Development Of Unconventional Reservoirs Research Articles

Simulation of temporary plugging agent transport and optimization of fracturing parameters based on fiber optic monitoring data

Temporary plugging and fracturing is an important technology for the efficient development of unconventional reservoirs. Due to the diverse physical properties of unconventional reservoirs and the complex stress environment, the evaluation of temporary plugging effect needs to consider the working conditions in the wells, and it also needs to focus on the transport and placement of temporary plugging agent in the near-well fracture region, so it is impossible to predict the effect of temporary plugging and fracturing effectively. In this paper, a numerical simulation study is carried out to investigate the transport and placement of temporary plugging agent in the near-well area, and a finite element model of “wellbore-near-well fracture” is established based on computational fluid dynamics, and numerical simulation and verification of temporary plugging and fracturing are carried out based on the fiber-optic monitoring data of temporary plugging and fracturing in Well A, as well as the optimization of some construction parameters. The results show that: as the volume concentration of temporary plugging agent increases, the temporary plugging effect is weakened and then strengthened, and the temporary plugging agent will enter into the heel cluster in advance when the concentration is small; at the initial stage, the increase in the quality of temporary plugging agent will cause some clusters to form incomplete plugging, but the quality of the plugging agent will not be changed after the quality is greater than 360kg; the temporary plugging effect is mainly reflected in the heel cluster, and the toe cluster is not obvious. This paper forms a set of temporary plugging and fracturing simulation methods based on the actual fiber-optic monitoring data in the field, which provides a reference for the optimization design of the type, particle size and dosage of temporary plugging agent during the temporary plugging construction process.

Self-Assembled Viscoelastic Surfactant Micelles with pH-Responsive Behavior: A New Fracturing-Displacement Integrated Working Fluid for Unconventional Reservoirs.

The integrated fracturing and oil recovery strategy is a new paradigm for achieving sustainable and cost-effective development of unconventional reservoirs. However, a single type of working fluid cannot simultaneously meet the different needs of fracturing and oil displacement processes. Here, we develop a pH-responsive fracturing-displacement integrated working fluid based on the self-assembled micelles of N,N-dimethyl oleoamine propylamine (DOAPA) and succinic acid (SA). By adjusting the pH of the working fluid, the DOAPA and SA molecules can be switched repeatedly between highly viscoelastic wormlike micelles and aqueous low-viscosity spherical micelles. The zero-shear viscosity of the working fluid enriched the wormlike micelles can reach more than 93,100 mPa·s, showing excellent viscoelasticity and sand-carrying properties. The working fluid is easy to gel-break when it encounters oil, generating a low-viscosity liquid without residue. In addition, the system has strong interfacial activity, which can greatly reduce the oil-water interfacial tension to form emulsions and can achieve reversible demulsification and re-emulsification by adjusting pH. Through the designed and fabricated microfluidic chip, it can be visualized that under the synergistic effect of viscoelasticity and interfacial activity DOAPA/SA can effectively expand the swept volume of tight fractured formations, promote pore wetting reversal and crude oil emulsification, and improve the displacement efficiency. The DOAPA/SA meets the design requirements of the fracturing-displacement integrated working fluids and provides a novel method and idea for constructing the integrated working fluids suitable for fracturing and displacement in unconventional reservoirs.

Study on the Interaction Propagation Mechanism of Inter-Cluster Fractures under Different Fracturing Sequences

Horizontal-well multi-cluster fracturing is one of the most important techniques for increasing the recovery rate in unconventional oil and gas reservoir development. However, under the influence of complex induced stress fields, the mechanism of interaction and propagation of fractures within each segment remains unclear. In this study, based on rock fracture criteria, combined with the boundary element displacement discontinuity method, a two-dimensional numerical simulation model of hydraulic fracturing crack propagation in a planar plane was established. Using this model, the interaction and propagation process of inter-cluster fractures under different fracturing sequences within horizontal well segments and the mechanism of induced stress field effects were analyzed. The influence mechanism of cluster spacing, fracture design length, and fracture internal pressure on the propagation morphology of inter-cluster fractures was also investigated. The research results indicate that, when using the alternating fracturing method, it is advisable to appropriately increase the cluster spacing to weaken the inhibitory effect of induced stress around the fractures created by prior fracturing on subsequent fracturing. Compared to the alternating fracturing method, the propagation morphology of fractures under the symmetrical fracturing method is more complex. At smaller cluster spacing, fractures created by prior fracturing are more susceptible to being captured by fractures from subsequent fracturing. The findings of this study provide reliable theoretical support for the optimization design of fracturing sequences and fracturing processes in horizontal well segments.

