timur and Schlumberger closer than the results of the cores. So, the Schlumberger and Timor method is the one used in calculating the permeability. The permeability values for most of Yamama formation range from: 0.1-10 md, and the permeability in the joints was less than 0.001 md.
2018
45 Petroleum Research, 2018(July-September), Vol. 28, No. 100 Introduction The aim of petrophysical studies is the reservoir formation zoning, determination of net pay zones, and, finally, investigation of the reservoir quality in different parts of the reservoir formation, and therefore, to determine the most suitable zones for optimal production from the reservoir and for more expert development of the hydrocarbon field. Porosity, water and hydrocarbon saturations, and permeability are the most important parameters that should be determined in petrophysical assessment to understand the reservoir quality. The purpose of this study is to determine the reservoir quality in different zones of Kangan reservoir formation in a well located at one of hydrocarbon fields in south of Iran. The concept of reservoir quality index (RQI) was introduced by Amaefule et al. by considering the reservoir permeability and porosity [1]. Worthington used the RQI to determine the cut-off for the most imp...
Iraqi geological journal, 2023
The shale content and mode of distribution, along with their impact on the reservoir properties of the Jeribe Formation, were investigated using the available log data in the two selected wells, NET-10 and NET-12, of an oilfield northern Iraq. The dolomite and dolomitic limestone lithology of the formation contains different ratios of shale, with the highest near the middle part of the formation. Horizons of 70 to 99% shale content were identified, but the general ratios are ranging between 10% and 50%. The data from the Spectral Gamma ray log revealed that the shale content of the formation is mostly composed of low Potassium minerals such as Chlorite and Montimorlinite, with appreciable percentages of Illite. The low Th/U ratios along the formation indicated a reduced condition of deposition except for about 2-3 meters of the upper part of the formation in the well NET-10, which looks to be precipitated in a natural depositional environment. Dispersed, Laminar, and Structural modes of shale distribution coexist within the formation in both studied wells. As the different modes of shale distribution have different impacts on the porosity and permeability of the reservoir rocks, the decrease and increase in the shale content did not perfectly correspond with an opposite fluctuation in the porosity values of the formation. The shale content in the formation has an impact on the porosity calculation by overestimating it by about 4-5% and subsequently underestimating the water saturation by 9% in the well NET-10 and 7% in the well NET-12.
Iraqi Journal of Chemical and Petroleum Engineering
The special core analysis tests were accomplished on a set of core plugs for Mishrif Formation (mA, mB1, and mB2cde/mC units) in West Qurna/1 oilfield, southern Iraq. Oil relative permeability (Kro) data and the Corey-type fit of the data as functions of the brine saturation at the core outlet face for individual samples in the water-oil imbibition process to estimate relative permeability measurements by the centrifuge method were utilized. Identical correlations for oil and water relative permeabilities were extracted by steady-state and unsteady-state methods. For the mA samples, the gas-water capillary pressure curves were within a narrow range (almost identical) indicating that mA is a homogeneous unit. Kro curves for three mB2ab plugs were practically identical, that is referring to the homogeneity in the upper portion of the unit. The mB2 unit has a more solidâphase concentration than other units. In addition, the general trend of low residual oil saturation is related to the...