Fractured-vuggy Reservoirs Research Articles

Experimental and numerical investigations of particle plugging in fracture-vuggy reservoir: A case study

Fracture-vuggy reservoirs commonly occur in carbonate rock and volcanic rock, leading to a significant loss of circulation. With both vugs and fractures, a fracture-vuggy reservoir is somewhat different from a fracture reservoir in pore structure and the plugging mechanism of particle materials. Based on the visualization model of a microfluidic chip and CFD–DEM numerical simulation, a set of methods was established to evaluate the effect of particle plugging in a fracture-vuggy reservoir. First, the influence of vugs on the particle bridging mechanism in the fracture-vuggy reservoir was analyzed using CFD–DEM numerical simulation. The results showed that vugs aggravated particle retention and reduced plugging efficiency. The particle plugging of the fracture-vuggy reservoir and fracture reservoir were compared through microfluidic experiments. This study provides a new evaluation method for characterizing particle plugging near a wellbore, and provides an intuitive understanding of the plugging mechanism of a fracture-vuggy reservoir.

Experiment analysis of remaining oil distribution and potential tapping for fractured-vuggy reservoir

Fractured-vuggy reservoir is characterized by various reservoir spaces, large multi-scale differences, uneven connectivity, and strong spatial heterogeneity, all of which bring great challenges to the understanding of the remaining oil distribution. Therefore, we built a visual physical model based on typical well groups, and intuitively simulated the remaining oil distribution of the fractured-vuggy reservoir through experiments. Then, we discussed the influence of the key parameters, including the injection-production position, injection rate, and bottom water intensity, on waterflooding development and remaining oil distribution. The results show that extending the injection-production distance and avoiding water injecting above the side with a deep dominant pathway is beneficial to enhance oil recovery. In a certain range, the swept area of injected water and displacement efficiency can be increased by appropriately increasing the injection rate. When the development depends on bottom water, the reserves between production wells cannot be effectively used. Based on the experiment results, five types of remaining oil distribution can be summarized: attic-type oil, blocked-type oil, retained-type oil, occluded-type oil, and shielded-type oil. There are multiple types of remaining oil in a fractured-vuggy system, so when tapping the remaining oil, it is necessary to comprehensively analyze the distribution and reserves scale to optimize the tapping scheme and maximize the recovery degree of the reservoir.

A novel triple-porosity model for fractured-vuggy reservoirs based on Maxwell-Garnett mixing rule

Under the new energy pattern, the petrophysical properties of carbonate reservoirs are still the research focus in the petroleum industry. Compared with conventional reservoirs, the calculation of water saturation is more complicated for carbonate reservoirs. One of the main challenges is that the accurate calculation of the porosity exponent of the reservoirs is influenced by the development of fractures and vugs. The existing triple-porosity model provides a way to calculate the porosity exponents; however, the existing model still has some problems: (1) The conduction theory adopted to establish the model varies from the actual conductivity process of the reservoir; (2) The model is deduced from the effective medium theory and regional empirical formula without considering the fracture shapes, thus it is not applicable for the carbonate reservoirs with fractures developed. Therefore, this paper proposed a novel triple-porosity model to calculate the porosity exponents by applying the Maxwell-Garnett mixing rule to the fractured-vuggy reservoir. This novel model can calculate the porosity exponents of reservoirs with the joint development of the vugs (non-connected vugs), fractures (fractures and connected vugs), and matrix pores. From the results of the novel model, the more developed the vugs, the greater the porosity exponents, and the more developed the fractures, the smaller the porosity exponent. Therefore, the porosity exponents of the reservoir can reflect the combined influence of the vugs, fractures and matrix pores. In order to effectively calculate the water saturation through this model, a method based on the binary processing of the Full-bore Formation Micro-Imager (FMI) logs was further proposed to calculate the vug porosity and fracture porosity. The field application demonstrated that the novel triple-porosity model can accurately calculate the water saturation of the fractured-vuggy reservoirs and provide guidance to the actual production.

