Reservoir Fluid Research Articles

Study Explores Design, Potential of Electric Submersible Generators

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214361, “Electric Submersible Generators: Using ESPs in an Unfamiliar Way,” by Charles E. Collins, Kenneth J. Frazier, and Bryan Coates, SPE, Baker Hughes. The paper has not been peer reviewed. _ The electrical submersible generator (ESG) is a modern interpretation of an old idea. The ESG can generate electricity to meet surface power needs or feed directly into the grid to create a revenue stream under the proper injection conditions. In typical configurations, a standard centrifugal pump is used in combination with an induction motor operated in such a way for the mechanical work of the pump to be converted into electrical energy. The complete paper explores ESG design considerations, theoretical underpinnings, and potential applications. What Is an ESG? A generic geothermal power plant typically consists of production wells that can be either artesian or artificially lifted. The heated well fluid will transfer the heat to a working fluid that rotates turbines to generate electricity. The reservoir fluid eventually will be reinjected into the formation to be warmed again and reproduced. It is common to use conventional electrical submersible pump (ESP) equipment to produce the fluids from the formation. The ESG concept focuses on injection wells from these power plants. Instead of drawing power from a source and moving fluid to the surface, the ESG takes injected fluid from the surface and creates power that can be used to offset surface power requirements onsite or sold directly back to the grid to generate revenue. The components of the ESG are very similar to those of an ESP, with an intake, discharge, seal, and cable attached to the motor. However, many of the components act essentially in reverse. The motor becomes a generator as it is driven by the pump acting as a turbine. The conventional ESP discharge becomes the intake, and the intake becomes the discharge. The cable still transmits the energy from the motor to the surface and vice versa. The seal section isolates the generator from the well fluid, handles thrust from the turbine, and equalizes the external pressure of the well with the internal pressure of the system. The generator effectively acts as a brake for the turbine. While most ESP stages are not typically designed to operate as a turbine, many will still maintain a system efficiency expected of ESPs. Application Guidelines As with conventional ESP systems, proper application of this equipment ensures desired run life and optimal electrical generation. General steps of equipment selection include the following: - Collect basic wellbore information - Verify flow rate, temperature, and pressure of injected fluid - Size the turbine accordingly based on the expected flow rate and pressure - Determine the size of the generator based on the load from the turbine and the expected heat rise

Pb-Zn mineralization formed from coupled hydrocarbon-bearing and hydrothermal fluids in the Ediacaran strata in the central Sichuan Basin, China

Hydrocarbon-bearing fluid plays a crucial role in the Pb-Zn mineralization process. The hydrocarbon role is still the subject of metallogenic research. This study determined the metal and sulfur sources and the hydrocarbon role in the mineralization instigated by mixing of hydrothermal and hydrocarbon-bearing fluids in the central Sichuan Basin based on petrography, fluid inclusion geochemistry, S and Pb isotope compositions, and changes in hydrocarbon phases and components. The results indicated that hydrothermal input significantly improved the salinity and temperature of reservoir fluids. Hydrothermal stages can be divided into three: (Ⅰ) pyrite and dolomite, (Ⅱ) quartz and sphalerite, and (Ⅲ) galena. Solid bitumen was formed at stage Ⅱ, and the oil inclusions were converted into gas inclusions from stage Ⅰ to Ⅱ, suggesting that the hydrothermal fluids caused the oil cracking. The Pb isotope compositions of pyrite, sphalerite, and galena showed that the Pb-Zn deposit had two metal sources from surface karst and hydrothermal fluids. Raman spectroscopy and sulfur isotope compositions implied that H2S formed during hydrothermal input was generated from TSR resulting from hydrothermal sulfate. The H2S produced by TSR preferentially led to the precipitation of metals (Pb, Zn, and Fe) derived from the hydrothermal fluid, followed by the precipitation of metals derived from the karst fluid. After the metal elements in the reservoir were depleted, the remaining H2S was conserved together with the natural gas in the reservoir. This study unravels the transformation of oil to gas and the H2S generation in the reservoir through hydrocarbon inclusion analysis in the metallogenic study, providing new insight into the Pb-Zn mineralization involving hydrocarbon-bearing fluid participation.