Carbon Dot Nanomaterials with High Interfacial Activity for Unconventional Reservoir Development

Carbon Dot Nanomaterials with High Interfacial Activity for Unconventional Reservoir Development

Topological Characteristics of the Pore Network in the Tight Sandstone Using Persistent Homology.

Tight sandstone reservoirs have become important areas for unconventional reservoir development, and their pore network is a key feature for identifying tight sandstone, which affects fluid migration path and reservoir development efficiency. However, the connectivity characteristics of the pore network at different scales have remained unclear owing to the numerous pores and uneven pore shape. Here, using pore size distributions from many hundreds of tight sandstone samples and subsequent topological data analysis, we construct the topological structure of the pore network in the Yanchang Formation tight sandstone of the Ordos Basin in China and visualize the topological characteristics of the pore network with distances. We show that there are three connected groups within the pore structure of the tight sandstone. The topology of the pore network resides on a trident ring manifold, suggesting that the pore network in the tight sandstone encompasses three obvious dominant connection paths. One prominent bar on the H0 dimension in the barcode indicates a two-point connection from nanoscale to microscale in the pore network. Three prominent bars with varying durations on the H1 dimension indicate the presence of three separate multipoint connections within a limited extent in the pore network. Connectivity of combined pores is good and controlled by the topological structure of the pore network. This demonstration of pore connections on a trident ring manifold provides a population-level visualization of the pore network in the tight sandstone.

Numerical Simulation of integrated three-dimensional hydraulic fracture propagation and proppant transport in multi-well pad fracturing

Multi-well pad fracturing is an indispensable technology for the sustainable development of unconventional oil and gas reservoirs, but the integrated simulation of fracture propagation and proppant migration in massive fracturing treatments remains challenging, including complicated numerical implementations and computational bottlenecks due to its multi-physics, fracture front propagation, size differences between proppant particles and hydraulic fractures. In this work, an integrated model of fracture propagation and proppant migration in multi-well pad fracturing was established based on the three-dimensional discontinuous displacement method for fracturing deformation computations and the Eulerian-Eulerian framework for capturing proppant concentration. The proposed simulator not only accounts for key physical processes such as stress shadow, dynamic flow rate distribution in the wellbore, fluid leak-off, perforation erosion, fractures evolution, proppant bridging, and gravitational settling, but also couples the simulation of 3D planar propagating fractures and proppant transport at well-pad scale, and presents excellent computational efficiency and promising applications than conventional fracturing models. To explore the fracture geometries and proppant distribution in typically stacked layers, single-well, multi-lateral wells, and multi-well pad fracturing are simulated from simple to complex. The findings showed that fracture propagation is jointly affected by intra-stage, inter-stage, and inter-well stress interference mechanisms, and fracture geometries are characterized by unevenness, asymmetry, and heel bias. Proppant transport is controlled by the fracture width and geometries, and most of the proppant is concentrated near the wellbore area and bridging at the narrow fractures. Fracture geometries and proppant distribution are sensitive to the landing locations of horizontal wells because hydraulic fractures always grow in the path of least resistance. Although close lateral well-spacing is beneficial to improve the stimulation efficiency, there are some challenges such as overlapped SRV, enhanced inter-well interference, and severe fracturing hits. Compared with the layout of stacked wells, staggered wells are not only beneficial to reduce the vertical inter-well interference, but also improve reservoir stimulation efficiency. Overall, the stimulated area of the high in-situ stress layers is relatively low even with intentionally landed wells.

