Fractured Shale Gas Research Articles

Productivity model of shale gas fractured horizontal well considering complex fracture morphology

Shale gas reservoir is characterized by complex pore structure, ultra-low permeability and a large number of natural fractures. Therefore, it is necessary to apply horizontal well drilling with hydraulic fracturing to stimulate the shale gas reservoirs by forming complex fractures network composed of main fractures (i.e., hydraulic fractures) and branch fractures (i.e., activated natural fractures). During shale gas fracturing, hydraulic fractures will initiate simultaneously, deflect under the stress interference with each other, activate adjacent natural fractures and connect with them. These complex behaviors of fractures propagation would greatly complicate the production prediction after shale gas fracturing. Currently, the majority of the production prediction models neglect the complexity of fractures network. Therefore, based on Fick's diffusion law, Langmuir isothermal adsorption equation and dual-medium seepage theory, this paper derived a productivity prediction model by considering complexity of fractures network, stress-sensitive effect and ad-desorption by using point source method, Duhamel principle and Laplace transform, and solved the model with perturbation theory, discrete superposition and Stehfest numerical inversion. Then, the production prediction model was verified by a field example analysis, and the influence of the morphology of main fractures and branch fractures on productivity is explored. It indicates that the main fracture shape has a great influence on the production, and the trapezoidal mode is closer to the production practice. The large deflection of main fractures, the high conductivity and large approaching angle of branch fractures are beneficial to improving the production of fractured shale gas horizontal wells.

Optimization of Shale Gas Fracturing Parameters Based on Artificial Intelligence Algorithm

Optimization of Shale Gas Fracturing Parameters Based on Artificial Intelligence Algorithm

A Comparison of Shale Gas Fracturing Based on Deep and Shallow Shale Reservoirs in the United States and China

China began to build its national shale gas demonstration area in 2012. The central exploration, drilling, and development technologies for medium and shallow marine shale reservoirs with less than 3,500 m of buried depth in Changning-Weiyuan, Zhaotong, and other regions had matured. In this study, we macroscopically investigated the development history of shale gas in the United States and China and compared the physical and mechanical conditions of deep and shallow reservoirs. The comparative results revealed that the main reasons for the order-ofmagnitude difference between China’s annual shale gas output and the United States could be attributed to three aspects: reservoir buried depth, reservoir physical and mechanical properties, and engineering technology level. The current engineering technology level of China could not meet the requirements of increasing production and reducing costs for deep shale gas reservoirs; they had reached the beneficial threshold development stage and lacked the capacity for large-scale commercial production. We identified several physical and mechanical reasons for this threshold development stage. Deep shale reservoirs were affected by the bedding fracture, low brittleness index, low clay mineral content, and significant areal differences, as well as by the transformation from elasticity to plasticity, difficulty in sanding, and high mechanical and strength parameters. Simultaneously, they were accompanied by six high values of formation temperature, horizontal principal stress difference, pore pressure, fracture pressure, extension pressure, and closure pressure. The key to deep shale gas horizontal well fracturing was to improve the complexity of the hydraulic fracture network, form adequate proppant support of fracture surface, and increase the practical stimulated reservoir volume (SRV), which accompanied visual hydraulic discrete network monitoring. On this basis, we proposed several ideas to improve China’s deep shale gas development involving advanced technology systems, developing tools, and supporting technologies in shale gas exploration and development in the United States. These ideas primarily involved stimulation technologies, such as vertically integrated dessert identification and optimization, horizontal well multistage/multicluster fracturing, staged tools development for horizontal wells, fractures network morphology monitoring by microseismic and distributed optical fiber, shale hydration expansion, soak well, and fracturing fluid flow back. China initially developed the critical technology of horizontal well large-scale and high-strength volume fracturing with a core of “staged fracturing with dense cutting + shorter cluster spacing + fracture reorientation by pitching + forced-sand addition + increasing diameter perforating + proppant combination by high strength and small particle size particles”. We concluded that China should continue to conduct critical research on theories and technical methods of horizontal well fracturing, suitable for domestic deep and ultra-deep marine and marine-continental sedimentary shale, to support and promote the efficient development of shale gas in China in the future. It is essential to balance the relationship between the overall utilization degree of the gas reservoir and associated economic benefits and to localize some essential tools and supporting technologies. These findings can contribute to the flourishing developments of China’s deep shale gas.

