Fracturing Fluid Injection Rate Research Articles

Synchronous vertical fracture propagation of multi-layer radial wells for enhancing stimulated height in shale oil reservoir

The diversity of interlayers in shale oil reservoir leads to a low degree of vertical reconstruction. This paper aims to propose a method to guide the synchronous initiation of hydraulic fractures in different layers by drilling multi-layer radial wells in spatial positions, and to form a fracture network that satisfies the vertical propagation range and complexity. In this paper, a 3D (three-dimensional) multi-layer radial well fracturing model considering fluid-mechanics coupling is established and the properties of shale oil reservoir are characterized according to the field geological profile. The influences of radial well spacing, fracturing fluid injection rate, and fracturing fluid viscosity on vertical fracture communication in multi-layer radial wells are investigated. The results show that the radial well has the characteristics of guiding fracture penetrating interlayers. Reducing radial well spacing and appropriately increasing injection rate and viscosity are beneficial to improving vertical fracture propagation ability. However, high fracture fluid viscosity under the same displacement will lead to a significant increase in fracture aperture and weaken the total fracture area. In addition, if the stress interference around the radial wells is low, the radial well can be located in the middle of each layer to minimize the fracture height limitation. This study can provide a solution idea for vertical propagation limitation of hydraulic fractures in shale oil reservoir.

Research on Horizontal Well Multi-Fracture Propagation Law under the Synergistic Effect of Complex Natural Fracture and Reservoir Heterogeneity

Conventional fracturing design generally only considers the propagation of a single fracture in homogeneous storage, but the heterogeneity characteristics of the reservoir and the development of complex natural fractures will affect the fracturing effect. In order to study the horizontal well fracture propagation law under the synergistic effect of complex natural fracture reservoir heterogeneity, the globally embedded cohesive element finite model is established, and the heterogeneous reservoirs are built by Python programming. The influencing factors of multi-fracture propagation with heterogeneous reservoirs are analyzed, including the in situ stress difference, the injection rate of fracturing fluid, the perforation spacing, and the perforating clusters number. The results show that the heterogeneity and the natural fracture of the reservoir will affect the in situ stress distribution and propagation direction. When the in situ stress difference is low, the reservoir heterogeneity and natural fractures have a great influence on the fracture morphology. With the increase in injection rate, the fracture length and fracture width increase. With the in situ stress difference increase, the fracture deflection angle decreases. With the increase in fracturing fluid injection rate, the fracture length increases. The number of hydraulic fractures communicating with natural fractures increases with the natural fracture number and the number of perforation clusters under the synergistic effect of complex natural fracture and reservoir heterogeneity.

Analysis of Fracturing Expansion Law of Shale Reservoir by Supercritical CO2 Fracturing and Mechanism Revealing

The rapid expansion of reservoir fractures and the enlargement of the area affected by working fluids can be accomplished solely through fracturing operations of oilfield working fluids in geological reservoirs. Supercritical CO2 is regarded as an ideal medium for shale reservoir fracturing owing to the inherent advantages of environmental friendliness, excellent capacity, and high stability. However, CO2 gas channeling and complex propagation of fractures in shale reservoirs hindered the commercialization of Supercritical CO2 fracturing technology. Herein, a simulation method for Supercritical CO2 fracturing based on cohesive force units is proposed to investigate the crack propagation behavior of CO2 fracturing technology under different construction parameters. Furthermore, the shale fracture propagation mechanism of Supercritical CO2 fracturing fluid is elucidated. The results indicated that the propagation ability of reservoir fractures and Mises stress are influenced by the fracturing fluid viscosity, fracturing azimuth angle, and reservoir conditions (temperature and pressure). An azimuth angle of 30° can achieve a maximum Mises stress of 3.213 × 107 Pa and a crack width of 1.669 × 10−2 m. However, an apparent viscosity of 14 × 10−6 Pa·s results in a crack width of only 2.227 × 10−2 m and a maximum Mises stress of 4.459 × 107 Pa. Additionally, a weaker fracture propagation ability and reduced Mises stress are exhibited at the fracturing fluid injection rate. As a straightforward model to synergistically investigate the fracture propagation behavior of shale reservoirs, this work provides new insights and strategies for the efficient extraction of shale reservoirs.

