Fractured-vuggy 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.

Visualization Experimental Investigation on Flow Regulation and Oil Displacement Characteristics of Gel Foam in Fractured-Vuggy Carbonate Reservoirs.

Fractured-vuggy reservoirs experience severe channeling during water and gas injection operations, and conventional foam shows weak regeneration capabilities in large-scale fracture spaces, thus failing to effectively seal them. Gel foam combines the advantages of both foam and gel, significantly enhancing the foam's stability and showing good suitability in fractured-vuggy reservoirs. In this article, the plugging and flow regulation properties of gel foam in fractures were studied through fracture displacement experiments. The dynamic plugging capability of gel foam was superior to that of ordinary foam, and its plugging effect was significantly influenced by the fracture opening. Gel foam had strong retention capacity in fractures, and after plugging large-opening fractures, the diversion rate of small-opening fractures was increased by at least 83.3 times during subsequent parallel water flooding, making the flow regulation effect remarkable. Through the oil displacement experiments in typical fractured-vuggy models, the profile control law and enhanced oil recovery performance of gel foam under different fractured-vuggy structures were studied. In the regular fractured-vuggy network, gel foam adhered to occupy the fractured-vuggy space for plugging and controlled the top gas migration direction to synergistically drive the recovery of remaining oil, ultimately achieving a recovery of 95%. In the combination of fractures and irregular vugs, due to the density, gel foam continuously pushed down and right along the fractures to the vugs, pushing the crude oil and formation water in the vugs to migrate to the production well. The recovery of the gel foam flooding stage was as high as 48%, and the final recovery reached 93.5; only a small amount of shielded remaining oil was difficult to drive. The research results are of great significance to the application of gel foam in enhancing oil recovery in fractured-vuggy reservoirs.

Towards in-depth profile control using s-MPG synergy with MSRG in fractured-vuggy carbonate reservoirs

In-depth profile control is a crucial technique employed to enhance oil recovery in fractured-vuggy carbonate reservoirs. However, it is a challenge to achieve in-depth profile control. In this paper, two types of organic gel systems, namely s-MPG and MSRG, tailored for fractured-vuggy reservoirs with 140 °C and 22 × 104 mg/L have been developed. FTIR was used to analyze the functional groups of s-MPG and MSRG. Additionally, the quality retention rates of s-MPG and MSRG were assessed using TG-DSC, yielding results of 92.85% and 92.65%, respectively. The dilution rates of s-MPG and MSRG are found to be 18.69% and 26.69%, respectively, demonstrating excellent compatibility and adaptability. The enhancement performance depends on the synergistic effect that the anti-dilution s-MPG effectively separates bottom water, while high-strength MSRG separates the oil layer. Moreover, the EOR performances of s-MPG synergy with MSRG in various types of fractured-vuggy carbonate models were also evaluated. The highest oil recovery of 12% is achieved in fracture network model. Laboratory results indicate that the synergistic combination of s-MPG and MSRG for water plugging in fractured-vuggy carbonate reservoirs results in a more effective enhancement of oil recovery compared to using a single gel system for plugging. Finally, the s-MPG synergy with MSRG has been applied in actual fractured-vuggy carbonate reservoirs. As expected, the water cut of typical well is reduced from 100% to 30% and the increased oil production is 1142 t totally. Therefore, this study presents a novel approach to achieving in-depth profile control by leveraging the synergistic effect of s-MPG with MSRG in fractured-vuggy carbonate reservoirs.

Co-Injection of Foam and Particles: An Approach for Bottom Water Control in Fractured-Vuggy Reservoirs

