Hydraulic Fracturing Technique Research Articles

Advances in enhanced geothermal systems: Integrating laboratory, numerical and field insights

An enhanced geothermal system is a designed and engineered thermal reservoir that has been deliberately stimulated to extract economically viable amounts of heat from geothermal resources having no natural permeability. Enhanced geothermal system projects are typically initiated to meet the industrial production standards, usually via techniques such as chemical stimulation, hydraulic fracturing, or thermal processes to enhance the permeability of the reservoir. The main aim of this study is to evaluate the current advancements in enhanced geothermal system through a comprehensive examination of laboratory experiments, numerical simulation, and fieldwork investigations from numerous studies that are insufficient captures and combined by current open literature. This study highlighted the critical importance of precisely developing fracture systems, whether natural or artificially induced, in ensuring the effectiveness of such projects. Notably, hydraulic fracturing techniques have been proven instrumental in enhancing the performance of enhanced geothermal systems. On the contrary, research conducted through numerical simulations has demonstrated consistent findings that it is beneficial to enhance the permeability of low-permeability rock for the efficient use of enhanced geothermal systems. Additionally, this study has highlighted the intricate and expensive nature of designing enhanced geothermal systems due to uncertainties in subsurface conditions especially from projects that are in initial stages of development. This study enables researchers and operators to improve the efficiency and safety of geothermal energy extraction, paving the way for more sustainable enhanced geothermal system projects in the future.

Influence of Shale Mineral Composition and Proppant Filling Patterns on Stress Sensitivity in Shale Reservoirs

Shale reservoirs typically exhibit high density, necessitating the use of horizontal wells and hydraulic fracturing techniques for efficient extraction. Proppants are commonly employed in hydraulic fracturing to prevent crack closure. However, limited research has been conducted on the impact of shale mineral composition and proppant filling patterns on shale stress sensitivity. In this study, shale cylindrical core samples from two different lithologies in Jimusaer, Xinjiang in China were selected. The mineral composition and microscopic structures were tested, and a self-designed stress sensitivity testing system was employed to conduct stress sensitivity tests on natural cores and fractured cores with different proppant filling patterns. The experimental results indicate that the stress sensitivity of natural shale porous cores is weaker, with a stress sensitivity coefficient below 0.03, significantly lower than that of fractured cores. The shale mineral composition has a significant impact on stress sensitivity, with the stress sensitivity of clayey argillaceous shale cores, characterized by higher clay mineral content, being higher than that of sandy argillaceous shale, characterized by higher quartz mineral content. This pattern is also applicable to fractured cores filled with proppants, but the difference gradually diminishes with increased proppant concentration. The choice of large particles and high-concentration proppant bedding can enhance crack conductivity. Within the experimental range, the crack conductivity of 20–40 mesh quartz sand is more than three times that of 70–120 mesh quartz sand. At an effective stress of 60 MPa, the conductivity of cores with a proppant concentration of 2 kg/m2 is 3.61 times that of cores with a proppant concentration of 0.3 kg/m2. Under different particle size combinations of proppant filling patterns, the crack conductivity at the crack front with large-particle proppants is 6.21 times that of mixed bedding. This study provides valuable insights for the hydraulic fracturing design of shale reservoirs and optimization of production system parameters in subsequent stages.

A three-dimensional numerical well-test model for pressure transient analysis in fractured horizontal wells with secondary fractures

During oil and gas reservoir development, multi-stage horizontal wells (MFHWs) and hydraulic fracturing techniques can effectively increase estimated ultimate recovery. However, there still lacks an understanding of the three-dimensional (3D) pressure transient behaviors of multi-stage fractured horizontal wells with secondary fractures. To narrow this gap, a three-dimensional numerical well-test model based on a discrete fracture model and unstructured tetrahedral grids is developed to study the pressure transient behaviors of MFHWs with secondary fractures. The pressure transient solutions of MFHWs with secondary fractures have been demonstrated by model verifications. The results show that the proposed model can accurately capture the complex transient flow around fractures, including early radial flow that is not easily captured by two-dimensional numerical well test models. The proposed model classifies the flow regimes of a MFHW as: wellbore storage and skin effects, early radial flow, bilinear flow, linear flow, elliptical flow, pseudo radial flow, and pseudo-boundary dominated flow. It is found that the fracture geometry has a relatively large effect on the shape of the pressure derivative curve in this work. The hydraulic fracture half-length has the greatest impact on the pressure transient behaviors of the MFHW, followed by fracture height and secondary fracture half-length, as found in this study. Additionally, fracture parameters are evaluated, and actual well testing data are interpreted, taking into account the fracture height. This work is meaningful to understand the three-dimensional pressure transient behaviors of MFHWs with secondary fractures.

