Multi-fractured Horizontal Wells Research Articles

Optimization of Mathematical Function-Shaped Fracture Distribution Patterns for Multi-Stage Fractured Horizontal Wells

A conventional oil and gas well does not have a natural production capacity, which necessitates a hydraulic fracturing operation. The effectiveness of the fracturing directly impacts the economic benefit of a single well. Among the various parameters, including fracture spacing, fracture width, and conductivity, fracture half-length is one of the main influencing factors on the productivity of horizontal wells. For conventional homogeneous reservoirs, research mainly focuses on fracture patterns with equal fracture lengths. However, in actual production processes, due to mutual interference and the superimposition of drainage areas between fractures, the production distribution of each fracture is non-uniform. Typical fracture distribution patterns mainly include uniform, staggered, dumbbell, and spindle. While many believe that the dumbbell-shaped fracture distribution pattern has the best effect, there has been no quantitative study on the length of each fracture under the dumbbell-shaped pattern. Based on this, this paper proposes a modeling approach for function-shaped fracture distribution that takes advantage of the high production of edge fractures and the low output of middle fractures in horizontal wells. The influence of this approach on production capacity is studied. Constant, linear, and parabolic functions are used to establish the relationship between fracture position and fracture half-length, optimizing the fracture distribution function to achieve the best production effect. This method can guide the horizontal well fracture distribution in the block to maximize productivity. The results show that the parabolic function-shaped model is better than the linear function-shaped model and the constant function-shaped model is the least effective. The research presented in this paper offers a new idea for optimizing on-site fracturing plans. It utilizes mathematical expressions to describe the parameters that affect productivity, which provides valuable guidance for designing multi-stage fractured horizontal wells in the field. In the future, this research will be extended by exploring the optimal fracture distribution function under different formation conditions.

Application of Micro-Seismic Monitoring in Post-Fracturing Evaluation of Shale Gas: A Case Study of Well X from Puguang Area, China

Multi-stage fracturing of horizontal wells is an indispensable technology to create complex fracture networks, which can unlock production potential and enable commercial productivity for shale gas with low porosity and permeability. Real-time monitoring of fracture networks is essential for adjusting key parameters, mitigating fracturing risks, and achieving optimal fracturing effects. Micro-seismic monitoring technology accurately captures and describes the development of fracture networks by detecting micro-seismic waves generated through rock ruptures, providing valuable insights into the evaluation of post-fracturing. In this study, we first introduced the basic parameters of well X that were obtained by laboratory experiments and logging interpretation, including porosity, gas-bearing properties, mineral composition, rock mechanics, and crustal stress. Then, the hydraulic fracturing scheme was designed on the basis of the geological engineering characteristics of well X. Finally, we conducted a comprehensive analysis of various factors that can affect hydraulic fracturing. This included an examination of the impact of pre-fluid temporary plugging and fracture complexity on the overall effectiveness of the operation. Based on the laboratory experiments and theoretical analysis, the following conclusions can be drawn: (1) fracture size is essentially formed when the fluid strength exceeds 35 m3/m; (2) both preflush with high viscosity and the amount of power sand exceeding 20 cubic meters are conducive to the propagation of fracture height; (3) temporary plugging balls facilitate the balanced propagation of multiple fracture clusters within a stage, whereas temporary plugging particles promote the formation of complex fractures; and (4) geological conditions are a prerequisite for creating a complex network of fractures, and only engineering techniques can facilitate the appropriate enhancement of fracture complexity. This study provides an essential method for the fracturing design of shale gas.