Optimal selection of sand filters for production wells on the basis of laboratory and experimental studies

The relevance of the study is due to the need to ensure the flow of more purified reservoir fluid into the bottomhole zone of the well. When opening a formation with production wells, the design of which includes anti-sand filters, there are some imperfections that are characterized by the degree and nature of its opening and are due to the designs of casing filters. For a rational choice of an anti-sand filter in a well, it is necessary to conduct experimental bench studies, taking into account well conditions. To accomplish this task, a stand was created that allows you to: determine the amount of fluid passing through with sand; the volume and granulometric state of the sands that pass through the filters when filtering the mixed liquid; state and change in the structure of rocks in the bottomhole zone of the well; dependence of the distance between the filter elements and the production casing on the performance of the sand filter. The main component of the stand is a combined-shaped filtration tray imitating a circular reservoir model. Based on the results of experimental studies, optimal designs of anti-sand filters are proposed. To select, it is necessary to take into account the hydraulic parameters of its operation, which can be determined based on the bench tests of two types of filter elements: block and frame-rod with wire winding, both in open hole and cased hole conditions, as the most promising in terms of application. Keywords: filtration; liquid; bottomhole; zone; well; anti-sand filter.

Применение технологии объединения методов разведочных работ для достижения экологического эффекта на месторождениях Каспия

The method of performing exploration works allowing to obtain an environmental effect in the Caspian Sea fields is described in the article. The research area includes the Rakushechno-Latitudinal and Khvalynsko-Sarmatian zones. Deposits of these zones differ in a complex geological structure. When creating a model of deposits a set of data is used: high-precision 3D seismic surveys on the study area and the results of drilling wells. Such detail of seismic exploration works allows to obtain high-quality results that are due to the high density of reflection points over the area and to the maximum use of various dynamic parameters of reflected waves. The results of such surveys are used in the calculation of reserves, justification of work on additional exploration and subsequent operation. Based on the results of seismic surveys a quantitative forecast of reservoir properties was carried out due to the inversion. For implementation seismic data was processed while preserving the true amplitudes of the seismic signal. Drilling wells were also the main source of information when performing work on calculating reserves. The complex structure and heterogeneity conditions of reservoir properties in area and section, the presence of discontinuous violations led to the use of the described technology, which involves the assessment of reserves and their transfer to the industrial category without testing in the column and causing inflow to the surface. This is done by means of a comprehensive accelerated diagnostics of productive formations for the assessment of reserves of the industrial category. Such a diagnosis provides for the study of productive formations based on the analysis and generalization of accumulated material on core, GIS, GDIS, GDK-OPK and PVT studies, without conducting tests in wells. With the help of these studies the filtration-capacitance properties of rocks, the nature of fluid saturation, contact positions, static levels, reservoir and bottom-hole pressures and reservoir temperatures, as well as deep sampling are determined. The use of modern instruments such as MDT (reservoir Tester) makes it possible to obtain reliable deep samples of the reservoir fluid. The results of data interpretation are successfully approved when making reports on UVS reserves calculation.

Correlations between Petroleum Reservoir Fluid Properties and Amount of Evolved and Dissolved Natural Gas: Case Study of Transgressive–Regressive-Sequence Sedimentary Rocks