Comprehensive Study on Microscopic Pore Structure and Displacement Mechanism of Tight Sandstone Reservoirs: A Case Study of the Chang 3 Member in the Weibei Oilfield, Ordos Basin, China

With the continuous growth in global energy demand, research and development of unconventional oil and gas reservoirs have become crucial in the field of energy. This study focuses on the Chang 3 reservoir of the Yanchang Formation in the Ordos Basin, Weibei Oilfield, China. This reservoir is a typical tight sandstone reservoir, and its microscopic pore structure and displacement mechanism are essential for the efficient development of tight oil. However, the reservoir faces challenges such as complex microscopic pore structures and unclear displacement mechanisms, which hinder the efficient development of tight oil. In light of these challenges, through various studies including core observation, high-pressure mercury injection tests, water flooding experiments, oil-water two-phase relative permeability measurements, and stress sensitivity experiments, it was found that the Chang 3 reservoir exhibits strong microscopic heterogeneity. The pore-throat distribution characteristics mainly present two types: single peak and double peak, with the double peak type being predominant. The reservoir was classified and evaluated based on these characteristics. The improved injection ratio and properties enhance oil displacement efficiency, but an increase in irreducible water saturation has a negative impact on efficiency. The stress sensitivity of the reservoir fluctuates between weak and strong, with permeability being sensitive to net confining pressure. It is recommended to pay particular attention to the stress-sensitivity characteristics during reservoir development. The research results provide a scientific basis for the optimized development of tight oil reservoirs in this region, promote the sustainable development of unconventional oil and gas resources, and have significant theoretical and practical implications.

Impact of Tool Eccentricity on Acoustic Logging Response in Horizontal Wells: Insights from Physical Simulation Experiments

Horizontal wells are extensively utilized in the development of unconventional reservoirs. However, the logging responses and formation evaluation in horizontal wells can be impacted by factors like anisotropy and tool eccentricity. To investigate the influence of tool eccentricity on acoustic logging response, physical simulation experiments of array acoustic logging were conducted in a scaled borehole formation model under different tool eccentricity conditions. The experimental data were analyzed, and the findings revealed that when the receiver array is parallel to the borehole axis, the P-wave slowness and S-wave slowness remain unaffected by tool eccentricity. However, the amplitudes of the P-wave and S-wave decrease significantly with increasing tool eccentricity, following an approximate negative exponential pattern. Additionally, when the transmitter is centered and the receiver array intersects the borehole axis at an angle, the wave velocities increase significantly with tool eccentricity, with the P-wave velocity showing a faster increase. Conversely, when the transmitter is eccentric and the receiver array intersects the borehole axis at an angle, the wave velocity decreases notably with tool eccentricity, and the P-wave velocity decreases even faster. These findings contribute to a better understanding of the impact of tool eccentricity on array acoustic logging response in horizontal wells and offer guidance for developing correction schemes to address this effect.

Advances in hydraulic fracture characterization via borehole microseismic and strain monitoring

We analyze the impact and challenges associated with microseismic monitoring in the development of unconventional reservoirs. We detail advanced methods that address some of these challenges and discuss emerging data analysis and acquisition technologies such as those provided by fiber-optic monitoring. During the development of unconventional resources, it is important to understand the stimulated rock volume obtained from the hydraulic fracturing treatment. Microseismic monitoring is one of the sources of information for estimating stimulated rock volume in which accurate hypocenter calculations provide the horizontal and vertical fracture geometry and extent. We developed hypocenter waveform-based relocation and collapsing techniques and demonstrated these on synthetic and field data to obtain an enhanced description of the fracture geometry. We further provide the initial analysis of a recently acquired data set composed of multiple monitoring wells instrumented with geophones and fiber optics operating simultaneously. Microseismic events recorded by the multiwell dual geophone/fiber setup show meaningful signal-to-noise ratio to enable a joint interpretation. Additional strain and temperature data provided by dynamic fiber-optic measurements extend the interpretation capabilities of the hydraulic fracturing phenomenon while providing an avenue for advanced research on fracture characterization.