Extreme massive hydraulic fracturing in deep coalbed methane horizontal wells: A case study of the Linxing Block, eastern Ordos Basin, NW China

Deep coal seams show low permeability, low elastic modulus, high Poisson’s ratio, strong plasticity, high fracture initiation pressure, difficulty in fracture extension, and difficulty in proppants addition. We proposed the concept of large-scale stimulation by fracture network, balanced propagation and effective support of fracture network in fracturing design and developed the extreme massive hydraulic fracturing technique for deep coalbed methane (CBM) horizontal wells. This technique involves massive injection with high pumping rate + high-intensity proppant injection + perforation with equal apertures and limited flow + temporary plugging and diverting fractures + slick water with integrated variable viscosity + graded proppants with multiple sizes. The technique was applied in the pioneering test of a multi-stage fracturing horizontal well in deep CBM of Linxing Block, eastern margin of the Ordos Basin. The injection flow rate is 18 m3/min, proppant intensity is 2.1 m3/m, and fracturing fluid intensity is 16.5 m3/m. After fracturing, a complex fracture network was formed, with an average fracture length of 205 m. The stimulated reservoir volume was 1 987×104 m3, and the peak gas production rate reached 6.0×104 m3/d, which achieved efficient development of deep CBM.

Research on Hydraulic Fracturing Technology of Long Boreholes along Strata of High Vast Thick Coal Seam

Gas extraction is a major technique for regional gas regulation and coal and gas comining in China. Assuring effective gas extraction operations is a crucial step in ensuring the supply of energy. The effect range of extraction drilling, pressure relief degree, and standard period of gas extraction are all constrained because of the geological constraints affecting coal gas permeability and occurrence. Combined with the advantages of directional drilling and high-efficiency pumping technology and antireflection enhanced pumping technology of hydraulic fracturing, directional long-drilling hydraulic fracturing can effectively improve the efficiency of gas control and expand the scale of gas control. The present study focuses on the exploration of directional long-hole hydraulic fracturing technique in thick coal seams with high gas content using Dafosi Mine as a case study. The research findings demonstrate that hydraulic fracturing contributes to the enlargement of pore size, pore density, and pore connectivity in coal seams. In-depth research was conducted on the expansion of coal seam fractures during the hydraulic fracturing process using the RFPA3D-flow numerical simulation program. Additionally, a comprehensive analysis of stress distribution around the fractures under the flow-solid coupling condition was performed. To further improve the effectiveness of hydraulic fracturing technique, the research team optimized the fracturing tools and construction processes in the four coal seams of Dafosi Mine. The impact of segmented hydraulic fracturing in coal seam bare hole drilling was also studied. Furthermore, an investigation method specific to the coal seam bare hole segmented hydraulic fracturing effects applicable to Dafosi Mine was developed. The maximum fracture extension pressure, minimum fracture closure pressure, and fracture morphology change characteristics during drilling and fracturing were measured, and the fracturing influence radius of coal seam was determined to be 46−58 m, the gas extraction concentration after fracturing increased by 2.20–4.22 times, and the 100-m extraction flow increased by 4.93–11.03 times. It gives other mines technical assistance so they can keep advocating and utilizing the horizontal directional long-drilling stage hydraulic fracturing technique.