Productivity Analysis and Evaluation of Fault-Fracture Zones Controlled by Complex Fracture Networks in Tight Reservoirs: A Case Study of Xujiahe Formation

The development of tight gas reservoirs presents a significant challenge for sustainable development, as it requires specialized techniques that can have adverse environmental and social impacts. To address these challenges, efficient development technologies, such as multistage hydraulic fracturing, have been adopted to enable access to previously inaccessible natural gas resources, increase energy efficiency and security, and minimizing environmental impacts. This paper proposes a novel evaluation method to analyze the post fracturing productivity controlled by complex fault fracture zones in tight reservoirs. In this article, a systematic method to evaluate stimulated reservoir volume (SRV) and fault-fracture zone complexity after stimulation was established, along with the analysis and prediction of productivity through coupled fall-off and well-test analyses. Focusing on the Xujiahe formation in the Tongnanba anticline of northeastern Sichuan Basin, a 3D geological model was developed to analyze planar heterogeneity. The fall-off analytical model, coupled with rock mechanical parameters and fracturing parameters such as injection rates, fracturing fluid viscosity, and the number of clusters within a single stage, was established to investigate the fracture geometric parameters and complexities of each stage. The trilinear flow model was used to solve the well-test analysis model of multi-stage fractured horizontal wells in tight sandstone gas reservoirs, and well-test curves of the heterogeneous tight sandstone gas fracture network model were obtained. The results show that hydraulic fractures connect the natural fractures in fault-fracture zones. An analysis of the relationship between the fracture geometric outcomes of each segment and the net pressure reveals that as the net pressure in the fracture increases, the area ratio of natural fractures to main fractures increases notably, whereas the half length of the main fracture exhibits a decreasing trend. The overall area of natural fractures following stimulation is 7.64 times greater than that of the main fractures and is mainly a result of the extensive development of natural fractures in the target interval. As the opening ratio of natural fractures increases, the length of the main fractures decreases accordingly. Therefore, increasing net pressure within fractures will significantly enhance the complexity of fracturing fractures in shale gas reservoirs. Furthermore, the initial production of Well X1–10, which is largely controlled by fault-fracture zones, and the cumulative gas production after one year, are estimated. The systematic evaluation method in this study proposed a new way to accurately measure fracturing in tight reservoirs, which is a critical and helpful component of sustainable development in the natural gas industry.

Pressure transient analysis for multi-stage fractured horizontal wells considering threshold pressure gradient and stress sensitivity in tight sandstone gas reservoirs

Tight sand gas reservoirs are characterized with low porosity and low permeability. The threshold pressure gradient (TPG) and stress sensitivity effect are particularly apparent during gas production in tight sand gas reservoirs, causing the pressure transient analysis (PTA) curves of multi-stage fracturing horizontal wells (MFHWs) in tight sand gas reservoirs to be abnormally upward and making it challenging to match current PTA models. Therefore, in this work, a new PTA model for MFHW considering TPG and stress sensitivity was established. Based on the point source function, a semi-analytical solution of the model could be obtained using the properties of series function, variable substitution, perturbation technique, Poisson superposition formula, Laplace transform, and numerical inversion. Moreover, the effects of TPG, stress sensitivity, well parameters, and fracture parameters on the PTA curves were analyzed. Overall, we believe that the results of this study can guide the pressure transient analysis of MFHWs in tight sand gas reservoirs and provide help for engineers with regard to evaluating the parameters of reservoirs and fractures more accurately.

Effects of CH4/CO2 multi-component gas on components and properties of tight oil during CO2 utilization and storage: Physical experiment and composition numerical simulation

An essential technology of carbon capture, utilization and storage-enhanced oil recovery (CCUS-EOR) for tight oil reservoirs is CO2 huff-puff followed by associated produced gas reinjection. In this paper, the effects of multi-component gas on the properties and components of tight oil are studied. First, the core displacement experiments using the CH4/CO2 multi-component gas are conducted to determine the oil displacement efficiency under different CO2 and CH4 ratios. Then, a viscometer and a liquid density balance are used to investigate the change characteristics of oil viscosity and density after multi-component gas displacement with different CO2 and CH4 ratios. In addition, a laboratory scale numerical model is established to validate the experimental results. Finally, a composition model of multi-stage fractured horizontal well in tight oil reservoir considering nano-confinement effects is established to investigate the effects of multi-component gas on the components of produced dead oil and formation crude oil. The experimental results show that the oil displacement efficiency of multi-component gas displacement is greater than that of single-component gas displacement. The CH4 decreases the viscosity and density of light oil, while CO2 decreases the viscosity but increases the density. And the numerical simulation results show that CO2 extracts more heavy components from the liquid phase into the vapor phase, while CH4 extracts more light components from the liquid phase into the vapor phase during cyclic gas injection. The multi-component gas can extract both the light components and the heavy components from oil, and the balanced production of each component can be achieved by using multi-component gas huff-puff.