Preparation and properties of bifunctional associative polymer with twin tail and long chain structure for shale gas fracturing

AbstractCompared with conventional fracturing, shale reservoir fracturing has the characteristics of 1000 tons of sand and 10,000 cubic meters of liquid. The concentrated reflection of the fracturing fluid is low friction and strong carrier which are required. A novel bifunctional associative polymer was synthesized by free radical micellar polymerization with twin tails and long chain hydrophobic monomers. The structures and characteristics of the polymer were confirmed by Fourier transform infrared spectroscopy, 1H NMR spectroscopy, DSC, SEM and AFM. Sand‐carrying of the fracturing fluid experiments shows when the quartz sand has a particle size of 0.3 and 0.6 mm, the sedimentation velocities are about 0.12 and 0.40 cm min−1, respectively. The drag reduction experimental results show that when the flow rate rises to 55 L·min−1, drag reduction rate can reach 68.1%. The polymer polyacrylamide has good shear performance, but the permeability damage rate is up to 16.10%.

Productivity Prediction of Fractured Horizontal Well in Shale Gas Reservoirs with Machine Learning Algorithms

Predicting shale gas production under different geological and fracturing conditions in the fractured shale gas reservoirs is the foundation of optimizing the fracturing parameters, which is crucial to effectively exploit shale gas. We present a multi-layer perceptron (MLP) network and a long short-term memory (LSTM) network to predict shale gas production, both of which can quickly and accurately forecast gas production. The prediction performances of the networks are comprehensively evaluated and compared. The results show that the MLP network can predict shale gas production by geological and fracturing reservoir parameters. The average relative error of the MLP neural network is 2.85%, and the maximum relative error is 12.9%, which can meet the demand of engineering shale gas productivity prediction. The LSTM network can predict shale gas production through historical production under the constraints of geological and fracturing reservoir parameters. The average relative error of the LSTM neural network is 0.68%, and the maximum relative error is 3.08%, which can reliably predict shale gas production. There is a slight deviation between the predicted results of the MLP model and the true values in the first 10 days. This is because the daily production decreases rapidly during the early production stage, and the production data change greatly. The largest relative errors of LSTM in this work on the 10th, 100th, and 1000th day are 0.95%, 0.73%, and 1.85%, respectively, which are far lower than the relative errors of the MLP predictions. The research results can provide a fast and effective mean for shale gas productivity prediction.

Experimental Study on the Fracture Behaviors Effect of Stress Conditions on the Fracture of Shale by Super-Critical Carbon Dioxide

This paper examines the fracture propagation problems of supercritical carbon fracturing in low permeability shale. Acoustic emission monitoring and computerized tomography (CT) scanning methods were used to study the influence of initial stress ratios on crack initiation and propagation crack in fracturing experiments. The results show that crack initiation pressure and crack morphology are very different under different stress conditions. Under the condition of constant confining pressure, when the initial stress ratio λ = 1, cracks are mainly in a horizontal direction; while for an initial stress ratio of λ < 1, cracks are mainly in a vertical direction. With the decrease of λ, crack initiation pressure, reopening pressure, and fracturing liquid volume also decrease, and crack propagation is not as obvious. According to CT scanning results, the crack propagation direction is the same as the maximum principal stress, and fewer cracks are initiated with a smaller initial stress ratio. Based on the acoustic emission characteristics, the fracturing process (including crack initiation, propagation, and closure), can be divided into three stages: 1) the pressure accumulation in the wellbore, 2) Pump Closure; and 3) crack reopening. This study provides the basis for a reasonable selection of shale gas fracturing formation and geo-sequestration of greenhouse gas CO2.

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.

Fracturing Productivity Prediction Model and Optimization of the Operation Parameters of Shale Gas Well Based on Machine Learning

Abstract Based on the massive static and dynamic data of 137 fractured wells in WY shale gas block in Sichuan, China, this paper carried out the analysis of shale gas fracturing production influencing factors, production prediction model, and fracturing parameter optimization model research. Taking geological, engineering, fracturing operation, and production data of fractured wells in WY block as data set, the main control analysis method is used to construct the shale gas fracturing production influencing factors as the sample set. A production prediction model based on six machine learning (ML) algorithms including random forest (RF), back propagation (BP) neural network, support vector regression (SVR), extreme gradient boosting (XGBoost), light gradient boosting machine (LightGBM), and multivariable linear regression (LR) has been established; the evaluation results show that the XGBoost model has the best performance on this sample set. The selection method of shale gas well fracturing operation scheme set is studied; the production rate and the ratio of cost and profit (ROCP) are comprehensively considered to select the final fracturing operation scheme. Research result shows that the data-driven production prediction model and fracturing parameter optimization model can not only be used to predict the production of shale gas fracturing and optimize operation parameters but also realize the sensitivity analysis of fracturing parameters and the effect comparison of fracturing operation schemes, which has good field application value.

