Characteristics Of Carbonate Reservoirs Research Articles

Effect of pore structure characteristics on gas-water seepage behaviour in deep carbonate gas reservoirs

The study of gas-water two-phase flow behavior has always been a focus and a difficult problem in the field of oil and gas seepage, and it is related to the formulation of reasonable development plans for oil and gas reservoirs. Deep carbonate gas reservoirs (depth>4500m) develop cross-scale porous media, which have extremely strong heterogeneity and very complex seepage characteristics. To the best of our knowledge, there has been no systematic study on the two-phase flow patterns of gas and water in deep carbonate gas reservoirs. This paper uses cast thin sections, scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR) to study the influence of carbonate rock pore structure characteristics on gas storage and seepage capabilities. The results show that the existence of cavities enhances the gas storage capacity of the reservoir and improves the seepage capacity of pore-throat space near the cavity. Fractures can effectively communicate with isolated cavities, enhance reservoir connectivity, and thereby significantly improve the overall seepage capacity of the reservoir. The centrifugal technique was combined with NMR to study the movable fluid characteristics of carbonate reservoirs. The critical flow throat radius and movable fluid saturation of the reservoir reveal that the degree of development of cavities and fractures determines the mobility of the fluid in the reservoir. The fluid mobility in the fracture-cavity-type reservoir is the strongest, while the fluid mobility in the pore-type reservoir is the weakest. Analysis of the normalized curve of gas-water relative permeability under high temperature and pressure reveals that formation water preferentially enters connected pores with low seepage resistance, and the strong storage capacity of cavities can effectively delay the non-uniform intrusion of formation water. The results of water invasion simulation experiments show that the water invasion phenomenon can improve the gas production rate and recovery rate of pore-type reservoirs. However, the formation water flow and channeling phenomena caused by reservoir heterogeneity will cause a large amount of gas to be sealed in the pore space of cavity-type and fracture-cavity-type reservoirs, reducing the recovery rate and economic benefits of these reservoirs. These findings further provide solid fundamentals for efficient and effective exploitation of deep carbonate gas reservoirs.

Log interpretation of carbonate rocks based on petrophysical facies constraints

The complex pore structure of carbonate reservoirs hinders the correlation between porosity and permeability. In view of the sedimentation, diagenesis, testing, and production characteristics of carbonate reservoirs in the study area, combined with the current trends and advances in well log interpretation techniques for carbonate reservoirs, a log interpretation technology route of “geological information constraint + deep learning” was developed. The principal component analysis (PCA) was employed to establish lithology identification criteria with an accuracy of 91%. The Bayesian stepwise discriminant method was used to construct a sedimentary microfacies identification method with an accuracy of 90.5%. Based on production data, the main lithologies and sedimentary microfacies of effective reservoirs were determined, and 10 petrophysical facies with effective reservoir characteristics were identified. Constrained by petrophysical facies, the mean interpretation error of porosity compared to core analysis results is 2.7%, and the ratio of interpreted permeability to core analysis is within one order of magnitude, averaging 3.6. The research results demonstrate that deep learning algorithms can uncover the correlation in carbonate reservoir well logging data. Integrating geological and production data and selecting appropriate machine learning algorithms can significantly improve the accuracy of well log interpretation for carbonate reservoirs.

Microbial carbonate reservoir characteristics and their depositional effects, the IV Member of Dengying Formation, Gaoshiti-Moxi area, Sichuan Basin, Southwest China

