Fractured Carbonate Reservoirs Research Articles

Evaluation Method of Water Injection Development Effects in Fractured Vuggy Carbonate Reservoirs: Case Study of FI7 Strike-Slip Fault Zone

As the main method of secondary development, water injection has been widely used in fractured vuggy carbonate reservoirs. By using an evaluation index system combined with an integrated approach to objectively evaluate and support targeted and operational adjustments of water injection development effects in fractured vuggy carbonate reservoirs, a comprehensive evaluation method is established in this study. The CRITIC method is used as the main approach, and the analytic hierarchy process, the entropy weight method, and the coefficient of variation method are used as sub-methods. Additionally, the clustering centres are divided using the clustering method to reduce the error caused by the irrational distribution of the relevant evaluation index data. The method is used to evaluate and analyse the effects of water injection development, using the FI7 fault zone of the Halahatang oilfield as an example. The application results show that the evaluation method is feasible and effective for cases with small data volume, fewer computational resources, and less time. This study has a certain reference significance for the evaluation of the effect of water injection development in similar fractured vuggy reservoirs.

Production Law of Shielding Oil in Fractured Carbonate Reservoirs: A Case Study of Northwest Oilfield, China

Multi-scale fractures in Northwest Oilfield are extremely developed. Fractures in both oil flow channels and water channels lead to the phenomenon of water channeling in the later stages of reservoir development, which may be affected by the bottom water cone. Gel plugging agents are widely used in the treatment of this phenomenon because of their low cost and high-water plugging efficiency. However, because there is often residual oil in small-scale fractures, the pressure law of different grades of differential fractures on gel is not clear, thus leading to low gel application efficiency and low oil recovery. There is still a lack of effective means through which to understand the regularity of shielding the remaining oil with gel strength and fractures of different grades. In this study, we conducted a novel analysis of the law of shielding oil production in fractured reservoirs. The gelling and rheological properties of anti-temperature gels (ATGs) with different strengths were studied. The plugging rate of oil phase was 96.39%, and that of water phase was 25.37%. ATG showed good oil–water selectivity. The influences of different grades of differential fractures on the production law of shielding the remaining oil were also studied, as well as the corresponding influence law chart. When the gel strength was in the range of 2.0–28.1 Pa and the fracture grade difference was 5–10, the recovery ratio was increased by 10.6–24%. The enhanced oil recovery can be quantitatively predicted by the scale of reservoir fractures and the strength of gel used. It has a certain guiding role for the field application of gel to efficiently shield residual oil in differential fractures.

Numerical investigation into the acid flow and reaction behavior in the tight, naturally fractured carbonate reservoir during acid fracturing

Tight naturally fractured carbonate reservoirs require acid fracturing to build the connectivity between the wellbore and natural fractures (NFs), where hydrocarbon is stored. The high leakoff nature of the NF complicates the acid flow and etching pattern, raising the difficulty in acid fracturing design and optimization. To explore the acid flow and reaction behavior in such reservoirs, an acid fracturing model accounting for the NF distribution is developed, which consists of a fracture surface characterization model, a fracture propagation model, and an acid-etching model. Based on the model, the effects of injection parameters and the NF properties on the effectiveness of acid fracturing are investigated. Then, strategies for acid fracturing the tight naturally fractured carbonate reservoirs are proposed. Results show that high pumping rates and retarded acids with low hydrogen ion (H+) diffusion coefficient is conducive to achieving a long acid penetration distance, while a low pumping rate and acids with a high H+ diffusion coefficient facilitates the NF etching. Therefore, a large stimulated area can be achieved by applying a multi-stage alternating injection of the crosslinked acid with a high pumping rate followed by the gelled acid with a low injection rate. NFs impact acid fracturing in two distinct ways: enhancing the non-uniform etching of the fracture surface and reducing the effective acid-etched fracture length through high leakoff. When NF density is high, leakoff control techniques should be employed; and when the NF inclination is high, non-uniform etching techniques should be used to generate acid-etched channels in flow barriers.

