Effective Stimulated Reservoir Volume Research Articles

Shale gas effective fracture network volume prediction and analysis based on flow back data: A case study of southern Sichuan Basin shale

Fracture network fracturing is the key technology to achieve the economic and effective development of shale gas, and the fracturing stimulation performance is seriously affected by the connectivity of fracture network. The effective stimulated reservoir volume is affected by many factors such as geological and engineering. But the current control factors affecting the effective fractures network volume (EFNV) are not well understood, resulting in blindness in the construction of high-quality effective fracture network. Thus, a new method is proposed for predicting the EFNV of shale gas under multiple factors. The EFNV of the field fracturing well was calculated based on the two-phase flow back model, which was established to invert the effective fracture network volume. Taking this inversion result as the goal, a prediction model of EFNV based on genetic expression programming (GEP) was developed, and the influence of influencing factors on the EFNV is analyzed quantitatively. The results show that with the cluster spacing and Poisson's ratio increase, the EFNV shows a downward trend. The increase of liquid strength, single-stage clusters, brittleness index, displacement and Young's modulus promotes the formation of EFNV. The optimal reservoir stimulation performance can be obtained by optimizing the fracturing operation parameters.

Prediction of effective stimulated reservoir volume after hydraulic fracturing utilizing deep learning

It is very important to utilize hydraulic fracturing for unconventional reservoir development. Accurate prediction of effective stimulated reservoir volume (SRV) after fracturing facilitates production evaluation. However, the traditional methods to predict SRV are time consuming and the precision cannot fully meet the requirements. To overcome the shortcomings, a new approach was presented using deep learning which includes four procedures. Firstly, the datasets were collected by numerical simulation considering non-Darcy flow characteristics. Additionally, the Branched Deep Neural Network model (B-DNN) was established after data fusion through adding a branch neural network. Then the optimal hyperparameters were obtained after adjusting to satisfy model accuracy and reliability. Finally, the prediction results of B-DNN and convolutional neural network (CNN) and recurrent neural network (RNN) were compared. The results show that the model with Softplus activation function, four hidden layers, and 250 neurons in each layer would have the best calculation results. The proposed model has good agreement with actual field data which can reach 97%. Furthermore, compared with the CNN and RNN models, it is shown that the B-DNN model has considerable prediction accuracy and is less time-consuming. This deep learning model provides new insight for production evaluation in the fractured tight oil reservoir.

Fracture Interference and Refracturing of Horizontal Wells

Due to fracture interference, not all perforations can be fractured, resulting in 20% of fractures contributing to 80% of the total production. The extraction of oil and gas also reduces production, necessitating refracturing. In this study, the finite element method was used to simulate multiple fractures fracturing simultaneously and the stress field distribution was then extracted and applied to a new geological model. This paper explains the effect of stress around the horizontal wellbore on new fractures during the refracturing of old wells using a temporary plugging technique. The results show that initial breaking pressures are the same, but as fractures extend, inter-fracture interference increases, resulting in different fracture extension pressures and widths. The fracturing fluid is filtered into the reservoir matrix after fracturing, reducing formation stress. Compared with fracturing at the initial fracture site, reperforating fracturing has a lower fracture extension pressure and a longer fracture length. According to this study, hydraulic fractures have a 15 m effective influence radius on the external formation. Stress relief is beneficial for fracture initiation prior to refracturing. Reperforating and fracturing, in combination with temporary plugging technology, can assist in increasing the effective stimulated reservoir volume and achieving high and stable production.

A mathematical model for estimating effective stimulated reservoir volume

This study presents a model application for the evaluation of Effective Stimulated Reservoir Volume (ESRV) in shale gas reservoirs. This current model is faster, cheaper, and readily available for estimating ESRV compared to previously published models. Key controlling parameters for efficient ESRV modeling, including geomechanical parameters and time, are considered for the model development. The model was validated for both single and multi-stage fractured reservoirs. For the single fractured reservoir, an ESRV of 3.07 × 106 ft3 was estimated against 3.99 × 106 ft3 of ESRV-FEM field data. Whereas, 7.00 × 109 ft3 ESRV was estimated from the multi-stage fractured reservoir against 7.90 × 109 ft3 of fractal-based model results. Stress dependence, time dependence, and permeability dependence of shale gas reservoirs are found to be essential parameters for the successful calculation of ESRV in reservoirs. An ESRV determined using this method can obtain the estimated ultimate recovery, propped volume, optimal fracture length, and spacing in fractured shale gas reservoirs.

