Horizontal Gas Wells Research Articles

Study on Fault Activation Evaluation Mechanism and Sensitivity Analysis in Shale Gas Hydraulic Fracturing

Shale gas hydraulic fracturing usually activates nearby faults and makes them slip. In horizontal wells, fault slip can result in serious casing deformation. Casing deformation slows the fracturing process, lowers production, and raises the cost of a shale gas well. It is challenging to obtain underground data on fault activation because of the deep shale reservoirs. As a result, the current study needed to indicate how hydraulic fracturing affects fault activation length. This made it challenging to control casing deformation. The fluid-structure coupled finite element method was used in this study to create a coupled seepage-stress model for heterogeneous shale formation. With microseismic signs and hydraulic fracking for shale gas, this model examined the variation law of pore pressure and ground stress. The fault activation coefficient was created to assess the fault activation duration and the impact of hydraulic fracturing. The model was verified by the microseismic signal. The outcomes of the numerical simulation demonstrate how the rapid rise in formation pore pressure during hydraulic fracturing affected the ground stress at the fault interface. The influence of ground stress variation at the fault interface on fault activation could not be ignored. Increased fault elastic modulus, fracture pressure, fracture time, and the fault Poisson ratio result in longer fault activation lengths. The length of the fault’s activation was decreased by the increase in fracture stage, distance from the fault, friction angle within the fault, and fault angle. Finally, a shale gas horizontal well with casing deformation in block C was analyzed. The results showed that reducing the fracturing duration can reduce the activation length of the fault by 68.25%, resulting in a 9.1 mm fault slide and a 0.86 mm casing deformation, respectively. This study offers theoretical guidelines for preventing fault activation during hydraulic fracturing in horizontal shale gas wells.

Factors affecting casing equivalent stress in multi-cluster fracturing of horizontal shale gas wells: finite element study on Weirong Block, southern Sichuan Basin, China

Multi-cluster fracturing technology was often used in horizontal well reservoir reconstruction to achieve production increase, which also affected casing equivalent stress distribution. This paper focuses on multi-cluster fracturing and establishes a fracturing model in line with the reality. The three-dimensional finite element model of multi-cluster fracture-formation-cement sheath-casing was proposed, the influence of cluster spacing and fracturing cluster number on casing equivalent stress was studied. On this basis, a single segment 8-cluster three-dimensional finite element model was developed. The influence of rock elastic modulus, casing inner wall pressure, geostress change and elastic modulus of cement sheath on casing equivalent stress was simulated from two aspects of uniform and non-uniform extrusion of wellbore. Actual data was used and analyzed for the fracturing section of a well in Weirong Block, southern Sichuan Basin, China. The results showed that the casing equivalent stress decreased with the increase of fracture dip angle. The casing equivalent stress increased with the increase of cluster spacing; however, it decreased with the increase of rock elastic modulus. The casing equivalent stress increased with the increase of casing wall pressure. Also, the cracks extrude the casing evenly did not affect the change on casing equivalent stress. It was also found that, when casing was uniformly squeezed by multiple fractures, the difference of ground stress had little effect on casing equivalent stress, while non-uniform extrusion had greater effect on casing equivalent stress. Further, when there was no wellhead pumping pressure, the casing equivalent stress increased with the increase of the elastic modulus of the cement sheath, and decreased on the contrary. The elastic modulus of rock was lower than that of cement sheath, and the casing equivalent stress increased with the increase of the elastic modulus of cement sheath, and decreased on the contrary. The research results had certain guiding significance for the prevention and control of casing damage in fracturing section.