It is well recognized that PVT data are essential in oil and gas production facilities as well as in the determination of the reservoir fluid composition in reservoir engineering calculations. In the current work, the studied borehole is located in Tawke oilfield in the High Folded Zone. The structural geology and lithological facies of rocks are studied and found to comprise fine crystalline dolomite and anhydrite interbedded with claystone and dolomite. In addition, the practical PVT data of black oil from Tawke oilfield, Zakho, from reservoirs to transgressive–regressive cycles, are studied. The PVT data are investigated to derive the empirical models that rule and correlate the properties of the reservoir fluids in terms of the amount of natural gas (methane, ethane, and propane) dissolved in reservoir fluids and evolving from the wells. The characteristics of the reservoir fluid, including °API, viscosity at reservoir pressure and bubble-point pressure, reservoir pressure and temperature, gas–oil ratio (GOR), coefficient of compressibility at reservoir pressure, gross heating value, and sample depth, are correlated. The lithological part reveals that the carbonate and some clastic rock facies are conducive to enhancing natural gas adsorption. The reservoir fluid properties show adverse effects on the amount of natural gas constituents evolving from the wells, while it shows positive effects on the dissolved reservoir fluids. The estimated empirical correlations can help indicate the quantity of natural gas that is dissolved in reservoir fluids and liberated from the wells depending on the characteristics of the reservoir. In addition, they can be used in numerical simulators to predict oil well performance.

Study of pore-throat structure characteristics and fluid mobility of Chang 7 tight sandstone reservoir in Jiyuan area, Ordos Basin

Abstract Quantitative studies of the pore-throat structure (PTS) characteristics of tight sandstone reservoirs and their effects on fluid mobility were proposed to accurately evaluate reservoir quality and predict sweet spots for tight oil exploration. This study conducted high-pressure mercury injection (HPMI) and nuclear magnetic resonance (NMR) experiments on 14 tight sandstone samples from the Chang 7 member of the Yanchang Formation in the Jiyuan area of the Ordos Basin. The HPMI was combined with the piecewise fitting method to transform the NMR movable fluid transverse relaxation time (T 2) spectrum and quantitatively characterize the PTS characteristics and the full pore-throat size distribution (PSD). Then, movable fluid effective porosity (MFEP) was proposed to quantitatively evaluate the fluid mobility of tight sandstone reservoirs and systematically elucidate its main controlling factors. The results showed that the PTS could be divided into four types (I, II, III, and IV), which showed gradual decreases in average pore-throat radius (R a), continuous increases in the total fractal dimension (D t), and successive deterioration of reservoir fluid mobility and percolation capacity. Moreover, the full PSD (0.001–10 μm) showed unimodal and multi-fractal characteristics. According to the Swanson parameter (r apex), the reservoir space types can be divided into small and large pore-throat and the corresponding fractal dimension has a relationship where D 1 < D 2. Large pore-throat had higher permeability contribution and pore-throat heterogeneity but a lower development degree and MFEP than small pore-throat, which had a relatively uniform and regular PSD and represented the primary location of movable fluids. Moreover, the development degree and heterogeneity of small pore throat controlled the flowability of reservoir fluids. MFEP can overcome the constraints of tiny throats and clay minerals on movable fluid, quantify the movable fluid content occupying the effective reservoir space, and accurately evaluate the reservoir fluid mobility. The combination and development of various pore-throat sizes and types in tight sandstone reservoirs results in different PTS characteristics, whereas differences in the mineral composition and content of reservoirs aggravate PTS heterogeneity, which is the main factor controlling the fluid mobility.

Characterization and Performance Evaluation of Modified Apatite Ore as a New Acid-Soluble Weighting Agent for Drilling Fluids

Summary Drilling in oil and gas reservoir formations requires the solid weighting agent used in drilling fluids to have good acid solubility to facilitate plugging removal in subsequent operations. Limestone is the most commonly used acid-soluble weighting agent, but its low density and significant thickening effect lead to a low weighting limit. To achieve control of drilling fluid density, rheology, sag stability, and acid solubility, the feasibility of using apatite (AP) ore as an acid-soluble weighting agent for drilling fluids has been discussed after it was modified by the nitrogen-containing organic polybasic phosphonic acid sodium salt. The basic characteristics of AP and modified AP (MAP) were analyzed. After that, the rheological, filtration, and sag stability properties of MAP-weighted water-based drilling fluids with densities of 1.2 g/cm3 and 1.6 g/cm3 were evaluated, and acid solubility, filter-cake permeability, core permeability damage, and plugging removal tests by acid solutions were performed to evaluate the formation protection effect. The results show that the density of AP is 2.98 g/cm3, and the main component is hydroxyapatite. Its negative electricity and hydrophilicity were enhanced after surface modification, so its dispersion stability in water was enhanced, thereby improving the rheology, filtration, and sag stability properties of the MAP-weighted drilling fluid. The solubility of MAP in 10% HCl solution reached 90.13%, and the core contamination experiments show that after being soaked in HCl solution, the return permeability of contaminated cores reached higher than 90%, indicating that the MAP invading the core can be efficiently dissolved and removed in the acidic working fluids used in the subsequent completion and stimulation operations, thus effectively protecting the reservoir formation. The properties of MAP are superior to those of limestone, and it can be used as a new acid-soluble weighting agent for drilling fluids, considering both drilling fluid performance regulation and reservoir formation protection.