Previous scientific research on reservoirs of the Deng IV Member in the Gaoshiti-Moxi area, the main production area of the Anyue gas field with reserves of tens of billions of cubic metres, has focused on karst palaeogeomorphology reconstruction, the facies distribution on platform margins, and their effects on creating favourable reservoirs. However, the quality of microbial carbonate reservoirs is also closely related to their original depositional environments on both inner and marginal platforms. Therefore, this paper attempts to reveal favourable microbial carbonate reservoir characteristics and the sedimentary effects on their distribution and prediction based predominantly on a synthetic analysis of the sequence stratigraphy and depositional facies. The results show that favourable reservoirs of the Deng IV Member are classified into three types according to their reservoir spaces: fracture-cavity, pore-cavity and pore reservoirs. Secondary dissolution pores and cavities are primary reservoir spaces developed mainly in nonskeletal grain dolomites with sparry cements, thrombolites, and stromatolites. The physical properties of the fracture-cavity and pore-cavity types of reservoirs are better than those of pore reservoirs and have porosities between 1 and 5% and permeabilities between 0.01 × 10–3 and 1 × 10–3 μm2. Vertically, favourable reservoirs are developed mainly in parasequence set 6 (PSS6) and PSS7 and are laterally distributed in well zone MX9-MX19-MX1 for the fracture-cavity type, MX105-MX110-GS20 for the pore-cavity type and MX17-MX107-MX41-MX102-GS102 for the pore type. Moreover, depositional effects on reservoirs in terms of depositional sequences, seismic facies, microfacies and microfacies associations indicate that to some extent, the fracture-cavity type of reservoir is constrained by the top boundaries of PSS7, PSS2, parasequence 17 (PS17) and PS14; the pore-cavity type of reservoir is constrained by the top boundaries of PSS7, PSS4, PS18 and PS12; and the pore type of reservoir is constrained by the top boundaries of PSS7, PSS6, PSS3, PSS2, PS18, PS17, PS14, and PS12. Seismic facies associated with shoals and mound-flat complexes are related to the facies distributions of pore cavities and pore reservoirs. MA1, MA3, MA7, and MA8 are predominant microfacies associations of favourable reservoirs of the Deng IV Member in the Gaoshiti-Moxi area. The above results are significant for further petroleum exploration and exploitation of ultradeep microbial carbonate reservoirs in this area.

Performance evaluation of microemulsion acid for integrated acid fracturing in Middle Eastern carbonate reservoirs

Considering the characteristics of carbonate reservoirs in the Middle East, a low-viscosity microemulsion acid that can be prepared on site and has an appropriate retardation ability was developed. It was compared with four conventional acid systems (hydrochloric acid, gelled acid, emulsified acid and surfactant acid) through experiments of rotating disk, multistage acid fracturing and core flooding with CT scanning. The micro-etching characteristics and conductivity of fracture surfaces were clarified, and the variation of saturation field during water invasion and flowback of spent acid and the recovery of oil phase relative permeability were quantitatively evaluated. The study shows that the addition of negatively charged agent to the oil core of microemulsion acid can enhance its adsorption capacity on the limestone surface and significantly reduce the H+ mass transfer rate. Moreover, the negatively charged oil core is immiscible with the Ca2 + salt, so that the microemulsion acid can keep an overall structure not be damaged by Ca2 + salt generated during reaction, with adjustable adsorption capacity and stable microemulsion structure. With high vertical permeability along the fracture walls, the microemulsion acid can penetrate into deep fracture wall to form network etching, which helps greatly improve the permeability of reservoirs around the fractures and keep a high conductivity under a high closure pressure. The spent microemulsion acid is miscible with crude oil to form microemulsion. The microemulsion, oil and water are in a nearly miscible state, with basically no water block and low flowback resistance, the flowback of spent acid and the relative permeability of oil are recovered to a high degree.

The role of textural parameters of industrial core CT scan images in detecting the petrophysical characteristics of carbonate reservoirs, Permian Dalan Formation, the central Persian Gulf