Evaluation of fractured carbonate reservoir and prediction of favorable areas in the eastern area of Amu Darya Right Bank

Fractured carbonate reservoirs are significantly developed in the eastern area of the Amu Darya Right Bank. However, their types, distributions, and fracture characteristics remain unclear. This uncertainty complicates reservoir prediction and hampers exploration and development processes. Given the strong correlation between fracture development and productivity, analyzing fractures is crucial. Comprehensive evaluation and prediction methods for fractured reservoirs are essential for advancing the oil and gas industry. Based on core and geological data analyses, it finds that these reservoirs exhibit low porosity and low to ultra-low permeability. By employing conventional logging alongside specialized methods, such as electrical imaging, nuclear magnetic resonance, and far detection logging, fractures and their effectiveness can be identified and evaluated, clarifying the characteristics of reservoir spaces. Constrained by the results from core and logging analyses, seismic single attribute analysis techniques is applied to predict fractures in the HX block of Amu Darya. To mitigate the limitations of single-attribute analysis, utilize a well-supervised BP neural network method for comprehensive fracture prediction. This multi-attribute approach increases the fracture prediction probability from less than 70%–72.7%. By integrating geological understanding and well logging, and considering the influence of lithology and structure on the reservoir, synthesize the fracture prediction results to optimally select favorable areas.

Research and Practice on EOR Development Strategy of Water Drive Followed by Gas Drive in Fractured Carbonate Reservoir in Bohai Sea

Abstract Focusing on the issues of high comprehensive water cut and low recovery degree following water flooding in the CFD 2-2 carbonate buried hill reservoir in the Bohai Sea, the productivity variation law, water cut rising characteristics and development effect of horizontal wells were analyzed based on different types of reservoir classification systems. The reservoir numerical simulation model of dual media coupling of matrix and fracture is established, and the analysis is done on the matrix and fracture production state, the distribution pattern of the residual oil, and the primary governing parameters.. The physical simulation experiment of water flooding to gas flooding is carried out. In conjunction with the distribution characteristics of fractures and matrix residual oil in low, middle and upper tiers of the framework, the development strategy of nitrogen injection pressure water cone in low water-flooded area, nitrogen flooding in middle inter-well residual oil enrichment area and nitrogen huff and puff in high well point residual oil enrichment area is put forward. The recovery rate is increased by 5-8 %, which successfully enhances the high water cut stage development effect, and provides reference for similar oilfield development.

Preparation and Characterization of Preformed Polyelectrolyte and Polyampholyte Gel Particles for Plugging of High-Permeability Porous Media.

Excessive reservoir water poses significant challenges in the oil and gas industry by diminishing hydrocarbon recovery efficiency and generating environmental and economic complications. Conventional polymer flooding techniques, although beneficial, often prove inadequate under conditions of elevated temperature and salinity, highlighting the need for more resilient materials. In this research, two types of acrylamide-based preformed particle gels (PPGs) were synthesized, as follows: polyelectrolyte and polyampholyte. These PPGs were engineered to improve plugging efficiency and endure extreme reservoir environments. The polyelectrolyte gels were synthesized using acrylamide (AAm) and sodium acrylate (SA), while the polyampholyte gels incorporated AAm, AMPS, and APTAC, with crosslinking achieved through MBAA. The swelling properties, modulated by temperature, salinity, and pH, were evaluated using the Ritger-Peppas and Yavari-Azizian models. The mechanical characteristics and surface morphology of the gels were analyzed using SEM and BET techniques. In sand pack experiments designed to mimic high-permeability reservoirs, the inclusion of 0.5 wt.% of fine PPGs substantially reduced water permeability, outperforming traditional hydrogels. Notably, the polyampholyte PPGs demonstrated superior resilience and efficacy in plugging. However, the experiments were limited by the low test temperature (25 °C) and brine salinity (26.6 g/L). Future investigations will aim to apply these PPGs in high-temperature, fractured carbonate reservoirs.