Production Decline Analysis and Hydraulic Fracture Network Interpretation Method for Shale Gas with Consideration of Fracturing Fluid Flowback Data

After multistage hydraulic fracturing of shale gas reservoir, a complex fracture network is formed near the horizontal wellbore. In postfracturing flowback and early-time production period, gas and water two-phase flow usually occurs in the hydraulic fracture due to the retention of a large amount of fracturing fluid in the fracture. In order to accurately interpret the key parameters of hydraulic fracture network, it is necessary to establish a production decline analysis method considering fracturing fluid flowback in shale gas reservoirs. On this basis, an uncertain fracture network model was established by integrating geological, fracturing treatment, flowback, and early-time production data. By identifying typical flow-regimes and correcting the fracture network model with history matching, a set of production decline analysis and fracture network interpretation method with consideration of fracturing fluid flowback in shale gas reservoir was formed. Derived from the case analysis of a typical fractured horizontal well in shale gas reservoirs, the interpretation results show that the total length of hydraulic fractures is 4887.6 m, the average half-length of hydraulic fracture in each stage is 93.4 m, the average fracture conductivity is 69.7 mD·m, the stimulated reservoir volume (SRV) is418×104 m3, and the permeability of SRV is5.2×10−4 mD. Compared with the interpretation results from microseismic monitoring data, the effective hydraulic fracture length obtained by integrated fracture network interpretation method proposed in this paper is 59% of that obtained from the microseismic monitoring data, and the effective SRV is 83% of that from the microseismic monitoring data. The results show that the fracture length is smaller and the fracture conductivity is larger without considering the influence of fracturing fluid.

Experimental Studies on Shale Cracks and Permeability Evolution Based on Acoustic Emission Monitoring

The matrix permeability of shale reservoirs is extremely low. Therefore, massive volume fracturing is needed to form a complex crack network and get adequate sufficient capacity during the well completion. After fracturing, the effective stimulated reservoir volume (ESRV) is vital for developing shale reservoirs, mainly determined by stimulated reservoir volume (SRV) and the increase in permeability. Microseismic monitoring is widely used in the field to describe the crack shape and determine the SRV, to evaluate the stimulation effect. However, no studies have been conducted on the relationship between microseismic parameters and permeability. Thereby, we conducted uniaxial compression tests on Longmaxi shale samples and measured their changes in porosity and permeability before and after loading combining the microseismic monitoring under a laboratory scale (acoustic emission (AE)). Results show that porosity has little influence on the permeability before and after loading, while the propagation and connection of cracks are the most critical factors. As the loading stress increases, the crack volume and sample connectivity both grow. Besides, for the Longmaxi shale, when the stress is loaded to 30~50% of uniaxial compressive strength (UCS), the cracks start to propagate steadily (dilation), the permeability begins to increase rapidly, and percolation occurs, which indicates that the dilation point is closely related to the percolation threshold. The AE rate and accumulative ringing number both increase when it is larger than the percolation threshold value. The variation of AE characteristics can be used to identify the percolation threshold. Finally, the graphic model including AE parameters, crack, and permeability evolution is established based on the experimental results, which could help us understand the relationship between microseismic parameters and permeability and provide a methodological basis for the ESRV evaluation in the field.

China’s Unconventional Challenge Spurs New Thinking on Shale and Tight Reservoirs