Digital petrophysics investigates the properties of rocks from images, especially core computed tomography (CT scan). The purpose of these investigations is to develop new methods for petrophysical evaluation of porous materials. In this article, textural parameters have been calculated from computed tomography images of the cores in Permian Dalan Formation in the central Persian Gulf. We tried to find more evidence that industrial CT scan images are useful in identifying the geological and petrophysical characteristics of hydrocarbon reservoirs. For this purpose, the textural parameters of the image, including contrast, correlation, homogeneity, energy and entropy were calculated and analyzed and a gray level co-occurrence matrix has been created. These parameters were compared with geological and petrophysical data obtained from laboratory measurements and thin section studies. Analysis of the thin sections under the microscope led to the identification of 12 microfacies. They range from mudstone to wackestone, packstone and grainstone. Some samples have been completely dolomitized and recognition of their primary microfacies is not possible. This group called crystalline carbonate. Results showed that various features in CT scan images can be differentiated using the arrangement of pixels, the gray intensity of each pixel and the relationship of each pixel to its neighboring pixels. Increasing porosity and permeability reduces the image heterogeneity. This is also the case for uniformly distributed pore types, including moldic and intercrystalline. Textural parameters were also compared with microfacies and diagenetic processes. Results indicate that they can increase heterogeneity with decreasing reservoir quality and vice versa. Finally, using numerical values of image textural parameters, three petrophysical classes were defined in the studied reservoir. As a result, various parts of the reservoir can be identified using CT scan images of the cores.

Prediction of the pore structure by machine learning techniques in the carbonate reservoirs in Iraq H oilfield

Pore structure impacts the capability of seepage pattern of subsurface fluid mineral and mineral exploitation efficiency. Because of the strong heterogeneity in carbonate reservoirs, the pore structure is nonlinearly varying and complex in reservoirs. It is necessary to establish a method for pore structure type (PST) prediction. Machine learning provides an efficient prediction method by finding the relationship between core test data and well‐logging data. In this paper, a reservoir identification method based on Gradient Boost Decision Trees (GBDT) is proposed for the pore structure characteristics of carbonate reservoirs integrating core test and logging data. Core testing data are utilized to form the training set for PST prediction. Then, we adopt the mutual information method to optimize the logging data as the input of the machine learning model. GBDT hyperparameters are optimized using the learning curve to make it have optimal performance. Finally, we compare the predicted result of GBDT with K‐Nearest Neighbor and support vector machines, demonstrating the superior performance of GBDT. The results indicate that the four PS are different in some properties, such as permeability, pore radius and shape of pore and throat. 20%, 10 and 0.15 are recommended as the optimal parameter values for Maximum feature, iteration number and Sub‐sample number to improve GBDT accuracy in carbonate reservoir PST prediction. Evaluation indicators of machine learning, including the Kappa coefficient, Heming distance, Jaccard similarity coefficient and Confusion matrices, indicate that GBDT has better performance. This research proves the high accuracy and applicability of machine learning technology in the carbonate reservoir and also provides a meaningful reference for the identification of the carbonate reservoirs in the central area of Iraq.

Microfacies and Reservoir Space Characteristics of Carbonate Reservoir of the Ordovician Yingshan Formation in Northern Slope of Tazhong Uplift, Tarim Basin

As an important stratum of exploration in the Tarim Basin, which is the largest petroleum basin in China, Yingshan Formation has great potential. The relationship between the fine division of microfacies and reservoir space characteristics has not been systematically studied which restricts further exploration. On the basis of the analysis of core, thin section, logging data, imaging logging data (FMI), and field outcrop, the microfacies types and reservoir space characteristics of the Ordovician Yingshan Formation are systemically studied. The results show that (1) nine microfacies (Mf1-Mf9) and four microfacies associations (MA1-MA4) were identified within the Ordovician Yingshan Formation. MA1-MA2 represent a medium- to high-energy sedimentary background, and MA3-MA4 represent a medium- to low-energy sedimentary background. (2) Four reservoir space types were observed in the Yingshan Formation, which are dominated by fracture-dissolution pore type, followed by small dissolution vug type, seldom fracture type, and large-scale karst-cavity type. (3) High-energy microfacies are the material basis of favorable reservoirs. The high-energy microfacies associations are prone to small dissolution vug and fracture-dissolution pore types of reservoirs; large cave reservoirs can sometimes be developed in the high part of the sequence and form favorable reservoirs in the Yingshan Formation. The low-energy microfacies associations mostly appear as original strata or interlayer, but after the superposition of structural cracks, buried karsts, or epigenetic karsts, low-energy microfacies associations may form relatively small-scale fractured and fracture-dissolution pore types of reservoirs in this area.