495 Radon and Fracking Exposures and Lymphoma Risk in a Canine Model of non-Hodgkin Lymphoma

OBJECTIVES/GOALS: The objective of this study was to determine whether residential radon and proximity to horizontal oil and drilling (fracking) are risk factors for the development of multicentric lymphoma in pet dogs, a spontaneous, immunocompetent model for non-occupational risk for NHL in humans. METHODS/STUDY POPULATION: Two case-control populations of dogs with multicentric lymphoma were utilized, with a focus on two dog breeds at high risk for lymphoma. Control dogs were matched for age, breed, and sex. Home addresses were collected for 54 Golden retrievers with lymphoma and 108 Golden retriever controls, and for 56 boxer dogs with lymphoma and 84 unaffected boxer controls. Counties of residence were matched to radon zones and percentage of home radon tests that exceeded the actionable level of 4 pCi/L, available by county through the EPA and the CDC National Environmental Public Health Tracking Network from 2008 to 2017. Locations of horizontal oil and gas wells were obtained from the Enverus Database, and distances from dog homes to the closest well, and well density by county, were calculated for each case and control. RESULTS/ANTICIPATED RESULTS: We found no significant differences in radon zones, county level radon measurements, or residential proximity to active fracking wells between dogs with lymphoma and unaffected controls in either the Golden Retriever or boxer populations. DISCUSSION/SIGNIFICANCE: Canine multicentric lymphoma resembles human NHL and is a valuable model of non-occupational environmental risk for NHL in people. Although we did not find geographic associations between radon and fracking wells, follow-up studies will measure household radon, as well as household air, water, and dog urine for potentially genotoxic chemicals.

Study on mechanical extending reach limit and automatic drillstring design method for shale gas horizontal wells

Study on mechanical extending reach limit and automatic drillstring design method for shale gas horizontal wells

Tubing Depth Optimization Study of Horizontal Well Drainage and Gas Production in WeiYuan Shale Gas Field

Timely production with a tube in shale gas wells can effectively ensure the stable decline of gas wells. However, there is no in-depth study on which position of tubing is the most favorable for the stable production of gas wells and whether the wellbore trajectory has an impact on this position. To determine the reasonable end of tubing (EOT), firstly, through the gas water flow experiment of the whole wellbore test device of a horizontal well, the characteristics of liquid accumulation in the test section and the liquid discharge at the outlet are analyzed. The results show, when the horizontal section inclines upward and the end of the tubing reaches 1/3 of the horizontal section, the gas flow carrying liquid is the smallest. Then, OLGA software is used to simulate the wellbore effusion in the production process of gas wells with different tubing depths under different wellbore trajectories. The results show when the horizontal section inclines upward and the end of the tubing arrives at 1/3 of the horizontal section, the cumulative production of the gas well is the largest. Based on comprehensive analysis, it is most favorable for horizontal shale gas wells when the end of the tubing is about 1/3 of the horizontal section.

Drainage Research of Different Tubing Depth in the Horizontal Gas Well Based on Laboratory Experimental Investigation and a New Liquid-Carrying Model

Since the structure of horizontal gas wells is more intricate than that of vertical wells, there is a lack of consistency in the form of liquid-carrying in different portions. Applying the commonly utilized liquid-carrying hypothesis of vertical gas wells into horizontal gas wells is therefore challenging. The maximum liquid volume that the gas flow could raise, the gas flow rate, and the maximum amount of energy that could be produced from a specific amount of gas flow should all be considered when determining the liquid volume that the gas flow could lift. This study is the first to integrate theoretical analysis with laboratory testing to analyze the gas–liquid flow law of drainage stability at varied tubing depths. The impact of gas drainage stability is then verified through the laboratory experiments. The novel model of various tubing depths, which is based on the energy of inflow and outflow from the horizontal well, is cleverly built. According to the study, the fluctuation is typically less when the tubing reaches the heel of the horizontal section than it is in the other sections, and the relative error of the new model, which is validated using laboratory tests, is typically less than 10%. The research showed that for horizontal gas wells with a normal structure, the gas flow and liquid discharge are most stable when the tubing reaches the heel of the horizontal section. Instead of depending exclusively on crucial liquid-carrying gas flow rates, the new model uses the combination of gas and liquid flow rates to make decisions concerning liquid loading and to quantify the liquid removal in real time, which is more realistic. The research illustrates how the study could provide a factual basis for assessing the capacity of horizontal gas wells to raise the liquid.