Production Allocation Method in Numerical Simulation for Fractured Vuggy Reservoirs

Production Allocation Method in Numerical Simulation for Fractured Vuggy Reservoirs

Seismic Wave Field Anomaly Identification of Ultra-Deep Heterogeneous Fractured-Vuggy Reservoirs: A Case Study in Tarim Basin, China

Ultra-deep (7500–9000 m) Ordovician tight limestone heterogeneous fractured-vuggy reservoir is an important target of FuMan Oilfield in Tarim Basin. The strike-slip fault controlled reservoir is related to formation fracture and dissolution caused by geological stress. The seismic wave-field anomaly characteristics with different energy and irregular waveform are displayed in the seismic profile. Accurate identification of fractured-vuggy reservoirs wrapped in tight limestone is the direct scheme to improve production efficiency. Therefore, a new combination method flow of seismic wave-field anomaly recognition is proposed. In this process, the seismic data must be preprocessed initially, and on this basis, robust formation dip scanning is carried out. Secondly, the dip data is applied to the transverse smoothing filter to obtain the formation background data. Eventually, the seismic wave-field anomaly data is the residual between background data and original seismic data. This method has been applied in blocks with different structural characteristics and can effectively improve the resolution of strike-slip fault controlled reservoirs. Based on the results, the drilling success rate is increased to more than 95%, and the high-yield rate of oil tests is increased to 75% in 2021. Multiple applications indicate that the method is robust and can be popularized.

Internal Structure Characteristics and Formation Mechanism of Reverse Fault in the Carbonate Rock, A Case Study of Outcrops in Xike’er Area, Tarim Basin, Northwest China

China’s Paleozoic deep carbonate effective reservoirs, mainly non-porous reservoirs, are generally formed under the interaction of late diagenesis, hydrothermal fluids, and structural fractures. Faults and their deformation mechanism and internal structure of fault zones play an important role in the formation of carbonate reservoirs and hydrocarbon accumulation. Based on the detailed analysis of outcrop data in Xike’er area, Tarim Basin, this paper systematically studies the deformation mechanism and internal structure of reverse fault in the carbonate rock, and discusses the reservoir characteristics, control factors and development rules. The study shows that the deformation mechanism of the fault in carbonate rocks is faulting and fracturing, and the dual structure of fault core and damage zone is developed. The fault core is mainly composed of fault breccia, fault gouge and calcite zone, and a large number of fractures are formed in the damage zone, which are cemented by calcite locally. The mineral composition and rare earth element tests show that the fault core has the dual effect of hydrothermal fluids and atmospheric fresh water, which is easy to be cemented by calcite; while the damage zone is dominated by atmospheric fresh water, which is a favorable zone for the development of fracture-vuggy reservoirs. Therefore, the damage zone is the “sweet spot” area of carbonate oil and gas enrichment, and generally shows strip distribution along the fault.

Effect of rubber particles on water flow behavior in fractured-vuggy reservoirs

The presence of the large channel in fractured-vuggy reservoirs diminishes the sweep efficiency of any water, gas or polymer flooding. This paper presents a novel type of rubber particle for water shutoff agent and the flow direction of water is adjusted by plugging the large channel. Simultaneously, through the microscopic displacement experiment of the organic glass etching model, the water flow behavior and injection parameters optimization are studied. The results show that the resistance of solid media to fluid flow is almost zero when the oil-water two-phase flow occurs, and the gravity action is prominent. Therefore, there are still a lot of residual oil of karst cave, flow around oil and attic oil with poor connectivity after the fractured-vuggy reservoir is displaced by injected water. In addition, the rubber particles can form a temporary plugging zone by migration – accumulation – bridging under formation conditions, resulting in the flow direction of subsequent injection water changes from the large channel to the small channel, thereby reducing water content and increasing oil production. By optimizing the injection parameters of rubber particles, the optimal injection volume, particle size and injection speed are obtained, which are 0.02PV, 0–1 mm, 2–4 mm and 25 mL/min, respectively.