Prediction of carbonate rock facies from core probe permeability measurements and well log data: a case study from carbonate reservoirs, Phu Khanh basin

Probe permeameter (also known as Mini-permeameter) has been widely used in many field and laboratory applications where in-situ measurements and spatial distributions of permeability are needed. Mini-permeameter measurements have become popular techniques for collecting localized permeability measurements in both laboratory and field applications. It is designed to obtain fast, cheap, intensive and non-destructive permeability measurements and to describe the spatial arrangement of permeability. Currently the probe permeability meter is designed and manufactured as a portable air permeability for field applications and to be used in outcrop and core samples. In this instrument, the permeability is measured by air that flows from the samples to be measured into an air chamber through the vacuum created by increasing the volume of the chamber. In carbonate reservoirs, permeability predicted from pure porosity-permeability empirical relationship is often difficult due to complex rock pore systems leading to poor porosity-permeability relations. Once the relationships between permeability and textural rock properties are clearly established in carbonates, they can provide better permeability predictions from porosity data. Rock texture is an important parameter for the understanding of the porosity and permeability characteristics of carbonate reservoirs. In addition to predicting carbonate rock facies from routine core plug porosity and permeability measurements, there is an approach to determine carbonate reservoir facies based on core-plug probe permeability. The results of the probe permeability measurements, in this paper, can be used in combination with the porosity values derived from the well logs to classify and predict rock facies in carbonate cored or uncored reservoirs in Phu Khanh basin.

Analysis of Elastic Characteristics of Carbonate Reservoirs

The purpose of this study is to analyze the elastic characteristics of the carbonate reservoirs of the Bashkirian and Moscovian Stages of the middle section of the Carboniferous system of the oil field. As part of the study, acoustic and density curves were restored for the intervals where logging was not performed. The petrophysical interpretation of the data, the identification of reservoirs, and the assessment of reservoir properties were carried out. The elastic properties analysis of the rocks has been conducted, and the possibility of identifying reservoirs using elastic parameters has been assessed. Based on the results of the elastic characteristics analysis, it is possible to distinguish between reservoir and tight rocks on acoustic and shear impedance, as well as define a confident relationship between acoustic impedance and rock porosity.

Study on discriminant method of rock type for porous carbonate reservoirs based on Bayesian theory

Rock typing is an extremely critical step in the estimation of carbonate reservoir quality and reserves in the Middle East. In order to recognize the rock types of carbonate reservoirs in the Mishrif Formation better, classify the reservoirs accurately, and establish the permeability model in line with the study area precisely, it is necessary to study the recognition method conforming to the actual situation of the study area. The practice shows that the current recognition methods based on capillary pressure curve, flow unit and NMR logging data can effectively distinguish rock types, but a large number of accurate experimental data are required, which can only be applied in a few cored well, however, cannot be applied in the whole oil field. In this study, based on core, thin section, logging data, the sedimentary characteristics of carbonate reservoir, logging response of four rock types as well as porosity and permeability characteristics of Mishrif Formation in W are comprehensively studied. Based on Bayesian stepwise discriminant theory in multivariate statistics, the Bayesian discrimination model based on conventional logging data is established. The examining results showed that, compared with the description of logging and coring, the accuracy of Bayesian discriminant model and cross confirmation rate have achieved more than 80% for the original sample. Reliability verification showed that the matching degree of the rock type recognized in the non-cored well with the core and mud logging was as high as 90%, which matched the depositional environment of the entire region. The study results confirm the validity and generalizability of the Bayesian method to identify and predict rock types, which can be applied to the entire Middle East region to solve the problem of the lack of core data to accurately evaluate the quality of non-cored wells and accurately predict production, meeting the needs of actual reservoir evaluation and production development in the Middle East.