Despite possessing some of the world’s largest shale-gas resources, China is likely in 2020 to have produced less than half of the 30 Bcm per year in shale gas that the government set as a goal in its latest Five-Year Plan. While such a small volume may make shale production seem inconsequential to China’s overall energy balance, it is clear that when it comes to developing unconventional hydrocarbons, China is playing a long game. With regard to shale alone, a 2013 US Energy Information Administration study noted that China has the world’s second-largest technically recoverable shale-gas resources at an estimated 1,115 Tcf; the US is first with 1,161 Tcf. Even more to the point, China is one of only four countries (including the US, Canada, and Argentina) that produce commercial volumes of both shale gas and of tight oil. But it is the lack of efficient technologies and infrastructure that stand in the way of China besting the US and creating its own “shale revolution.” China’s most attractive reserves occur in remote, mountainous areas where, in some cases, shale resources can lie as deep as 3500 m. In separate papers presented in October during the 2020 SPE Russian Petroleum Technology Conference, the China National Petroleum Company (CNPC) detailed new technologies it is applying to meet some of these challenges. Paper SPE 202066, coauthored by subsidiaries of CNPC, Downhole Service Company and CCDC Petroleum Drilling & Technology Company Ltd., details the application of enhanced-hydraulic- fracturing technology (EHFT) to raise the effective stimulated reservoir volume (SRV) in the Sichuan shale basin. A second paper (SPE 202062), coauthored by CNPC and Halliburton, offers a case study in tight-oil production in Daqing employing an intensive fracture-cluster-completion strategy using a microemulsion flowback technology. The Spice in Sichuan Shale China boasts three shale basins (Sichuan, Tarim, and Yantze), but its principal development focus is in the southwestern province of Sichuan, which holds half of the country’s shale reserves. In developing fields such as Weiyuan, Changning, and Jiaoshiba, producers target the Ordovician Wufeng-Silurian Longmaxi formation. The total proved geological reserves of these three gas fields exceeds 500 Bcm, the authors noted in their paper. To develop infrastructure supporting industrial-scale operations and to introduce and test new technologies to raise shale output, China has established several national pilot demonstration areas. One of those is the Weiyuan national shale demonstration area in south Sichuan, where the authors quote an annual production of 2.5 Bcm. Staged horizontal fracturing is the main technology used at Weiyuan and other Chinese shale fields as producers strive to expand the fracture extension area, increase the reconstruction volume, and improve the productivity of single wells. An analysis of production data from Weiyuan showed, however, that the long-term conductivity of fractures is limited because the length and height of supporting fractures are short. Thus, because of the limited volume of reconstruction, production decreases rapidly and efficiency suffers as pressure declines.

Regularization to Stein unbiased risk estimation denoising and threshold for first-break picking to low signal-to-noise ratio of surface microseismic monitoring — Case of gas shale fracturing

With monitoring of the acoustic emission phenomenon caused by rock deformation and failure, microseismic monitoring has been widely used in the development of unconventional oil and gas fields. Due to the complex environment and diversity types of the noise, the signal energy of surface microseismic monitoring is weak and the signal-to-noise ratio (S/N) of raw data is very low. In the process of data processing, many human resources are needed to discriminate the first-break picking because of the low S/N, and this directly affects the error of microseismic event location. We have adopted the regularization to Stein unbiased risk estimation (R-SURE) algorithm based on the continuous wavelet transform to separate the signal from the noise in different decomposition levels. The regularization factor is the adaptive change of the different geology and fracturing engineering, which is related to shale brittleness, fracturing pressure, and displacement. As a result, the threshold from the R-SURE algorithm is multiresolution in different levels, and the S/N could be improved effectively. In addition, we established the threshold discriminant for picking up the first-break wave of low-S/N data combined with the Akaike information criterion and characteristic function, which compared the maximum absolute value in the time window. The method has good robustness and low computational complexity. The first arrival is automatically and accurately judged, which improves the accuracy of the event location. We successfully applied these methods to the surface microseismic monitoring of shale gas fracturing in several wells in southwest China. The S/N of the raw data has been improved, the effective stimulated reservoir volume and the performance of the gas production are predicted with the results, which provides important technical support for shale gas development in the area.

Post-flowback production data suggest oil drainage from a limited stimulated reservoir volume: An Eagle Ford shale-oil case

We analyze flowback and post-flowback production data from six multi-fractured horizontal wells completed in Eagle Ford shale formation. Petrophysical analysis of samples from an offset well shows that the target shale is in oil window with type II kerogen. We analyze two groups of wells with different well-completion and operational parameters. Wells fractured with slickwater, with higher total injected volume (TIV) and larger choke size show higher initial oil rate, but faster pressure depletion compared with the wells fractured with cross-linked gel, with lower TIV and smaller choke size. Both groups show supercharged fractures when flowback starts and reservoir pressure remains above bubble point during post-flowback period. Interestingly, rate-normalized pressure plots of oil and water from both groups during post-flowback period show pronounced unit slope indicating boundary dominated flow (BDF), while this trend is not observed during flowback period. Analysis of rate-normalized pressure and rate-decline data suggests that both oil and water are produced from a closed tank under BDF conditions. We propose a multiphase flowing material balance (FMB) model to describe water and oil production from an effective stimulated reservoir volume (ESRV) during post-flowback period. The proposed FMB model assumes negligible oil and water influx into ESRV. The driving forces considered are closure of fractures and expansion of oil and water in ESRV. Applying the proposed model on post-flowback data confirms that after fracture depletion, oil is produced from highly stimulated matrix around hydraulic fractures while water is mainly produced from fractures.