Unified early-to-late time forecasting method for multi-fractured horizontal wells in unconventional gas reservoirs with fracture interference effects

This paper presents a unified forecasting approach for multi-fractured horizontal gas wells from early to late time considering inter-fracture communication effects based on Green’s Function Method. The proposed methodology circumvents the need to determine the end of linear flow time currently required in available forecasting methods. As a result, the application of independent solutions for specific flow regimes is avoided, diminishing the degree of uncertainty for the analyst. The present work also aims to decrease the degree of empiricism in current forecasting models based on pseudo-time and DOI by addressing the nonlinearity in the flow equation in a rigorous manner. The proposed methodology is validated against finely gridded numerical simulation models to demonstrate the capabilities of the proposed approach to forecast multi-fractured horizontal gas well performance. Further comparative studies against available approximate methods, such as classical and pseudo-time-based analytical solutions, are also considered to showcase the limitations in the current state-of-the-art of production data analysis of unconventional gas wells. It is evidenced that for the cases of higher pressure drawdown, where the nonlinear behavior of gas flow is exacerbated, current approaches fail to predict the expected system behavior. This finding confirms the importance of the proposed methodology, which consistently yielded the best matches given its capabilities to incorporate nonlinearity in a more rigorous manner.

Liquid Loading of Horizontal Gas Wells in Changbei Gas Field

The Changbei gas field, which initially exhibited high gas-production performance, is dominated by large-displacement horizontal wells. With the decrease in reservoir pressure, the liquid loading in the gas well is currently severe, and production has been rapidly decreasing. Thus, recognizing the gas-well liquid loading to maintain stable gas-well production is necessary. A method was established to identify the water source of the liquid loading in the Changbei gas field. First, formation water and condensate water were identified based on the mineralization of the recovered water and the mass concentration of Cl− and K+ + Na+, and then the condensate content of the water produced in the gas well was qualitatively evaluated. The water–gas ratio curve for the gas well was plotted to determine whether the produced water was edge-bottom water, pore water, or condensate. Then a method was established to distinguish the start time of liquid loading in the gas well using a curve depicting a decrease in production; the method was also used to estimate the depth of the gas well where liquid loading occurs, according to the bottomhole pressure. First, based on the available production data, the Arps decline model was applied to fit the production curve for the entire production phase; the resulting curve was compared with the actual production curve of the gas well, and the two curves diverged when fluid accumulation began in the gas well. Finally, the liquid-loading depth of the gas well was estimated based on the bottomhole pressure. This method can be used to determine the fluid accumulation and calculate the liquid-loading depth of gas wells with unconnected oil jackets. The analysis revealed that in the Changbei gas field, condensate was the type of water primarily produced in 35 gas wells, accounting for 62.5% of the total number of gas wells. Edge-bottom water was the type of water primarily produced in 16 gas wells, accounting for 28.6% of the total number of gas wells. In the remainder of the gas wells, pore water was the water primarily produced; the calculations of accumulation time and accumulation volume of typical gas wells in the block revealed that some gas wells started to accumulate liquid after 45–50 months, and the amount of accumulation could reach several tens of meters, while others were in good production condition. The method established in this paper could enhance our understanding of liquid loading in gas wells in the Changbei gas field and lay a foundation for the development of gas-well deliquification techniques.