Microfacies and diagenetic overprints in the limestones of Middle Jurassic Fort Member (Jaisalmer Formation), Western Rajasthan, India: Implications for the depositional environment, cyclicity, and reservoir quality

The present study investigates the microfacies and the effects of diagenetic processes on the reservoir quality of limestones of the Fort Member, Jaisalmer Formation, Western Rajasthan. The study interpolates an integrated approach including field studies, petrography, staining, and X‐ray diffraction techniques. The Fort Member is composed of medium‐ to thick‐bedded, nodular highly fossiliferous limestones, which are fine‐ to medium‐grained, poorly‐ to very well‐sorted, and comprise angular‐ to well‐rounded grains of low to high sphericity. These limestones contain abundant skeletal (bivalves, brachiopods, echinoderms, foraminifera, algae, gastropods, sponge, coral, and calcispheres) and non‐skeletal grains (intraclasts, ooids, and peloids). On the basis of detailed petrographic investigations, eight microfacies have been recognized including: bioclastic wackestone, whole‐fossil wackestone, bioclastic lithoclastic packstone, aggregate grainstone, peloidal grainstone, ooidal grainstone, bioclastic grainstone, and coated bioclastic grainstone. Based on the microfacies analysis, the limestones of the Fort Member are inferred to have been deposited in shoal, lagoon, and open marine environments. The diagenetic overprints of the Fort Member limestones is characterized by the several diagenetic features such as micritization, cementation, dolomitization, compaction, dissolution, silicification, neomorphism (aragonite to calcite transformation and development of microspar), and secondary porosity. Such main diagenetic features affecting the carbonates are developed in marine phreatic, meteoric phreatic, mixed meteoric phreatic and burial diagenetic environments. Micritization of allochems, dolomitization of lime muds, and cementation by isopachous calcite, granular calcite cement, neomorphism, and recrystallization of bioclasts are developed in meteoric‐phreatic diagenesis. The meteoric‐vadose diagenesis led to prevalence of dissolution process and sparry calcite infilling the fractures. Dolomitization, blocky calcite cement, and silicification processes were developed during the burial diagenesis. These diagenetic processes have direct effects on the modification of both intergranular and intragranular/crystalline porosity. In this manner, it is found that the calcite cementation, micritization, and compaction were responsible for the reduction of the pore spaces, whereas dolomitization, dissolution, formation of moldic pores, and fracturing increased the pore volumes. Therefore, the enhanced pore volumes improved the carbonate reservoir characteristics, suggesting the limestones of the Fort Member to be a better carbonate reservoir for hydrocarbon accumulation.

Assessment of continuous and alternating CO2 injection under Brazilian-pre-salt-like conditions

Carbonate rocks have become very important in Brazil with pre-salt reservoir discoveries in Santos and Campos Basins. Since then, great efforts in research and technology have been made to characterize and develop these reservoirs. In this sense, outcrop analogue studies have become a powerful tool for helping the recognition of geological heterogeneities responsible for controlling the fluid flow in hydrocarbon reservoirs. Besides that, pre-salt oil recovery is associated with high carbon dioxide (CO2) production, and due environmental issues, it is required a sustainable destination for this contaminant. CO2 injection in the reservoir, either pure or mixed to the produced gas stream, could be a good manner to deal with this undesirable component and increase the oil recovery. This work uses outcrop analogue characterization to understand how carbonate reservoir characteristics impact the selection of the best recovery strategy under Brazilian-pre-salt-like conditions. Numerical simulation models were run using the flow simulator TEMPEST MORE (version 7.1) with isothermal compositional modeling. The oil recovery process was modeled by continuous and alternating injection of CO2 and water. The recovered oil fractions for the simulation case with water alternating CO2 injection were higher than with the use of continuous injection of CO2 or water.