A machine learning framework for rapid forecasting and history matching in unconventional reservoirs

We present a novel workflow for forecasting production in unconventional reservoirs using reduced-order models and machine-learning. Our physics-informed machine-learning workflow addresses the challenges to real-time reservoir management in unconventionals, namely the lack of data (i.e., the time-frame for which the wells have been producing), and the significant computational expense of high-fidelity modeling. We do this by applying the machine-learning paradigm of transfer learning, where we combine fast, but less accurate reduced-order models with slow, but accurate high-fidelity models. We use the Patzek model (Proc Natl Acad Sci 11:19731–19736, https://doi.org/10.1073/pnas.1313380110, 2013) as the reduced-order model to generate synthetic production data and supplement this data with synthetic production data obtained from high-fidelity discrete fracture network simulations of the site of interest. Our results demonstrate that training with low-fidelity models is not sufficient for accurate forecasting, but transfer learning is able to augment the knowledge and perform well once trained with the small set of results from the high-fidelity model. Such a physics-informed machine-learning (PIML) workflow, grounded in physics, is a viable candidate for real-time history matching and production forecasting in a fractured shale gas reservoir.

Fracturing Parameters Optimizing Simulation of Horizontal Well In WeiYuan Shale Gasfield

Multistage fracturing and multi-clusters with long lateral fracturing were applied during developing the WeiYuan shale gas field, and the fracturing parameters were variable obviously for the fracturing lateral, perforating clusters, pumping rate, fracturing fluid volume and proppant quality. In this paper, the 3D geological model of a WeiYuan shale gas pad was used to simulate and optimize the fracturing parameters of the shale gas horizontal wells. The simulating results show that there is a reasonable matching relationship between different fracturing lateral length and the perforating clusters, and there is an optimal fluid volume and proppant quality. As the length of the fracturing lateral and the number of clusters increase, the spacing of horizontal wells need to be reduced reasonably. With the purpose of fracturing parameters optimization for WeiYuan shale gas horizontal wells, it is recommended to increase the number of perforation clusters, increase the treating rate, and use the reasonable fluid volume and proppant quality for different fracturing lateral. The research results of this paper have guiding significance for the optimization and treatment of fracturing shale gas horizontal well.

Hydraulic fracturing flowback chemical composition diversity as a factor determining possibilities of its management

The chemical characteristic of flowback fluid from hydraulic fracturing for shale gas exploration/production in various localizations is presented. The results of statistical analysis have shown that variability in the chemical composition of these fluids is statistically significant and depends on the time difference between fracturing process and flowback sampling as well as sampling spot within the installation for flowback collection. Parameters which depend on sampling schedule (time and spot of sampling) are as follows: electrical conductivity and concentration of ammonia, boron, barium, calcium, lithium, sodium, magnesium, manganese, sodium, strontium, silicate, bromide, and chloride. Independent parameters are pH, total organic carbon (TOC), concentration of potassium, and iron. The ranges of the values of the characteristic parameters were determined, taking into account the representativeness of the samples, supported by statistical tests. The methods for the reuse of flowback fluids in terms of chemical composition are presented.

Experimental Study on Spontaneous Imbibition Characteristics of Fracturing Fluid at Cores from Different Layers in Fuling Shale Gas Reservoir

With low porosity and low permeability, shale reservoirs cannot be mined economically without large-scale hydraulic fracturing operation. However, abundant fracturing fluid will enter the reservoirs during the process of fracture. Nevertheless, there have not been specific research findings on the imbibition law of Fuling shale gas reservoir in China. In this study, an imbibition experiment was carried out on the shale core of Jiaoshiba block of Fuling shale gas reservoir to learn spontaneous imbibition characteristic of Fuling shale gas reservoir. Based on the experimental results, the imbibition process of Fuling shale gas reservoir fracturing fluid is divided into two stages. During the first stage, i.e., the former 30 hours, imbibition velocity is high, with the cumulative imbibition occupying more than 70% of the total imbibition; during the second stage, i.e., the latter 30 hours, the imbibition velocity substantially drops towards balance. There is a typical power function relationship between the average imbibition velocity and imbibition time, and this function relationship runs throughout the whole imbibition process. Nonetheless, the imbibition process of shale core cannot be described directly by the Handy equation. The imbibition velocity is closely related to clay mineral content and pore structure characteristics of shale core. The higher the clay mineral content, the higher the imbibition velocity. According to the relationship between the average imbibition velocity and imbibition time, we derived the estimation equation of fracture area formed by fractured shale gas well to estimate the fracture scale formed by shale gas well fracturing.