Fractured-vuggy carbonate reservoirs are tectonically complex; their reservoirs are dominated by holes and fractures, which are extremely nonhomogeneous and are difficultly exploited. Conventional water injection can lead to water flooding, and the recovery effect is poor. This paper takes the injection of foam and solid particles to control bottom water as the research direction. Firstly, the rheological properties of foam were studied under different foam qualities and the presence of particles. The ability of foam to carry particles was tested. By designing a microcosmic model of a fractured-vuggy reservoir, we investigated the remaining oil types and the distribution caused by bottom water. Additionally, we analyzed the mechanisms of remaining oil mobilization and bottom water plugging during foam flooding and foam–particle co-injection. The experimental results showed that foam was a typical power-law fluid. Foam with a quality of 80% had good stability and apparent viscosity. During foam flooding, foam floated at the top of the dissolution cavities, effectively driving attic oil. Additionally, the gas cap is released when the foam collapses, which can provide pressure energy to supplement the energy of the reservoir. Collaborative injection of foam and solid particles into the reservoir possessed several advantages. On one hand, it inherited the benefits of foam flooding. On the other hand, the foam transported particles deep into the reservoir. Under the influence of gravity, particles settled and accumulated in the fractures or cavities, forming bridge plugs at the connection points, effectively controlling bottom water channeling. The co-injection of foam and solid particles holds significant potential for applications.

A Stokes–Darcy–Darcy model and its discontinuous Galerkin method on polytopic grids

In this paper, we propose and numerically solve a model considering confined flow in fractured porous media coupled with free flow in conduits. Such a situation arises, for example, for fluid flows in fractured vuggy carbonate reservoirs and caves/conduits, where a matrix and fractures are the main spaces for fluid storage and flow. The flow in caves and conduits is governed by the Stokes equation; the flow in fractured porous media, which consists of both a matrix and fractures, is described by a coupled Darcy–Darcy (bulk–fracture) model. Then, the two models are coupled through suitable (physically consistent) interface conditions on the interface between fractured porous media and caves/conduits, playing a key role in a physically faithful simulation that achieves high accuracy. The construction of all the interface conditions of the coupled model is based on the fundamental properties of the traditional bulk–fracture model and the well-known Stokes–Darcy model. The weak formulation is derived for the proposed model, and the well-posedness of the model is theoretically analyzed. We also propose a polyhedral discontinuous Galerkin finite element approximation for the Stokes flow in conduits and Darcy flow in the porous matrix, which is coupled with a conforming finite element scheme for the flow in the fracture. Optimal error estimates in a suitable energy norm are obtained. Two-dimensional numerical experiments are conducted to validate the proposed model and to demonstrate the features of both the model and the numerical method, such as the optimal convergence rate of the numerical solution; the detail flow characteristics around fractures, the matrix, and conduits; and the applicability to real-world problems.

A New Symmetry-Enhanced Simulation Approach Considering Poromechanical Effects and Its Application in the Hydraulic Fracturing of a Carbonate Reservoir

The exploration of fractured-vuggy carbonate reservoirs usually involves hydraulic fracturing to maximize recovery. At present, effectively communicating natural discontinuities is a technical challenge. In this article, we investigated the origin and propagation of cracks in fractured-vuggy reservoirs using discrete element hydraulic fracturing simulations that included poromechanical effects. A particular focus on the microscopic force-displacement symmetry of adjacent pore pressures is introduced. Our results demonstrate that the poromechanical effect significantly increases the strength of overpressurized reservoir formations. Moreover, the effect of injected fluid viscosity on the hydraulic fracturing effectiveness was studied through two simulation tests. The outcomes highlight the critical influence of fluid viscosity on the propagation of micro-cracks in overpressure fractured-vuggy reservoirs.

High-pressure capacity expansion and water injection mechanism and indicator curve model for fractured-vuggy carbonate reservoirs

Water injection for oil displacement is one of the most effective ways to develop fractured-vuggy carbonate reservoirs. With the increase in the number of rounds of water injection, the development effect gradually fails. The emergence of high-pressure capacity expansion and water injection technology allows increased production from old wells. Although high-pressure capacity expansion and water injection technology has been implemented in practice for nearly 10 years in fractured-vuggy reservoirs, its mechanism remains unclear, and the water injection curve is not apparent. In the past, evaluating its effect could only be done by measuring the injection-production volume. In this study, we analyze the mechanism of high-pressure capacity expansion and water injection. We propose a fluid exchange index for high-pressure capacity expansion and water injection and establish a discrete model suitable for high-pressure capacity expansion and water injection curves in fractured-vuggy reservoirs. We propose the following mechanisms: replenishing energy, increasing energy, replacing energy, and releasing energy. The above mechanisms can be identified by the high-pressure capacity expansion and water injection curve of the well HA6X in the Halahatang Oilfield in the Tarim Basin. By solving the basic model, the relative errors of Reservoirs I and II are found to be 1.9% and 1.5%, respectively, and the application of field examples demonstrates that our proposed high-pressure capacity expansion and water injection indicator curve is reasonable and reliable. This research can provide theoretical support for high-pressure capacity expansion and water injection technology in fracture-vuggy carbonate reservoirs.