Numerical investigation of hydraulic fracture propagation behavior in vuggy, naturally fractured carbonate reservoir – A case study of Shunbei oil field

Successful exploitation of the fractured-vuggy carbonate reservoirs (FVCR) requires establishing long-term connectivity between the wellbore and vugs where hydrocarbon is stored. Acid fracturing is a common practice to create passageways for such reservoirs. However, the fracture propagation behavior is complex due to the interaction among hydraulic fractures (HFs), natural fractures (NFs), and vugs. Yet, a comprehensive investigation accounting for the geological genesis of FVCRs, fracture propagation behavior analysis, and exploitation strategies has not been conducted so far. To this end, taking the Shunbei oil field, Tarim Basin, China, as an example, this study using the RFPA (Realistic Failure Process Analysis) simulator classifies the possible NF distribution patterns in the Shunbei oil field through forward modeling in the first place. Then, the interaction mechanism among HFs, NFs, and vugs is analyzed from the perspective of damage mechanics. The results indicate that the vugs can be connected either hydraulically or mechanically. Finally, the field scale fracture propagation simulations are performed to examine the effect of engineering parameters and geological properties on the stimulation effectiveness. The exploitation strategies for different geological conditions are proposed based on the field scale simulation.

Production optimization in a fractured carbonate reservoir with high producing GOR

The Gas-Oil Ratio (GOR) is a crucial production parameter in oil reservoirs. An increase in GOR results in higher gas production and lower oil production, potentially leading to well shut-ins due to economic infeasibility. This study focuses on a real fractured oil field that requires urgent production operations to reduce the producing GOR. In this study, the static model for the field was developed using commercial software, involving steps such as data collection, fault modeling, meshing, and statistical analysis to prepare for dynamic simulation. The dynamic model incorporates geometry, gridding, and rock properties from the static model, utilizing a dual-porosity approach for the naturally fractured reservoir and the Peng-Robinson equation for fluid phase behavior. Initial reservoir conditions, production history, and rock-fluid interactions were defined, with relative permeability curves indicating a water-wet reservoir and low critical gas saturation affecting the GOR. To better understand the relationship between reservoir and production parameters, a detailed sensitivity analysis was performed using the Response Surface Methodology (RSM). Following the sensitivity analysis, a history matching process was conducted using the Designed Exploration and Controlled Evolution (DECE) optimizer to validate the model for future forecasts. Six operational scenarios were defined to decrease the production GOR and enhance final recovery from the field. The results indicate that the water injection scenario is effective in preventing the GOR increase by maintaining reservoir pressure, thereby sustaining production over a longer period. This scenario also improves oil recovery by approximately 6% compared to the base case. Finally, optimization was carried out using the DECE optimizer for each scenario to fine-tune the operational parameters. The goal was to maximize oil revenue for each scenario during the optimization process. This study stands out as one of the few that provides a comprehensive analysis of production behavior and development planning for a real fractured reservoir with high producing GOR.

Technology Focus: Unconventional and Tight Reservoirs (July 2024)

Unconventional reservoirs bear a unique perplexity in that, at every scale, they are different from their conventional counterparts and even one another. Small nuances in any one parameter can result in a vastly different well result, which may affect how an area, or even an entire play, is interpreted. This month’s selection of papers is all about those differences, in recognition that it is technology that drives innovation through understanding what these differences mean and how best to extract value from these vast resources. Starting at the well scale and looking at the benefits of knowing the efficacy of each stimulation stage, paper URTeC 3864145 is from the Ordos Basin in China. Investigating hydraulic fracture performance on a stage-by-stage basis proves time and time again that understanding the details can improve overall development outcomes. The case study reviews two hydraulic fracture diagnostic techniques used in combination to determine water breakthrough and shutoff plans. Zooming out to the play scale, paper SPE 216292 is focused on the most variable of unconventional reservoirs: the carbonate reservoir. This case study of the Austin Chalk formation in Texas analyses the production uplift from application of horizontal, multistage fracture stimulation technology in tight or fractured carbonate reservoirs. The application of unconventional technology in carbonate reservoirs can extended field life, and the deployment of this technology should be considered for any redevelopment or reassessment of potential resources trapped in tight carbonate reservoirs. Finally, paper OTC 34832 draws on the concept of innovation that is required to unlock unconventional resources. Novel methods of stimulation are the cornerstone of unconventional technology in that well stimulation is a basic requirement of all low-permeability reservoirs. The paper describes a trial pilot from idea through execution from Kuwait Oil Company for enhanced oil recovery in tight formations using downhole hydrogen generation from in-situ exothermic multistage chemical reactions between two unique hydroreacting agents. The paper also provides lessons learned and optimization insights from the trial, concluding that a successful, low-cost alternative stimulation technique was demonstrated and repeatable. Recommended additional reading at OnePetro: www.onepetro.org. SPE 216139 Tight Gas Reservoir Characterization and Comparison of PLT Methods: Microseismic Monitoring, Fiber-Optical Production Logging, and Tracer-Coated Sand Monitoring Applied in the Same Well by Xiao Yao, Petrochina, et al. SPE 216149 New Insight in Developing Tight Fractured Carbonate Reservoirs, Mishrif Formation, West Kuwait by M. El-Jeaan, Kuwait Oil Company, et al. SPE 215712 Successful Utilization of In-Situ Dune Sands in Saudi Arabian Unconventional Frac Operations by Nahar Qahtani, Saudi Aramco, et al.