Fluid Identification Using XGBoost Combined with MAHAKIL in Low-Permeability Reservoirs

Summary Low-resistance reservoirs have been of great interest as a key topic in the study of low-permeability reservoirs. Accurate identification of fluid properties is a challenging problem in the effective exploration of such reservoirs. Logging data, as a common identification tool, can provide rich and highly accurate geological information. Here, we combine extreme gradient boosting (XGBoost) and MAHAKIL’s oversampling method for fluid property identification using logging data from low-permeability sandstone reservoirs. The MAHAKIL method is used to solve the class imbalance problem due to unbalanced training samples, and the data are fed into XGBoost to build a geological model with complex abstract feature weights related to fluid properties through multiple decision trees. We first demonstrate that MAHAKIL can improve the XGBoost model accuracy using four evaluation criteria, namely, the F1-score, recall, precision, and accuracy, among which the F1-score is most applicable to the classification problem of reservoir fluid prediction. Then, the receiver operating characteristic (ROC) and area under the curve (AUC) values are used to demonstrate that MAHAKIL improves the XGBoost model performance. Finally, the results and performance of this method and the traditional XGBoost model with unbalanced real data are compared. The results show that the proposed method is superior for fluid property identification in low-permeability sandstone reservoirs with imbalanced learning samples.

A Continuous Projection-Based EDFM Model for Flow in Fractured Reservoirs

Summary Various researchers have evaluated different methods of modeling fractured reservoirs accurately and efficiently. Of these methods, the embedded discrete fracture model (EDFM) is one of the most popular because it does not require the mesh for the simulation domain to conform to the orientation of the natural fractures. However, it is limited because it cannot accurately model low-conductivity fractures. Although the projection-based EDFM (pEDFM) was developed to address this limitation of the EDFM, recent studies show that pEDFM still cannot accurately model low-conductivity fractures that are neither parallel to the simulation grid nor cutting through the matrix cell diagonals. In these cases, it has been observed that reservoir fluids can flow around low- or even zero-conductivity fractures. This paper presents a rigorous analysis, which reveals that the error when modeling inclined low-conductivity fractures with pEDFM is because the projections of the fracture on the gridblock faces are discontinuous. This discontinuity implies that the matrix cell interfaces along the path of the fractures only project a fraction of the fracture area on these interfaces in each direction. So, none of these faces captures the sealing potential of these interfaces, and the pore fluid can flow around even zero-conductivity fractures. We present a robust algorithm that ensures that the projections of inclined fractures on cell faces are continuous in 3D. We refer to the model based on this algorithm as the continuous projection-based EDFM (CPEDFM) and show that it directly solves the pEDFM limitation. We present the simulation of several cases and their selected projection faces to demonstrate why CPEDFM works. We also verify the CPEDFM method by comparing the CPEDFM and pEDFM model results to high-resolution simulation results. To demonstrate the feasibility of modeling complex, realistic systems using CPEDFM, we simulate a 3D compositional Eagle Ford shale reservoir with 75 low-conductivity and 75 high-conductivity fractures. The results show that pEDFM overestimates production because it does not fully account for the sealing effects of inclined low-conductivity fractures. In conclusion, this paper presents a novel numerical model for accurately and efficiently simulating reservoirs containing fractures of arbitrary conductivity, size, and orientation in 3D.