Experimental study on shale fracturing effect and fracture mechanism under different fracturing fluid viscosity: A case study of Guanyinqiao Member shale in Xishui, Guizhou, China

In this study, a series of laboratory fracturing experiments were conducted on samples mined from reservoirs of the Guanyinqiao Member shale in Xishui County, Guizhou Province, using a traditional triaxial fracturing simulation system. Based on the experimental results, the breakdown pressure and effective stimulated reservoir volume were obtained for four fracturing fluids (supercritical carbon dioxide, water, NO-sand, and sand). The fracture mechanism was then analyzed using acoustic emission monitoring data. Based on the curves of pressure vs injection time for different fracturing fluids, the breakdown pressure increased with increasing fracturing fluid viscosity. When sands with different viscosities were used as the fracturing fluid, the breakdown pressure first increased and then decreased with an increase in the sand viscosity. The distribution of the tracer or proppant was not only correlated with the fracturing effect, but also promotes the filling crack of the tracer and proppant at a certain viscosity as the best fracturing effect. During sand fracturing, the proppant mainly formed shear cracks. The results provide a valuable technical reference for shale gas mining.

A new concept for the extraction of gas from Permian ultra-deep coal seams of the Cooper Basin, Australia: Expanding Reservoir Boundary Theory

An alternative geomechanical reservoir boundary condition is proposed for ultra-deep coal seams of the Cooper Basin in central Australia. This new concept is embodied within the author’s ‘Expanding Reservoir Boundary (ERB) Theory’, which calls for a paradigm shift in gas extraction technology, diametrically opposed to current practices. As with shale, full-cycle, standalone commercial gas production from Cooper Basin ultra-deep coal seams requires a large stimulated reservoir volume (SRV) having high fracture surface area for gas desorption. This goal has not yet been achieved after 13 years of trials because, owing to the bipolar combination of shale-like reservoir properties and coal-like geomechanical properties, these poorly cleated, inertinitic coal seams exhibit ‘hybrid’ characteristics. Stimulation techniques adopted from other play types are incompatible with the highly unfavourable combination of nanoDarcy-scale permeability, ‘ductility’ and high stress. Nevertheless, gas flow potential counterintuitively increases with depth, contingent upon the creation of an effective SRV. Optimum reservoir conditions occur at depths beyond 9000 feet (2740 m), driven by dehydration, high gas content, gas oversaturation, overpressure and a rigid host rock framework. The physical response of ultra-deep coal seams and the surrounding host rock to pressure drawdown is inadequately characterised. It remains to be established how artificial fracture and coal fabric aperture width change due to the competition between desorption-induced coal matrix shrinkage and compaction caused by increasing effective stress. Studies by the author suggest that pressure arching may ultimately control gas extraction efficiency. Harnessing this geomechanical phenomenon could resolve the technical impasse that currently inhibits commercialisation. Pressure arching neutralises SRV compaction by deflecting stress to adjacent strata of greater integrity. These strata then function as an abutment for accommodating increased stress outside the SRV. This shielding effect allows producing ultra-deep coal seams to progressively de-stress and ‘self-fracture’ naturally, in an overall state of shrinkage-induced tensile failure. An ‘expanding reservoir boundary and decreasing confining stress’ condition is generated by the combined, mutually sustaining actions of coal matrix shrinkage and sympathetic pressure arch evolution. This causes the SRV to steadily increase in size and permeability. Cooper Basin ultra-deep coal seams may be effectively stimulated by harnessing this self-perpetuating, depth-resistant mechanism for creating permeability and surface area. The ultra-deep coal seams may be induced to pervasively ‘shatter’ or ‘self-fracture’ naturally during production, independent of ‘brittleness’, analogous to the manner in which shrinkage crack networks slowly form, in a state of intrinsic tension, within desiccating clay-rich surface sediment.