Modeling on ball migration and seating in a horizontal well with multi-cluster perforations

Ball-throwing temporary plugging fracturing is a new technology for achieving uniform-length fracture in a horizontal well. The migration and seating law of a temporary plugging ball (TPB) in the horizontal well is still not clear. Based on the computational fluid dynamics-discrete phase model coupling method, a three-cluster spiral perforated borehole model is established to analyze the effects of the density, diameter, and number of TPB, fracturing fluid injection rate, and viscosity on the migration and seating behaviors of TPB. The results show that the buoyancy ball and the gravity ball have better sealing effects on cluster 3, which is near the borehole heel, and cluster 1, which is near the borehole toe, respectively. When the diameter of TPB is 1–1.3 times the perforation diameter, the overall plugging effect is better. When the number of TPB is 5/6 times the total number of perforations, the plugging effect at cluster 3 and cluster 1 is better. When the injection rate of fracturing fluid ranges from 0.5 to 2.5 m3/min, the plugging efficiency at cluster 3 is higher with a low injection rate. When the viscosity of the fracturing fluid is 20–30 mPa s, cluster 3 and cluster 1 have better plugging effect.

Transportation and sealing pattern of the temporary plugging ball at the spiral perforation in the horizontal well section

Multistage fracturing of horizontal wells is a critical technology for unconventional oil and gas reservoir stimulation. Ball-throwing temporary plugging fracturing is a new method for realizing uniform fracturing along horizontal wells and plays an important role in increasing oil and gas production. However, the transportation and sealing law of temporary plugging balls (TPBs) in the perforation section of horizontal wells is still unclear. Using COMSOL computational fluid dynamics and a particle tracking module, we simulate the transportation process of TPBs in a horizontal wellbore and analyse the effects of the ball density, ball diameter, ball number, fracturing fluid injection rate, and viscosity on the plugging efficiency of TPB transportation. This study reveals that when the density of TPBs is close to that of the fracturing fluid and a moderate diameter of the TPB is used, the plugging efficiency can be substantially enhanced. The plugging efficiency is greater when the TPB number is close to twice the number of perforations and is lower when the number of TPBs is three times the number of perforations. Adjusting the fracturing fluid injection rate from low to high can control the position of the TPBs, improving plugging efficiency. As the viscosity of the fracturing fluid increases, the plugging efficiency of the perforations decreases near the borehole heel and increases near the borehole toe. In contrast, the plugging efficiency of the central perforation is almost unaffected by the fracturing fluid viscosity. This study can serve as a valuable reference for establishing the parameters for temporary plugging and fracturing.

Fracture propagation and evolution law of indirect fracturing in the roof of broken soft coal seams

Indirect fracturing in the roof of broken soft coal seams has been demonstrated to be a feasible technology. In this work, the No. 5 coal seam in the Hancheng block was taken as the research object. Based on the findings of true triaxial hydraulic fracturing experiments and field pilot under this technology and the cohesive element method, a 3D numerical model of indirect fracturing in the roof of broken soft coal seams was established, the fracture morphology propagation and evolution law under different conditions was investigated, and analysis of main controlling factors of fracture parameters was conducted with the combination weight method, which was based on grey incidence, analytic hierarchy process and entropy weight method. The results show that “士”-shaped fractures, T-shaped fractures, cross fractures, H-shaped fractures, and “干”-shaped fractures dominated by horizontal fractures were formed. Different parameter combinations can form different fracture morphologies. When the coal seam permeability is lower and the minimum horizontal principal stress difference between layers and fracturing fluid injection rate are both larger, it tends to form “士”-shaped fractures. When the coal seam permeability and minimum horizontal principal stress between layers and perforation position are moderate, cross fractures are easily generated. Different fracture parameters have different main controlling factors. Engineering factors of perforation location, fracturing fluid injection rate and viscosity are the dominant factors of hydraulic fracture shape parameters. This study can provide a reference for the design of indirect fracturing in the roof of broken soft coal seams.