Fatigue analysis of all-electric shale gas fracturing truck frame

Fracturing truck is the core equipment in shale oil and gas exploitation. The operation environment is harsh. As the main bearing structure of the fracturing truck, the frame should have high efficiency and reliability to ensure the stable operation of the fracturing truck. Therefore, a frame model of the all-electric fracturing vehicle was established in this paper, and the load spectrum of the frame was simulated with white noise load when the fracturing vehicle was running on uneven road surface, and the finite element transient analysis of the frame was carried out. Then, a five-block diagram of fatigue analysis was established by using ncode Design-Life software, and the fatigue analysis results of the fracking truck frame were calculated according to the linear cumulative damage theory and S-N material characteristic curve. The research provides an effective reference for the detection of the fracking truck frame, so as to ensure the running stability of the fracturing truck.

Volume fracturing and drainage technologies for low-pressure marine shale gas reservoirs in the Ordos Basin

There are abundant natural gas resources in the marine shale gas reservoir of Middle Ordovician Wulalike Formation in the Ordos Basin, which is an important resource base for PetroChina Changqing Oilfield Company to increase the reserves and production of oil and gas. Compared with the other shale gas reservoirs at home and aboard, however, the marine shale gas reservoir of Middle Ordovician Wulalike Formation in the Ordos Basin has a lower formation pressure coefficient and poorer reservoir physical properties and gas-bearing property, so its production increase difficulty is higher. In this paper, horizontal-well volume fracturing was studied and tested based on the earlier vertical well tests. According to the technical idea of the staged multi-cluster massive fracturing of long horizontal section, the propagation mechanisms and morphological characteristics of fractures were studied and analyzed based on the fracturing geological characteristics of the shale gas reservoir in the Ordos Basin. On this basis, a full three-dimensional fracture model was optimally established for parameter optimization. The fracturing of the test well ZP1 was carried out with 15 stages and 103 clusters. After the fracturing, a more complex fracture network was formed with a fracture complexity index of 0.4–0.6. The microseismic monitoring zone is 579 m long and 266 m wide and the fracture is 146 m high. To address the drainage difficulty after large-volume fracturing of low-pressure shale gas in the Ordos Basin, this paper carries out a gas energized fracturing test. Considering the characteristics of reservoir physical properties, gas-bearing property and segmented fractures, 805 m3 liquid nitrogen was injected in stages during the fracturing of the test horizontal well. The formation pressure coefficient measured from pressure buildup data is increased from 0.7 to 0.8 to 1.88. The wellbore gas–liquid flow model was established and the parameters of long-period control-pressure drainage were optimized. The critical surface equipment was upgraded to achieve accurate measurement, safety and environmental protection. And the following research and practice results were obtained. First, based on the technological innovation and optimization, continuous gas–liquid two-phase flow is realized in the test well ZP1 and its production rate and pressure during the test are stable with the tested daily shale gas production at the wellhead of 6.42 × 104 m3. Second, after fracturing, the absolute open flow of the test well reaches 26.4 × 104 m3/d, which is more than 10 times higher than the production rate of the vertical well in the same block during the test. Thus, a significant breakthrough is realized in the exploration of marine shale gas in North China.

Optimising well orientation in hydraulic fracturing of naturally fractured shale gas formations

Complex interactions between hydraulic fractures and natural fractures often result in highly complex fracture networks that might lead to bypassed resources damaging the economic viability of developments. In this study the impact of natural fractures of the formation on production from hydraulically fractured wells is studied using a recently developed fracture upscaling method (FUM). By capturing the distribution of complex fracture networks using FUM, a novel idea of changing the well orientation to optimise recovery is proposed. It is shown that with a natural fracture spacing of 15 m a small change in well orientation up to 30° from the standard orientation can increase the recovery by up to 15% for natural fractures at an angle of at least 60° with σhmax. The increased recovery is a result of the natural fractures and stress orientation complementing each other to assist the propagation of hydraulic fractures deeper into the formation. It is also shown that as natural fracture density increases (fracture spacing decreases) the effect of changing the well orientation becomes more significant. Changing the well orientation when there are two perpendicular planes of natural fractures is also investigated. However, no optimal orientation can be found in these cases, suggesting there needs to be a strong average directionality of the natural fractures in the reservoir to support a beneficial well orientation change. A simple economic analysis shows a small well orientation change can allow a larger well spacing which could lead to a direct reduction in the cost of developing a shale reservoir. The results also show the positive effect this has on the NPV of the project with different gas prices, and a rapid positive NPV status reducing the risk of investment.