Prediction of production indicators of fractured-vuggy reservoirs based on improved Graph Attention Network

Various storage and seepage spaces exist in fractured-vuggy carbonate reservoirs composed of multi-scale dissolution pores and fractures. The frequent regulation of the working system causes nonlinear and unstable production data along with complex water breakthrough characteristics, which lead to difficulty in real-time prediction. Traditional methods based on the water drive curve and autoregressive machine learning ignore the spatial correlation among production wells and local geological characteristics. To address these problems, we propose a model based on improved attention, the spatiotemporal multi-graph convolutional network (STMCN), for production prediction. The unit production wells are abstracted as directed graph network nodes to establish adjacency, connectivity and correlation graphs to extract the spatial and semantic features from different perspectives through graph convolutional networks. To depict the law of fluid movement, we realize the fusion of spatial and semantic information through dynamic routing. Aiming at the autocorrelation characteristics of production sequences, the model uses the self-attention mechanism to capture the dependencies in production sequences. The gating mechanism is designed to achieve dynamic production prediction by adaptively aggregating the spatiotemporal characteristics. This paper evaluates the predictive performance of our model by two real-world datasets of the Tahe Oilfield. The results show that the mean absolute error (MAE), root mean squared error (RMSE), and mean absolute percentage error (MAPE) of our proposed model for the prediction of well A2 were 3.19, 4.66 and 0.07, respectively, which were better than the relatively new baseline model.

Mechanistic Study and Optimization of High Water Cut Phase Management Strategies in Fracture-Vuggy Carbonate Reservoirs with Bottom Water

Fracture-vuggy carbonate reservoirs commonly exhibit sufficient bottom water energy and are characterized by fractures or other interconnected channels with bottom water, which can easily cause high water cut in oil wells during production. The main reasons are as follows: firstly, bottom water coning leads to water flooding. Secondly, artificial water injection flooding fails and shows high water cut in oil production. This paper further clarifies the causes of high water cut in fractured-vuggy carbonate reservoirs and explores rational and feasible management strategies to improve the current water flooding situation and reduce the comprehensive water cut in oil wells. In this paper, numerical simulation technology is used to establish a mechanism model based on the actual reservoir conditions. By comparing the development effects of four bottom water suppression measures, including the adjustment of flow channel, artificial barriers, adjustment of flow potential and gas injection, the optimal measure is selected and the relevant parameters are optimized. Building upon this, further optimization of water injection methods is conducted to explore comprehensive management strategies for enhancing the water flooding effect during high water cut periods. The research demonstrates that bottom water can be effectively inhibited by artificial barriers, leading to an expansion of the swept volume of water injection and achieving the goal of improving the high water cut condition in carbonate reservoirs. Optimal implementation of artificial barriers occurs when the water cut reaches around 80%. Specifically, positioning barriers at the bottom of perforations and setting the barrier radius at 0.15–0.2 times the well spacing obtain the most favorable results. Additionally, short-term injection with long-term shut-in, identified through cyclic water injection simulations, exhibits superior oil recovery enhancement. Validation conducted in a practical field of a fractured carbonate reservoir over a five-year period has led to a substantial increase in oil production by 5.6 × 104 t and a 12% reduction in water cut. The research approach and methodology presented in this paper can provide valuable insights and serve as a reference for the development of high water cut periods in fractured-vuggy carbonate reservoirs.