FEATURES OF WELL KILLING IN CONDITIONS OF CARBONATE RESERVOIR AND HIGH GOR

The article presents the results of studies on the use of well killing technology in fractured carbonate reservoirs of the Republic of Bashkortostan under conditions of loss of kill fluid and high GOR of the product. The geological and technical conditions of the Metelinskoye field are summarized, and the factors complicating well killing before routine and workover are described - reduced reservoir pressure during operation, previous large-volume salt-acid treatments, and the presence of hydrogen sulfide.The article substantiates the choice of invert-emulsion solutions (IER) for killing wells in the Metelinskoye field, taking into account the experience of using various killing technologies in the Volga-Ural oil and gas province. The authors have determined the physicochemical and rheological characteristics of kill compositions based on IER of various densities. An increase in the effective viscosity at high shear rates and the limit shear stress of the IER with an increase in the density of the composition was revealed. Taking into account the high risks of gas breakthrough during well killing in the Metelinskoye field, studies were also conducted to assess the gas-retaining capacity of the IER on an experimental installation by extruding the composition from a metal capillary. It has been shown that the gas holding capacity of these compositions with increasing density is described by an equation with a power function and a high degree of reliability. The effect of hydrogen sulfide neutralizer addition on IER properties was investigated. In order to increase the success of killing, the IER-based killing technology was selected and adapted to the existing conditions. The better blocking ability of higher density formulations has been confirmed. Successful well tests. To reduce the risks of using the IER and optimize the consumption of reagents during the further use of the technology, organizational and technical measures for killing and subsequent repair of wells were developed and implemented. The results of this work can be used in wells of the Ural-Volga region, Eastern Siberia and Timan-Pechora province with the presence of losses and a high gas factor, the repair of which is complicated by the lack of fluid circulation and the presence of excess pressure at the wellhead with signs of gas shows.

Experimental study and prediction method of solid destabilization and production in deep carbonate reservoir during mining

Wellbore instability is one of the significant challenges in the drilling engineering and during the development of carbonate reservoirs, especially with open-hole completion. The problems of wellbore instability such as downhole collapse and silt deposit in the fractured carbonate reservoir of Tarim Basin (Ordovician) are severe. Solid destabilization and production (SDP) was proposed to describe this engineering problem of carbonate reservoirs. To clarify the mechanism and mitigate potential borehole instability problems, we conducted particle size distribution (PSD) analysis, X-ray diffraction (XRD) analysis, triaxial compression tests, and micro-scale sand production tests based on data analysis. We found that the rock fragments and silt in the wellbore came from two sources: one from the wellbore collapse in the upper unplugged layers and the other from the production of sand particles carried by the fluid in the productive layers. Based on the experimental study, a novel method combining a geomechanical model and microscopic sand production model was proposed to predict wellbore instability and analyze its influencing factors. The critical condition and failure zone predicted by the prediction model fit well with the field observations. According to the prediction results, the management and prevention measures of wellbore instability in carbonate reservoirs were proposed. It is suggested to optimize the well track in new drilling wells while upgrading the production system in old wells. This study is of great guiding significance for the optimization of carbonate solid control and it improves the understanding of the sand production problems in carbonate reservoirs.