Analytical Optimization of Hydraulic Fracturing

Hydraulic fracturing optimization is a critical aspect of improving the recovery of unconventional shale formation. This paper discusses the use of different types of proppants, rate optimization, and proppant amount optimization to improve hydraulic fracturing techniques. The paper begins with a discussion of proppant selection, which is a critical aspect of hydraulic fracturing. The authors highlight the importance of proppant endurance in holding the fracture opening and provide a range of proppants suitable for different confining pressures. Tables and charts are included to illustrate the permeability values of various proppants under different closure stress values. This section also emphasizes the significance of proppant shape in creating a more conductive path in the fracture. The next section of the paper discusses the methodology used in the study, including the Fracpro software simulation parameters. The authors then delve into the optimization of proppant specific gravity and the results of their experiments with five different types of proppants. The paper highlights the impact of proppant specific gravity on fracture width and dimensionless conductivity (FCD). The author also focusses on the optimization of pumping rate, which is an essential parameter of hydraulic fracturing operations. The paper includes simulation studies conducted to determine the effects of pumping rate on fracture parameters such as propped length and propped height. The authors highlight the relationship between rate and FCD and how it is affected by permeability values of the proppant. Finally, the paper discusses proppant amount optimization, which is a critical point of hydraulic fracturing optimization. The authors provide an overview of the results of the experiments conducted to determine the optimal amount of proppant required for different hydraulic fracturing operations. Overall, this paper provides valuable insights for researchers and engineers working to improve hydraulic fracturing techniques for tight shales formation. The authors use a combination of theory, experiments, and charts to provide a comprehensive overview of the various aspects of hydraulic fracturing optimization.

Comments: New Year Marks JPT’s 75th Anniversary

We’re excited to begin the year with the commemoration of JPT’s 75th anniversary. This issue launches our special features dedicated to JPT’s reporting of technology and practices over the past 7½ decades. Emerging Technology Senior Editor Stephen Rassenfoss and Senior Technology Editor Trent Jacobs penned this month’s articles highlighting innovations in drilling, completions, and reservoir engineering. Each month, our editors will dive into the archives to round up milestones of industry advancements and achievements as reported in JPT. Since its inaugural issue in January 1949, JPT has remained true to its mission of reporting the technological and scientific learnings and advancements in the global oil and gas industry. Built upon a strong technical foundation, it continues to draw upon the expertise and knowledge of industry experts to disseminate up-to-date, relevant information to SPE members from all disciplines. JPT’s evolution began with The American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME), founded in 1871 in Wilkes-Barre, Pennsylvania. It was one of the first national engineering societies established in the US. In subsequent years, AIME was joined by four other engineering founder societies—The American Society of Mechanical Engineers (ASME), the American Institute of Electrical Engineers (now the Institute of Electrical and Electronics Engineers [IEEE]), the American Society of Civil Engineers (ASCE), and the American Institute of Chemical Engineers (AIChE)—and formed the United Engineering Foundation. (US President Herbert Hoover, a mining engineer, served as AIME’s president in 1920.) As AIME itself continued to grow, it decentralized and formed four independently operated member societies: SME (Society for Mining, Metallurgy, and Exploration); TMS (The Minerals, Metals, and Materials Society); AIST (Association for Iron & Steel Technology); and SPE (Society of Petroleum Engineers). AIME had as part of its membership a small, but growing, number of petroleum engineers. These members had specific technological issues far removed from their peers in the older, more-established engineering disciplines. The AIME Petroleum Branch Executive Committee (whose members represented companies such as The Pure Oil Co., Dowell Inc., Humble Oil and Refining Co., and the Texas Co.) determined that the best way to meet this group’s needs was to develop a “publication so dominantly petroleum as to secure wide reader interest,” one that would “rapidly gain the respect of the industry.” Over the years, that goal was achieved. JPT came to be recognized worldwide as the source for authoritative technical information in the petroleum industry. JPT’s first issue included four technical papers, one of which was “A Hydraulic Process for Increasing the Productivity of Wells.” The paper’s author, J.B. Clark, noted, “To date the process has been used in 32 jobs on 23 wells in 7 fields, resulting in a sustained increase in production in 11 wells.” The hydraulic fracturing techniques for well stimulation that he discussed have been responsible for the subsequent recovery of billions of barrels of oil. Also, bear in mind that the world’s total crude oil production in 1949 was about 3.8 billion bbl, less than the projected total US annual production in 2023—4.7 billion bbl. Other articles related to the oil and gas business were “Private Financing of Oil-Producing Properties” and “Middle Eastern Oil and Its Importance to the World.” Interestingly, although the content is outdated, both topics remain relevant today, 75 years later. Join us each month to explore our rich history and follow us on LinkedIn. All issues of JPT from 1949 to date are available in OnePetro. Even a cursory glance at the titles of the papers will show the remarkable evolution of technology over the years. We wish you the best in 2024, both in your professional and personal lives.