Optimization and Performance Evaluation of an Atomized Acid System for the Expansion of Carbonate Gas Injection

The conventional liquid acid has several shortcomings in the acidizing process of fractured-vuggy carbonate reservoirs, including high filtration loss, fast reaction rate, high friction resistance, and difficult flowback. To address these issues, a new atomizing acid acidizing technology is proposed, combining the gas injection development practice from the fractured-vuggy carbonate reservoir in the Tahe oilfield. The laboratory experiments were conducted to optimize the type and concentration of atomized acid, iron ion stabilizer, corrosion inhibitor, and atomization stabilizer. The acid atomization rate was evaluated under different combinations of gas and liquid injection flows using a self-made atomized acid well migration simulator, and the best atomization scheme was selected. Furthermore, a kinetic experiment for the acid–rock reaction was carried out to evaluate the retarding performance of the atomized acid. The optimized formula for the atomizing acid system consists of 15~25% hydrochloric acid, 0.005% atomizing stabilizer (AEO-7), 1% iron ion stabilizer (EET), 1.5% corrosion inhibitor (EEH-160), and water. The optimal gas and acid injection scheme is gas injection at 2m3/min and acid injection at 10 mL/min, which maintains an atomization rate of over 80% after the acid mist migrates through the wellbore. Compared with gelling acid, the acid–rock reaction rate of atomized acid is 8.5, 9.1, and 10.6 times slower under acid concentrations of 15%, 20%, and 25% respectively. The retarding effect of atomized acid is superior, facilitating etching and initiating underdeveloped gas drive channels and thereby increasing the probability of gas communication with new reservoirs. The research findings presented in this paper establish a theoretical foundation for the practical implementation of the atomized acid acidizing process in the field.

Generation and distribution of overpressure in ultra-deep carbonate reservoirs controlled by intra-cratonic strike-slip faults: The Ordovician of Shuntuoguole area in the Tarim Basin

The strike-slip fault-controlled ultra-deep fractured-vuggy carbonate reservoir is an increasingly important exploration target. However, the high heterogeneity of fault-controlled reservoirs and the ineffective methods available for pressure prediction make it difficult to assess the risk of potential overpressure in ultra-deep carbonate reservoirs. Abnormal overpressure is common in the ultra-deep strike-slip fault-controlled carbonate reservoirs in the Shunbei Oilfield of the Tarim Basin. According to measured pressures, petroleum accumulation history, and fault framework, this study investigates the generation mechanisms of overpressure in fault-controlled carbonates and reconstructs the pressure evolution of reservoirs. Finally, the effect of strike-slip faults on current overpressure distribution is discussed. Measured pore pressure data from 90 wells showed that all reservoirs present in the major fault zones are normally pressured, and the reservoirs present far away from the major faults commonly develop overpressures. The distribution patterns of overpressure in the Middle-Lower Ordovician reservoirs coincide with areas with fault reactivation during the Himalayan Period. The results of the comprehensive analysis of petroleum accumulation history, fault activity, and well production suggested that dry gas generation is a primary cause of overpressure in the Middle-Lower Ordovician reservoirs. The relatively low temperature in the reservoir, in addition to the highly compartmentalized nature of overpressure, indicated that these overpressured gas migrate vertically into the Ordovician formation from deep strata along strike-slip faults. The pressure evolution restored by basin modelling and fluid inclusion showed that distinct differences in overpressure magnitude in the different reservoirs were formed at the stage of gas charging but not at the early stages of oil accumulation. The difference in physical properties of the two types of fault-controlled reservoirs resulted in different pressure distributions and oil-bearing levels in the ultra-deep carbonate reservoirs at present. The strike-slip fault zones are the primary pathways by which overpressured fluids migrate from the deeper Cambrian formation into the Ordovician reservoirs and act as barriers to separate the pressure systems in the ultra-deep carbonate reservoirs. These findings are expected to help mitigate the drilling risks with overpressure in deep strike-slip fault-controlled carbonate reservoirs.