One Approach to Numerical Modeling of the Heat and Mass Transfers of Two-Phase Fluids in Fractured-Porous Reservoirs

The work is devoted to numerical modeling of the processes of heat and mass transfer of a two-phase fluid in the environment of a production well, which is necessary for monitoring the development of fractured-porous reservoirs. This work proposes an efficient approach to constructing a solution to the problem. To solve the problem, a model of the “double medium” type is used, where the pore part of the reservoir is considered as the first medium, and the system of natural fractures is considered as the second medium. For the resulting mathematical model, the difference schemes with time weights are constructed based on the algorithm of splitting by physical processes, which ensure the correctness and consistency of fluxes in the fracture system and the pore reservoir. In the numerical solution, the approximations of differential operators obtained in the framework of the finite difference method are used. For the parallel implementation of the developed numerical approach, the domain decomposition method and the matrix sweep algorithm are chosen. The program implementation is made using the MPI standard. Computational experiments are carried out, the results of which confirm the effectiveness of the developed numerical algorithm and its parallel implementation. In numerical experiments, the distributions of pressure and temperature near an operating production well are obtained, on the basis of which it is possible to adjust the operation of wells in order to increase production.

Supervised machine learning for discriminating fluid saturation and presence in subsurface reservoirs

This paper describes a workflow that combines machine learning and frequency-related multi-attribute analyses to predict the occurrence of water, oil, and high or low gas saturations in three Miocene Gulf of Mexico clastic reservoirs, the Ursa, King Kong and Lisa Anne fields. The models are trained on labeled data from the Ursa Field dataset and validation is conducted on the King Kong and Lisa Anne Field datasets, comprising four wells with oil and varying gas saturations. We also analyze the impact of fluid-type and saturation on a suite of frequency-related attributes, including independent frequency magnitudes and spectral shape attributes.We also assess feature significance using SHAP Analysis and our results indicate that that high gas saturation is characterized by high magnitudes of low frequencies, increased bandwidth, and lower skewness and kurtosis values. Conversely, low gas saturation is distinguished by high magnitudes of medium frequencies, reduced bandwidth, and higher skewness and kurtosis values.Our workflow demonstrates the power and utility of supervised machine learning for reservoir fluid identification and saturation prediction. Human interpreters relying solely on post-stack seismic data may find the task of reservoir fluid predictions challenging and the results may be compromised by subjectivity. This study underscores the potential of machine learning to improve hydrocarbon exploration and production, providing a more robust approach to prospect risk assessment using post-stack seismic data and frequency attributes.

Mechanistic investigation of using low salinity alkaline surfactant solutions in carbonate reservoirs based on polarity of crude oil

The chemical enhanced oil recovery (CEOR) process is introduced as one of the most effective methods for reducing the residual oil saturation through oil reservoirs. Because the chemical phase has a great potential for altering the reservoir rock and fluids properties. The main purpose of this study is a combination of low saline water (LSW) with surfactant and alkaline-surfactant to achieve maximum oil recovery by the combination of different mechanisms. In this work, the fluid–fluid and rock-fluid interactions were investigated by conducting several experimental techniques for two varied crude oil samples. Due to the high polarity of resin and asphaltene molecules, these two crude oil samples were divided into low-polar and high-polar samples. The optimum diluted seawater was used as LSW for both crude oil samples at 3000 ppm total dissolved solids. Based on obtained results from the interfacial tension (IFT) measurement tests and dynamic contact angle, using NaOH with LSW and AOS at critical micelle concentration (CMC) has a greater influence on reducing the IFT and altering the carbonate rock wettability from oil-wet to water-wet condition compared to Na2CO3. Adding only 100 ppm NaOH to the LSW-AOS(CMC) solution, the IFT values between an alkali-surfactant solution with low-polar and high polar crude samples were decreased from 0.43 and 1.33 mN/m to 0.21 and 0.55 mN/m, respectively. Moreover, the pH of LSW-AOS solution rises with the addition of NaOH to the solution and the surface charge moves toward a more negative charge based on the zeta potential results. This phenomenon increases the repulsion between surface charge and negatively charged polar components and, consequently desorption of polar components from the rock surface get improved. Furthermore, some in-situ surfactant (soap) generates by a reaction between NaOH and carboxylic acids and the creation of an ion pair between surfactants (AOS and Soap) and adsorbed polar groups which lead to the creation of a hybrid mechanism between LSW, AOS, and NaOH for changing the wettability from oil-wetness toward water-wetness. Therefore, the maximum oil recovery was achieved by flooding with LSW- AOS(1000 ppm)-NaOH (100 ppm) solution for both crude oil samples, high polar and low polar cured oil samples, that obtain 42.24 % and 71.67% recovery factors, respectively. Moreover, coreflooding results confirmed the micromodel results in the presence of initial water saturation at high temperature condition.