Pore and permeability changes in coal induced by true triaxial supercritical carbon dioxide fracturing based on low-field nuclear magnetic resonance

Supercritical carbon dioxide (ScCO2) fracturing is a green, clean, waterless extraction technique that has gained widespread attention. Coal pore properties, such as porosity, pore size distribution, connectivity, and permeability, are critical for fracturing and efficient coalbed methane production. This study examines the effects of ScCO2 fracturing on coal reservoir pore modification by conducting true triaxial ScCO2 fracturing experiments on high-rank coal samples under various stresses and injection rates. Low field nuclear magnetic resonance technique was used to compare and analyse the pore permeability characteristics of the samples before and after ScCO2 fracturing. The research discusses the influence of stress and ScCO2 fracturing fluid injection rate on coal pore modification and its controlling mechanisms. The results show a significant impact on coal pore modification, with a 59.85 % increase in porosity, 60 % increase in pore volume, 56 % increase in pore throat volume, and 47.5 % increase in permeability. Under the same injection rate and fixed temperature (40 °C), higher stress differences (8 MPa) benefit large pore modification and connectivity, while lower stress differences (4 MPa) are more favourable for micropore and transition pore modification and connectivity. These findings contribute to a deeper understanding of the microscopic mechanisms of ScCO2 fracturing in modifying coal pores.

A Study on Fracture Propagation Law of CO2 Composite Fracturing in Shale Reservoir

Background: In recent years, CO2 composite fracturing technology has been widely used in unconventional reservoirs. Compared to conventional hydraulic fracturing, CO2 fracturing can create complex fractures, replenish formation energy and reduce oil flow resistance. For shale oil reservoirs with natural fractures, CO2 composite fracturing can not only give full play to the advantages of complex fracture networks created by CO2 but also make use of water-based fracturing fluid to create long fractures with high conductivity. Methods: Based on fracture fluid flow, stress interference, natural fracture description, and CO2 phase change equation, a CO2 composite fracture propagation model was established in this paper to simulate the effects of fracturing fluid type, CO2 proportion, construction scale, natural fracture development, fracturing fluid injection rate and other factors on the propagation morphology of CO2 injection fracture network in shale oil reservoirs. Results: The results show that the water-based fracturing fluid is beneficial to the formation of long main fractures, but the overall complexity of the fracture network and the effective stimulated volume of the fracture network are significantly lower than that of CO2 fracturing. The application of the appropriate proportion of CO2 composite fracturing fluid can give full play to the comprehensive advantages of CO2 and water-based fracturing fluid and realize the full stimulation of the reservoir. CO2 fracturing in shale oil reservoirs with low principal stress difference and high natural fracture development extent can communicate natural fractures in a large range and form a complex fracture network. For shale oil reservoirs with natural fractures, a high fracturing fluid injection rate can significantly improve the complexity of the fracture network. Conclusion: The CO2 composite fracturing technology is applied to horizontal wells in X shale reservoir, and the production after fracturing is significantly higher than that of offset wells, which can be applied in the same type of reservoir and has broad application prospects.

A Thermal-Fluid-Solid Coupling Computation Model of Initiation Pressure Using Supercritical Carbon Dioxide Fracturing

With the characteristics of low fracturing pressure, little damage to the reservoirs, and assuming the role of carbon storage, supercritical carbon dioxide (SC-CO2) fracturing is suitable for the development of unconventional oil and gas resources. Based on the tensile failure mechanism of rocks, this paper establishes a thermal-fluid-solid coupling initiation pressure model for SC-CO2 fracturing. Using this model, the changes in formation temperature and pore pressure near a wellbore caused by invasion of CO2 into the formation are analyzed, as well as the impact of these changes on the tangential stress of reservoir rocks. The field data of SC-CO2 fracturing in a sandstone gas well are used to validate the reliability of the model. The results show that SC-CO2 fracturing can significantly reduce the initiation pressure, which decreases with the increase in fracturing fluid injection rate. The minimum value of tangential stress is located at the well wall, and the direction of tangential stress caused by formation temperature and pore pressure is opposite, with the former greater than the latter. The increase in Poisson’s ratio, the increase in elastic modulus and the decrease in bottom hole temperature can reduce the initial fracturing pressure of the reservoir. The computation model established in this paper provides an effective method for understanding the reservoir fracturing mechanism under the condition of SC-CO2 invasion.