Experimental study on acid etching mechanism of acid fracturing in carbonate reservoirs

Acid fracturing is one of the most effective methods to enhance oil and gas production in carbonate reservoirs. The effect of acid fracturing is mainly affected by the conductivity, which is controlled by the acid-etched morphology of the fracture face and near-wellbore zone. Currently, the acid etching mechanism of the fracture face and near-wellbore zone is not considered in traditional experiments. The flow and reaction of acid in the fracture are simulated by using the cores with processed artificial fracture and the high-temperature acid-resistant experimental setup based on traditional experiments. The results under different conditions are obtained. The fracture face and inlet end face of cores are analyzed by combining the dissolution rate, reaction rate, average etching depth, and standard deviation. The effects of the lithology, pump rate, thickening agent concentration, and acid concentration on the acid etching mechanism of acid fracturing in carbonate reservoirs are investigated.

The Dependence of Water and Gas Breakthrough on the Choice of Model Parameters in Naturally Fractured Reservoirs Using Sector and Full Reservoir Models

Assessing fractures in carbonate reservoirs is crucial due to their substantial impact on reservoir permeability. Understanding the characteristics of these fractures is vital for optimizing oil production. Additionally, extremely heterogeneous and anisotropic permeability distribution within the natural fractured reservoir is often caused by the complexity of a fracture network. Therefore, accurate reservoir modelling and simulation must be conducted in order to achieve ultimate recovery. In this paper, a sector model has been developed based on the studied example field, and its results are compared with the full reservoir model to find out the degree of resemblance between their outputs. The study area has four natural fracture compartments, with an average reservoir height of 95m and WOC and GOC depths of 685 m and 590 m, respectively. A dual-porosity and single-permeability modelling system was used to simulate the properties of the reservoir rock. This model was derived from the Petrel layercake model. A sensitivity analysis was also carried out to look into the relationships between field performance and the well. The outcomes of both models demonstrated that matrix permeability and fracture dimension had a significant impact on the early breakthrough of water and gas to comparable, huge extents. Other factors, such as aquifer size and WOC, show a moderate impact on water and gas breakthrough as well as final recovery.

A Study on the Effect of New Surfactant Proportions on the Recovery Improvement of Carbonate Reservoir

The strategy of integrating water injection and chemical additives in combining secondary and tertiary oil recovery techniques has been widely investigated in enhancing oil recovery efficiency. Nevertheless, there is a lack of sufficient evidence on the effectiveness of a mixture of cationic and nonionic surfactants combined with water injection techniques in enhancing recovery in the application of carbonate reservoirs. Therefore, it is particularly critical to explore the impact of this combination strategy in enhancing recovery in fractured carbonate reservoirs. The recovery enhancement effect can be assessed by conducting phase behavior experiments and determining interfacial tension and contact angle. Further, the effectiveness of specific surfactant ration solutions in enhancing recovery can be verified by performing drive-off experiments. The results show that low mineralization water and surfactants have a significant synergistic effect in enhancing the recovery efficiency of carbonate reservoirs, with the optimal ratio of cationic to non-ionic surfactants being 2.5:1. The optimized surfactant ratio is able to increase the recovery of carbonate reservoirs by 20% compared to the original recovery rate.

Analysis of Seismic Response Characteristics of Fractured Carbonate Reservoirs Based on Physical Model (Tarim Basin)

Anomalous bright spots, called the string of bead-like response, are typical seismic migration profile features in carbonate fractured reservoirs in the Tarim Basin, and they are indicators of high-quality oil and gas reservoirs. Correctly recognizing the correspondence between fractures and the SBLR can contribute to the efficient drilling of target carbonate fractured reservoirs. Physical models can describe fractured reservoirs more directly and efficiently than real situations and have obvious advantages in accurately and quantitatively designing parameters such as dipping angles and the number of layers of fractured reservoirs. Under such a background, according to the real tectonic characteristics of the Tarim Basin, among the main hydrocarbon reservoirs, fractured reservoirs with various parameters were designed and a physical model was constructed according to the real stratigraphic parameters. After seismic data acquisition and processing, the response characteristics of the string of bead-like response were extracted and summarized from seismic migration profiles for all fractured reservoirs, which provided targeted analyses and discussions on the fracture dipping angle, number of fracture layers, overlying stratigraphic influences, and planar attributes of the fractured reservoirs. In general, the larger the fracture dip, the more difficult it is to identify, while the slope of reflection strength and maximum absolute amplitude attributes can be important markers for fractured reservoir identification. The physical modeling study of fractured reservoirs in this paper can provide a basis for the analysis and prediction of carbonate fractured reservoirs in the Tarim Basin.