RTA-Assisted Numerical History-Matching Workflow

Summary Due to strong nonlinearities in the governing diffusivity equation for flow in porous media, numerically assisted rate-transient analysis (RTA) techniques have been suggested for the analysis of multiphase production data from multifractured horizontal wells (MFHWs). However, these methods are based on some limiting assumptions that cannot be generalized for three-phase flow or when relative permeability is unknown. In this study, a new RTA-assisted history-matching technique is proposed to simultaneously match production data and diagnostic plots during the calibration process. In the proposed method, the objective function is modified to include the derivative of the integral of rate-normalized pressure for the primary phases. As such, in the history-matching process using compositional numerical simulation, the flow regimes are also matched, which can increase the reliability of the calibrated numerical model. This approach is applied to a challenging data set of production data from an MFHW completed in a Canadian shale reservoir hosting a near-critical gas condensate fluid. The results demonstrate that when the modified objective function is used, the history-matching scheme will reject models that cannot reproduce the flow regimes even if the production data are visually matched. Another benefit of this modified history-matching workflow is that, unlike other numerically assisted RTA techniques, it is not limited to any specific conceptual model or reservoir geometry. Further, interactions between parameters are accounted for during the calibration process. Including the derivative terms in the objective function can ensure a better history-matched model with improved forecast quality. However, comparing the convergence rates of the history-matching with the standard and modified objective functions indicates that adding the derivative terms comes with an additional computational cost requiring more iterations and a slower convergence rate. In this study, a modified objective function is introduced for the first time to enhance the numerical history-matching process to ensure the resulting calibrated model can also reproduce the observed transient flow regimes. This approach is easy to implement and is not limited to a specific model geometry or any input-output relationship.

A Productivity Prediction Model for Multistage Fractured Horizontal Wells in Shale Gas Reservoirs

The tiny sizes of pores and throats in shale gas reservoir increase the complexities of the flow mechanisms, which challenge the accuracy of current productivity models during optimization design and prediction for multistage fractured horizontal wells (MFHWs). This paper established a productivity prediction model for MFHWs with cased hole completion and open hole completion. The model couples the gas flow in the matrix, fractures, and wellbore using potential superposition principle and considers multiple mechanisms of gas flows in a shale gas reservoir, such as stress-sensitive effect, wellbore friction, as well as interference between fractures. Based on the developed model, a productivity prediction method for MFHWs in shale gas reservoirs has been established, and sensitivity of the impact factors on productivity was analyzed. The analysis revealed that MFHWs are suitable for shale gas reservoirs with certain thickness. The number of fractures has significant impact on the production of shale gas reservoir. And the fractures at the both sides have higher production rate than the intermediate ones for multistage fractured horizontal wells. The fracture half-length has insignificant effect on the productivity of MFHWs. The production of shale gas reservoir also increases with pressure drop. The wellbore friction has insignificant effect on the production of MFHWs. The findings of this study can provide a basis for scientific evaluation of the production of MFHWs in shale gas reservoirs.