Experimental study on fluid flow behaviors of waterflooding fractured-vuggy oil reservoir using two-dimensional visual model

The carbonate reservoir plays a pivotal role in conventional oil and gas reservoirs. However, due to limited knowledge of fluid flow characteristics in fractured-vuggy carbonate formations (vuggy means a small to medium-sized cavity inside rock), high efficiency reservoir development remains challenging. In this study, the similarity principle is utilized to design a two-dimensional visual model based on geological data and the injection-production characteristics of a fractured-vuggy reservoir in M Oilfield. To investigate the characteristics of oil–water flow, the oil–water interface, and residual oil distribution, flooding experiments are conducted at various injection-production positions, types, and injection rates. The results suggest that a low injection/high production strategy is optimal for achieving maximum oil recovery. As a consequence, this configuration is employed in the subsequent flooding experiments. The optimal oil recovery of 82.2% is attained via pore injection and vug production. The Jamin effect exerts an influence on the oil-water flow in structures connected by small channels at the bottom of large vugs, necessitating adjustment of the flow rate to achieve optimal injection conditions. The variation of the oil–water interface height in each vug due to structural flaws results in suboptimal overall oil recovery. The oil recovery is limited to approximately 30% at an injection rate below 8 ml/min but can be enhanced to over 70% with a higher injection rate exceeding 8 ml/min. The residual oil of the fractured-vuggy reservoir is typically found in the tops of structures and peripheral areas with poor connectivity. The findings of this study offer direction for optimal production in fractured-vuggy carbonate reservoirs and facilitate a more comprehensive comprehension of oil–water flows within the reservoir.

Distribution, exploitation, and utilization of intermediate-to-deep geothermal resources in eastern China

The part of China, east of the Hu Huanyong Line, is commonly referred to as eastern China. It is characterized by a high population density and a well-developed economy; it also has huge energy demands. This study assesses and promotes the large-scale development of geothermal resources in eastern China by analyzing deep geological structures, geothermal regimes, and typical geothermal systems. These analyses are based on data collected from geotectology, deep geophysics, geothermics, structural geology, and petrology. Determining the distribution patterns of intermediate-to-deep geothermal resources in the region helps develop prospects for their exploitation and utilization. Eastern China hosts superimposed layers of rocks from three major, global tectonic domains— namely Paleo-Asian, Circum-Pacific, and Tethyan rocks. The structure of its crust and mantle exhibits a special flyover pattern, with basins and mountains as well as well-spaced uplifts and depressions alternatively on top. The lithosphere in Northeast China and North China is characterized by a thin, low density crust and mantle, whereas the lithosphere in South China has a thin, low density crust and a thick, high density mantle. The middle and upper crust contain geobodies with high conductivity and low velocity, with varying degrees of development that create favorable conditions for the formation and enrichment of geothermal resources. Moderate-to-high temperature geothermal resources are distributed in the Mesozoic–Cenozoic basins in eastern China, although moderate temperature geothermal resources with low abundance dominate. Porous sandstone reservoirs, karstified fractured-vuggy carbonate reservoirs, and fissured granite reservoirs are the main types of geothermal reservoirs in this region. Under the currently available technical conditions, the exploitation and utilization of geothermal resources in eastern China favor direct utilization over large-scale geothermal power generation. In Northeast China and North China, geothermal resources could be applied for large-scale geothermal heating purposes; geothermal heating could be applied during winter along parts of the Yangtze River while geothermal cooling would be more suitable for summer there; geothermal cooling could also be applied to much of South China. Geothermal resources can also be applied to high value-added industries, to aid agricultural practices, and for tourism.

Fracability Evaluation Method of a Fractured-Vuggy Carbonate Reservoir in the Shunbei Block.

