Fracturing Technology Research Articles

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.

Experimental investigation on the propagation of hydraulic fractures in massive hydrate-bearing sediments

Hydraulic fracturing is regarded as one of the potential technical means to realize efficient development of natural gas hydrate. Massive-distributed hydrates are widespread around the world, although the solid fluidization method has been proposed to develop this kind of reservoir, the process of this method is complex, and there are still a lot of key problems need to be solved. Meanwhile, when the hydrate decomposed during production, how to maintain formation stability is still an unsolved key problem. Therefore, we consider using hydraulic fracturing technology to exploit this kind of reservoir. On the one hand, the fractures formed by high viscosity fracturing fluid can improve the reservoir permeability. On the other hand, the proppant added during fracturing can play a good supporting role to the formation. In this work, a series of large-size (300 × 300 × 300 mm) hydraulic fracturing physical simulation experiments were conducted under true triaxial stress states to investigate hydraulic fracture propagation law in massive-distributed hydrate-bearing reservoir. The effects of massive hydrate size, approaching angle and fracturing fluid displacement on the fracture propagation were studied. The experimental results indicated that massive hydrate exerts an important influence on hydraulic fracture propagation. Two main massive hydrate-hydraulic fracture interaction modes were observed in our experiments: (a) When the massive hydrate size is small, the hydraulic fractures mainly propagated along the interface between the sediment matrix and the massive hydrate. (b) The hydraulic fractures penetrated the massive hydrate, which usually occurs when hydraulic fracture encountered large-size massive hydrate, and the penetrated position moves from both sides to the central position of the massive hydrate. The approaching angle has a significant effect on the massive hydrate-hydraulic fracture interaction law. Under the condition of high approaching angle, hydraulic fractures easily penetrated the massive hydrate. The influence of fracturing fluid displacement on massive hydrate-hydraulic fracture interaction is closely related to massive hydrate size. When hydraulic fractures encountered the small-size massive hydrate, increasing the displacement has a limited effect on massive hydrate-hydraulic fracture interaction, and the hydraulic fractures still mainly propagated along the interface. When large-size massive hydrates are distributed in the sample, increasing the displacement has a significant effect on the massive hydrate-hydraulic fracture interaction, and hydraulic fractures tend to branch, the complex fracture geometry would be formed. In this study, a new large-size massive hydrate sample preparation method was proposed, and the effects of various factors on the hydraulic fracture propagation law were investigated experimentally, which can provide guidance for the fracturing design of massive hydrate-bearing reservoir.

Calculation of fracture number and length formed by methane deflagration fracturing technology

The innovative Methane in-situ deflagration fracturing technology offers several benefits. It can prevent formation pollution and eliminates the need for complex treatment procedures for backflow materials. Additionally, it reduces ground transportation expenses and is poised to become a highly effective and eco-friendly waterless fracturing technology. This paper suggests methods for determining the number and length of fractures in oil and gas well stimulation, considering the main influencing factors. The fracture number is calculated using mass conservation principles, while the fracture length is determined using the crack propagation model. The fracturing experiments with large-sized samples were conducted to verify the technical feasibility of the new fracturing technology and fill the gap in large-scale physical model experimental research for deflagration fracturing technology. Following the experiment, compare experimental data with calculated data, and analyze the factors that affect the fracture number and length. The results indicate that both methods are highly feasible and possess strong predictive accuracy. It is advised that to enhance the fracturing effect on formations with high crustal stress, it is beneficial to appropriately increase the peak pressure, reduce the pressure rate, and increase the fracturing time while ensuring that the wellbore remains undamaged. Moreover, these proposed methods are versatile and adaptable, making them suitable for explosive fracturing within hydraulically fractured formations and high-energy gas fracturing technology.

Concept and key technology of “multi-scale high-density” fracturing technology: A case study of tight sandstone gas reservoirs in the western Sichuan Basin