A reactive-transport phase-field modelling approach of chemo-assisted cracking in saturated sandstone

Hydraulic fracturing and acidification techniques are important approaches for deep energy recovery engineering. However, the details of the interactions and impacts between acid fluids and solid porous media remain inadequately modelled, necessitating further research in this domain. Building on this need, we present a novel approach for modelling the chemo-hydro-mechanical response in sandstone during fracture propagation which is induced by the injection of acid fluids into the reservoir. Our comprehensive framework integrates various mechanisms including acidified reactions in sandstone, reactive flow transport, pore pressure diffusion, solid deformation, mass exchanges due to chemical reactions, and fracture propagation in poroelastic media, all within the framework of the phase field approach. To accurately capture the system’s behaviour, we derive its total potential energy, taking into account factors such as poroelasticity, fracture forces acting on the fracture sides, and crack dissipation, while also integrating the mechanical–chemical degradation function into the energy derivations. The progress of chemical degradation, which we treat as a damage parameter, is characterized by mass exchanges, and these in turn manifest as changes in porosity. In order to quantify these mass exchanges, we have established a corresponding mass balance equation specifically for the minerals involved. These changes in porosity can be naturally and effectively described through the volumetric relations of the minerals situated within the solid porous media. The proposed coupled framework is verified through multiple numerical examples. Initially, we validate the model using a classical unit-slit crack example for the solid phase and discuss the predominant influences of porosity alterations on the mechanical response of solid cracking. Following this, we verify the model by injecting water/acid and compare the results with analytical solutions. Finally, a chemical benchmark is employed to calibrate the chemical reaction model and simulate acid fluid injection scenarios.

Enhancement for drag reducer release efficiency from inverse polymer emulsion using pH-responsive dynamic covalent surfactant

The increasing global fossil resources consumption requires convert the sights into the exploitation of tight oil resources. Polymer emulsion drag reducers are widely used in hydraulic fracturing techniques for inhibition of fluid turbulence and reservoir stimulation for enhanced oil recovery. However, the poor release efficiency and requirement for extra hydrophilic surfactant for phase inversion limit the practical application. Herein, a hydrophobic surfactant oleylamine-4-carboxybenzaldehyde (OA-CBA) was synthesized with oleic amine (OA) and 4-carboxybenzaldehyde (CBA). OA-CBA exhibited pH-responsive behavior, attributing to the existence of dynamic covalent bond in OA-CBA. The OA-CBA stabilized monomer emulsions, consisted of acryla-mide (AM), 2-acrylamide-2-methylpropane sulfonic acid (AMPS) and Acrylic acid (AA), suggests remarkable dynamic and storage stability, which supply stable microreactors for polymerization. Furthermore, polymer emulsion with pH-responsive behavior was obtained by inverse emulsion polymerization upon redox initiation. The polymer drag reducer was completely released within 10 s upon adjusting the pH value to 2.26. Notably, the pH-responsive polymer emulsion exhibited 18 times faster release time compared to traditional polymer emulsion stabilized by Span 80, along with a 63.2% drag reduction rate. The rapid release of the polymer was realized by regulating pH merely instead of introduction of extra hydrophilic surfactant, which reconciles the contradiction of stability and release of polymer from emulsions.

Crucial Development Technologies for Volcanic Hydrocarbon Reservoirs: Lessons Learned from Asian Operations