FRACTAL STUDY ON THE PERMEABILITY IN CHARGED MICRO-FRACTURED POROUS MEDIA

Fractured porous media is of great significance to the exploration and development of unconventional reservoirs. In this paper, a fractal model for permeability through micro-fractured porous media with consideration of the electric double layer (EDL) effect is proposed based on the fractal theory. The present model indicates that the permeability is a function of the electrokinetic parameters and micro-structural parameters of fractured porous media, and each parameter has a clear physical meaning, the results from the proposed model are found to be in good agreement with experimental data. Moreover, factors influencing the permeability are also analyzed in detail. The results indicate that the more obvious EDL effects will lead to permeability becoming lower. The present fractal model for the permeability with the EDL effect can provide guidance for tight reservoir development or other micro-porous media transportation.

Quantitative Analysis of Hydraulic Fracturing Test Site 2 Completion Designs Using Crosswell Strain Measurement

Summary The implementation of effective completion design configurations during hydraulic stimulation is critical for the economic development of unconventional reservoirs. Low-frequency distributed acoustic sensing (LF-DAS)-based crosswell strain measurement is an advanced monitoring technique used to diagnose completion design efficiency but has been primarily restricted to qualitative analysis. In this study, we apply our novel Green-function based inversion algorithm to calculate fracture geometry (i.e., width) using the Department of Energy sponsored Hydraulic Fracturing Test Site 2 (HFTS-2) data set. The adopted algorithm relies on a 3D displacement discontinuity method to construct geomechanical models inverting linear elastic strain to hydraulic fracture widths. We use the inversion algorithm to calculate dynamic fracture widths using LF-DAS data recorded at two horizontal monitoring wells with permanent optical fiber installations. The inverted fracture widths at the monitoring wells from more than 100 hydraulic fracturing stages are used to diagnose the efficiency of eight unique completion designs implemented across three fracturing wells. We develop several metrics to evaluate completion design efficiency including the evenness of fracture widths at the monitoring wells, fracture density (i.e., number of fracture hits per foot), and fracture-width-density (i.e., fracture width/stage length). We observe a significant impact on completion efficiency with varying degrees of limited entry, tapered configurations, and stage length designs. Results indicate improved hydraulic stimulation is achieved with the implementation of limited-entry designs for extended stage lengths (ESLs), but no observable trend for normal stage lengths (NSLs). Tapered configurations significantly improve efficiency for ESLs but indicate little impact on normal-length designs. Reducing the space between perforation clusters (PCs) is determined to negatively impact design performance. Additionally, our quantitative analysis describes the impact of the nearby depletion zone on completion design efficiency. The methodology developed in this study provides operators with another level of quantitative information to optimize hydraulic fracturing treatments and reduce costs associated with the development of unconventional wells.

CDEM-Based Numerical Simulation of Uniaxial Compressive Mechanical Properties of Rocks

Understanding the mechanical properties of rock is of great significance for the development of unconventional reservoirs. However, a large number of bedding makes the mechanical laws of rock unclear. To investigate the effect of bedding properties on the uniaxial mechanical properties of rock, the coal model containing bedding is developed based on the continuous–discontinuous method, and the effect of bedding angle, bedding strength, bedding number, and loading rate on the uniaxial mechanical properties of rock is investigated. The failure morphology, stress–strain evolution, peak stress, and fracture degrees are analyzed and discussed in detail. The reliability of the numerical model in this paper has been verified by comparison with the indoor experiments. The results show that when the bedding angle is 0°, the peak stress of the rock is maximum, 8.16 MPa, and when the bedding angle is 90°, the fracture degree of the rock is maximum, 3.74%. For the different bedding strengths, the peak stress first decreases linearly with the decrease of the bedding strength. The peak stress barely varies when the bedding strength is less than 0.5 MPa. The fracture degree of the rock shows a nonlinear increase with the increase in bedding strength. For different bedding numbers, the activation of the bedding is not related to the bedding number. The loading speed also has a great influence on the mechanical properties of rock. With the increase in loading rate, the difficulty of bedding activation gradually increases, and the complexity of fractures gradually increases. This study aims to further improve the understanding of the effect of bedding properties on the uniaxial mechanical properties of rock.