Analysis of Wellbore Flow in Shale Gas Horizontal Wells

Analysis of Wellbore Flow in Shale Gas Horizontal Wells

A COMPREHENSIVE REVIEW OF HYDRAULIC FRACTURING TECHNIQUES IN SHALE GAS PRODUCTION

Shale gas has emerged as a significant source of natural gas due to advancements in hydraulic fracturing and horizontal drilling technologies. This extraction method has facilitated drilling and production activities in regions previously untouched by oil and gas development. Hydraulic fracturing, a well-stimulation technique suitable for low and moderate-permeability reservoirs, relies on the successful drilling of horizontal wells and the creation of multiple hydraulic fractures to ensure economic viability. While shale gas presents significant energy production opportunities, concerns have been raised regarding its environmental impact. To mitigate these risks and determine the most effective approach for shale gas extraction, alternative fracturing technologies are being investigated. Notably, a considerable number of perforation clusters in shale gas horizontal wells do not contribute to production, highlighting the potential for refracturing. Therefore, a comprehensive analysis is required to evaluate the performance of hydraulic fracturing and alternative fracturing technologies in shale gas wells, considering factors such as cost-effectiveness, environmental impact, and gas extraction efficiency. This article aims to evaluate the hydraulic fracturing technology's capability to enhance gas recovery in shale gas formations as well as its environmental implications. The focus of this research is primarily on the hydraulic fracturing technique employed in shale gas development, its production capability, and associated environmental concerns. Through a systematic evaluation, this study provided valuable insights into the potential of hydraulic fracturing in maximizing gas recovery while addressing environmental challenges in shale gas formations.

An Artificial Intelligence Algorithm for the Real-Time Early Detection of Sticking Phenomena in Horizontal Shale Gas Wells

An Artificial Intelligence Algorithm for the Real-Time Early Detection of Sticking Phenomena in Horizontal Shale Gas Wells

Optimization of High Temperature-Resistant Modified Starch Polyamine Anti-Collapse Water-Based Drilling Fluid System for Deep Shale Reservoir.

During drilling in deep shale gas reservoirs, drilling fluid losses, hole wall collapses, and additional problems occur frequently due to the development of natural fractures in the shale formation, resulting in a high number of engineering accidents such as drilling fluid leaks, sticking, mud packings, and buried drilling tools. Moreover, the horizontal section of horizontal well is long (about 1500 m), and the problems of friction, rock carrying, and reservoir pollution are extremely prominent. The performance of drilling fluids directly affects drilling efficiency, the rate of engineering accidents, and the reservoir protection effect. In order to overcome the problems of high filtration in deep shale formations, collapse of borehole walls, sticking of pipes, mud inclusions, etc., optimization studies of water-based drilling fluid systems have been conducted with the primary purpose of controlling the rheology and water loss of drilling fluid. The experimental evaluation of the adsorption characteristics of "KCl + polyamine" anti-collapse inhibitor on the surface of clay particles and its influence on the morphology of bentonite was carried out, and the mechanism of inhibiting clay mineral hydration expansion was discussed. The idea of controlling the rheology and water loss of drilling fluid with high temperature resistant modified starch and strengthening the inhibition performance of drilling fluid with "KCl + polyamine" was put forward, and a high temperature-resistant modified starch polyamine anti-sloughing drilling fluid system with stable performance and strong plugging and strong inhibition was optimized. The temperature resistance of the optimized water-based drilling fluid system can reach 180 °C. Applied to on-site drilling of deep shale gas horizontal wells, it effectively reduces the rate of complex accidents such as sticking, mud bagging, and reaming that occur when resistance is encountered during shale formation drilling. The time for a single well to trip when encountering resistance decreases from 2-3 d in the early stages to 3-10 h. The re-use rate of the second spudded slurry is 100 percent, significantly reducing the rate of complex drilling accidents and saving drilling costs. It firmly supports the optimal and rapid construction of deep shale gas horizontal wells.

How can casing deformation be prevented during hydraulic fracturing of shale gas?—A case study of the Weiyuan area in Sichuan, China