Oil and gas reservoirs in volcanic rocks are a particular type of unconventional reservoir and present unique challenges for exploration and production engineers. To help the oil industry understand volcanic reservoirs and solutions to complex development problems, we reviewed their key engineering technologies as well as their geological characteristics. The distinctive geological characteristics of volcanic hydrocarbon reservoirs are strong heterogeneity, low porosity and permeability, complex fracture systems, etc. The volcanic reservoir rock types in order of hydrocarbon abundance are basalt (38.5%), andesite (15.9%), volcaniclastic (12.1%), and rhyolite (11.5%). The porosity ranges from 0.1 to 70%, and permeability ranges from 0.0007 to 762 md. In some commercially developed volcanic reservoirs of China, the average porosity is 7.7–13%; the average permeability is 0.41–3.4 md. Engineers have applied a variety of adapted technologies to produce volcanic reservoir economically. Horizontal wells can increase production and reserves by 4–6 times those of vertical wells, and longer wells are preferred. Specialized hydraulic fracturing techniques are suggested, including small or mixed proppant size, second HF treatment after proppant slugging, high-viscosity frac fluid with high-temperature resistance, special fluid loss reducer, high pump pressure, Extreme Overbalance Perforating, limited-entry fracturing, matrix acidizing, etc. Water control measures include producing below critical rates, partial perforation or penetration, controlling hydraulic fracture height, using horizontal wells, implementing complete cementing job, etc. Well productivity evaluation should be conducted to understand well performance and appropriately allocate production rates among wells, using the modified AOF method and other productivity prediction models considering breakdown fracture gradient, gas slippage effect, non-Darcy effect, etc. Well sites need to be selected based on recognizing profitable lithologies, lithofacies, high porosity and permeability, relatively developed fracture systems, thick net pay zones, etc. The critical questions for the industry are how to enhance volcanic reservoir recovery with more efficient and economic hydraulic fracturing and water control techniques. This is one of the first papers systematically summarizing the engineering technologies and unique solutions to develop volcanic reservoirs. Further and more complete reviews can be carried out in the future, and more novel and effective techniques can be explored and tested in the field.

Exploring the inhibitory effect of H2O on CO2/CH4 adsorption in coal: Insights from experimental and simulation approaches

To investigate the inhibitory effect of H2O on the adsorption of CH4/CO2 in coal, the anthracite was selected for physical adsorption experiments on CH4/CO2 gases in this study. Combined with Materials Studio software, the effect of moisture on the isothermal adsorption characteristics of CH4/CO2 in coal was investigated by using density functional theory and giant canonical Monte Carlo simulation. The intermolecular interaction energies were obtained, as well as the effects of electrostatic potentials, adsorption sites, and hydrogen bonding of oxygen-containing functional groups. The results show that: ①According to the CH4/CO2 isothermal adsorption experiments, it was found that moisture significantly inhibited the adsorption of CH4/CO2 by coal. For CH4, the relationship between adsorption constants a/b and moisture content can be expressed by the equations y = 43.447-3.348x and y = 3.225-0.751x. For CO2, adsorption constant a follows a power function relationship with moisture content, expressed as y = 29.114x-0.063, while adsorption constant b is represented by the polynomial fitting equation y = 1.672+0.508x+0.083x2. ② The findings have revealed correlations between the moisture influence coefficient and moisture content. The exponential functional equation η = exp(-0.188ω) was found to be more accurate for coal adsorbing CH4, whereas the linear functional equation η = 1/(1 + 0.243ω) was considered more appropriate for CO2. ③ The van der Waals and electrostatic energies between coal and CH4/CO2 decreased with an increase in moisture content, whereas the van der Waals and electrostatic energies between coal and H2O increased. ④ The orders of hydrogen bond formation ability between CH4/CO2 and functional groups were as follows: –CHO > –COOH > –OH > –CH3 and –OH > –COOH > –CHO > –CH3. The ability of H2O to form hydrogen bonds with –COOH, –OH, –CHO, and –CH3 is as follows: –COOH > –OH > –CHO> –CH3. This study provides a theoretical basis for the integrated use of hydraulic fracturing techniques and coalbed gas injection and replacement.

Improving Hydraulic Fracturing Productivity in Khalda Oil Fields (Western Desert -Egypt)

The hydraulic fracturing technique is used to create a highly conductive path between the reservoir and wellbore at an economic rate. There are two types of hydraulic fracturing based on the pumping schedule: the first is the conventional hydraulic fracturing which uses continuous pumping schedule and forms a proppant pack inside the fracture. The second is the channel hydraulic fracturing which uses intermittent (pulsing) pumping schedule and forms proppant pillars inside the fracture. The aim of this work is to study the factors affecting the fracture conductivity of the channel fracturing technique. Technical and economical comparison has been conducted between the above-mentioned two types of fracturing using real production data. The Fracturing Computer-Aided Design and Evaluation (FracCADE) simulator was utilized for this purpose. The results indicate that the conductivity of the channel fracturing technique is greater than that of the conventional one. The pulse time and perforated cluster length were found to have a significant effect on the fracture conductivity because of their influence on the pillar spacing. The results indicate also that: the cost of the channel fracturing is greater than that of the conventional one by about 26.28 %. However, the NPV of the produced oil by the channel fracturing is more than the same of the conventional one. In addition, the payout time of the channel fracturing is shorter which means a faster return of investments.