A three-dimensional numerical pressure transient analysis model for fractured horizontal wells in shale gas reservoirs

Shale gas development has greatly contributed to the world's energy supply. Pressure transient analysis (PTA) has extremely helped the development of shale gas. In this paper, a three-dimensional numerical model for transient pressure analysis of multi-stage fractured horizontal wells (MFHWs) in shale gas reservoirs was proposed, which was based on the embedded discrete fracture model (EDFM). The adsorption effect of shale gas, stress sensitivity of shale reservoir, and high-velocity non-Darcy flow in fractures were considered in this model, and the model was solved by Matlab Reservoir Simulation Tool (MRST). The discrete process of governing equations is described in detail, the typical MFHW pressure transient response curve of a shale gas reservoir was obtained, different flow regimes were divided, and three-dimensional pressure distribution profile of different flow stages were drawn to clearly understand the flow states of shale gas in the reservoir. The effects of different flow mechanisms and fracture properties on the log–log curves of the MFHW pressure transient response were analyzed in detail. The numerical PTA model proposed in this paper not only considers a variety of complex flow mechanisms of shale gas, but also accurately describes the characteristics of complex fracture network of shale reservoirs in three-dimensional conditions through EDFM. In addition, the problems of the incomplete description of shale gas flow stages by conventional analytical methods and semi-analytical methods were avoided through the numerical solution. The pressure response behavior of fluid in shale gas reservoir can be better explained by using this model, which helps to reduce the uncertainty of shale reservoir development.

Upscaling simulation method of fluid flow for fracturing-shut in-flowback-production process in tight oil reservoirs: Hysteresis effects of capillary pressure and relative permeability

The hysteresis effect is a key factor to accurately predict the fluid distribution and production performance of fracturing-shut in-flowback-production (FSFP) process in tight oil reservoirs. In this paper, the upscaling simulation method of fluid flow for FSFP process has been proposed. This method, which establishes the connections between the pore network model (PNM) and the reservoir numerical model, not only effectively characterizes the hysteresis effects of capillary pressure and relative permeability in tight oil reservoirs, but also realizes the upscaling process from the pore-throat scale to the reservoir scale. First, the quasi-static pore network model for tight oil reservoirs considering the boundary layer has been established. And then, the capillary pressure curves and relative permeability curves of the drainage process (non-wetting phase displacing wetting phase process) and imbibition process (wetting phase displacing non-wetting phase process) have been obtained. Moreover, the hysteresis model has been added to numerical simulation of FSFP process and the hysteresis scanning curves have been calculated. Finally, a numerical model considering different hysteresis effects for multistage-fractured horizontal well of a tight oil reservoir located at Ordos Basin, China, has been established to investigate the oil saturation change and oil recovery during the whole process of FSFP. The results show that the hysteresis effects of capillary pressure and relative permeability will increase the predicted exchange volume of oil-water between matrixes and fractures in fracturing-shut in process, and decrease the predicted oil recovery in flowback-production process. Which is proved by the actual production performance of the tight oil reservoir developed by elastic energy.

Enhanced Gas Production from Class II Gas Hydrate Reservoirs by the Multistage Fractured Horizontal Well

In the two test productions that have been conducted in the hydrate reservoir test development zone in the South China Sea, the gas production capacity of single wells is low and the exploitation difficulty with the cost is too high for commercial demand economically. The low permeability of the hydrate-bearing layer (HBL) acts as the major barrier for pressure propagation during depressurization. Hydraulic fracturing by the combined depressurization is considered a promising hydrate production enhancement technology that can effectively improve the seepage state in the reservoir. In this study, to evaluate the effectiveness of the development methods association with fracturing, we established an idealized Class II hydrate reservoir and studied it using a multi-stage fractured horizontal well to assist in depressurization extraction. In order to evaluate the production enhancement effect of this method, we compared the gas production results of four methods, including single vertical well, vertical fractured well, horizontal well, and multistage fractured horizontal well through numerical simulation. In order to investigate the influence of key fracture parameters on the production enhancement effect, a sensitivity analysis of the production effect of Class II hydrate reservoirs with different fracture spacing, number of fractures, fracture conductivity, and fracture length was conducted, and the results were analyzed in terms of gas production and water production behavior curves as well as physical field evolution over time. The simulation results show that the multi-stage fractured horizontal wells have the best production increase in the comparison of well types. In the analysis of fracture parameters, it can be found that the selection of proper fracture spacing and dimensionless fracture conductivity can lead to a significant increase in gas production.