The fracability of carbonate reservoirs is a key indicator for evaluating whether reservoirs can be effectively fractured. Taking the fractured-vuggy carbonate reservoir in the Shunbei block as an example, the microscopic characteristics and mechanical properties of this reservoir were analyzed. The test results showed that the core microstructure is relatively dense, the micropores and microfractures are developed, and the mineral composition is characterized by "high carbonate and few impurities". The compressive strength, Young's modulus, and Poisson's ratio of the rock increased with the increase in the confining pressure. Poisson's ratio is more sensitive to confining pressure than Young's modulus and shows the ductile transformation tendency from a low confining pressure to a high confining pressure. Considering the difficulty of forming a complex fracture network, we put forward a "fracture propagation factor" equation constructed with five main factors, including brittleness, fracture toughness, natural fracture, hole size, and horizontal stress difference, and then the fracture propagation factor of Yijianfang formation is calculated to be greater than 0.5. It is known that the Yijianfang formation has higher fracability. On this basis, combined with the construction parameters, a model for evaluating the fracability of a fractured-vuggy carbonate reservoir was established. The comprehensive fracability of four wells in the Shunbei block was calculated by the model. From the calculation results, the comprehensive fracability index of SHB43X was 0.5406 and greater than that of the other three wells, which has a high correlation with the production after fracturing.

Gas condensate well productivity in fractured vuggy carbonate reservoirs: A numerical modeling study

The spatial distribution of fractures and cavities may generate important impact on the fluid flow behavior in fractured vuggy carbonate reservoirs. However, the recovery mechanism of gas condensate wells is not well understood due to the lack of effective reservoir simulation methods that coupled porous-medium and free flows occurring in fractured vuggy carbonate reservoirs. In this work, a novel compositional reservoir model is developed for modeling the production dynamics of gas-condensate well in complex fractured vuggy reservoirs. The compositional multiphase fluid flow through rock matrix and fractures is assumed to follow Darcy's law, while the free flow in cavities is modeled based on the assumptions of instantaneous thermodynamic equilibrium and phase segregation controlled by gravity. An advanced numerical calculation method combining finite volume method (FVM) and embedded discrete fracture-vug model (EDFVM) is developed to efficiently solve the multi-component multiphase flow problem. Case studies are conducted to investigate the gas-condensate flow behavior and well production performance under various configurations of fracture-cavity patterns. Two scenarios are considered by placing the production well at the top and bottom of the models, which aim to mimic different locations of directional well target. The results indicate that when cavities are present, condensate oil accumulates mainly beneath the cavities due to the effect of gravity segregation. Thus, more condensate oil may be produced with depletion at the bottom of the reservoir. However, condensate oil distributes surrounding the production well when cavities are absent, and the production performance of gas-condensate well is less affected by depletion location. Furthermore, the cumulative condensate oil and gas production are higher when cavities are present because of the continuous supplement of condensate gas by cavities. Our research findings have important implication for the design of directional well planning in the fractured vuggy gas condensate reservoirs.

Field Monitoring and Identification Method for Overflow of Fractured-Vuggy Carbonate Reservoir

Since carbonate reservoirs develop pores and fractures and have a complex formation pressure system, overflow and even blowout seriously threaten the exploration and development of these kinds of reservoirs. According to the overflow characteristics of fractured-vuggy carbonate reservoirs, a field monitoring and identification method for overflow has been developed. This method is based on the top-down logic framework for early overflow identification, combined with optimized monitoring parameters. The DBSCAN clustering algorithm is used to identify abnormal logging parameters, and thus, a probability weight coefficient of overflow (K) indicated by the abnormal engineering parameters of a gas well can be calculated. K is divided into four early warning response levels of overflow, and the overflow control operation can be made according to the different levels of early warning response. Based on this method, an integrated software system for field monitoring and identification of early overflow is designed. This software system integrates the functions of data collection and management, overflow risk parameter calculation, overflow early warning, and overflow simulation analysis. Finally, according to a case analysis of overflow prediction for a fractured-vuggy carbonate reservoir in Well XX, this method’s prediction stability and accuracy are demonstrated, indicating that it can be used for the overflow early warning in engineering practice.

Numerical simulation of hydraulic-mechanical-chemical field coupled acid fracturing in complex carbonate reservoir

In a fractured-vuggy carbonate reservoir (FVCR) are distributed many irregular natural fractures and cavities. The acid fracturing is an effective stimulation method for FVCR. It involves the hydraulic, mechanical and chemical (HMC) field coupling process. To effectively simulate the acid fracturing in FVCR, the natural fractures are hierarchically treated. For the large fractures, which play the leading role in all physical fields, the fully coupled model is adopted. While for the small fractures, which play the leading role in part physical fields, the partly coupled model is adopted. By this means, the computation stability and efficiency are significantly improved. This is particular important for the field scale simulation of FVCR. Besides this, the acidization of the natural fracture in the inactive and activated states are considered. The simulation results suggest that this method can well simulate the acid fracture activation, propagation, interaction with natural fractures and connection with cavities in FVCR. It provides a stable and efficient approach for the acid fracturing simulation in complex FVCR.