There are abundant tight sandstone gas resources in the Sichuan Basin, which are the important objects of reserve and production increase and large-scale development. Due to their discontinuous sandbody distribution, narrow channels, and strong horizontal and vertical heterogeneity, however, conventional fracturing technologies cannot achieve the ideal stimulation effect here. In order to address this difficulty, this paper dissects the geology engineering characteristics of tight sandstone gas reservoirs in the western Sichuan Basin. Starting from the seepage mechanics theory, the concept of “multi-scale high-density” tight gas fracturing technology is put forward by fully referring to the experience of previous multi-round reservoir stimulation in the western Sichuan Basin and the idea of unconventional volume fracturing technology. In addition, its conceptual connotation, key technologies and implementation effects are illustrated. The following research results are obtained. First, the seepage characteristics make it necessary for the efficient production of tight gas reserves to increase fracture density and stimulated reservoir volume (SRV). Second, the “multi-scale high-density” fracturing technology emphasizes the rationality of high-density hydraulic fracture creation and the matching of multi-scale fracture flow capacity, and aims at establishing a multi-level fracture system with effective and steady gas flow in tight reservoirs through fracturing. Third, the “wide, dense, support, stable, and precise” fracturing technology is applied to improve single well production and estimated ultimate recovery (EUR). Fourth, the engineering practice of “multi-scale high-density” fracturing technology in the tight reservoirs of Jurassic Shaximiao Formation and Triassic Xujiahe Formation in the ZJ Gas Field realizes the average single well production rate of 15.6 × 104 m3/d, which is 1.96 times higher than that before the stimulation. Obviously, it provides powerful support for the operation of the ZJ Gas Field into a giant gas field with the reserves of 100 billion cubic meters. In conclusion, the formation of the concept and key technologies of “multi-scale high-density” fracturing technology effectively supports the efficient development of tight gas in the western Sichuan Basin and points out the following research direction of tight gas reservoir stimulation. The research results provide reference and guidance for the large-scale benefit development of tight gas in China.

Technology Focus: Hydraulic Fracturing Operations (June 2023)

With the global normalization of economies over the past 2 years after the pandemic, the demand for energy has only been increasing, and all forecasts show this demand will continue to grow. In light of the current geopolitical situation globally, balancing the energy trilemma (ensuring energy security, energy equity, and environmental sustainability) is a key global challenge. With the ever-increasing energy demand, oil and gas remains a major component within the energy mix to address this challenge and to aid in satisfying the growing demand. Hydraulic fracturing continues to be the main technology differentiator that enables enhancing recovery from both green- and brownfield reservoirs globally. During the past few years, the industry has made great strides in reducing carbon emissions through the deployment of new technologies in fracturing equipment manufacturing, including electric, hybrid, and turbine-driven fracturing equipment spreads. We have also seen the application of automation and emissions monitoring being widely adopted throughout the industry in an effort to lower the operational carbon footprint. Fracture monitoring to optimize fluid volumes and designs remains a critical area of development. Research is ongoing with the focus on combining different monitoring technologies including tracers, fiber optics, downhole cameras, and microseismic monitoring. There also have been innovations in using surface data to develop cost-effective solutions to monitor fracture-geometry propagation. Nanotracers and low-cost disposable fiber-optic cables have been areas that have seen increasing deployments within the monitoring realm. Cluster efficiency and stage spacing is being optimized in basins globally by studying perforation erosion, fracture propagation, and performance between various perforation strategies using different gun configurations in both single clusters and multiple clusters including extreme-limited-entry applications. We have seen improvements in the pressure ratings of dissolvable and flow-through plugs with the aim of aiding in improving turnaround efficiency in plug-and-perf wells. Multistage hardware has seen enhancements with new completion technologies such as cemented ball-drop multistage fracturing systems and multistage openhole systems with sand-screens that require minimum intervention being developed and deployed. Globally, we have observed increasing application of lessons learned to revamp older technologies and fracturing concepts such as the use of crosslinked gels, energized fluid systems, and tip screenout designs. In addition to conventional reservoirs, we also are seeing a growing application of stimulation and fracturing technologies being considered and deployed for geothermal applications. The recent technological developments and deployments cement the fact that hydraulic fracturing will remain an important pillar to solving the world’s energy requirements in the years to come. Recommended additional reading at OnePetro: www.onepetro.org. SPE 212342 Overflush and Fracturing: Playing Poker With Your Completion by Martin Rylance, THREE60 Energy SPE 212749 Natural-Gas-Powered Direct-Drive Turbine Hydraulic Fracturing Technology Delivers High-Power Density and Energy Transfer Efficiency for Environmental, Economic, and Operational Benefits by Guillermo Rodriguez, BJ Energy Solutions, et al. SPE 212322 Combined Video and Ultrasonic Measurements for Fracture Diagnostics—Greater Than the Sum of the Parts by Tobben Tymons, EV, et al. SPE 209159 Lessons Learned From the Large-Scale CO2 Stimulation of 11 Unconventional Wells in the Williston Basin: A Practical Review of Operations, Logistics, Production Uplift, and CO2 Storage by Lionel Ribeiro, Equinor, et al.