Establishment and application of propped hydraulic fracture conductivity theoretical model based on fracturing efficiency index

Hydraulic fracturing technology is a key technology for the development of unconventional oil and gas reservoirs, and the conductivity of hydraulic fractures has a great impact on their production. The paper introduces the "fracturing efficiency index" as means of characterising the dynamic relationship between hydraulic fracture expansion and proppant filling. It also suggests a way to figure out the proppant fracture inflow capacity. This approach addresses issues such as uneven fracturing fluid dosage, a wide range of injection discharges, and inconsistent sand spreading concentration encountered during fracturing operations. Based on this model, the influencing factors of the flow-conducting capacity such as proppant particle size, sand spreading concentration, liquid injection displacement, and proppant crushing rate, were analyzed, and the calculated results of this model are closer to the experimental results of the API flow-conducting capacity test compared with the calculated results of the reference model. Finally, this model was used to optimize the fluid volume, sand volume, and displacement of hydraulic fracturing in the Jiping 1H shale gas field. The research results show that: (1) the fracturing efficiency index is negatively correlated with the conductivity of hydraulic fractures, whereas is positively correlated with the enhancement of conductivity; (2) our model is applicable to the calculation of supported fracture inflow capacity for high sand concentration, large particle size, intermediate fracture flow and low crushing rate, and the results are close to more than 98.58%, 98.29%, 95.68% and 95.08% of the experimental results, respectively; (3) On-site hydraulic fracturing does not result in higher production capacity with more fracturing fluid dosage, higher displacement and more sand addition; there are optimal fluid, optimal displacement and optimal sand intervals, which are optimized to increase production by 26.92%. It can be seen that the hydraulic fracture conductivity model can optimize various parameters of on-site fracturing construction.

A New Approach for Production Prediction in Onshore and Offshore Tight Oil Reservoir

Rapid technological advances have accelerated offshore and onshore tight oil extraction to meet growing energy demand. Reliable tools to carry out production prediction are essential for development of unconventional reservoirs. The existed tri-linear analytical solutions are verified to be versatile enough to capture fundamental flow mechanisms and make accurate production predictions. However, these solutions are obtained in Laplace space with the Laplace transform and numerical inversion, which may lead to uncertainty in the solution. In this paper, a general analytical solution is derived in real-time space through integral transform and average pressure substitution. Namely, the partial differential equations describing subsurface fluid flow are firstly triple-integrated and then the obtained volume average pressure are replaced with the rate-dependent expressions. Furthermore, the ordinary differential equations related to oil rate are solved analytically in real-time space. To validate our model, this derived solution is verified against two numerical models constructed with two typical physical configurations. The great match indicates the accuracy and applicability of the analytical solution. According to the developed workflow, two field cases including offshore and onshore tight oilfield data are selected for history matching and production prediction. This new approach not only makes the obtained solution more simplified, but also helps field engineers diagnose flow patterns more quickly to better optimize production schemes.

Research on a Calculation Model of Cable Tension and Pumping Displacement of a Logging Tool String of Horizontal-Well Drillpipes

Summary With the vigorous development of unconventional oil and gas reservoirs, logging technology of horizontal-well drillpipes has become increasingly important. The improper selection of displacement during the pumping of drilling rods into horizontal wells can lead to accidents such as cable entanglement or tool-string pump detachment. Based on a comprehensive consideration of multiple factors such as drillpipe joints, small gap flow, pressure loss along the pipe, temperature, pressure, tool-string passability, and waterhole diameter variation, a cable tension analysis model for a logging tool string of a horizontal-well drillpipe is established. This model can predict a reasonable pumping displacement by analyzing the tension in the entire wellbore section, thereby avoiding cable entanglement or even tool-string pump detachment accidents during downhole operation. To verify the effectiveness of the model, we analyzed the cable tension during logging operations in Wells M1 and M2 using on-site test data and compared them with the measured tension data. The determination coefficient (R2), mean absolute error (MAE), and root mean square error (RMSE) were used to evaluate the degree of fit and accuracy of the model. The experimental results showed that the model can accurately predict the pumping displacement range before logging operations, ensuring that the cable does not entangle and the tool string is not pumped out during the downhole operation, thus providing effective methods and theoretical guidance for on-site drilling rod-pumping logging operations.