Numerical Simulation via CFD Methods of Nitrogen Flooding in Carbonate Fractured-Vuggy Reservoirs

A reservoir-scale numerical conceptual model was established according to the actual geological characteristics of a carbonate fractured-vuggy reservoir. Considering the difference in density and viscosity of fluids under reservoir conditions, CFD (computational fluid dynamic) porous medium model was applied to simulate the process of nitrogen displacement in a fractured-vuggy reservoir after water flooding. The effects of gas injection rate, injection mode, and injector–producer location relation were studied. The results show that nitrogen flooding can yield additional oil recovery of 7–15% after water flooding. Low-speed nitrogen injection is beneficial in obtaining higher oil recovery. High speed injection can expand the sweep area, but gas channeling occurs more easily. In gas–water mixed injection mode, there is fluid disturbance in the reservoir. The gas channeling is faster in low injector–high producer mode, while the high injector–low producer mode is beneficial for increasing the gas sweep range. Nevertheless, the increment of recovery is closely related to well pattern. After nitrogen flooding, there are still a lot of remaining oil distributed in the trap area of gas cap and bottom water in the reservoir that water and gas injection can’t sweep. The establishment of the numerical conceptual model compensates for the deficiency of physical simulation research, stating that only limited parameters can be simulated during experiments, and provides theoretical bases for nitrogen flooding in fractured-vuggy reservoir.

A New Model for Predicting Flow in Fractured-Vuggy Carbonate Reservoirs under Pseudosteady State Condition

For constant rate production of a single well in a closed boundary fractured-vuggy carbonate reservoir, when the pressure wave propagates to the reservoir boundaries, boundary-dominated flow occurs, and the transient flow period ends, the reservoir will be in a state of pseudoequilibrium (i.e., pseudosteady state flow occurs, and the pressure at any point in the reservoir declines at the same constant rate over time). The characterization of fluid flow in the fractured-vuggy carbonate reservoir under pseudosteady state condition is of significance in describing the productivity index (PI) of the well. However, due to complex mechanisms (e.g., stress dependency of reservoir properties and crossflow between different systems of the reservoirs) during flow in fractured-vuggy carbonate reservoirs, researches on productivity prediction in fractured-vuggy carbonate reservoirs under pseudosteady state are very limited. The present work is aimed at developing a new analytical model for predicting flow in fractured-vuggy carbonate reservoirs under pseudosteady state condition. In the derived model, the crossflow between different systems (i.e., matrix, fracture, and vug) of the reservoirs was taken into account. In addition, based on Hooke’s law, a quantitative model was proposed to study stress-dependent permeability of the fracture system, which connects the reserve spaces. Moreover, the roughness morphology characteristics of fracture surface were taken into account with fractal theory. Finally, with our derived model, influences caused by various related factors on productivity were analyzed. The results show that well productivity during pseudosteady flow will be significantly affected by the morphology of fracture surface (e.g., fracture microstructure parameters) and effective stress. Specifically, due to effective stress, the fracture system in the fractured-vuggy reservoirs will be deformed, and the corresponding properties (e.g., permeability, porosity, and conductivity) will change, leading to the change of well productivity. In addition, there exists a negative relationship between the elastic storage capacity ratio of vugs and well productivity during pseudosteady flow. Moreover, a larger value of matrix-fracture interporosity flow coefficient or vug-fracture interporosity flow coefficient corresponds to a larger value of well productivity during the pseudosteady period. The new derived model is beneficial to improve the productivity prediction accuracy and reduce uncertainty. What is more, the findings of this study can help for providing theoretical reference for the design of efficient development of fractured-vuggy carbonate reservoirs.