Study on H-shaped fracture propagation and optimization in shallow dull-type coal seams in the Hancheng block, China

The initiation and propagation of hydraulic fractures dominate the fracture morphology and conductivity, thereby determining the fracturing stimulation effect. This work took the shallow dull-type coal seam in the Hancheng block as the research object, and focused on the propagation and optimization of the H-shaped fracture. By using a combination of mechanical theoretical analysis, laboratory experiment, numerical simulation, field test, and optimization evaluation, an integrated study on the formation conditions, morphology evolution, propagation laws, main controlling factors, and optimal design of H-shaped fractures was conducted. The mechanical criterion for identifying H-shaped fracture propagation was derived through the analysis of the stress fields on the fracture surface. A 3D numerical model of H-shaped fractures was established with cohesive element method, and the propagation law and influencing factors of H-shaped fractures were investigated. Sensitivity analysis of the influencing factors on the H-shaped fractures was performed with grey incidence analysis method. The optimization of the H-shaped fracture parameters was performed by fracture propagation numerical simulation. The results show that H-shaped fractures dominated by horizontal fractures are generally formed in shallow dull-type coal seams. H-shaped fractures can improve the CBM development effect by parameter optimization of indirect fracturing technology. The judging criterion for H-shaped fracture formation is that the tensile strength of the upper and lower weakly cemented horizontal interfaces is less than that of the coal seam and the vertical principal stress is lower than the minimal horizontal principal stress. The incidence degree of fracturing fluid injection rate, viscosity, perforation location, minimum horizontal stress difference, and coal seam permeability on the H-shaped fracture propagation decreases in turn. The engineering factors (fracturing fluid injection rate and viscosity and perforation location) are the major impact factors. With the increase in coal seam permeability, the horizontal fracture develops from stubby-type to slender-type. The minimum horizontal principal stress difference mainly affects the horizontal fracture. As the fracturing fluid viscosity increases, the horizontal fracture length increases first and then decreases. The fracturing fluid injection rate has a great impact on the height-length profile of horizontal fractures. The optimal injection rate seems to be 6.5–7 m3/min, the optimal fracturing fluid viscosity is between 10 mPa·s and 15 mPa·s, and the optimal perforation location is selected near the formation interface. These research results could provide a reference for the design and optimization of efficient fracturing of coalbed methane reservoirs.

Criterion for Hydraulic Fracture Propagation Behavior at the Interface of a Coal Measure Composite Reservoir

Regarding the three expansion modes of hydraulic fractures at the interface of a coal measure composite reservoir (arrested, deflection, and penetration), based on the coupling theory of fluid flow and solid elastic deformation, a criterion that considers the influences of the injection parameters (fracturing fluid injection rate and viscosity) is established to predict the propagation path of hydraulic fractures at the interface of a composite reservoir. The criterion judges the propagation behavior of the fractures by comparing the water pressure in the wellbore and the critical seam pressure of the penetration and deflection. The controlled variable method is used to analyze the influences of the various factors on the propagation behavior of hydraulic fractures at the interface between layers. The results show that the differences in in situ stress, the interface cohesion, and the included angle mainly affect the critical seam pressure of the fracture deflection. The differences in elastic modulus, fluid injection rate, and fracturing fluid viscosity directly affect the water pressure in the wellbore. The difference in the fracture toughness mainly affects the crack propagation path by affecting the critical seam pressure of the deflection. The smaller the difference in the in situ stress is, the more likely it is that the hydraulic fractures will penetrate the layer. Larger differences in the fracture toughness between layers, interfacial cohesion, fluid injection rate, and fracturing fluid viscosity are more conducive to the hydraulic fractures penetrating the layer. When the angle between the hydraulic fractures and the interface is 25–55°, the hydraulic fracture is more likely to expand along the interface. This criterion takes into account the influences of the injection parameters and is of great significance to gaining a better understanding of the propagation behavior of hydraulic fractures at an interlayer interface.