Insight into functional groups of salt compounds on the performance of viscoelastic surfactant-based fluids

Clean fracturing fluids (CFFs) hold great potential for the development of unconventional reservoirs due to their characteristics (e.g., fracturing-oil expulsion integration and low formation damage). Organic salts, as adjuvants, play a significant role in regulating the performance of CFFs. In this work, four CFFs containing different organic salts were prepared to investigate the impact of functional groups in organic salts on the CFF performance. Results show that the functional groups markedly influence the rheological properties, temperature resistance and drag reduction performances of CFFs through inducing the micelle formation and thus enhancing the micelle network strength. Sodium 4-vinylbenzenesulfonate (SV) with vinyl endowed the CFF with the stronger micelle network. Furthermore, the functional groups were found to impact the adsorption of surfactants at interface, which affects the oil–water interfacial tensions and regulates the spontaneous imbibition performance of CFFs. SV enables a higher imbibition efficiency of 25.6 % after 90 h. Density functional theory (DFT) calculation results confirmed that the functional groups of salts are capable of manipulating the interactions between salt anions and surfactant, ultimately determining the CFF performance. This work provides guidance for the selection of salt additives to improve the CFF performance.

Study Reviews Eagle Ford Parent-Well Frac-Hit Analysis, Prediction, and Mitigation

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3873139, “Eagle Ford Parent-Well Frac Hit (Frac-Driven Interaction), Impact Characterization, Prediction, and Mitigation,” by Yongshe Liu, Lucy Luo, and Susan Naiser, ConocoPhillips, et al. The paper has not been peer reviewed. _ While some wells show production uplifts after a frac hit (FH), many wells experience production degradation or complete loss of production because of failed casing or plugged wellbores. The complete paper focuses on Eagle Ford FH characterization, production-impact-prediction methods, and mitigation techniques. The techniques and findings presented in this paper are intended to improve the understanding of FH trends and their effects on the development of unconventional reservoirs. FH Detection and Data Collection Parent-Well Production Data. The authors write that identifying and building a database recording FH effects for every parent well has been a significant effort, with more than 1,600 wells drilled in the Eagle Ford by ConocoPhillips. This mass of data, however, serves as an excellent record of changes to production rate, water cut, yield, and pressures. Parent-Well Surface Pressure. Parent-well surface pressure data can be important for FH analysis. Such data provide direct measurement of the timing and magnitude of FHs at the parent well. FH-event timing typically can be correlated with the pumping of a specific completion stage when integrated with evaluation of stress and expected fracture orientation. With this information, an FH pathway can be inferred between the infill and the parent wellbore. Collating this information assists in the generation of a map that captures all FH events with the extension of this analysis to all stages and parent wells. To characterize FHs, parameters derived from the pressure response include the rate of pressure increase (intensity), pressure-increase magnitude, time to response, and volume to response. An automated tool has been created to identify these pressure-based parameters and record them in a database. FH Diagnostic Data. FHs can be detected using special hydraulic fracture diagnostic data that are not collected commonly, such as microseismic, distributed acoustic sensing, downhole pressure gauge, and tracer data. Other relevant information used for FH analysis includes well spatial configurations, completion data, reservoir properties, and operational data, such as mud-loss and cleanout data. FH Analysis Work Flow The proposed integrated work flow for analyzing FHs involves collecting data on fieldwide FH events and their associated production effects and incorporating other relevant information such as geology, completion, and well schedule. Empirical analysis is conducted to identify the key trends and drivers of FHs, followed by the development of mechanistic models for a better understanding of the underlying physics and a multivariate analysis (MVA) model for prediction.