Breakthrough of natural gas exploration in the beach facies porous dolomite reservoir of Middle Permian Maokou Formation in the Sichuan Basin and its implications: A case study of the tridimensional exploration of Well JT1 in the central-northern Sichuan Basin

The neritic carbonate reservoir of Middle Permian Maokou Formation in the Sichuan Basin has been always treated as a fractured and fractured-vuggy reservoir. After realizing the breakthrough of natural gas exploration in the Lower Cambrian Canglangpu Formation in the Taihe gas bearing area of central-northern Sichuan Basin, Well JT1, a wildcat well, recently discovers a beach facies porous dolomite reservoir in the Maokou Formation above the Canglangpu Formation, and the high-yield industrial gas flow of 112.8 × 104 m3/d is obtained during the test. And thus, Well JT1 achieves the breakthrough of tridimensional natural gas exploration in multiple gas bearing series of strata in the vertical direction and realizes the new discovery of reservoir type in the Maokou Formation. In order to further clarify the characteristics and control factors of the beach facies porous dolomite reservoir of Maokou Formation in the Taihe gas bearing area, this paper studied its sedimentary evolution, high-energy beach facies characteristics, reservoir characteristics and following natural gas exploration direction. And the following research results were obtained. First, along the syneclise margin of central-northern Sichuan Basin develops a beach facies porous reservoir of the second Member of Maokou Formation, whose lithology is dominated by residual dolarenite and calcsparite calcarenite and reservoir space is mainly acted by intergranular pores and intercrystalline pores, with the average porosity of 4.9%. Second, in the middle and late stage of Maokou period, Guangyuan-Bazhong paleo faulted depression was developed in the northern Sichuan Basin and intraplatform low was developed in the central-northern Sichuan Basin. In the central and the northern Sichuan Basin, the high-energy beach of Maokou Formation is distributed around the faulted depression and the syneclise margin in a large scale, and the paleogeographic pattern of “one-margin and three-high belt” is presented. Third, under the control of high-energy beach facies, the Maokou Formation porous reservoir in the central-northern Sichuan Basin is distributed along the “one-margin and three-high belt” in a large scale. The high-energy beach facies of “one-margin and three-high belt” covers the area of 6500 km2. In this area, multiple sets of source rocks (Cambrian, Silurian and Permian) are developed vertically, hydrocarbon source fault is developed and carrier system is good, which is favorable for the large-scale hydrocarbon enrichment and accumulation. In conclusion, there are geological conditions for the development of facies controlled porous reservoir in the Maokou Formation of the Sichuan Basin, and the “one-margin and three-high belt” is the favorable area for the exploration of beach facies porous dolomite reservoir. The research results point out the new exploration field and direction for the large-scale increase of natural gas reserves in the Sichuan Basin.

Analysis of Interwell Connectivity of Tracer Monitoring in Carbonate Fracture-Vuggy Reservoir: Taking T-Well Group of Tahe Oilfield as an Example

Carbonate fracture-vuggy reservoirs are one of the hot spots in oil and gas exploration and development. However, it is extremely difficult to describe the internal spatial structure of the fracture-vuggy unit and understand the interwell connection relationship. As a method to measure reservoir characteristics and feedback reservoir production information directly according to the detected concentration curve, interwell tracer technology provides a direct measure for people to understand the law of oil-water movement and reservoir heterogeneity and is widely used in various domestic oil fields. Based on the flow law of tracer and the CFD flow simulation basic model, this paper establishes the physical conceptual model and studies the influence of three physical parameters (the flow velocity of the fluid passing through the connected channel, diameter of the connected channel, and length of the connected channel) on the concentration curve at the outlet. In addition, the influence of different interwell connection modes on tracer concentration was studied and classified scientifically. According to the simulation, the tracer concentration curve can be classified into three types: unimodal curve, bimodal curve, and multimodal curve. Finally, the injection-production well group in the T-well area of the Tahe Oilfield is taken as an example, the connection mode between injection and production wells in this well area is further discussed and has been verified, which can be used as a reference for the connectivity analysis of similar carbonate reservoirs.