DEVELOPMENT OF ZEOLITE-CONTAINING LAYERS IN WESTERN SIBERIA DEPOSITS

Often, during the development of wells that have come out of drilling, these wells do not reach the design operating modes, since when the aqueous filtrate of the drilling fluid penetrates into the bottomhole formation zone (BFZ) and comes into direct contact with clay minerals, the pores narrow, the formation of insoluble sediments and creates insurmountable barriers. for the movement of reservoir fluids in the reservoir to the perforation interval, resulting in a decrease in the productivity of production wells. If the clayey cement of the reservoir rock contains zeolite, then its role in reducing the porosity and permeability properties (PPP) of rocks in the bottomhole zone of wells will be insignificant, since its presence does not lead to an increase in the water saturation of rocks in the bottomhole zone of wells and does not affect the reduction well flow rate. The article presents the results of experimental work on core samples of zeolite-containing rocks and geological and field studies in order to establish the effect of zeolites on obtaining potential well flow rates. Acid solutions are proposed for the development of wells when they exit from drilling.

Enhanced machine learning—ensemble method for estimation of oil formation volume factor at reservoir conditions

Since the oil formation volume factor (Bo) is crucial for various calculations in petroleum engineering, such as estimating original oil in place, fluid flow in the porous reservoir medium, and production from wells, this parameter is predicted using conventional methods including experimental tests, correlations, Equations of State, and artificial intelligence models. As a substitute to conventional black oil methods, the compositional oil method has been recently used for accurately predicting the oil formation volume factor. Although oil composition is essential for estimating this parameter, it is time-consuming and cost-intensive to obtain through laboratory analysis. Therefore, the input parameter of dissolved gas in oil has been used as a representative of the amount of light components in oil, which is an effective factor in determining oil volume changes, along with other parameters, including pressure, API gravity, and reservoir temperature. This study created machine learning models utilizing Gradient Boosting Decision Tree (GBDT) techniques, which also incorporated Extreme Gradient Boosting (XGBoost), GradientBoosting, and CatBoost. A comparison of the results with recent correlations and machine learning methods adopting a compositional approach by implementing tree-based bagging methods: Extra Trees (ETs), Random Forest (RF), and Decision Trees (DTs), is then performed. Statistical and graphical indicators demonstrate that the XGBoost model outperforms the other models in estimating the Bo parameter across the reservoir pressure region (above and below bubble point pressure); the new method has significantly improved the accuracy of the compositional method, as the average absolute relative deviation is now only 0.2598%, which is four times lower than the previous (compositional approach) error rate. The findings of this study can be used for precise prediction of the volumetric properties of hydrocarbon reservoir fluids without the need for conducting routine laboratory analyses by only employing wellhead data.