Study of Acid Fracturing Strategy with Integrated Modeling in Naturally Fractured Carbonate Reservoirs

Study of Acid Fracturing Strategy with Integrated Modeling in Naturally Fractured Carbonate Reservoirs

Formation mechanical mechanism of low-angle fractures in pre-salt carbonate reservoirs: a case study from Carboniferous KT-I formation of the NT oilfield in the eastern margin of the Precaspian Basin, Kazakhstan

Fracture is an important factor that affects the oil and gas productivity of carbonate reservoirs. Much researches have been done on the origin of high-angle fractures in carbonate reservoirs, but few efforts have been made on the genetic mechanical mechanism of low-angle fractures. Based on the seismic data, core data, conventional logging data and rock mechanics experimental data, combined with three-dimensional in situ stress field simulation methods, the features, formation geological conditions and genetic mechanical mechanism of low-angle fractures (LAFs) were analyzed by applying Coulomb–Moore criterion, Griffith criterion and non-coordination criterion. The proportion of the number of shear fractures is as high as 90.2%, while that of tensile fractures is only 9.8% in the study area. Shear fractures are mainly unfilled fractures, and tensile fractures are mainly partially filled fractures. The LAFs were formed in the second tectonic movement, in which the knee-fold structure with high in the west and low in the east developed in the study area. The buried depth of most parts of the KT-I formation is 800 m when the study area develops the knee-fold structure, with a maximum depth of 1800 m and a minimum buried depth of 70 m, and the dip angle of the steepest part of the stratum is about 20°. A large number of LAFs were formed in the study area under the joint influence of tectonics and abnormally high pressure of water, including near-horizontal LAFs in the non-weak fabrics section (type I low-angle shear fractures), the LAFs having a certain angle with bedding in the non-weak fabrics section (type II low-angle shear fractures) and near-horizontal LAFs in the weak fabrics section (type III low-angle shear fractures). The formation of type I and type II low-angle shear fractures follows the Coulomb–Moore criterion. Type I low-angle shear fractures are formed in strata with a certain dip angle, while type II low-angle shear fractures are formed in near-horizontal strata. Type III low-angle shear fractures are formed under the comprehensive influence of pre-existing weak fabrics and strong horizontal extrusion, which follows the non-coordination criterion. Low-angle tensile fractures are mainly caused by abnormally high pressure and reverse faults in the study area, following Griffith’s criterion. The research in this paper not only reveals the formation mechanical mechanism of LAFs in pre-salt carbonate reservoirs but also provides guidance for the prediction of LAFs and solving the problem of water channeling caused by LAFs in oil fields.

Tectonic fractures induced by strike-slip faulting in intracratonic ultradeep carbonate rocks: Insights from the finite element method and self-adaptive constraints computational model for boundary conditions