Single Well Productivity Prediction Model for Fracture-Vuggy Reservoir Based on Selected Seismic Attributes

Single well productivity is an important index of oilfield production planning and economic evaluation. Due to fracture-vuggy reservoirs being characteristically strongly heterogeneous and having complex fluid distribution, the commonly used single well productivity prediction methods for fracture-vuggy reservoirs have many problems, such as difficulty in obtaining reservoir parameters and producing large errors in the forecast values of single well productivity. In this paper, based on the triple medium model, the Laplace transform and Duhamel principle are used to obtain the productivity equation of a single well in a fracture-vuggy reservoir. Secondly, the seismic attributes affecting the productivity of a single well are selected using the Spearman and Pearson correlation index calculation method. Finally, the selected seismic attributes are introduced into the productivity equation of the triple medium model through the interporosity flow coefficient and the elastic storativity ratio, and the undetermined coefficients under different karst backgrounds are determined using multiple nonlinear regression. From these, a new method for predicting single well productivity of fracture-vuggy reservoir is established. In order to verify the feasibility of the new method, based on the actual production data of a fracture-vuggy reservoir in Xinjiang, the new single well productivity prediction method is used to predict the productivity of 134 oil wells. The results show that the new productivity prediction method not only reduces calculation workload, but also improves the accuracy of productivity prediction, which contributes to a good foundation for future oilfield development.

A triple-porosity radial composite model for two-phase well test analysis of volatile oil in fractured-vuggy reservoirs

In this study, by employing a novel analytical model for well test analysis, characterization is performed for a fractured-vuggy reservoir containing volatile oil with flowing wellbore pressure below the bubble-point pressure. Well test analysis in such medium is challenging due to complications in reservoir geology and fluid behavior. Rock complications arise because of existence of three media which interact with one another due to different flow behavior. Fluid related challenges are caused by gas liberation and two phase flow near the well bore. To perform the analysis, a synthetic model was investigated and pressure data were generated. Pressure data in such reservoir exhibited a radial composite behavior. Subsequently, a triple porosity radial composite model was developed for analysis and parameter estimations in such reservoirs. It is shown that reservoir parameters could be predicted with acceptable accuracy using the proposed model. The estimated effective permeabilities in all cases were close to the actual value, with absolute relative error less than 0.1. However the obtained interporosity flow parameters were slightly different from single phase parameters due to the presence of gas bank near the wellbore.

Study on the channel flow control mechanism of an equidensity particle agent in fractured-vuggy carbonate reservoirs

ABSTRACT To define the channel flow control (CFC) mechanism of the equidensity particle agent, the effect of CFC treatment in fractured-vuggy carbonate reservoirs was systematically analyzed by visual simulation experiments and field tests. The typical visual experimental model of the fractured-vuggy reservoir was designed based on the fractured-vuggy reservoir outcrop characteristics. It overcomes the shortcomings of the conventional model, whose experimental results are greatly affected by subjective factors. The water breakthrough in the dominant flow channel caused substantial shielded remaining oil to be left in the reservoir, resulting in violent flooding of the oil well. The shielded remaining oil accounted for approximately 43.8% of reserves, which is the potential point of the CFC treatment. The CFC treatment can effectively enhance the shielded remaining oil recovery by 22.2% in laboratory experiments. Based on its own efficient suspension and migration ability, the equidensity particle agent can be transferred to the whole dominant flow channel in the fractured-vuggy carbonate reservoirs. By using the multistage distributed shrinkage joint at the outlet of each vuggy and inside of each fracture to control the flow capacity, the equidensity particle agent can equably control the dominant flow channel along the path to realize a wide range of water flooding in the fractured-vuggy carbonate reservoirs.