Dynamic analysis of oil‐water two‐phase flow for a multiple‐fractured horizontal well with multiple finite‐conductivity fractures in triple media carbonate reservoir

AbstractCarbonate reservoir is one of the important reservoir in the world. Because of the characteristics of carbonate reservoir, horizontal well and acid fracturing have become a key technology for efficiently developing carbonate reservoir. Establishing corresponding mathematical models and analyzing transient pressure behaviors of this type of well‐reservoir configuration can provide a better understanding of fluid flow patterns in formation as well as estimations of important parameters. A mathematical model for a oil‐water two‐phase flow multiple‐fractured horizontal well with multiple finite‐conductivity fractures in triple media carbonate reservoir by conceptualizing vugs as spherical shapes is presented in this article. A semi‐analytical solution is obtained in the Laplace domain by using source function theory, Laplace transformation, and superposition principle. Analysis of transient pressure responses indicates that nine characteristic flow periods of multiple‐fractured horizontal wells with multiple finite‐conductivity fractures in triple media carbonate reservoir can be identified. Parametric analysis shows that water saturation of matrix, vug and fracture system and acid fracture, fracture half‐length, fracture number, fracture spacing and acid fracture conductivity can significantly influence the transient pressure responses of multiple‐fractured horizontal wells with multiple finite‐conductivity fractures in triple media carbonate reservoir. The model presented in this article can be applied to obtain important parameters pertinent to reservoir or fracture by type curve matching, and it can also provide useful information for optimizing fracture parameters.

Comprehensive Well Test Interpretation Method, Process, and Multiple Solutions Analysis for Complicated Carbonate Reservoirs

Abstract The main characteristic of the complicated carbonate reservoirs is notably strong heterogeneous, leading to a high uncertainty in formation parameter evaluation. The most reliable method for obtaining the dynamic parameters is well test interpretation. However, the well test curve shows similar characteristics for multi-layers reservoirs, dual-medium reservoirs, and carbonate reservoirs with lithology mixed sedimentation lithology. Sometimes the well test fitting result under the mentioned three kinds of models is satisfied, but the interpretation result is quite different. In order to reduce the parameter evaluation multiplicity, the synthetic identification and evaluation method for obtaining the physical parameters of the complicated carbonate reservoir was proposed, based on completion types, core analysis, lithology analysis, and well test results. The evaluation method distinguishes the different carbonate reservoir characteristics from similar well test responses by summarizing and classifying the completion method, reservoir fracture characteristics, and production logging test (PLT) results. The reliability of the proposed method is verified by an application of actual carbonate reservoir parameters evaluation. The proposed method can distinguish among multi-layers reservoirs, dual-medium, and complicated reservoirs with mixed sedimentation lithology whose main characteristic is that concavity existing in the pressure derivative curve. If the well test match results were satisfied enough which lead to the proposed method and process was ignored, the interpretation results and production performance prediction may deviate largely from the actual situation.

Characteristics of Arun Carbonate Reservoir and Its Implication To Optimize the Most Potential Gas Resource Zone In Arun Gas Field, Aceh, Indonesia

DOI:10.17014/ijog.6.2.209-222Since the discovery of major oil and gas reserves in carbonate rocks in the Middle East, carbonate reservoirs became important to the petroleum industry. Carbonate rocks have covered only 20% of the sedimentary rock records. However, carbonate reservoirs hold 50% of the world petroleum reserves. Arun Carbonate Reservoir is one of the biggest proven retrograde gas reservoirs in the world. After more than thirty years of production, Arun Carbonate Reservoir had an initial gas in place of 14.1 TCF residual hydrocarbon gas. The issue makes Arun Carbonate Reservoir became an interest to be studied for the development and production of hydrocarbon in other carbonate reservoirs in Indonesia. One of the fundamental topics to be studied is the characteristics of Arun Carbonate Reservoir itself. The characteristics of carbonate reservoir usually cause a lot of geologic and engineering problems in the development and production of hydrocarbon reserves. This paper aims to identify the characteristics of Arun Carbonate Reservoir and its implication to delineate the potential gas resource zone in the Arun Gas Field, Aceh, Indonesia. The data from sixteen wells have been examined through several multidiscipline studies: geophysics (well logging), geology (facies, lithology and diagenetic analyses), and petrophysics (core analysis). The result of this study shows that Arun Carbonate Reservoir (N5-N8) contains limestone 92%, 5% dolomite, and 3% dolomitic limestone (or other), and petrophysically have 16% porosity and 13.5 md permeability in average. Arun Carbonate Reservoir is divided into four facies (Reef, Near Reef, Inter Reef Lagoon, and Middle Shelf). Of four facies in Arun Carbonate Reservoir, only two facies which can be categorized as productive facies: Reef and Lagoonal Facies. The potential zones of hydrocarbon resources have vertically been documented in Arun Carbonate Reservoir.