A novel production data analysis method for multi-fractured horizontal wells with infill well-caused fracture interference

Tightening the well spacing for unconventional tight reservoirs is an efficient technique to enhance oil and gas recoveries. Infill well-caused fracture connection between wells is widely reported in the field with small well spacing. This will make it difficult to make formation evaluation and fracture characterization between wells compared to single well cases. In this paper, a novel production data analysis (PDA) method is proposed for fracture characterization with the consideration of interwell fracture connections after the hydraulic fracturing of the infill. The PDA method is based on a semianalytical model, in which the small-scaled fractures are treated with the concept of stimulated reservoir volume (SRV). Thus, the fracture connections between wells are classified into three types, including SRV, fractures, and both SRV and fractures. The physical model is discretized into several linear flow regions, so the mathematical model can be solved semianalytically. An integrated workflow is proposed to analyze the production data for the wellpad, and three steps are mainly included in the workflow, including PDA for the parent well before infill, PDA for the parent well after infill, and PDA for the infill well. In each step, the production performance in the early linear and bilinear flow regimes are analyzed with approximate solutions in the square and fourth root-of-time plots. Because only the relationship between unknown model parameters can be obtained with the approximate solutions, history matching to the production data in log-log plots is further used to determine each unknown parameter. The PDA method is benchmarked with a synthetic case generated by the numerical simulator tNavigator and a field case from Southwestern China. The results show that both good matches and precise parameters can be obtained with the proposed PDA method. The connected fracture number will not be sensitive in PDA when the wells are connected with high-conductive dSRV. The innovation of this paper is that a practical method is provided for PDA analysis of well groups with fracture connection, and it will be a good technique for fracture characterization and well-interference analysis for tight formations.

A new approach for flow simulation in complex hydraulic fracture morphology and its application: Fracture connection element method

Efficient flow simulation and optimization methods of hydraulic fracture morphology in unconventional reservoirs are effective ways to enhance oil/gas recovery. Based on the connection element method (CEM) and distribution of stimulated reservoir volume, the complex hydraulic fracture morphology was accurately described using heterogeneous node connection system. Then a new fracture connection element method (FCEM) for fluid flow in stimulated unconventional reservoirs with complex hydraulic fracture morphology was proposed. In the proposed FCEM, the arrangement of dense nodes in the stimulated area and sparse nodes in the unstimulated area ensures the calculation accuracy and efficiency. The key parameter, transmissibility, was also modified according to the strong heterogeneity of stimulated reservoirs. The finite difference and semi-analytical tracking were used to accurately solve the pressure and saturation distribution between nodes. The FCEM is validated by comparing with traditional numerical simulation method, and the results show that the bottom hole pressure simulated by the FCEM is consistent with the results from traditional numerical simulation method, and the matching rate is larger than 95%. The proposed FCEM was also used in the optimization of fracturing parameters by coupling the hydraulic fracture propagation method and intelligent optimization algorithm. The integrated intelligent optimization approach for multi-parameters, such as perforation number, perforation location, and displacement in hydraulic fracturing is proposed. The proposed approach was applied in a shale gas reservoir, and the result shows that the optimized perforation location and morphology distribution are related to the distribution of porosity/permeability. When the perforation location and displacement are optimized with the same fracture number, NPV increases by 70.58%, which greatly improves the economic benefits of unconventional reservoirs. This work provides a new way for flow simulation and optimization of hydraulic fracture morphology of multi-fractured horizontal wells in unconventional reservoirs.