Using fracture-based continuum modeling of coupled geomechanical-hydrological processes for numerical simulation of hydraulic fracturing

This paper describes numerical simulation of hydraulic fracturing using fracture-based continuum modeling (FBCM) of coupled geomechanical-hydrological processes to evaluate a technique for high-density fracturing and fracture caging. The simulations are innovative because of modeling discrete fractures explicitly in continuum analysis. A key advantage of FBCM is that fracture initiation and propagation are modeled explicitly without changing the domain grid (i.e. no re-meshing). Further, multiple realizations of a preexisting fracture distribution can be analyzed using the same domain grid. The simulated hydraulic fracturing technique consists of pressurizing multiple wells simultaneously: initially without permeating fluids into the rock, to seed fractures uniformly and at high density in the wall rock of the wells; followed by fluid injection to propagate the seeded fracture density hydraulically. FBCM combines the ease of continuum modeling with the potential accuracy of modeling discrete fractures and fracturing explicitly. Fractures are modeled as piecewise planar based on intersections with domain elements; fracture geometry stored as continuum properties is used to calculate parameters needed to model individual fractures; and rock behavior is modeled through tensorial aggregation of the behavior of discrete fractures and unfractured rock. Simulations are presented for previously unfractured rock and for rock with preexisting fractures of horizontal, shallow-dipping, steeply dipping, or vertical orientation. Simulations of a single-well model are used to determine the pattern and spacing for a multiple-well design. The results illustrate high-density fracturing and fracture caging through simultaneous fluid injection in multiple wells: for previously unfractured rock or rock with preexisting shallow-dipping or horizontal fractures, and in situ vertical compressive stress greater than horizontal. If preexisting fractures are steeply dipping or vertical, and considering the same in situ stress condition, well pressurization without fluid permeation appears to be the only practical way to induce new fractures and contain fracturing within the target domain.

Enhancing Water Management in Shale Gas Extraction through Rectangular Pulse Hydraulic Fracturing

Although conventional hydraulic fracturing techniques have revolutionized shale gas development, they have raised concerns regarding water management and environmental impacts. This research introduces an innovative step-rectangular pulse hydraulic fracturing method to optimize water usage and reduce environmental hazards in shale gas extraction. The method involves the application of lower-energy fluid in a step-rectangular pulse pattern, which results in higher pressures, more intricate fractures, and improved water management. A comprehensive analysis of the propagation and attenuation characteristics of this technique is conducted using a combination of a two-dimensional pulse transient flow equation with damping, software numerical simulations, and theoretical analysis. The study reveals that the step rectangular pulse hydraulic fracturing method offers superior pressurization and more complex fracture networks in shale reservoirs while lowering water consumption by 20% less than conventional methods and increasing shale gas production by 12%. Through identifying optimal pulse parameters, this research provides valuable guidance for field implementation, promoting efficient water management and environmental sustainability in hydraulic fracturing operations. This novel approach to hydraulic fracturing has the potential to significantly advance the industry’s efforts to address water management challenges and mitigate environmental risks associated with shale gas extraction.

Assessment of CO2 fracturing in China's shale oil reservoir: Fracturing effectiveness and carbon storage potential