A novel well-logging data generation model integrated with random forests and adaptive domain clustering algorithms

With geological evolution, reservoirs have hierarchical properties, leading to distinct domain characteristics in their logging curves, which can contribute to the reconstruction of unknown well logging curves. In recent years, many studies have used machine learning (ML) algorithms to reconstruct logging curves without incorporating domain features, which can cause their poor performance. Since decomposing raw data into domain data can optimize an expected variance and thus improves the accuracy and robustness of ML prediction models, we propose a random-forest-adaptive-domain-clustering (RF-ADC) model to generate unknown well logging curves. First, we present an adaptive domain clustering algorithm based on gap statistics (GS) and balanced iterative reducing and clustering using hierarchies (BIRCH). With the adaptive domain clustering process, well logging curves are automatically divided into microscope domains, and their corresponding domain models are constructed. Then we utilize the random forest (RF) algorithm to generate unknown well logging curves based on domain data. Taking logging curves of a shale gas reservoir as an example, our experiments show that the proposed RF-ADC model achieves promising results. Compared with the model without clustering operation, the RF-ADC model provides superior performance with its mean absolute error (MAE), mean squared error (MSE), root mean squared error (RMSE), and mean absolute percentage error (MAPE) values reducing by 15.55%, 39.30%, 18.95%, and 11.43%, respectively. In addition, the predictive performance of the proposed RF-ADC model is better than that of baseline models of long short-term memory network and convolutional neural network. Furthermore, after analyzing, the GS and BIRCH methods are applicable to obtaining an optimal number of domains and decomposing well logging data for horizontal wells. Our delineation results also provide insights into detailed reservoir recognition, which is important for further identification of reservoirs and stratification work. Moreover, the proposed RF-ADC model can also achieve effective prediction with a small dataset (MAE = 8.205, RMSE = 10.922, and MAPE = 0.039). In summary, this RF-ADC model provides a fast, economical, and effective tool for the generation of unknown well logging curves for horizontal wells in shale gas reservoirs. It will further facilitate the exploration and development of unconventional reservoirs.

A novel supramolecular deep eutectic solvent enhancer for fracturing-oil expulsion fluids

Crude oil remains the predominant energy source today. Clean fracturing fluids (CFFs) have great potential to overcome the challenges of unconventional oil reservoir development due to their integrated fracturing-oil expulsion characteristics. The performance of CFFs is closely related to oil production. In this work, a novel β-cyclodextrin (β-CD)-based supramolecular deep eutectic solvent (SDES) was developed as a promising enhancer for CFF performance. The SDES facilitates the formation of high-strength micelle networks through hydrogen bonds and host–guest interactions to significantly improve the rheological properties, temperature resistance and drag reduction performances of CFFs. The ion–dipole interactions between SDES components and salt cations restrain micelle disassembly, thereby enabling remarkable resistance of CFFs to salt. SDES could further increase the imbibition efficiency to 45.4 % in 62 h because of its interface activity. SDES also endowed CFF with superior gel breaking performance and reusability. Moreover, SDES hardly resulted in the reduction of reservoir permeability. The β-CD in SDES further enhanced the interactions between compounds in CFFs, making it a more effective option compared with traditional DES. This work demonstrates the substantial potential of SDES as a new and green medium for improving the CFF performance, offering promising prospects for the industry.

Impacts of proppant distribution on development of tight oil reservoirs with threshold pressure gradient

Field evidence indicates that proppant distribution and threshold pressure gradient have great impacts on well productivity. Aiming at the development of unconventional oil reservoirs in Triassic Chang-7 Unit, Ordos Basin of China, we presented an integrated workflow to investigate how (1) proppant placement in induced fracture and (2) non-linear flow in reservoir matrix would affect well productivity and fluid flow in the reservoir. Compared with our research before (Yue et al., 2020), here we extended this study into the development of multi-stage fractured horizontal wells (MFHWs) with large-scale complicated fracture geometry. The integrated workflow is based on the finite element method and consists of simulation models for proppant-laden fluid flow, fracture flow, and non-linear seepage flow, respectively. Simulation results indicate that the distribution of proppant inside the induced cracks significantly affects the productivity of the MFHW. When we assign an idealized proppant distribution instead of the real distribution, there will be an overestimation of 44.98% in daily oil rate and 30.63% in cumulative oil production after continuous development of 1000 days. Besides, threshold pressure gradient (TPG) also significantly affects the well performance in tight oil reservoirs. If we simply apply linear Darcy’s law to the reservoir matrix, the overall cumulative oil production can be overrated by 77% after 1000 days of development. In general, this research provides new insights into the development of tight oil reservoirs with TPG and meanwhile reveals the significance of proppant distribution and non-linear fluid flow in the production scenario design.