Thermodynamic energy change and occurrence mechanism of multiple fluids in coal reservoirs

Systematic understanding of the occurrence mechanism of multiple fluids in coal reservoirs is the basis for efficient development of coalbed methane (CBM). In this study, the adsorption capacity, adsorption potential and adsorption heat data of coal samples of different metamorphic degrees under single/multi components isothermal adsorption were obtained through isothermal adsorption equipment and the atomic force microscopy (AFM). The adsorption potential energy and electric potential energy were innovatively combined to expound the characteristics of the thermodynamic energy change in coal reservoirs, and the occurrence mechanism of multiple fluids in coal reservoirs were discussed. It is found that: (a) the adsorption amount of these two gases decreases first and then increases with the increase of coal rank in both single-phase adsorption and competitive adsorption. (b) CO2 shows superior adsorption in comparison to CH4. The larger the proportion of a certain component in the mixed gases system, the better this component's adsorption performance. (c) The adsorption potential of the two gases is not affected by temperature, and with the increase of coal metamorphism, the adsorption potential shows first a decrease, followed by an increase. (d) The CH4 adsorption heat of coal samples increase with higher adsorption amount, but the CO2 adsorption heat of some coal samples has a negative linear correlation with adsorption amount.

Impact of fracturing fluid retention and flowback on development effect after large scale fracturing in shale oil wells: A case study from the shale oil of Chang 7 Member, Yanchang Formation, Ordos Basin

In order to reveal the impact of fracturing fluid retention and flowback on the development effect after large-scale fracturing in shale oil wells, and to formulate a reasonable flowback policy, this paper employs a combination of core physical simulation experiments and theoretical analysis. We have designed a specially designed device that can evaluate the development effect of quasi-natural energy in oil reservoirs. The impact of fracturing fluid retention on development is simulated by changing the amount of fracturing fluid injected into the formation in a fractured horizontal well model (referred as injection volume), and the impact on development effect is analyzed by changing the properties of fracturing fluid to adjust the difference in the degree of flowback. Based on the experimental results, the mechanism of fracturing fluid retention and flowback after large-scale fracturing in shale reservoirs is further explored. The results of the experiments show that the flowback rate of fracturing fluid exhibits a monotonic decreasing trend with increasing the volume of injected fluid, as increasing the volume of injected fluid helps to enhance its retention in the formation and reduce the flowback rate. The degree of fracturing fluid flowback is critical to the mobility of crude oil in the tight reservoir. The entering of fracturing fluid into the reservoir slows down the rate of discharge in the fracture network, effectively extending the reach of the fracturing fluid in the tight reservoir and allowing more crude oil to be used, which in turn results in higher crude oil production. However, too much injection fluid may affect the fluid production. Simulation experiments reveal that the use of fracturing fluid retention or controlling the rate of flowback by changing the viscosity of fracturing fluid can be a way to enhance the development effect of horizontal shale oil wells. The results of this paper provide a basis for understanding the mechanism of shale oil development, exploring technical ideas to improve the development effect, and making decisions on the flowback parameters.

Consistency Checks for Pressure-Volume-Temperature Experiment of Formation Oil and Gas at High Temperature

The oil and gas phase behavior of high temperature is complex and changeable, which is usually obtained by PVT experiments. The accuracy of the experiment data plays a crucial role in the reserve evaluation and development plan of oil and gas reservoirs. However, the current PVT experiment consistency checks are not suitable for high-temperature reservoir conditions. This paper proposes a systematic check method for the PVT experiment data consistency at high temperature. These checks revise the material balance method, Hoffman method, and equilibrium constant method by using the equilibrium constant calculation method at high temperature. The consistency check of component data and constant volume depletion experiment data is carried out by combining the three improved methods with the component check method, so as to judge the experiment data accurately. In this paper, two high-temperature reservoir fluids—gas condensate sample fluid X and volatile oil sample fluid Y—are selected to carry out consistency checks with component data and constant volume depletion data. This check method is of great significance to study the phase behavior of formation oil and gas at high temperature, especially for volatile oil and gas condensate fluid.