Who’s Right? Imaging of Fractures Often Delivers Conflicting Measures

There are two ways to measure how much entry holes grow due to erosion during fracturing, and the results they offer are often different. This matters because these competing technologies, one using cameras and the other ultrasound, have become an essential tool for measuring fracturing performance. When oil companies run side-by-side tests, there are enough differences in the hole size measurements to raise the question: Which one is right? While the averages and trend lines for the data sets look close enough for engineers used to noisy downhole data, differences in the measures of specific entry holes can be disconcerting for those trying to evaluate performance at the cluster level. “There is quite a bit of disagreement in them, with gaps of up to 100%, and many gaps of 25% or more,” said Tobben Tymons, visual analytics director for EV, the company that pioneered visual imaging. He made that observation when he described the result of a two-well test where EV partnered with Archer to measure entry holes using both camera and ultrasound methods (SPE 212322). The paper presented at the 2023 SPE Hydraulic Fracturing Technology Conference and Exhibition (HFTC) included Fig. 1 comparing the measurements using photos and ultrasound as pairs of colored dots within a stage in a side-by-side well test. The red dots were based on a camera image of the entry holes in the casing; the yellow were based on ultrasound. They show that these tools can deliver significantly different measures for some of the holes. Fig. 1 shows multiple instances where only one method can provide a usable measure. The paper offered explanations for the differences with something engineers often ask for and rarely get—a study offering a detailed look at the pros and cons of competing diagnostic methods. The conflicting numbers shown in the EV-Archer paper were in line with the results of a previous side-by-side test by Chevron which showed similar measurement differences (SPE 209122). At the conference, Hess and ConocoPhillips also offered papers on measurement differences. It’s a hot topic because bad data could lead an operator to invest a lot of money and time on changes that don’t deliver the production expected based on the entry-hole measures in test wells. There is agreement that the accuracy of these data matters. But on the question of which method is delivering accurate numbers, the advice varied widely. The paper by Hess offered this advice: “The technology of perforation imaging has come a long way and drastically improved in recent years; however, there are differences in the detail of the images. The trends are very similar between the compared technologies. The learning is to use one technology and consistently benchmark against it.” When asked about picking one method and sticking with it, Tymons said he “strongly disagrees with the approach.” Using one method avoids seeing the inconsistencies between the two technologies, but no matter which method is used, “there are instances where it is simply wrong,” he said.

Study on seepage model of Multiple Horizontal wells with complex fracture networks in tight Reservoir Based on boundary element method

Horizontal well and volume fracturing technology are the key technologies to develop unconventional reservoirs. Tight reservoir is belonging to multi-scale seepage mediaafter fracturing, and theflow of fluid in it is extremely complicated. In this paper, based on the boundary element method (BEM), the seepage model of horizontal wells with complex fracture networks in irregular boundary reservoir is established for the first time. The model takes into account the influence of irregular reservoir boundary, dual media, complex fracture network and interference of multiple wells on horizontal well seepage. Using this model, the sensitivity analysis of wellbore storage coefficient, skin factor, fracture permeability and interporosity transfer coefficient is carried out. The model expands the application scope of BEM in the field of seepage simulation of unconventional oil and gas reservoirs and provides theoretical guidance for the development of tight oil reservoirs.

Practice and development suggestions of hydraulic fracturing technology in the Gulong shale oil reservoirs of Songliao Basin, NE China

This paper reviews the multiple rounds of upgrades of the hydraulic fracturing technology used in the Gulong shale oil reservoirs and gives suggestions about stimulation technology development in relation to the production performance of Gulong shale oil wells. Under the control of high-density bedding fractures, fracturing in the Gulong shale results in a complex fracture morphology, yet with highly suppressed fracture height and length. Hydraulic fracturing fails to generate artificial fractures with sufficient lengths and heights, which is a main restraint on the effective stimulation in the Gulong shale oil reservoirs. In this regard, the fracturing design shall follow the strategy of “controlling near-wellbore complex fractures and maximizing the extension of main fractures”. Increasing the proportions of guar gum fracturing fluids, reducing perforation clusters within one fracturing stage, raising pump rates and appropriately exploiting stress interference are conducive to fracture propagation and lead to a considerably expanded stimulated reservoir volume (SRV). The upgraded main hydraulic fracturing technology is much more applicable to the Gulong shale oil reservoirs. It accelerates the oil production with a low flowback rate and lifts oil cut during the initial production of well groups, which both help to improve well production. It is suggested to optimize the hydraulic fracturing technology in six aspects, namely, suppressing propagation of near-wellbore microfractures, improving the pumping scheme of CO2, managing the perforating density, enhancing multi-proppant combination, reviewing well pattern/spacing, and discreetly applying fiber-assisted injection, so as to improve the SRV, the distal fracture complexity and the long-term fracture conductivity.