Fine calculation method for fracture morphology based on microseismic events and its application

AbstractMicroseismic monitoring is an effective method to interpret the morphological parameters of artificial fractures (length, height, and orientation), which is the key to the design of hydraulic fracturing. It is difficult to recognize effective fracture shape after fracturing by using microseismic monitoring data only, which results in a very confusing interpretation of fracture morphology that is quite different from reality. Therefore, in this study, we propose an innovative classification method based on the principal component analysis theory combined with fracturing operation parameters (proppant amount and volume) and derived theoretical formulas for calculating the correction coefficients (volume, length, and height) to optimize and describe fracture patterns finely. By applying 36 wells in Qie‐6 block of the Qinghai Oilfield, the microseismic monitoring events were identified, and the fracture morphology and effective stimulated reservoir volume (ESRV) were corrected. This method is a reliable technology for the interpretation of fracture morphology for field hydraulic fracturing construction.

Horizontal well fracturing mode of "increasing net pressure, promoting network fracture and keeping conductivity" for the stimulation of deep shale gas reservoirs: A case study of the Dingshan area in SE Sichuan Basin

The deep shale gas reservoirs of Upper Ordovician Wufeng–Lower Silurian Longmaxi Formation in the Dingshan area of the southeastern Sichuan Basin have a great burial depth and complicated geologic features, so the fracturing technologies that are used for medium–shallow shale gas reservoirs are not suitable for their stimulation. In this paper, "double sweet spot" zones of shale gas were selected by combining engineering and geological research. The horizontal well fracturing technology suitable for deep shale gas reservoir was developed. And the fracturing mode suitable for medium–shallow shale gas reservoirs was improved. In addition, the improved fracturing mode and technology were applied in 3 deep shale gas wells in the Dingshan area. And the following research results were obtained. First, the deep shale gas reservoirs in the northwest of the Dingshan area have the characteristics of "double sweet spot" of geology and fracturing, and the development of natural fractures and bedding fractures provides a favorable condition for the formation of complex fracture networks after fracturing. Second, a combined fracturing mode of "pre acid + gel + slickwater + gel" was developed for the "double sweet spot" zones. In this mode, high-viscosity slickwater is adopted to increase the proppant-transport ability of liquid and enhance the fracture-creating effect, the fracturing technology of "controlling the near and extending the far" can increase the effective stimulated reservoir volume far from the well, and the ultra-high pressure facility can increase the fracturing displacement and the net pressure in fractures. Third, after reservoir stimulation, 3 deep shale gas wells present remarkable stimulation results, and their shale gas production rate during the testing is in the range of 10.50 × 104–20.56 × 104 m3/d. In conclusion, the improved fracturing mode and technology can provide a technical method for the stimulation of deep shale gas reservoirs in the Dingshan area, as well as a support for the breakthrough of exploration and development of deep shale gas reservoirs.

ANALYTIC EVALUATION METHOD OF FRACTAL EFFECTIVE STIMULATED RESERVOIR VOLUME FOR FRACTURED WELLS IN UNCONVENTIONAL GAS RESERVOIRS

It has been proved that effective stimulated reservoir volume (ESRV) is a significant area dominant to the production of the fractured well in unconventional gas reservoirs. Although ESRV properties can be estimated based on the microseismic technology and the analysis of actual fracturing data, the operations are complicated and results are inaccurate. Due to the complex structure of stimulated reservoir volume (SRV) with fractal and chaotic characteristics, a fractal evaluation model for ESRV (ESRV-FEM) of fractured wells in unconventional gas (both tight and shale gas) reservoirs is developed. Multiple gas transport mechanisms, SRV and unstimulated reservoir volume (USRV) are included. According to the pressure transient analysis (PTA), influences of multiple transport mechanisms on gas transport behaviors in ESRV are conducted. Moreover, the fractal index representing the heterogeneity degree is applied to estimate the ESRV under different inter-porosity flow coefficients and storage ratio conditions based on the ESRV-FEM. In addition, the presented ESRV-FEM is validated by an actual field case. The results show that gas adsorption has a significant effect on the radial flow duration time in SRV, and the heterogeneity makes the radial flow on PTA curves no longer show a horizontal line with the value of 0.5. Calculated ESRV sizes are compared with the assumed ones under different fractal indexes. The stronger the heterogeneity, the smaller ESRV is. The ESRV size of a fractured well in shale gas reservoirs is only 52.11% of SRV size when the fractal index equals to 0.6. The ESRV-FEM presented in this paper is expected to provide an effective method for the evaluation of the ESRV of fractured wells in unconventional gas reservoirs.