Fractured horizontal well productivity model for shale gas considering stress sensitivity, hydraulic fracture azimuth, and interference between fractures

Productivity prediction plays an important role in the efficient and rational development of shale gas reservoirs. Current research on the productivity of multistage fractured horizontal wells in shale gas reservoirs does not consider the stress-sensitive effects of natural fractures, hydraulic fracture morphology, and seepage characteristics in the same capacity model. Therefore, we considered the adsorption, desorption, and diffusion mechanisms (pseudo-steady state and transient diffusion) of shale gas in reservoirs and the stress-sensitive effects of natural fractures based on the dual-medium seepage theory model. The finite conductivity of the hydraulic fracture and hydraulic fracture azimuth were considered in the hydraulic fracture model. The source function method was used to discretize the crack, and the hydraulic fracture model was superimposed. Finally, the two models were coupled to obtain the unstable seepage and productivity models of the multistage fractured horizontal well in a shale gas reservoir. According to the established horizontal well production model of shale gas fracturing, the production characteristic curve was calculated by programming, and the simulation results were compared with the field data of shale gas wells to verify the accuracy of the model. We used the model to analyze the effects of fracture conductivity, fracture half-length, fracture spacing, skin factor, storage ratio and leakage coefficient on productivity.

Development of a Simpler but Accurate Free Gas Deviation Factor for Fractured (Dual-Porosity) Volumetric Gas Reservoir Fluid

Gas compressibility factor, also known as gas deviation factor or Z-factor, is a thermodynamic correction factor which describes the deviation of a real gas from ideal gas behaviour. The, free gas Z-factor in the Material Balance Equation (MBE) of single-porosity gas reservoirs with insignificant rock (matrix) compaction (after pressure depletion) does not reflect cases in low-permeability gas reservoirs having remarkable rock compaction. Through gas MBE modifications, previous researchers developed Z-factors for dual-porosity (fractured) low permeability gas reservoirs by incorporating gas desorption; however, their approaches create complexity for routine calculations. Therefore this study was designed with the purpose of deriving a free gas Z-factor for single-porosity low-permeability gas reservoirs and further modifying it for more simplicity and accuracy in a dual-porosity scenario. The free gas Z-factor derived for single-porosity low-permeability gas reservoirs is expressed as: where , , , , and are single-porosity Z-factor without rock compaction at pressure , water compressibility, initial water saturation, matrix compressibility, initial gas saturation and pressure depletion, respectively. However, the developed dual porosity free gas Z-factor model incorporates ratio of dual porosity to initial matrix porosity, and it is expressed as: where and are initial matrix porosity and fracture porosity, respectively. The Z-factor model was graphically and statistically correlated with an existing free gas Z-factor model for dual porosity reservoirs. For all the hydraulically fractured shale gas formations considered, the correlations yield R2 values of 1.000.

Integrated characterization of the fracture network in fractured shale gas Reservoirs—Stochastic fracture modeling, simulation and assisted history matching