Shale oil resources are abundant in China, and their large-scale development plays a critical role in the national energy strategy. Hydraulic fracturing is widely employed for shale oil extraction, but the large-scale water consumption in this process poses serious environmental concerns. In recent years, CO2 fracturing has been proposed as an alternative method to improve fracturing effectiveness, reduce water consumption, and simultaneously store CO2 underground. This is the first field-testing study in China to systematically analyze the CO2 fracturing technology and quantitatively evaluate its recovery efficiency and CO2 storage capacity in the shale oil wells in Jianghan Basin. We designed and conducted a comparative investigation of hydraulic fracturing, CO2-water fracturing, and CO2 methanol-based fracturing techniques in terms of the effectiveness of fracturing, water saving, and CO2 storage. The results showed that CO2 methanol-based fracturing was most effective in eliminating the need for freshwater consumption on site and storing CO2, with an effective CO2 storage rate as high as 82.5%, suggesting a promising direction for carbon offset in the oil and gas industry. CO2-water fracturing reduced freshwater consumption and also effectively stored CO2 at an effective storage rate of up to 79.5%, making it more efficient than hydraulic fracturing but less so than CO2 methanol-based fracturing. The research provides a valuable reference for the development and practice of waterless fracturing for shale resources, and also sheds light on the potential of carbon storage in the oil and gas industry to achieve the carbon neutrality goal of China.

Prediction of Tensile Strength in Tight Sandstone Based on Well Logging Data

The tensile strength of tight sandstone reservoirs has a direct impact on crack initiation, hydraulic fracture propagation, and the connectivity between hydraulic fractures and natural fractures during hydraulic fracturing processes. To overcome the limitations of experimental testing methods and field hydraulic fracturing techniques, this study conducted Brazilian tensile strength tests to obtain tensile strength data for 16 sets of tight sandstone samples. By comparing these experimental results with well logging data, a predictive model for the tensile strength of tight sandstone was established based on geophysical well logging data, with a correlation coefficient exceeding 0.92. The research findings indicate a positive correlation between tensile strength and sample density. This study provides support for fracture design, assesses fracturability, and aids in the selection of optimal drilling locations for hydraulic fracturing operations.

Gas fracturing behavior and breakdown pressure prediction model for granite under different confining pressure and injection rate

Conventional hydraulic fracturing techniques are often found problematic for extracting geothermal energy in hot dry rock (HDR). As an alternative, employing the less viscous gas to replace water as the fracturing fluid showed great potential for more effective fracturing of HDR. In this work, the failure behavior and mechanism of granite during gas fracturing under different confining pressures and gas injection rates are comprehensively examined. It is shown that the breakdown pressure increases with the increase of confining pressure, whereas higher gas injection rate can result in evident decrease of the breakdown pressure. As the confining pressure grows, the acoustic emission (AE) event increases rapidly, with much higher AE counts observed at high gas injection rates than at low injection rates. Comparatively, the AE energy decreases under high confining pressure, due probably to granite transitioning from brittle to ductile. It is interesting that the b-value of AE varies dramatically as the gas injection rate becomes higher with significant fluctuations, indicating the ratio of large fracture and small fracture changes drastically during gas fracturing. In addition, the length of the induced fractures decreases with the increase of confining pressure during gas fracturing, and the length and width of vertical fractures are evidently larger when at high gas injection rate. Last, a novel theoretical predictive model is proposed for estimating breakdown pressure during gas fracturing based on the average tensile stress criteria, which is featured by considering the effect of confining pressure and gas flow behaviors. The theoretical prediction agrees with the experimental results. The present study can provide valuable results for theoretical analysis and engineering applications of gas fracturing in stimulating the HDR reservoirs.

A new process to develop marine natural gas hydrate with thermal stimulation and high-efficiency sand control

The development of marine gas hydrate from low-permeability offshore reservoirs with serious sand incursion issues is a challenging task. Currently, there are no mature technologies in the world. Therefore, we proposed a comprehensive development process, including the following measures: (1) Vertical injection-production well pattern enhanced by multi-layer fracturing and hot water injection by seawater source heat pump. (2) An advanced multi-layer hydraulic fracturing technique incorporating cold fracturing fluid, low-temperature consolidation proppant, multi-stage sliding sleeve packer, and a chemical diverting agent. (3) A series of sand control measures including hydraulic fracturing, consolidation proppant, and stand-alone screen. (4) Several rounds of hot water injection-soaking-production (huff-n-puff) on injection wells, and finally continuous injection-production, with depressurization. Then, we built a gas hydrate decomposition rate model to simulate this process. The results show that hot water injection combined with multi-layer hydraulic fracturing can significantly improve the gas hydrate dissociation rate compared with the schemes without hot water injection or fracturing. Combining hot water injection by seawater source heat pump, multi-layer horizontal fractures by advanced hydraulic fracturing technique, and a set of sand control techniques, can efficiently control sand while producing gas hydrate.