Dynamic Analysis of a Fractured Vertical Well in a Triple Media Carbonate Reservoir

Carbonate reservoir is one of the important reservoirs in the world. Because of the characteristics of carbonate reservoir, vertical well and acid fracturing have become a key technology for efficiently developing a carbonate reservoir. Establishing corresponding mathematical models and analyzing transient pressure behaviors of this type of well-reservoir configuration can provide a better understanding of fluid flow patterns in formation as well as estimations of important parameters. A mathematical model for a fractured vertical well in triple media carbonate reservoir by conceptualizing vugs as spherical shapes is presented in this article. A semi-analytical solution is obtained in the Laplace domain by using source function theory, Laplace transformation, and the superposition principle. Analysis of transient pressure responses indicates that several characteristic flow periods of fractured vertical wells in triple media carbonate reservoir can be identified. Parametric analysis shows that the fracture length can significantly influence the transient pressure responses of fractured vertical wells in triple media carbonate reservoir. The model presented in this article can be applied to obtain important parameters pertinent to reservoir or fracture by type curve matching, and it can also provide useful information for optimizing fracture parameters.

Microfacies, diagenesis, and stable isotope analysis of the Jurassic Jumara Dome carbonates, Kachchh, Western India: Implications for depositional environments and reservoir quality

The microfacies, detailed diagenesis, and stable isotope analysis of the carbonates, exposed at Jumara Dome, have been analysed to explore their impact on reservoir quality. The carbonates of Jumara Dome are mostly fine‐ to medium‐grained, and some are coarse‐grained, poorly to very well sorted, having angular to well‐rounded grains of low to high sphericity. Bioclasts are the most abundant constituent in these carbonates and includes brachiopods, foraminifers, ostracodes, calcispheres, algae, bryozoans, echinoderms, sponges, gastropods, and corals. Twelve microfacies were recorded in the present investigation. The temporal distribution of microfacies association reflects an ideal shallowing‐upward sequence representing a system of bioclastic bars developed on a carbonate ramp, which separates a lagoonal environment from open marine environment. In Jumara Dome carbonates, the δ13C values range from −1.89‰ to 1.44‰ and δ18O values range from −8.95‰ to −4.26‰ and suggest a marine environment of deposition for these carbonates under warmer Jurassic climate conditions. Micritization, silicification, compaction, cementation, neomorphism, geopetal structures, and porosity are the main diagenetic features affecting the carbonates and developed in marine phreatic, fresh water phreatic, mixed marine‐fresh water phreatic, and burial diagenetic environments. The diagenetic processes (mechanical compaction and cementation) has affected the carbonates reservoir characteristics, but the dissolution has resulted in generation of secondary porosity in the form of moulds, stylolites by pressure solution, and fractures (calcite veins), and enhancing the permeability resulting in improvement of carbonate reservoir characteristics, suggesting the carbonates of the Jumara Dome could be a better carbonate reservoir for petroleum accumulation.

Flow Modeling of Well Test Analysis for a Multiple-fractured Horizontal Well in Triple Media Carbonate Reservoir