Optimization of Fracturing Parameters by Modified Genetic Algorithm in Shale Gas Reservoir

Shale gas reservoirs have extremely low porosity and permeability, making them challenging to exploit. The best method for increasing recovery in shale gas reservoirs is horizontal well fracturing technology. Hence, fracturing parameter optimization is necessary to enhance shale gas horizontal fracturing well production. Traditional optimization methods, however, cannot meet the requirements for overall optimization of fracturing parameters. As for intelligent optimization algorithms, most have excellent global search capability but incur high computation costs, which limits their usefulness in real-world engineering applications. Thus, a modified genetic algorithm combined based on the Spearman correlation coefficient (SGA) is proposed to achieve the rapid optimization of fracturing parameters. SGA determines the crossover and mutation rates by calculating the Spearman correlation coefficient instead of randomly determining the rates like GA does, so that it could quickly converge to the optimal solution. Within a particular optimization time, SGA could perform better than GA. In this study, a production prediction model is established by the XGBoost algorithm based on the dataset obtained by simulating the shale gas multistage fracturing horizontal well development. The result shows that the XGBoost model performs well in predicting shale gas fracturing horizontal well production. Based on the trained XGBoost model, GA, SGA, and SGD were used to optimize the fracturing parameters with the 30-day cumulative production as the optimization objective. This process has conducted nine fracturing parameter optimization tests under different porosity and permeability conditions. The results show that, compared with GA and SGD, SGA has faster speed and higher accuracy. This study’s findings can help optimize the fracturing parameters faster, resulting in improving the production of shale gas fracturing horizontal wells.

Performance forecasting of hydraulically fractured horizontal wells using dynamic-drainage-area concept with correct distance of investigation

Performance forecasting of multi-fractured horizontal wells (MFHWs) completed in tight/shale oil or gas reservoirs is of great significance in the development of unconventional resources. Dynamic drainage area (DDA) concept has emerged as a production forecasting methodology for unconventional reservoirs. This paper investigated the DDA method and derived correct expressions of distance of investigation (DOI) for both constant production rate and constant bottom-hole pressure cases by integrating material balance and deliverability equation within the range of DOI. The modified DDA method with correct DOI coefficients provided in this paper permits direct calculation of dynamic performance at arbitrary time steps before the end of transient linear flow. At the same time smooth production forecasting of MFHWs from transient linear to boundary-dominated flow is realized without modification by extra coefficient. Hybrid models such as DDA plus dual-exponential and DDA plus hyperbolic are presented, which can be applied quickly and easily to MFHWs in unconventional reservoirs as alternatives to complex numerical simulation. Meanwhile, average pressure in the range of DDA can be readily obtained with correct DOI coefficients, avoiding complex iterative calculations. The reliability and practicability of this solution have been demonstrated by synthetic and field cases in this work.

A practical analytical model for performance prediction in unconventional gas reservoir

Ninety percentage of newly proven natural gas reservoirs of China are mainly unconventional resources, which can be typically developed by multi-stage fracturing horizontal well technology. Two regions typically occur near each fracture after hydraulic fracturing, in which the lower permeability region is considered as the storage source and the higher permeability region as the flow channel. The existed analytical models so far are mainly derived by Laplace transforming. In this paper, an improved practical analytical solution is derived for unconventional gas reservoirs bypassing the Laplace transform and numerical inversion. Through solving material balance equation and adopting the integration, a rate vs. pseudo-time solution in real-time domain can be directly obtained. Five numerical cases are created to verify the accuracy of the proposed analytical solution and the ratio of regular/irregular region pore volume is also proved to be derived reversely by the output parameters, which is significant for the field engineers to evaluate the effect of hydraulic fracturing. Moreover, a field example of a multi-fractured horizontal well in a tight gas reservoir is provided for demonstrate application.