In the process of hydraulic fracturing of shale gas horizontal wells in the Weiyuan area of Sichuan, China, casing deformation (CD) is a frequent problem that has seriously affected the benefits of shale gas development and remains to be solved for many years. In this paper, based on the analyses of Multi-finger Imaging Tool-24 (MIT-24) data, microseismic data, and the relationship between CD and engineering parameters, we confirm that the wellbore morphology in all CD sections in the Weiyuan area is consistent with shear deformation characteristics and clarify the cause of all CD: hydraulic fracturing leads to increased fluid pressure in well-intersecting faults and large fractures (F-Fs), inducing their shear slip, and eventually leads to asymmetric compression on the casing by strata on both sides of F-Fs, i.e., CD. On this basis, we propose a set of methods to control (or moderate) the shear slip of F-Fs by reducing the additional fluid pressure in target F-Fs during hydraulic fracturing to prevent CD, including multi-cluster perforations, temporary plugging F-Fs and fracturing fluid flowback. We also analyze the theoretical basis, feasibility and workflow of these methods. These methods have been tested in 44 horizontal wells in the Weiyuan area, of which the result is a radical decrease in the CD rate of the single well (from 54% to 9.1%), indicating that the slip of F-Fs and the resulting CD during hydraulic fracturing can be controlled and providing a reference for the prevention of hydraulic fracturing-induced earthquakes.

Velocity String Drainage Technology for Horizontal Gas Wells in Changbei

The Changbei gas field is dominated by wells with large horizontal displacement, which have exhibited high gas production performance at an early stage of development. With the decrease in reservoir pressure, the liquid loading in the gas well is relatively high and gas production rapidly decreases. Therefore, suitable drainage measures are required to maintain stable gas production. Based on the characteristics of the unconnected oil jacket of gas wells in Changbei, a velocity string was used for drainage. A critical liquid-carrying model was established to determine the location of liquid loading in horizontal gas wells in Changbei. First, the coefficients of the liquid-carrying model were determined through theoretical analysis of the characteristics of the gas well formation. Then, the depth setting of the velocity string was analyzed. The critical liquid-carrying model was employed to calculate the liquid-carrying flow rate of each section; the calculated flow rates were compared with the actual flow rates to determine whether fluid accumulation occurred in each section of the gas well. Thereafter, with the help of the oil and casing position, the suitable setting position of the velocity string was determined. The formation fluid was driven from the tubing into the casing owing to the increase in the overflow area, based on the principle of reducer fluid mechanics. The fluid velocity in the larger overflow cross-section decreased, thereby reducing the drainage capacity of the gas well and resulting in liquid loading. Finally, a timing analysis was performed. After the formation pressure decreased, the well production and flow rate changes were analyzed by placing two velocity strings of different sizes at different wellhead pressures in the gas well with fluid accumulation. The results indicated that although the velocity string was set at a position suitable for fluid drainage, fluid accumulation still occurred after a production period, thus necessitating replacement deliquification.

The Mechanism of Casing Deformation before Hydraulic Fracturing and Mitigation Measures in Shale Gas Horizontal Wells

During the development of shale gas, one of the major challenges is the casing deformation (CD) in the horizontal section due to the geological activity. Recently, the casing deformation before hydraulic fracturing (CDBF) occurred in multiple shale gas wells in L block in China. In this paper, based on the theory of tubular mechanics, the relationship between casing buckling and CDBF caused by casing running in is analyzed qualitatively and quantitatively. It is found that the buckling deformation caused by running the casing string process is not sufficient to prevent the tool (Φ99 mm bridge plug). On the other hand, the mechanism of CDBF is systematically analyzed based on the actual field data and finite element (FE) method. In order to analyze the CDBF mechanism, the comparison between the actual casing trajectory and the reservoir rock (S#1, S#2, S#3 and M#1) in horizontal section in H2 platform is carried out, and the preliminary CDBF mechanism is proposed. Then, two groups of FE models are established to reduce the CD process to verify the preliminary mechanism. It is found that the numerical simulation results (high stress section length from FE model) are in good agreement with the actual CD logging results. Based on the analytical results, the corresponding mitigation measures are proposed based on the analysis of the CDBF mechanism. Our work could offer a detailed theoretical basis and reference of CDBF for shale gas well application.