The large uncertainty in fracture characterization for shale gas reservoirs seriously affects the confidence in making forecasts, fracturing design, and taking recovery enhancement measures. It is of significance to make the most of multiple data in fracture characterization, including the measurements of hydraulic fracturing treatment, core, microseismic, production data, etc. Besides, handling the complex fracture networks (CFNs) explicitly is demanded in large-scale field case studies. This paper presents an efficient method to characterize the complex fracture networks (CFNs) and reduce the uncertainties by integrating stochastic CFNs modeling, reservoir simulation, and assisted history matching. In CFNs modeling, the geometry of CFNs is generated stochastically constrained by the measurements of hydraulic fracturing treatment, core, and microseismic data, and a stochastic parameterization model is used to generate an ensemble of initial realizations of the stress-dependent fracture conductivities. To efficiently simulate the discrete fractures in field cases, the edge-based Green Element Method (eGEM) is modified by applying a steady-state fundamental solution and the technique of local grid refinement (LGR). Assisted-history-matching based on EnKF is implemented to calibrate the CFNs models and further quantify the uncertainties. The proposed method is applied to a field case from a multi-fractured horizontal shale gas well. The results show that the computation of the modified eGEM is much cheaper than the original eGEM when the steady-state fundamental solution and the technique of LGR are applied. Besides, acceptable precision can be obtained with relative coarse grids, for example, 50 m primary grids and 25 m refined grids near the fractures can be used in the test case. These advantages make the modified eGEM quite efficient in assisted history matching of large-scale field applications. The history matching results and EUR distributions show that the uncertainties are significantly reduced after 5 steps assimilation, and good results can be obtained after 10 steps assimilation. The distribution ranges of the matrix permeability and porosity are significantly narrowed down after history matching, while the matrix compressibility is hard to be determined because the rock compressibility is so small comparing to gas compressibility that gas production is not sensitive to it. The results also show that only part of the fractures are well-propped because only the fractures in a certain range of the wellbore are with good properties, that is high initial fracture conductivities and low conductivity moduli. • An integrated method for complex fracture networks (CFNs) characterization. • Geological, seismic, fracturing and production data can be assimilated. • An efficient froward model for field-scale reservoir simulation with CFNs. • Property calibration and uncertainty quantification of CFNs.

Deep shale gas in China: Geological characteristics and development strategies

Deep shale gas reservoir (3,500 ∼ 4,500 m) of Wufeng–Longmaxi Formation in southern Sichuan Basin in China has great potential for exploration and development, with resource of 16.31 × 1012 m3, counting 84% of the total resources in this area. And the deep shale gas wells in Luzhou and west Chongqing have achieved good development results in the past two years. We systematically summarized the geological characteristics of deep shale gas reservoir of Wufeng–Longmaxi Formation, and discussed the facing challenges and proposed some corresponding strategies. The deep shale gas reservoir in southern Sichuan Basin has six major characteristics. The reservoir is concentrated in depositional center and deep-water shelf environment. The reservoir is rich in silica and organic carbon while low in calcium and clay. Organic pores, inorganic pores, and microfractures are developed and well interconnected to form networks. Surface porosity is generally > 5% and increasing with depth. The gas content is 4.7 ∼ 7.5 m3/t, higher than that in Changning, Weiyuan, and Zhaotong area. The deep shale gas pressure coefficient is greater than 2.0 and is the highest in the southern Sichuan Basin, indicating its best preservation condition. Up to now, deep shale gas exploration is still encountered with many problems and challenges, including great difficulty in accurately obtaining reservoir parameters, unclear of high production mechanism, urgent need for optimal and quick drilling technology, great difficulty in reservoir fracturing, and unclear of hydro-fracture expansion rules. We proposed two strategies corresponding to the challenges, including deepen the delicate reservoir evaluation and clarify the rules of high production and enrichment of shale gas wells, and strengthen field experiments and explore effective and applicable technologies for drilling and fracturing of deep shale gas in China.

Optimization design method for the bypass trajectories of infill adjustment wells in the fracturing areas of shale gas fields

In the design of a shale-gas cluster horizontal well, it is necessary to consider the bypass of the fracturing influence domains of existing wells and the interference between fracturing influence domains when the wellbore trajectories of infill adjustment wells in the fracturing areas are designed. In order to quickly evaluate the rationality of the design scheme of fracturing wellbore trajectory in an infill adjustment well, this paper adopted the vector algebra method to build a geometric model of the obstacles in the shale gas fracturing area. In this geometric model, the influence domains of hydraulic fractures are taken into account. Then, based on this geometric model, the optimization design model of bypass trajectory in the shale gas fracturing area was established by taking the minimization of total trajectory length and trajectory potential energy as the optimization objective and the anti-collision between trajectories as the constraint. Besides, the geometric check method to judge if there is any interference between fracturing influence domains was provided. Finally, the established optimization design model was verified based on the actual drilling data of Fuling Shale Gas Field in the Sichuan Basin. And the following research results were obtained. First, the obstacle sizes in fracturing areas will be seriously underestimated if the fracturing influence domains are neglected. Second, if the fracturing influence domains are neglected, the designed bypass trajectory can bypass the wellbore trajectories of old wells, but may intersect the fracturing influence domains of existing wells, thus inducing drilling accidents. In conclusion, the proposed optimization design model of bypass trajectory in the shale gas fracturing area can satisfy the constraint of anti-collision and bypass and achieve the optimization objective of minimizing total trajectory length and trajectory potential energy, and the corresponding design calculation avoids complex calculation and check.