Data-Driven Inversion-Free Workflow of Well Performance Forecast Under Uncertainty for Fractured Shale Gas Reservoirs

Abstract Well performance prediction and uncertainty quantification of fractured shale reservoir are crucial aspects of efficient development and economic management of unconventional oil and gas resources. The uncertainty related to the characterization of fracture topology is highly difficult to be quantified by the conventional model-based history matching procedure in practical applications. Data-space inversion (DSI) is a recently developed inversion-free and rapid forecast approach that directly samples the posterior distribution of quantities of interest using only prior model simulation results and historical data. This paper presents some comparative studies between a recent DSI implementation based on iterative ensemble smoother (DSI-IES), model-based history matching, and conventional decline curve analysis (DCA) for shale gas rate forecast. The DSI-IES method treats the shale gas production rate as target variables, which are directly predicted via conditioning to historical data. Dimensionality reduction is also used to regularize the time-series production data by low-order representation. This approach is tested on two examples with increasing complexity, e.g., a fractured vertical well and a multistage fractured horizontal well in the actual fractured Barnett shale reservoir. The results indicate that compared with the traditional history matching and DCA methods, the DSI-IES obtains high robustness with a high computational efficiency. The application of data-space inversion-free method can effectively tap the potential value directly from historical data, which provides theoretical guidance and technical support for rapid decision-making and risk assessment.

A two-phase type-curve method with multiscale fluid transport mechanisms in hydraulically fractured shale reservoirs

The quantitative understanding of hydraulic fracture (HF) properties guides accurate production forecasts and reserve estimation. Type curve is a powerful technique to characterize HF and reservoir properties from flowback and long-term production data. However, two-phase flow of water and hydrocarbon after an HF stimulation together with the complex transport mechanisms in shale nanopores exacerbate the nonlinearity of the transport equation, causing errors in type-curve analysis. Accordingly, we propose a new two-phase type-curve method to estimate HF properties, such as HF volume and permeability of fracture, through the analysis of flowback data of multi-fractured shale wells. The proposed type curve is based on a semianalytical solution that couples the two-phase flow from the matrix with the flow in HF by incorporating matrix influx, slippage effect, stress dependence, and the spatial variation of fluid properties in inorganic and organic pores. For the first time, multiple fluid transport mechanisms are considered into two-phase type-curve analysis for shale reservoirs. We analyze the flowback data from a multi-fractured horizontal well in a shale gas reservoir to verify the field application of the proposed method. The results show that the fracture properties calculated by the type-curve method are in good agreement with the long-time production data.

Dynamic Productivity Prediction Method of Shale Condensate Gas Reservoir Based on Convolution Equation

The dynamic productivity prediction of shale condensate gas reservoirs is of great significance to the optimization of stimulation measures. Therefore, in this study, a dynamic productivity prediction method for shale condensate gas reservoirs based on a convolution equation is proposed. The method has been used to predict the dynamic production of 10 multi-stage fractured horizontal wells in the Duvernay shale condensate gas reservoir. The results show that flow-rate deconvolution algorithms can greatly improve the fitting effect of the Blasingame production decline curve when applied to the analysis of unstable production of shale gas condensate reservoirs. Compared with the production decline analysis method in commercial software HIS Harmony RTA, the productivity prediction method based on a convolution equation of shale condensate gas reservoirs has better fitting affect and higher accuracy of recoverable reserves prediction. Compared with the actual production, the error of production predicted by the convolution equation is generally within 10%. This means it is a fast and accurate method. This study enriches the productivity prediction methods of shale condensate gas reservoirs and has important practical significance for the productivity prediction and stimulation optimization of shale condensate gas reservoirs.

Well interference evaluation considering complex fracture networks through pressure and rate transient analysis in unconventional reservoirs