Effect of Fault Slip on the Casing Passability of Horizontal Shale Oil and Gas Wells

Summary Fault slip, a secondary effect of the hydrofracture to extract shale oil and gas, deforms the casing locally and affects downhole tools going through it, hindering the exploitation plan. The casing passability is introduced to evaluate the casing passability for the downhole tool. A simulation model of the fault slip was established to analyze the effect of fault type, slip distance, and fault dip on the casing passability. Meanwhile, the simulation method adopted in this paper was verified by the large-scale physical experiments of the perforated casing subjected to uniform outer pressure. Based on the experimental results and the geometry of fault slip, an empirical formula is proposed for the relationship between casing passability and fault slip. The result shows that the sensitivity of casing passability affected by fault type is ranked from highest to lowest by strike-slip fault, normal fault, and reverse fault. This study provides a reference for determining the available diameter of downhole tools quickly and reduces the cost of exploring wells when downhole tools are obstructed.

Synthesis of the Oil-Based Nanoblocker Poly(MMA-BMA-BA-St) and the Study of the Blocking Mechanism.

Well wall instability is one of the problems that seriously affect the efficiency of oil and gas drilling and extraction, and the economic losses caused by accidents due to well wall instability amount to billions of dollars every year. Aiming at the fact that well wall stabilization is the current technical difficulty of drilling shale gas horizontal wells with oil-based drilling fluids, the oil-based nanoplugging agent poly(MMA-BMA-BA-St) was synthesized by the Michael addition reaction with compounds such as styrene, methyl methacrylate, and butyl methacrylate as raw materials. The structure and characteristics of the oil-based nanoblocker poly(MMA-BMA-BA-St) were characterized by infrared spectroscopy, particle size analysis, and thermal weight loss analysis. The particle size distribution of poly(MMA-BMA-BA-St) is 80.56-206.61 nm, with an average particle size of 137.10 nm, and it can resist the high temperature of 372 °C. The effects of poly(MMA-BMA-BA-St) on the performance parameters of oil-based drilling fluids were investigated by rheological experiments, electrical stability tests, and HTHP filtration loss experiments. The results show that when poly(MMA-BMA-BA-St) is added at 0.5 wt %, it has less influence on the rheological parameters of drilling fluids, the breaking emulsion pressure remains basically unchanged, the stability of the drilling fluid is better, the dynamic-plastic ratio of the drilling fluid is higher than 0.27, the filtration loss is the lowest, and it shows good rock-carrying properties. The results of mud cake experiments and artificial lithology experiments show that poly(MMA-BMA-BA-St) has the best sealing effect, with a mud cake permeability of 1.12 × 10-4 mD and a sealing rate of 30.00% when added at 0.5 wt %; the artificial core permeability was 4.0 × 10-4 mD, and the sealing rate was 91.23%. Poly(MMA-BMA-BA-St) showed good sealing performance. The oil-based nanoplugging agent poly(MMA-BMA-BA-St) has good dispersion in oil-based drilling fluids and can enter the nanopore joints to form a dense plugging layer under the action of formation pressure to prevent the intrusion of drilling fluids, thus reducing the impact of drilling fluids on the formation, maintaining the stability of the well wall and reducing downhole complications.

Modeling of solids particle diversion to promote uniform growth of multiple hydraulic fractures

Solid particulate additives are sometimes used to promote the uniform growth of multiple hydraulic fractures in horizontal oil and gas wells. The principle is that solid particulates block, accumulate, and form larger porous plugging zones preferentially at entrances of fracture taking in the most fluid volume. These porous zones create fluid flow resistance or additional pressure loss; thereby, inhibiting the growth of these dominant fractures and diverting fluid to suppressed fractures. While this technology is promising, governing design parameters and ramifications of placing solids diverters inside the fracture remain unclear. This paper models the propagation of multi-fractures with diverter pressure losses induced by the porous plugging zones. The resulting non-linear hydraulic fracturing problem is solved numerically with an Implicit Level Set Algorithm (ILSA) for each time step and the mechanisms of diversion are illustrated by comparing and contrasting cases with and without particle diverter. In both cases, during the fluid ramp-up period (pumping rate gradually increases from 0 to fracturing rate (QT)), the injection can be equally distributed among fractures before the stress interference affects the fluid allocation (Phase I). Then, stress interference starts to partition more fluid into outer fractures and suppress the growth of the middle fracture (Phase II). Once the perforation friction loss is sufficient to counteract the stress interaction, injection begins to shift to the middle fracture, but still gives a significantly non-uniform fracture growth (Phase III). At this point, solid diverter particles are introduced, leading to three additional phases of growth. Phase IV introduces solid diverters to the treatment at a reduced pumping rate. Particles bridge, accumulate and create porous plugging zones at the flow entrance. A higher pressure drop in outer fractures diverts injection fluids to the middle fracture. Phase V resumes the treatment rate to QT without diverter. The increased pump rate in turn increases the pressure drop in outer fractures and diverts more fluids to the middle fracture. This results in a rapid extension velocity for the middle fracture, enabling it to have the chance to catch up with the longer outer fractures (in Phase VI). This process is controlled by the interplay among stress interference, perforation friction loss, and diverting pressure drop. These simulations demonstrate that a model-based optimization could improve the effectiveness of the diverter technology and promote a uniform multi-fracture growth.