A study of inter-stratum propagation of hydraulic fracture of sandstone-shale interbedded shale oil

The vertical production layer of a shale oil reservoir in the Songnan Region, China, is mainly sandstone-shale interbed, and the reservoir thickness is uneven. As a result of varying interlayer properties, the hydraulic fracture height is hard to increase, and the propagation pattern of the fracture is unclear. In this paper, features of sandstone-shale lithological combination in the Songnan Region were explored by indoor rock mechanics experiments, which clarified the rock mechanics parameters and characterized the anisotropic features. Combined with the well-logging curves, the dynamic and static elastic moduli, Poisson's ratio, and tectonic coefficient were obtained. An evaluation model for crustal stress in the Songnan Region of China was built based on the hydraulic fracturing data. Additionally, a numerical model for 3D propagation of hydraulic fracture was established based on the finite element method to obtain three forms of fracture propagation and the effects of eight parameters, including fracturing fluid injection rate, interface strength, vertical stress, horizontal stress, elastic modulus, etc., on the height and length of hydraulic fracture were investigated. The results showed that increased viscosity and vertical stress of fracturing fluid could effectively increase fracture propagation height, low interface strength, fracturing fluid injection rate, and maximum and minimum horizontal principal stresses, thus favoring the propagation of hydraulic fractures. This study provides some guidance for the efficient development of sandstone-shale interbedded reservoir fracturing.

Study on the influence of mechanical characteristics of multi-rhythm inter-salt shale oil on fracture propagation in Qianjiang formation, China

There are many inter-salt rhythmic shale reservoirs in Qianjiang sag, and the mineral composition content with different rhythms is different. The thin interbedding characteristics of inter-salt shale oil reservoirs bring technical challenges to hydraulic fracturing. Taking one shale oil well in Qianjiang depression as an example, the mechanical properties and interface characteristics of rock under temperature and confining pressure are analyzed. The physical simulation test of fracture propagation under different fracturing fluid is completed, and the effects of four different factors on fracture propagation are analyzed by numerical analysis method. The results show that the mechanical characteristic and failure modes with different rhythms are obvious differences. Under uniaxial and triaxial compression, glauberite mudstone and shale have high strength, and salt rock shows obvious plastic deformation characteristics. The interbedded rock has clear interface characteristics. The cohesion of glauberite mudstone and shale bedding surface obtained from direct shear test is 0.60 MPa and 0.99 MPa. The fracture morphology of inter-salt shale is mainly affected by the development degree of rock bedding. The mechanical parameters, in situ stress difference, and the displacement have an important impact on the longitudinal propagation of fracturing fractures. The width and height of fracture propagation decrease, with the increase in the minimum horizontal principal stress in the salt layer, and the width of fracture in shale increases. The crack height decreases with the increase in tensile strength of the interlayer. With the increase in fracturing fluid injection rate from 3.0 to 7.0 ml/min, the propagation height of hydraulic fractures and the width of fractures in shale increase significantly. The research results can apply to understanding the mechanism of hydraulic fracture propagation in inter-salt shale formation.

Numerical simulation of single-cluster and multi-cluster fracturing of hydrate reservoir based on cohesive element

Horizontal well multistage fracturing technology has potential as a technical method to improve the permeability of clayey silt natural gas hydrate (NGH) reservoirs as it can increase the contact area between a horizontal well and an NGH reservoir. Although this technology has been successfully applied to the exploitation of shale gas and coalbed methane, the relevant technical experience cannot be directly applied to clayey silt NGH reservoirs. Based on the properties of the clayey silt NGH reservoir at the SH2 site in the Shenhu area of the South China Sea, herein, we established a three-dimensional hydraulic fracturing model based on cohesive elements to analyze the influence of the fracturing fluid injection rate on the initiation and propagation of single-cluster fractures and the influence of fracture spacing on simultaneous fracturing and sequential fracturing of multi-cluster fractures. We comprehensively analyzed the distribution characteristics of fracture morphology and the phenomenon of stress interference between fractures under different conditions. The results showed that without fracture interference, fractures tended to propagate to the middle and upper parts of the reservoir owing to the low fracture propagation resistance. Simultaneous fracturing and sequential fracturing produced different staggered fracture distribution patterns, which were caused by the geostress field changing owing to the generation of fractures. Our findings broaden the understanding of hydraulic fracturing in clayey silt NGH reservoirs.