Severe well interference through complex fracture networks (CFNs) can be observed among multi-well pads in low permeability reservoirs. The well interference analysis between multi-fractured horizontal wells (MFHWs) is vitally important for reservoir effective development. Well interference has been historically investigated by pressure transient analysis, while it has shown that rate transient analysis has great potential in well interference diagnosis. However, the impact of complex fracture networks (CFNs) on rate transient behavior of parent well and child well in unconventional reservoirs is still not clear. To further investigate, this paper develops an integrated approach combining pressure and rate transient analysis for well interference diagnosis considering CFNs. To perform multi-well simulation considering CFNs, non-intrusive embedded discrete fracture model approach was applied for coupling fracture with reservoir models. The impact of CFN including natural fractures and frac-hits on pressure and rate transient behavior in multi-well system was investigated. On a log–log plot, interference flow and compound linear flow are two new flow regimes caused by nearby producers. When both NFs and frac-hits are present in the reservoir, frac-hits have a greater impact on well #1 which contains frac-hits, and NFs have greater impact on well #3 which does not have frac-hits. For all well producing circumstances, it might be challenging to see divergence during pseudosteady state flow brought on by frac-hits on the log–log plot. Besides, when NFs occur, reservoir depletion becomes noticeable in comparison to frac-hits in pressure distribution. Application of this integrated approach demonstrates that it works well to characterize the well interference among different multi-fractured horizontal wells in a well pad. Better reservoir evaluation can be acquired based on the new features observed in the novel model, demonstrating the practicability of the proposed approach. The findings of this study can help for better evaluating well interference degree in multi-well systems combing PTA and RTA, which can reduce the uncertainty and improve the accuracy of the well interference analysis based on both field pressure and rate data.

Principal characteristics of marine shale gas, and the theory and technology of its exploration and development in China

The exploration and development theory and technology of marine shale gas with shallow burial depth of 3500 m in South China has become mature after more than 10 years of practice. In order to continuously promote the exploration and development of shale gas in China, based on the research results of many scholars, combined with production practice, the main characteristics of marine shale gas in China and the main theory and technology of exploration and development are further summarized. The results show that: (1) The basic characteristics of marine shale gas in southern China are marine deep-water shelf deposition, and organic-rich shale is distributed continuously in a large area; The organic matter is stored in situ after high thermal maturity gas generation, and the gas content of shale is affected by late tectonic activity; The reservoir space is dominated by nano-scale pores, and the reservoir is super-tight and ultra-low permeability, which has no natural productivity without well stimulation; Bedding and natural fracture affect the productivity of shale gas wells; The mechanical properties of shale rock determine the effect of horizontal wells. In the early stage of well production, the production rate is high and the decline is fast, while in the middle and late stage, the rate is low but the production cycle is long. (2) Based on the above characteristics, the theory of “sweet spot” and “sweet interval” of shale gas and the theory of effective development of artificial gas reservoir are established, that is, the sedimentary and tectonic interaction forms the “sweet area” or “sweet spot” of marine shale gas. Gas productivity is determined by geological and engineering factors, so the “sweet spot” must be found to develop. By constructing artificial gas reservoir through “making an artificial high permeability area, and reconstructing a seepage field”, the effective development of ultra-tight and low permeability shale gas reservoirs can be realized. It is the most effective technique for shale gas development to accurately create “transparent geological body” of reservoirs based on geology-engineering integrated evaluation technology and establish artificial gas reservoir through multi-stage fracturing technology. (3) The overpressure area in the southern Sichuan Basin is the “sweet area” for shale gas development. The “sweet interval” of the lower Silurian Longmaxi Formation with a thickness of 3–5 m and high brittle-rich organic matter is the optimal “golden target” for horizontal wells. (4) The development leapfrog from the first generation to the second generation has been realized by the key technology of multi-stage fracturing of horizontal wells. The EUR per well of Upper Ordovician Wufeng Formation and Longmaxi Formation in southern Sichuan has increased from 0.5 × 108 m3 in the initial stage to 1.0 × 108–1.2 × 108 m3 at present with a buried depth of shallower than 3500 m. (5) The effective area favorable for shale gas development in southern Sichuan is 2.0 × 104 km2, and it is estimated that the proven geological reserves of shale gas can reach 10 × 1012 m3. It is preliminarily predicted that the shale gas production in China will exceed 300 × 108 m3 in 2025 and reach 400 × 108 m3 in 2035.