Experimental and Modeling Investigation on Gas-Liquid Two-Phase Flow in Horizontal Gas Wells

Abstract Wellbore pressure gradient in gas wells is significant in designing deliquification technologies and optimizing production. At present, no model has yet to be established specifically for gas wells at a wide gas flowrate range. When calculating pressure gradient in a specific gas field, engineers must evaluate these widely used models and get the best performance model at a certain range. To establish a more comprehensive model in horizontal gas wells, an experimental study was conducted to investigate the flow behavior of liquid-gas two-phase flow at different gas and liquid velocities and inclined angles in a 50 mm visual pipe. The evaluation of these widely used models against the experimental data shows that no model can predict liquid holdup at different gas velocity ranges, and huge deviations due to several reasons can be observed. After conducting a comprehensive analysis, a new liquid holdup correlation was proposed based on the Mukherjee–Brill model by correlating from the experimental results, which have parametric ranges closer to the production of gas wells. This new model adopts a new dimensionless gas velocity number to characterize flow similarities and better scale up pressure from the experiment to the gas wells. By validating against experimental data and field data, the results indicate that the new two-phase flow model has stable performance and can accurately predict pressure gradients at different ranges of pressure and gas/liquid velocities.

An Analytical Hierarchy-Based Method for Quantifying Hydraulic Fracturing Stimulation to Improve Geothermal Well Productivity

Hydraulic fracturing (HF) has been used for years to enhance oil and gas production from conventional and unconventional reservoirs. HF in enhanced geothermal systems (EGS) has become increasingly common in recent years. In EGS, hydraulic fracturing creates a geothermal collector in impermeable or low-permeable hot dry rocks. Artificial fracture networks in the collector allow for a continuous flow of fluid in a loop connecting at least two wells (injector and producer). However, it is challenging to assess the fracability of geothermal reservoirs for EGS. Consequently, it is necessary to design a method that considers multiple parameters when evaluating the potential of geothermal development. This study proposes an improved fracability index model (FI) based on the influences of fracability-related geomechanical and petrophysical properties. These include brittle minerals composition, fracture toughness, minimum horizontal in-situ stress, a brittleness index model, and temperature effect to quantify the rock’s fracability. The hierarchical analytic framework was designed based on the correlation between the influencing factors and rock fracability. The results of the qualitative and quantitative approaches were integrated into a mathematical evaluation model. The improved fracability index model’s reliability was evaluated using well logs and 3D seismic data on low-permeable carbonate geothermal reservoirs and shale gas horizontal wells. The results reveal that the improved FI model effectively demonstrates brittle regions in the low-permeable carbonate geothermal reservoir and long horizontal section of shale reservoir. We divide the rock fracability into three levels: FI > 0.59 (the rock fracability is good); 0.59 > FI > 0.32 (the rock fracability is medium); and FI < 0.32, (the rock fracability is poor). The improved FI model can assist in resolving the uncertainties associated with fracability interpretation in determining the optimum location of perforation clusters for hydraulic fracture initiation and propagation in enhanced geothermal systems.