Data-driven multi-objective optimization design method for shale gas fracturing parameters

Accurate design of fracturing parameters in shale gas reservoirs does not only increase the productivity and profitability of wells but also minimize the damage fracturing fluids cause to fluid-sensitive formations. However, obtaining a highly accurate and optimized fracturing parameters with rapid as well cost-effective simulation run is difficult to achieve. This study proposed a framework for optimizing shale gas fracturing parameters based on least squares support vector regression (LSSVR) prediction model and non-dominated sorting genetic algorithm-II (NSGA-II). This framework was named the multi-objective optimization prediction model (MOO-PM). In the proposed framework, the flowback ratio of fracturing fluid (FBR) and first month gas production (PROD) were considered as the objective functions while the fracturing parameters including horizontal length, number of fractured sections, fractured length, fracturing fluid injection rate, fracturing fluid viscosity, volume of fracturing fluid and proppant amount were chosen as the optimization variables. Firstly, based on field data the LSSVR prediction model was established. Secondly, the accuracy of the model was verified by the remaining field data. Subsequently, the Latin Hypercube method was used to construct a sample set of fracturing parameters within a predetermined range of variables and the corresponding objective functions were calculated by the LSSVR method. Finally, Pareto front was used to generate flowback ratio and first-month production by the NSGA-II algorithm. To the best of our knowledge, this is the first time that LSSVR prediction model and multi-objective method are applied simultaneously to optimize shale gas fracturing parameters. Furthermore, the novel multi-objective optimization framework was applied to data from the Weiyuan as well as the Changning shale gas reservoirs in Sichuan basin, southwest China. It was concluded that this framework could optimize fracturing parameters of shale gas reservoirs with higher accuracy and efficiency.

Quantitative characterization of crack propagation behavior under the action of stage-by-stage fracturing induced by SC-CO2 fluid

The use of supercritical carbon dioxide (SC-CO2) for the fracturing of coal bodies has excellent development prospects and practicability. It alters the fissure structure of coal bodies and achieves CO2 geological sequestration. This process, which involves the mutual interaction of coal, fissures, supercritical fluid, and gas, can be subdivided into fluid-induced and phase change-induced fracturing stages. Numerical simulation of the SC-CO2 fracturing was carried out in a stagewise manner to characterize each stage's fracturing performance quantitatively. The effects exerted on the crack propagation behavior by such factors as the ground stress deviation, the permeability coefficient of coal bodies, fracturing fluid injection rate and temperature, was studied in detail for each stage. The crack morphology, length, and width of cracks induced in each stage in proportion to the total crack length and width values were determined and analyzed. The research results show that the crack length ratio of the SC-CO2 fluid-induced fracturing stage to the total crack length was 80–90%, with the remaining 10–20% corresponding to the CO2 phase change-induced fracturing stage. This indicates that cracks propagation primarily occurred at the former stage. Meanwhile, the crack width ratios were nearly the same: 40–55% for the former stage versus 45–60% for the latter stage. Thus, the crack width increased dramatically at both stages of the SC-CO2 fracturing in the coal bodies. The research findings refined the insight into the SC-CO2 fracturing mechanism in coal bodies.

Crack initiation pressure prediction for SC-CO2 fracturing by integrated meta-heuristics and machine learning algorithms

The replacement of water by supercritical carbon dioxide in coal and rock mass fracturing has shown excellent development prospects. However, large-scale industrial implementation of supercritical carbon dioxide fracturing (SCDF) requires an accurate estimation of crack initiation pressure, while laboratory test methods are time-consuming and involve too complicated testing and sample preparation procedures. To better predict the SCDF crack initiation pressure, this study applied three hybrid artificial intelligence models, which alternatively combined the particle swarm optimization algorithm (PSO) with the BP neural network (BPNN), extreme learning machine (ELM), and support vector machine (SVM). Their prediction results were compared with each other and with those of the conventional linear multivariate regression analyses (L-MRA). Data samples for the prediction models’ training were experimentally obtained via the SCDF indoor tests with various influencing factors, including vertical principal stress, horizontal maximum principal stress, horizontal minimum principal stress, fracturing fluid injection rate, fracturing fluid temperature, coal and rock mass tensile strength, coal and rock mass elastic modulus, and coal and rock mass Poisson's ratio. The models’ output variable was the SCDF crack initiation pressure. The correlation coefficient (R), root mean square error (RMSE), and mean absolute error (MAE) were used to evaluate and compare the performance of the predictive models. Their prediction accuracy can be ranked in the decreasing order as PSO-SVM, PSO-ELM, PSO-BPNN, and L-MRA, with corresponding R values of 0.9339, 0.9135, 0.6971, and 0.6057, respectively. The PSO-SVM hybrid intelligent model was found to provide the most efficient SCDF crack initiation pressure prediction. The results obtained are quite instrumental in the promotion and application of SCDF technology.