Theory, technology and practice of shale gas three-dimensional development: A case study of Fuling shale gas field in Sichuan Basin, SW China

In the Jiaoshiba block of the Fuling shale gas field, the employed reserves and recovery factor by primary well pattern are low, no obvious barrier is found in the development layer series, and layered development is difficult. Based on the understanding of the main factors controlling shale gas enrichment and high production, the theory and technology of shale gas three-dimensional development, such as fine description and modeling of shale gas reservoir, optimization of three-dimensional development strategy, highly efficient drilling with dense well pattern, precision fracturing and real-time control, are discussed. Three-dimensional development refers to the application of optimal and fast drilling and volume fracturing technologies, depending upon the sedimentary characteristics, reservoir characteristics and sweet spot distribution of shale gas, to form “artificial gas reservoir” in a multidimensional space, so as to maximize the employed reserves, recovery factor and yield rate of shale gas development. In the research on shale gas three-dimensional development, the geological + engineering sweet spot description is fundamental, the collaborative optimization of natural fractures and artificial fractures is critical, and the improvement of speed and efficiency in drilling and fracturing engineering is the guarantee. Through the implementation of three-dimensional development, the overall recovery factor in the Jiaoshiba block has increased from 12.6% to 23.3%, providing an important support for the continuous and stable production of the Fuling shale gas field.

Hydraulic Fracturing Unlocks Potential of Europe’s Largest Reservoir

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205250, “Hydraulic Fracturing at Clair: Unlocking the Potential of Europe’s Largest Reservoir,” by Alistair M. Roy, SPE, Graeme H. Allan, SPE, and Corrado Giuliani, SPE, BP, et al. The paper has not been peer reviewed. _ Greater Clair, Europe’s largest oil field, has two existing platforms, Clair Phase 1 and Clair Ridge, on production with the potential for a third platform targeting the undeveloped Lower Clair Group (LCG) to the South of Phase 1. In some areas, however, low matrix quality and lack of natural fractures were the dominant characteristics, resulting in lower production rates. The authors write that fracturing technology brings opportunities to unlock poorer Phase 1 and Ridge reservoir areas. Introduction Reservoir Description. The Clair field is 75 km west of the Shetland Islands on the UK Continental Shelf within the extensional Faroe-Shetland Basin. The Old Red Sandstone reservoir is divided into two lithostratigraphic units, the Upper and LCG. The LCG contains the bulk of the oil in place and underpins the Clair development. The reservoir is characterized by large variations in facies and permeabilities. The LCG is subdivided into six units, I through VI, based on variations in sedimentary facies and heavy mineral assemblages. Development drilling preferentially targets the highest quality reservoirs in Units V and III. The LCG is defined as a dual-permeability system with a variable fracture distribution. Three main scales of fracture features are observed in the core: fault-related, fracture corridors unrelated to large offsets, and lower-density joint-type networks. Open fracture density varies considerably by stratigraphy, with the highest densities in Units V and VI. Field Development Phases. Exploration Well 206/08-1A discovered Clair in 1977. Clair underwent a protracted appraisal program before sanction of the Phase 1 development in 2001. The commercial viability of the reservoir was not confirmed until an extended well test in 1996 proved that oil rates from 15,000 to 20,000 BOPD could be sustained from long horizontal wells targeting high-productivity fracture zones. The scale and complexity of the reservoir drove a phased multiplatform development. Phase 1 began production with 20 producer and injector wells coming online between 2005 and 2011. Five additional wells drilled during 2016–2017 increased platform production by 70%. The second platform, Clair Ridge, came online in 2018, and the development wells drilled to date have encountered varying degrees of natural fractures. Design and Characteristics of Well A23 for Hydraulic Fracturing Candidate Well for Propped Fracturing. Horizontal Well A23 was completed in March 2017. The lateral penetrated the low-permeability unfractured Unit VI of the LCG in the Graben area of Phase 1. It crosses the core/graben fault, which is assumed to act as a baffle to communication between Zones 1 and 2 and Zones 3 and 4. Well A23 was put on gas lift production in 2017, producing approximately 1,300 BOPD. The well trajectory was designed to remain 40 m above the shale layer and to facilitate roughly transverse fractures within Unit VI Upper by drilling perpendicularly to the maximum horizontal stress to overcome vertical drainage issues.