Evaluation of fractured–vuggy reservoir by electrical imaging logging based on a de-noising method

The existence of fractures and vugs in igneous formation is a key factor to determine the productivity of oil and gas reservoirs. Fracture–vug plane porosity and porosity spectrum (fracture–vug parameters) are important parameters to evaluate the development of fractures and vugs. In the process of drilling, the bit forms shallow holes and scratches on the borehole wall which is characterized by pitting, strip and block noise in the electrical imaging logging static image. The background noise affects the identification of fractures and vugs and the extraction of parameters. It is found that the background noise mainly exists in the high-frequency conductivity data. In order to suppress the background noise, empirical mode decomposition is applied to conductivity data of electrical imaging logging, and the wavelet hard threshold de-noising is applied to high-frequency intrinsic mode function components. The de-noising fracture–vug parameters have a good correspondence with the electrical imaging logging static image, and have a better linear relationship with the core porosity. These illustrate that the application of the de-noising method in the electrical imaging logging is reasonable and effective. The de-noising porosity spectrum becomes narrower in the reservoir with poor fractures and vugs, which can reveal the development of secondary pores more clearly. In reservoir interpretation, the de-noising fracture–vug plane porosity and porosity spectrum have good consistency with conventional and acoustic logging data, which can effectively evaluate the fractures and vugs in reservoirs.

Acid Fracturing Optimizing Design and Application in Deep Naturally Fractured Carbonate

More than 30% of carbonate reservoirs in the Tarim oilfield and XiNan oil-gas field are naturally fractured-vuggy reservoirs, of which the production is high in most cases and economic returns can be achieved within a short period of time. Acid fracturing is one of the key technology for development of such naturally fractured-vuggy reservoirs. Mud overflow and loss may be emerged at the same time while drilling fractured-vugular carbonate, once it happened, the well control will become complicated. So, the wellbore is drilled a certain distance up or transversal to these huge caves or natural fractures, and acid fracturing will be executed to connected the reservoirs to obtain the hydrocarbon in the reservoir. Acid-fracturing design of fractured-vugular carbonate is based on the relationship between the wellbore and fractured-vugular reservoirs. The acid fracturing design in naturally fractured-vuggy carbonate reservoir is different from the conventional one, it should be optimized based on the spatial positions of the fracture-vuggy body identified via geophysical prospecting, the wellbore and the distance between the two. In the case that the wellbore precisely reaches the top of the fracture-vuggy body, good oil and gas show or overflow is frequently happened. At this moment, drilling ceases and the wellbore are cemented and completed. The small-scale acid fracturing treatment is then carried out, and connectivity between etched fractures and the top of the fracture-vuggy body will lead to high hydrocarbon production. If a certain distance exists between the wellbore and fracture-vuggy reservoirs, 3D seismic imaging will be adopted to calculate the vertical distance between the center of the storage body and the wellbore, which is then used to optimize the injected fluid volume, pump rate and acid fracturing techniques. To create connectivity with the fracture-vuggy storage body relatively far away from the wellbore, acid fracturing involving preflush or multi-stage injection is used. Pressure drops by several ∼ several tens of MPa usually occur as the artificial fracture propagates into the fracture-vuggy body. After fracturing penetrating into the fracture-vuggy body, acid injection starts. During the early acid injection, the pump rate is raised up for longer etched length inside the fracture. It is then lowered during the late acid injection to improve the conductivity of etched fractures. If multiple fracture-vuggy bodies exist near the wellbore, the temporary diverting acid-fracturing will be treated, optimized with respect to the distance between the wellbore and different fracture-vuggy storage bodies, spatial relationship between the maximum principal stress direction and fracture-vuggy storage body and the trend of natural fractures, will be implemented to communicate with multiple naturally fractured vuggy reservoirs. This acid fracturing integrating geophysical prospecting and wellbore trajectory has been applied in hundreds of wells in the Tarim oilfield. Moreover, the success rate of such acid fracturing treatments is increasing with the advancement in the characterization of the fracture-vuggy reservoirs.

Measurement of CO2 diffusion coefficients in both bulk liquids and carven filling porous media of fractured-vuggy carbonate reservoirs at 50 MPa and 393 K.