“Double sweet spot” identification method via cluster analysis of petrophysical properties from well logg data: A case study of a tight sandstone reservoir

In recent years, interest in unconventional resource plays has grown substantially due to horizontal drilling and hydraulic fracturing techniques. However, the high cost of drilling, choosing the right locations for perforation intervals during hydraulic fracturing is a crucial issue. Therefore, identifying so called “sweet spot” with high potential for hydrocarbon production plays an important role in oil and gas industry. In this study a new “double sweet spot” identification method using cluster analysis of well-logged petrophysical properties of facies is presented. Firstly, an engineering sweet spot identification method based on geophysical responses parameters (brittleness index and permeability) is introduced to classify the target zone. Triaxial compression tests are performed to obtain the static Young's modulus and Poisson's ratio of the rock samples. To calculate dynamic Young's modulus and Poisson's ratio, a novel model for determining interval transit time of S-wave is proposed based on the multiple linear regression theory according to well logging data. By performing the cluster analysis, an intersection diagram of permeability and calculated normalized Rickman's brittleness is built and then engineering sweet spots in target zone are characterized based on well-logged petrophysical properties of facies. By plotting the intersection diagram of porosity and oil saturation based on the cluster analysis theory, geological sweet spots in target zone were characterized and four types of rock petrophysical facies are divided: Sandstone A (So＞48%, 8＜φ＜19%); Sandstone B (31＜So＜48%, 6＜φ＜18%); Sandstone C (18＜So＜31%, 8＜φ＜20%) and Sandstone D (0＜So＜18%, 8＜φ＜17%). Secondly, target formation classification is carried out using a proposed geological sweet spot identification method based on reservoir physical parameters (oil saturation and porosity). The relationship between core electrical resistivity and water saturation is determined by traditional Archie's formula and then an oil saturation prediction model in target reservoir is established. Based on the experimental porosity and permeability measurements of 47 core samples and well logging data, a porosity interpretation model is proposed. By plotting the intersection diagram of porosity and oil saturation based on the cluster analysis theory, geological sweet spots in target formation are characterized and four types of rock petrophysical facies are given: Sandstone A (K＞0.1mD, BI＞38); Sandstone B (K＞0.1mD, 33＜BI＜38); Sandstone C (K＞0.1mD, BI＜33) and Sandstone D (0.01＜K＜0.1mD, 10＜BI＜60). The integrated “double sweet spot” identification results of Well 1 in Daqing tight sandstone oil reservoir are given. Rock AA is the most favorable type of petrophysical rock facies and rock DD is the worst favorable type of petrophysical rock facies. Finally, an integrated “double sweet spot” identification method proposed in this study was applied to screen proper interval candidates during refracturing operation in a tight sandstone oil reservoir in China. After refracturing operation a gradually increase of average oil production in well group was found from 1.10 t/d to 5.63 t/d. This novel “double sweet spot” identification method has applicability in other tight oil reservoirs around the world.

Weighting Failure Mechanisms of Pre-Driven Recovery Rooms and Evaluation of Hydraulic Fracturing Applications: A Case Study

Roof weighting failures of pre-driven recovery rooms may cause huge economic losses and even casualties. The excessive dynamic load from the sliding of the broken main roof rock block causes the recovery room roof and inner supports to lose their support capacity during the last weighting. Discrete element software UDEC was used to investigate the surrounding rock deformation of the pre-driven recovery room with the main roof break at different positions. The results show that when the recovery room’s length from the main roof rock layer’s fracture region is short, the immediate roof is subjected to high deviatoric stress and the occurrence of horizontal stress concentration due to the deflection of the fractured rocks, and eventually the roof supports fail owing to the development of macroscopic shear crack zones. In this research, the hydraulic fracturing technique was applied to pretreat the main roof (fine-grained sandstone) of the 31108 panel at Huoluowan Coal Mine. Field observations suggest that the strength and duration of the periodic weighting after hydraulic fracturing treatment are both significantly reduced, effectively maintaining the bearing layer performance of the roof of the recovery room and coal pillar walls. The proposed fracturing design offers an effective method of ground control to the coal mines facing roof weighting failures of recovery rooms.