Microgravity Monitoring in Fractured-Vuggy Carbonate Reservoirs

With the development of Tahe Oilfield entering the high water cut stage, gas channeling occurs in fractured-vuggy system during nitrogen injection, resulting in some inefficient wells. To improve the development effect of gas flooding, how to define the distribution of fracture, vuggy, and remaining oil has become one of the urgent problems to be solved at present. Microgravity monitoring technology uses high-quality data, the residual gravity anomaly of the target layer is obtained by depth recursion processing, the density distribution of the target layer is obtained by layer density inversion, and the fractured-vuggy distribution is depicted by edge detection. The results show that the lower part of the fractured-vuggy system in the north is connected to the middle, while the fractured-vuggy system in the south is directly connected to the middle, which leads to different effects of injected nitrogen. The early injected nitrogen in the SX area is mainly distributed in the north. Nitrogen injection in the north needs to reach a certain amount of gas before the middle can be effective. Nitrogen is injected in the south, and the central part is effective quickly. The research results provide a basis for adjusting injection-production scheme and improving reservoir development effect. Compared with the production performance and seismic interpretation results, it verifies the accuracy of ultradeep microgravity monitoring in depicting the development of fractured-vuggy system, which provides a new technology and idea for characterizing fractured-vuggy carbonate reservoirs.

Hilbert–Huang Transform Incorporating Analytical Mode Decomposition and Its Application in Fractured-Vuggy Carbonate Reservoir Prediction

High-precision time-frequency (TF) analysis (TFA) can accurately detect anomalies in oil and gas reservoirs. However, conventional TFA methods cannot effectively identify fractured-vuggy carbonate reservoirs, which are deep and strongly heterogeneous. In this paper, a TFA method based on analytical mode decomposition (AMD) and the Hilbert-Huang transform (HHT) is proposed. Specifically, seismic signals are decomposed by empirical mode decomposition (EMD) and then by AMD. Finally, the TF distribution of the seismic signals is obtained after Hilbert spectrum analysis (HSA). Synthetic seismic data demonstrate that the AMD-HHT method can effectively eliminate mode mixing and provide higher time and frequency resolutions and energy focus than conventional TFA methods. In addition, model and field seismic data also verify that the AMD-HHT method can effectively detect hydrocarbon-related energy anomalies hidden in broadband seismic data.

Quantitative characterization of deep fault-karst carbonate reservoirs: A case study of the Yuejin block in the Tahe oilfield

The Ordovician reservoirs in the Tahe oilfield are dominated by fractured-vuggy carbonate reservoirs, of which fault-karst reservoirs are a hot topic in recent years. Fault-karst reservoirs feature high production, large burial depth, and strong heterogeneity under the control of faulting and karstification. Based on geological, logging, and seismic data, this study classified the Ordovician fault-karst reservoirs in the Yuejin block of the Tahe oilfield into three types, namely karst-cave, dissolved-vug, and fractured types, and established the integrated identification criteria of the three types of reservoirs. This study characterized karst caves, dissolved vugs, and multi-scale faults through seismic wave impedance inversion and frequency-domain detection of multi-scale faults. 3D geological models of different types of reservoirs were built using the combined deterministic and stochastic methods and characterized the spatial distribution of multi-scale faults, karst caves, dissolved vugs, and physical property parameters of reservoir. This study established the method for the geological modeling of fault-karst reservoirs, achieved the quantitative characterization and revealed the heterogeneity of fault-karst reservoirs. The karst-cave and dissolved-vug types are high in porosity and act as reservoirs, while the fractured type is high in permeability and act as flow pathway. This study lays the foundation for the development index prediction, well emplacement, and efficient development of the fault-karst carbonate reservoirs.