Diffusion coefficients are necessary to describe the mass transfer and adsorption rate of CO2 in formation fluids. However, data is scarcely reported for actual reservoir conditions of high pressure and temperature, which are normal in most scenarios of the CO2-enhanced oil recovery process in China's fractured-vuggy reservoirs and carbon storage process. Accordingly, this work employed the pressure decay method (PD) and relevant mathematical models to determine the CO2 diffusion coefficient in both liquids and cavern filling porous media at 50 MPa and 393 K. The effects of the type of reservoir fluids, the properties of carven filling porous media, and water saturation on CO2 diffusion coefficients were investigated. Results in bulk reservoir liquids showed that the CO2 diffusion coefficient in the oil sample was 4.1243 × 10−8 m2 s−1, much higher than those in the pure alkane phase, pure water and brine sample from reservoirs. Results of CO2 diffusion in carven filling porous media saturated with oil demonstrated a significant dependence on properties such as porosity and permeability, and a correlation in the CO2 diffusion coefficients between the bulk oil phase and cavern filling porous media in the form of touristy was documented. CO2 diffusion in the fractured cavern porous media was much higher than that without fracture. An increase in water saturation reduced CO2 diffusion coefficients in the carven filling porous medium studied, herein. Thus, the CO2 diffusion coefficient is essentially related to the type of liquid and properties of the filling media.

Workflow of Fracture Prediction Using Curvature-Related Attributes and a Case Study

Fracture is a kind of important reservoir in petroleum exploration, which usually exist in the carbonate rock or igneous rock. However, it is always difficult to predict the fracture with the seismic data. In this paper, based on curvature attributes, we develop a workflow for the prediction of fractured zone, fracture orientation, and open fractures. We begin with curvature calculation to predict fractured reservoirs and then calculate rose diagrams using curvature data. Fracture orientation is established by comparing the rose diagrams from imaging logs and the analogues from curvature data. We identify two principal orientations and calculate the azimuth intensity in these two directions using the curvature data. As per the crossplots of azimuth intensity in two directions and productivity, the azimuth with good correlation is the open azimuth of fractures. We apply this method to a Kazakhstan oilfield K and predict fractured-vuggy reservoirs in the eastern field and fractured reservoirs in the western field. In accordance with the prediction, there are two groups of fractures, one in a northeast direction and the other in a northwest direction. NE fractures are open in the northern field, and NW fractures are open in the southern field. We suggest two sites for well drilling, which obtain economic oil flow.

Study on the stability and rheological properties of nitrogen foam under high-pressure condition

After a period of exploitation of carbonate fractured-vuggy reservoir, the water content of oil well keeps increasing, and some wells appear violent water flooding in a short period of time, which leads to the rapid decrease of production. The injection of particle plugging agent is one of the main measures to improve the oil recovery. Foam fluid has the characteristics of low density, high viscosity and low moisture filtration, which can effectively carry plugging particles to the target plugging layers. A stable foam system with high temperature and salinity is optimized and the rheological properties of the foam are studied in this research. The results show that the foam can maintain high viscosity and carry particles effectively even at a higher shear rate.

Numerical Simulation and Experimental Studies of Karst Caves Collapse Mechanism in Fractured-Vuggy Reservoirs

Karst cave collapse usually occurs during the process of drilling and reservoir development. Karst cave collapse increases drilling risk and seriously affects oil production. In order to reveal the collapse mechanism of karst caves in fractured-vuggy reservoirs in Tahe oil field, rock mechanic experiments and numerical simulation studies were conducted. In rock mechanic experiments, three types of rock mechanics tests (uniaxial compression, triaxial compression, and Brazilian splitting) were carried out to obtain the basic rock mechanics parameters. In numerical simulation studies, the collapse conditions of a single karst cave and a cave system were studied. Numerical simulation results indicate that for a single karst cave, the size and geometrical features of karst caves are the main factors influencing collapse condition. For a cave system, a combination pattern and distance between caves are two main factors affecting collapse condition. In order to facilitate the application of these research results, the authors present formulas for calculating the critical conditions of karst cave collapse by means of multivariate linear regression method. The calculation formulas and prediction chart were verified as consistent with actual field results. The research results in this paper have great theoretical and practical value for revealing the mechanism of karst cave collapse in fractured-vuggy carbonate reservoirs.