Case Study for Effective Stimulated Reservoir Volume Identification in Unconventional Reservoirs

Case Study for Effective Stimulated Reservoir Volume Identification in Unconventional Reservoirs

APPLICATION OF FRACTAL GEOMETRY IN EVALUATION OF EFFECTIVE STIMULATED RESERVOIR VOLUME IN SHALE GAS RESERVOIRS

According to hydraulic-fracturing practices conducted in shale reservoirs, effective stimulated reservoir volume (ESRV) significantly affects the production of hydraulic fractured well. Therefore, estimating ESRV is an important prerequisite for confirming the success of hydraulic fracturing and predicting the production of hydraulic fracturing wells in shale reservoirs. However, ESRV calculation remains a longstanding challenge in hydraulic-fracturing operation. In considering fractal characteristics of the fracture network in stimulated reservoir volume (SRV), this paper introduces a fractal random-fracture-network algorithm for converting the microseismic data into fractal geometry. Five key parameters, including bifurcation direction, generating length ([Formula: see text]), deviation angle ([Formula: see text]), iteration times ([Formula: see text]) and generating rules, are proposed to quantitatively characterize fracture geometry. Furthermore, we introduce an orthogonal-fractures coupled dual-porosity-media representation elementary volume (REV) flow model to predict the volumetric flux of gas in shale reservoirs. On the basis of the migration of adsorbed gas in porous kerogen of REV with different fracture spaces, an ESRV criterion for shale reservoirs with SRV is proposed. Eventually, combining the ESRV criterion and fractal characteristic of a fracture network, we propose a new approach for evaluating ESRV in shale reservoirs. The approach has been used in the Eagle Ford shale gas reservoir, and results show that the fracture space has a measurable influence on migration of adsorbed gas. The fracture network can contribute to enhancement of the absorbed gas recovery ratio when the fracture space is less than 0.2 m. ESRV is evaluated in this paper, and results indicate that the ESRV accounts for 27.87% of the total SRV in shale gas reservoirs. This work is important and timely for evaluating fracturing effect and predicting production of hydraulic fracturing wells in shale reservoirs.

Overview and prospect of fracture propagation and conductivity characteristics in deep shale gas wells

There are tremendous shale gas resources in China, however, many of them can’t achieve economical production due to a lower effective stimulated reservoir volume (ESRV). Up to now, very few researches have been conducting on the mechanisms of fracture propagation and conductivity, which are the two main controlling factors of the effective development of shale gas play. As we all know that with the increasing depth of shale gas wells, many parameters such as in-situ stress, stress difference between minimal horizontal stress and maximal one, rock mechanics, etc. are all changed a simultaneously, which results in different fracture propagation and conductivity mechanisms. Therefore, firstly, a comprehensive analysis on fracture propagation and its conductivity characteristics in shallow wells were conducted. The mechanism of single fracture propagation and multiple fractures’ propagation simultaneously in open hole wells were summarized in detail. Besides, the effect of casing completion and fracturing treatment parameters on single fracture initiation and propagation was analyzed, and the corresponding results for multiple fractures may take references to that in open hole wells. Based on above studies, the mechanism of conductivity of single fracture and complex one in the condition of multiple affecting factors were analyzed too. After that, the proppant transport pattern within the complex fracture and its transportation law in divergent fracture were simulated, which may be used to optimize treatment parameters of hydraulically fracturing and achieve the object of expected conductivity and maximal ESRV. Finally, according to the formation geologic characteristics of deep shale gas play, the future research tendency was indicated, such as the mechanism of fracture propagation in the mode of well pad with multiple horizontal wells and multiple clusters, and in the condition of mixed natural fractures pattern with both horizontal interface and high angle fractures, the mechanism of high conductivity of network fracture formed by rock self-supported, which has great significance for developing deep shale gas play economically and effectively.