Characteristics of hydraulic fracture penetration behavior in tight oil with multi-layer reservoirs

The tight oil reservoirs of Fuyang and Gaotaizi in the Daqing Oilfield exhibit characteristics such as thin layers and distributed barriers, which pose challenges for maintaining drilling accuracy within the desired geological sweet spot. Hydraulic fracturing has emerged as the optimal method to connect production wells with target layers effectively. Understanding the behavior of hydraulic fracture propagation in multiple thin layers with significant differences in mechanical properties is crucial for assessing the extent of effective drainage. In this study, a finite element numerical simulation model incorporating cohesive elements is employed to investigate and quantify the effects of stress differences and rock mechanical parameters on fracture penetration. The results indicate that the stress difference between the reservoir and barrier layers plays a key role in controlling hydraulic fracture penetration and height. Moreover, the flow rate and viscosity of the fracturing fluid have a noticeable impact on fracture progression. Hydraulic fractures tend to propagate along the interface of layers with low flow rate and fluid viscosity, thereby hampering the penetration performance in those layers. To achieve a comparable penetrated fracture length in low permeability reservoirs, it is necessary to increase the volume of fracturing fluid in high permeability reservoirs. Furthermore, the barriers layers, which possess relatively weaker mechanical properties, can constrain the width development of hydraulic fractures. This limitation may result in the risk of excessive liquid without sufficient proppant (commonly known as “over liquid but no sand”). Therefore, appropriate measures should be implemented to increase the net pressure and avoid encountering this complex situation.

Long-term production forecast in tight and shale reservoirs: Adapting probability density functions for decline curve analysis

Decline curve analysis (DCA) is a popular method for predicting the production of oil and gas wells over time. It involves using historical data to match a mathematical function with the production data, which can then be used to forecast future production. However, DCA in unconventional tight and shale reservoirs poses unique challenges. Unlike conventional reservoirs, these unconventional reservoirs exhibit a production decline that is both faster and more erratic. This behavior, combined with the inherent complexities of the reservoir properties and fluid flow mechanisms, makes it challenging for traditional DCA models to provide accurate predictions of future production.This study proposes a new approach for forecasting long-term production in tight and shale reservoirs, using probability density functions (PDFs) that have been adapted and evaluated for this purpose. The PDF-based DCA models were tested against traditional DCA models using data from over 80 wells in different unconventional basins across North America.Results show that the PDF-based models outperformed the traditional models, with the Dagum and Beta prime models achieving the highest performance scores on various statistical measures, especially in wells with limited production history for model training. To ensure accuracy, appropriate statistical tests should be used to validate the PDF-based decline curve analysis, such as calculating the mean absolute error (MAE) or other relevant metrics.Our research introduces a novel method of adapting PDFs for decline curve analysis, specifically tailored for tight and shale reservoirs. This adaptation offers a more accurate and comprehensive prediction of future production by effectively capturing the inherent uncertainty and variability seen in unconventional reservoirs. One of the standout features of our proposed PDF-based approach is its versatility. Unlike traditional models that may struggle with erratic data, our models can seamlessly fit production data, whether it possesses peaks or not. This approach could be valuable for producers and investors who want to make informed decisions about drilling and production in unconventional reservoirs.

Research and application of construction technology of digital mud cake formed by drilling fluid filtration

In drilling engineering, mud cake is formed when drilling fluid invades the near-wellbore zone, which can reduce drilling fluid leakage and reservoir pollution and maintain wellbore stability. To study the three-dimensional spatial characteristics of mud cakes, such as heterogeneity, particle accumulation, and porous media, CT scan images of cores and mud cakes before and after drilling fluid intrusion are used as the research object. The composite filtering and segmentation method for typical regions of images based on grayscale values and the batch segmentation method for large regions of images based on deep learning are investigated. On this basis, a visualized digital mud cake is constructed, and microscopic evaluation indexes such as the percentage, equivalent radius, throat length, sphericity, and coordination number of pores and particles in the mud cake are established. The application results show that the number of isolated pores in the outer mud cake formed by static filtration of drilling fluid is more than that of dynamic ones, the connectivity of pores is poor, and the particles have a better sealing effect on pores. The combined effect of the outer and inner mud cake results in different effects on core intrusion. The construction technique of digital mud cake can study the structure at a micron scale. This technique can provide more detailed guidance for engineering situations, such as optimization of drilling fluid systems in fractured formations, damage evaluation of reservoirs by drilling fluid, and influence of mud cake on cementing quality.