Abstract Carbonate reservoir is one kinds of important reservoir in the world. Because of the characteristics of carbonate reservoir, horizontal well, and acid fracturing became a key technology for efficiently developing carbonate reservoir. Establishing corresponding mathematical models and analyzing transient pressure behaviors of this type of well-reservoir configuration can provide a better understanding of fluid flow patterns in formation as well as estimations of important parameters. A coupling mathematical model for a fractured horizontal well in triple media carbonate reservoir with three kinds of reservoir outer boundaries by conceptualizing vugs as spherical shapes is presented in this article, in which the infinite conductivity of the acid fractures is taken into account. A semi-analytical solution is obtained in the Laplace domain by using source function theory, Laplace transformation, discretization of fracture, and superposition principle. Analysis of transient pressure responses indicates that several characteristic flow periods of fractured horizontal wells in triple media carbonate reservoir can be identified. Parametric analysis shows that fracture half-length, fracture number, fracture spacing, conditions of reservoir outer boundary, and so on can significantly influence the transient pressure responses of fractured horizontal wells in triple media carbonate reservoir. The model presented in this article can be applied to obtain important parameters pertinent to reservoir or fracture by type curve matching, and it can also provide useful information for optimizing fracture parameters.

Fuzzy Logic in Carbonate Reservoir Quality Assessment: A Case Study from Tarim Basin, China

Introduction: To address reservoir quality assessment in highly complex and heterogeneous carbonate reservoirs, a methodology utilizing fuzzy logic is developed and presented in this paper. Based on carbonate reservoir characteristics, three parameters reflecting the macroscopic and microscopic of storage abundance, permeability, and median of pore throat radius were selected to establish the factor set and the evaluation criteria. After analysis of core and test data, a membership function is constructed by semi-drop trapezoid method and the weight formula is also determined by reservoir factor sub-index. The developed method then is used to evaluate a carbonate reservoir in the Tarim Basin in China. Based on the result of single well evaluation, the plane classification map of the carbonate reservoir quality is constructed. Results obtained from reservoir quality assessment in the K32 well show that I-level, II-level, and III-level reservoir qualities account for 58%, 37%, 5% of the reservoir, respectively. The results are consistent with the actual production data demonstrating reliability of the proposed method for reservoir quality assessment practices in usually very complex and heterogeneous carbonate reservoirs. Background: Carbonate reservoirs are complex and heterogeneous and this makes their evaluation a difficult task. Objective: To overcome the uncertainties associated with evaluation of complex carbonate reservoirs a reliable method to accurately evaluate carbonate reservoirs is presented. Methods: Fuzzy logic is used to evaluate a carbonate reservoir from Tarim Basin in China. Based on carbonate reservoir characteristics, three parameters reflecting the macroscopic and microscopic of storage abundance, permeability, and median of pore throat radius are selected to establish the factor set and to evaluate the criteria of carbonate reservoir. After the analysis of core and test data, a membership function is reasonably constructed by semi-drop trapezoid method and the weight formula is also determined by reservoir factor sub-index. Results: An effective methodology for the evaluation of reservoir quality in carbonate reservoirs is established by using fuzzy logic. In addition, an example reservoir from China is used to demonstrate the applicability of the developed method. Conclusion: Based on the result of single well evaluation, the plane classification map of the carbonate reservoir is constructed. Favorable zones in the reservoir are also delineated. Evaluation results are consistent with the actual production data of gas and oil which proves that the proposed method is instrumental in reservoir quality assessment.

The nonlinear oil–water two-phase flow behavior for a horizontal well in triple media carbonate reservoir

Carbonate reservoir is one of the important reservoirs in the world. Because of the characteristics of carbonate reservoir, horizontal well has become a key technology for efficiently developing carbonate reservoir. Establishing corresponding mathematical models and analyzing transient pressure behaviors of this type of well-reservoir configuration can provide a better understanding of fluid flow patterns in formation as well as estimations of important parameters. A mathematical model for a oil–water two-phase flow horizontal well in triple media carbonate reservoir by conceptualizing vugs as spherical shapes are presented in this article. A semi-analytical solution is obtained in the Laplace domain using source function theory, Laplace transformation, and superposition principle. Analysis of transient pressure responses indicates that seven characteristic flow periods of horizontal well in triple media carbonate reservoir can be identified. Parametric analysis shows that water saturation of matrix, vug and fracture system, horizontal section length, and horizontal well position can significantly influence the transient pressure responses of horizontal well in triple media carbonate reservoir. The model presented in this article can be applied to obtain important parameters pertinent to reservoir by type curve matching.