Volume fracturing of deep shale gas horizontal wells

Deep shale gas reservoirs buried underground with depth being more than 3500 m are characterized by high in-situ stress, large horizontal stress difference, complex distribution of bedding and natural cracks, and strong rock plasticity. Thus, during hydraulic fracturing, these reservoirs often reveal difficult fracture extension, low fracture complexity, low stimulated reservoir volume (SRV), low conductivity and fast decline, which hinder greatly the economic and effective development of deep shale gas. In this paper, a specific and feasible technique of volume fracturing of deep shale gas horizontal wells is presented. In addition to planar perforation, multi-scale fracturing, full-scale fracture filling, and control over extension of high-angle natural fractures, some supporting techniques are proposed, including multi-stage alternate injection (of acid fluid, slick water and gel) and the mixed- and small-grained proppant to be injected with variable viscosity and displacement. These techniques help to increase the effective stimulated reservoir volume (ESRV) for deep gas production. Some of the techniques have been successfully used in the fracturing of deep shale gas horizontal wells in Yongchuan, Weiyuan and southern Jiaoshiba blocks in the Sichuan Basin. As a result, Wells YY1HF and WY1HF yielded initially 14.1 × 104 m3/d and 17.5 × 104 m3/d after fracturing. The volume fracturing of deep shale gas horizontal well is meaningful in achieving the productivity of 50 × 108 m3 gas from the interval of 3500–4000 m in Phase II development of Fuling and also in commercial production of huge shale gas resources at a vertical depth of less than 6000 m.

The qualitative and quantitative fracture evaluation methodology in shale gas reservoir

Fracturing has been identified as a key method for unconventional reservoir development, and it enhances single well productivity and ultimate recovery. Most estimations of fracturing effect are limited to draw boxes around micro-seismic event maps, and add up the 3D volume where micro-seismic events are observed. But the observed volume always is larger which brings error for fracture evaluation. Meanwhile, there is lack of evaluation for the effective permeability, the fracture half-length, the effective stimulated reservoir volume, etc. This paper will present a new method to appraise and diagnose the fracture parameters for shale gas reservoirs qualitatively and quantitatively, which not only can determine the fracture geometry and volume but also determine the fracture parameters, such as effective permeability, fracture half-length, etc. The qualitative evaluation method is combined the relationship table between the fracture geometry and rock brittleness with different pressure response characteristics which can be used to determine the fracture geometry. Then the modern well test analysis method is applied to invert complex fracture parameters for realizing the quantitative evaluation. This method is applied in 3 shale gas wells, and the reasonable interpretation results are achieved with comparison and analysis. The field application results proved that it is a great methodology in shale gas reservoirs. It also can be expanded to other unconventional such as shale gas reservoirs.

Applying macroscopic material balance to evaluate interplay between dynamic drainage volume and well performance in tight formations

This study presents a novel approach to predict the production performance and evaluate the efficiency of fracturing stimulation. Despite the great success of fracturing operation in production from unconventional oil/gas resources, prediction of well performance is yet to be understood.We develop a mathematical model relating dynamic drainage volume and well deliverability in extremely low permeable formations. As the pressure disturbance created at the production well starts propagating throughout the reservoir, it will shape an expanding drainage volume; the boundaries of drainage volume are pushed back expanding the size of productive region as production continues. We treat the expanding drainage volume as moving boundary problem. In our mathematical model, the weak (integral) form of mass balance equation is written for the productive region. Fluids and rock compressibility, desorption parameters (for shale gas), and production rates are controlling the speed at which the boundaries are advancing.The calculated well deliverability is used to determine optimal fracturing spacing for wells completed in one of the oil shale plays in the United States. Two approaches are studied: 1) keep the original horizontal length and change the number of fracture clusters; 2) keep the original fracture spacing and change the horizontal length.For the wells studied here, changing the fracture spacing and the horizontal length result in various level of performance enhancement. Through the study, we determine the optimal parameters: optimal fracture spacing and optimal well spacing.The ultimate drainage volume (effective stimulated reservoir volume) and optimal fracture spacing can be obtained by the proposed method; therefore, neither comprehensive inputs required for the strong form (differential) nor any pre-knowledge about the productive region (shape, size,…) are needed for the new approach.