Modified zipper fracturing in enhanced geothermal system reservoir and heat extraction optimization via orthogonal design

Modified zipper fracturing in horizontal wells is an effective tool for promoting the energy productivity of hot dry rock based enhanced geothermal system. However, the following two questions are not fully understood: 1) what extent of heat extraction from geothermal reservoir can be improved; 2) how to obtain the optimized fracture morphology meeting heat extraction requirements. We established a two-dimensional horizontal wells hydraulic fracturing model to study the fracture propagation and effects of modified zipper fracturing, and developed a length index to evaluate the impacts of fracture morphology on reservoir heat transfer behavior. The critical length, which is half of the interval between two horizontal wells, determines whether fracture propagation has effects on heat extraction or not. The orthogonal design is used to study the sensitivity of factors affecting hydraulic fracturing and heat extraction. Fracture spacing has insignificant influence on morphology, and therefore we set it as 30 m which is the optimal spacing. According to different formation parameters (in-situ stress difference and elastic modulus), controlling fracturing fluid injection rate is the best choice to optimize fracture morphology. These research results would supply a guidance for designing hydraulic fractures to meet the maximum heat extraction in enhanced geothermal system. • We studied fracture propagation and thermal effects of modified zipper fracturing. • Crack length has significant impacts on heat extraction rather than crack width. • Critical length determines if crack propagation distinctly improve heat extraction. • Thirty-meter is the best fracture spacing for heat transfer enhancement in reservoir. • Injection flow rate controlling is an effective way to optimize fracture morphology.

Study on fracture propagation behavior in ultra-heavy oil reservoirs based on true triaxial experiments

Abstract As the ultra-heavy oil reservoirs developed by steam assisted gravity drainage (SAGD) in the Fengcheng oilfield, Xinjiang have problems such as huge steam usage, long preheating period, low production, and inaccessible reserve in local parts. Based on the rock mechanics and porosity/permeability characteristics of heavy oil reservoir and interlayer, a series of true triaxial experiments and CT tests considering the fracturing fluid injection rate, viscosity, perforation density and location of fracture initiation were conducted to disclose the propagation behavior of micro- and macro-fractures in the reservoirs and mudstone interlayers. These experiments show that fracturing in the heavy oil reservoirs only generates microfractures that cannot break the interlayer. In contrast, when fracturing in the interlayer, the higher the injection rate (greater than 0.6 m3/min), the lower the viscosity, the easier it is to form macro-fractures in the interlayers, and the further the fractures will propagate into the reservoirs. Also, increasing perforation density tends to create complex macro-fracture network in the interbedded reservoirs and mudstone interlayers. The findings of this study can provide scientific guidance for the selection of fracturing layer and the optimization of parameters in the interlayer fracturing of heavy oil reservoirs.

Technical Feasibility of Using Frac-Packed Wells for Producing Natural Gas from Offshore Gas Hydrate Reservoirs

This paper presents a feasibility analysis of using frac-packing completion techniques to produce natural gas from offshore gas hydrate reservoirs. A case study was carried out for the gas hydrate accumulations in the northern South China Sea. The feasibility analysis covers the requirements of proppant size, fluid injection rate, fracturing pressure, and well productivity. For the median grain size of sediments in the studied formation from 2.60 to 28.96 μm with an average value of 8.49 μm, the required range of proppant size is between 333 mesh to 748 mesh (0.001 inch ~ 0.003 inch). Since the proppants in this size range are not commercially available, it would be economical to use screened natural sands as proppants in frac-packing operations. The minimum flow rate of fracturing fluid required to carry the 0.003 inch proppant/sand into the fracture tip at 510 ft is 3.64 bpm, which is much lower than the practical values ranging from 20 bpm to 100 bpm. Therefore proppant/sand transport during frac-packing is not a concern. To create a horizontal fracture of 510 ft radius with a fracturing fluid injection rate of 72 bpm, the maximum bottom hole injection pressure is predicted to be 2,378 psi, which is only 334 psi above the reservoir pressure and can be handled by most pumps used in frac-packing operations. Well productivity forecast with a simplified mathematical model shows that a commercial gas production rate of 16 MMscf/day is achievable with the fracture radius of 510 ft. However, the model requires further validation.