Numerical simulations of the paleostress field during a period of tectonic fracture formation and rock failure criteria are used to quantitatively predict the development and occurrence of tectonic fractures induced by the formation of the SB18 fault zone in the Middle Ordovician Yijianfang Formation of the Shunnan area, Tarim Basin, China. The results of acoustic emission experiments, mechanical property measurements, and tectonic fracture occurrence observations obtained from core descriptions and fullbore formation microimager logs are combined with the Andersonian model of faulting and the finite element method, which is widely used for the numerical simulation of stress fields, to investigate the paleotectonic and in situ stress fields via numerical simulation. The quantitative prediction of the opening pressure and opening sequence of tectonic fractures is based on the occurrence of tectonic fracture, numerical simulation of in situ stresses, and coordinate system conversion. The results show that the width of the fracture zone induced by strike-slip faulting is ∼310 m. The degree of fracture development is significantly increased when the Young’s modulus, paleostress difference, and paleostress difference coefficient of the rock are elevated. The current horizontal principal stress is positively correlated with the distance from the fault, and the elevated areal density of the secondary faults causes a clockwise deflection of the horizontal stress direction. SSE-striking shear fractures with orientations ranging from 140° to 150° and two sets of tensional fractures with orientations ranging from −40° to −35° and 55° to 60° are preferentially opened in the water injection development stage of the reservoir. As the horizontal stress difference, horizontal stress difference coefficient, and angle between the maximum horizontal principal stress and a fracture decrease, the fracture opening pressure decreases. At the structural highs (burial depths <6225 m) and lows (burial depths >6225 m), the fracture burial depth is positively and negatively correlated with the opening pressure, respectively. Quantitative prediction of tectonic fracture developmental characteristics, opening pressure, and the opening sequence and investigation of the main factors that control their development can help to identify and support opportunities for hydrocarbon exploration and development of fractured carbonate reservoirs.

Fracture prediction and application in carbonate reservoirs based on the rescaled range analysis- finite difference numerical analysis methods

For carbonate reservoirs, the study of fractures is crucial. In this paper, the identification and prediction of fractures in carbonate reservoirs are carried out by applying R/S-FD numerical analysis method by using core, thin section and imaging logging data. The analysis concludes that the AC, CAL, DEN, and GR curves are very sensitive to the response of fracture development segments as calculated by the rescaled range analysis (R/S) analysis method, but some fractures are still misidentified. After finite difference (FD) calculation on the basis of R/S calculation, high-angle structural fractures can be accurately identified, and the R/S-FD fracture identification results of different curves can be verified with the results of core and imaging logging, and the fracture identification accuracy can reach 71.69%. The number of fracture development segments is positively correlated with the cumulative oil production, the number of producing layers and the cumulative thickness of producing layers, and the wells with more fracture development segments have higher cumulative oil production, more producing layers and larger cumulative thickness of producing layers. This method improves the accuracy of fracture identification in carbonate reservoirs, which is of great significance for oil and gas exploration.

Enhancing Reservoir Zonation through Triple Porosity System: A Case Study

Summary The Asmari-Jahrom reservoirs, located in southwest Iran, are recognized as one of the major fractured reservoirs in the world. Understanding the role of fractures in enhancing hydrocarbon flow and permeability is of utmost importance. In this study, petrophysical conventional logs [neutron porosity (NPHI), density (RHOB), sonic (DT), and gamma ray (GR)] and advanced image logs [formation microresistivity imaging (FMI)] were used to investigate the reservoir properties. The novelty of this study lies in the implementation of triple porosity on reservoir quality and identification of flow units in Asmari-Jahrom reservoirs using petrophysical and borehole image logs. By quantifying fracture and vuggy porosity and correlating them with velocity deviation log and fracture parameters [fracture aperture (VAH) and fracture density (VDC)], it was demonstrated that fracture porosity is directly related to VAH. High peaks were observed in fracture parameters, particularly in VAH diagrams where the velocity deviation log was negative and low. Total porosity from density logs was found to match secondary porosity from petrophysical logs, validating FMI results. However, FMI log resolution was higher, enabling clearer identification of fracture porosity peaks. The velocity deviation log indicated that the predominant type of porosity in the reservoir was matrix (primary) porosity. However, fracture and vuggy porosity were also observed in certain zones. Based on indirect evidence such as drilling mud loss, porosity type (matrix, fracture, and vuggy), porosity amount, and oil saturation, 18 zones were identified to determine quality zones with appropriate reservoir quality. Asmari-Jahrum reservoirs were found to possess high storage and flow capacity. The presence of multiple fracture types, especially longitudinal fractures, contributed to the development of secondary porosity and enhanced flow unit quality. Despite their complexity, these fractured carbonate reservoirs were analyzed comprehensively through integrated petrophysical and FMI log interpretation, enabling optimized reservoir performance and facilitating hydrocarbon production.