Formulation optimization of materials used in temporary plugging diversion between fracture front end and cluster in shale gas: From laboratory research to field application

The staged and multi-cluster fracturing of horizontal wells is the main fracturing technology used for shale gas reservoir development. Temporary plugging diversion (TPD) is an important technical means to realize a uniform propagation of hydraulic fractures and avoid problems such as frac hits (i.e., well-to-well interference). Although this technology has been extensively used worldwide, field monitoring results have shown that temporary plugging cannot effectively improve the nonuniform propagation of multiple fractures. The fundamental reason is the lack of an organic combination of laboratory research and field application. To solve this problem, this study investigated the reservoir adaptability and plugging performance of three types of temporary plugging agent (TPAs), namely, powder, particle, and fiber, used in the fracturing of wells in the Weiyuan (WY) shale gas field, Sichuan, China, using a pressure-bearing capacity test device for three dimensional (3D)-printing-simulated TPA. A calculation method for the plugging efficiency of the TPA was established, and the ratio and concentration of the TPA were optimized under different fracture widths. The similarity criterion was used to calculate the amount of TPA required for different fracture widths. A field application chart of the TPA was formulated, and a method that connects laboratory research and field application was established. The results showed that the three TPAs have good reservoir adaptability and degradation performance. It is recommended to use 200–400 mesh powder + 6 mm fiber with different concentrations and dosages when performing temporary plugging and fracturing at the front end of 1–3 mm fractures. In the case of inter-cluster TPD for a fracture width of 4–6 mm, a combination of 20 mesh powder + 6 mm fiber + 1–3 mm particles is recommended. The field application results showed that the pressure increased significantly at the front end of the fractures and during inter-cluster temporary plugging when the plugging agent was in place, and there were no frac hits in the adjacent wells. This paper provides a practical research method for hydraulic fracturing involving temporary plugging, from laboratory research to engineering application.

Laboratory Investigation of Cryogenic Fracturing of HDR Wellbores Under Triaxial-Confining stresses

Hot dry rock (HDR) contains abundant thermal energy, which can be extracted through fracturing and used for electricity generation. Due to its deep depth, high temperature and high-pressure conditions, it is difficult to initiate fractures for conventional hydraulic fracturing technology. This paper studies the advantage of cryogenic fracturing on the HDR. We have carried out a series of laboratory experiments on granite samples with different lengths of the open hole under triaxial-confining stresses (10 MPa). The nitrogen fracturing wellbores of high temperature (100−300 °C) granites are processed by LN2 (liquid nitrogen) and NoLN2 (no liquid nitrogen) and retained with 20 mm and 30 mm open hole to form four control groups. The fracturing results showed that LN2 cryogenic stimulation is more effective in reducing the HDR initiation pressure. With a 20 mm open hole, the breakdown pressure of samples with LN2 decreases by 13.9%-18.7% compared with untreated samples. When the open hole changes from 20 mm to 30 mm, the breakdown pressure of samples with NoLN2 is reduced by 6.7%-15%. The longer the open hole of the samples is, the more complex the fracture patterns after the nitrogen fracturing are. This can be attributed to the length of the open hole. The longer it is, the more complex the micro-fractures on the surface are, and the force of the direction parallel to the cross-section is significantly increased. The results of our research afford Enhanced Geothermal Systems (EGS) basics and help the early realization of thermal power generation from HDR.

Major advancement in oil and gas exploration of Jurassic channel sandstone in Well Bazhong 1HF in northern Sichuan Basin and its significance

In January 2023, Well Bazhong 1HF in the northern Sichuan Basin obtained high-yield industrial oil flow of over 100 cubic meters from the Jurassic channel sandstone for the first time, realizing a major breakthrough. In order to provide more support for further oil and gas exploration in this area, this paper analyzes the sedimentary and reservoir characteristics of the Jurassic Lianggaoshan Formation in Bazhong region of northern Sichuan Basin and their control factors based on the exploration achievements of Well Bazhong 1HF. Then, oil and gas reservoir characteristics and oil and gas sources are comparatively analyzed. Finally, the key technologies for the exploration of channel sandstone oil and gas with multi-stage vertical superimposition, lateral migration, thin reservoir and strong heterogeneity are researched and developed, and the next oil and gas exploration direction in the Lianggaoshan Formation of northern Sichuan Basin is pointed out. And the following research results are obtained. First, in the second member of Lianggaoshan Formation (“Liang 2 Member” for short) in Bazhong region, multi-stage underwater distributary sand bodies of delta front are developed with sandstone thickness of about 25 m and average porosity of 5.6%. The pore types are mainly primary intergranular pores and feldspar/debris intragranular dissolved pores, the pore throat structure is good, and the development of good-quality reservoirs is controlled by the sedimentary microfacies of underwater distributary channel. Second, the oil and gas reservoir of Liang 2 Member is a highly oil-bearing condensate gas reservoir/volatile oil reservoir, whose oil and gas is mainly sourced from the semi-deep lacustrine shale of Liang 1 and 2 Members. Third, channel sand bodies are superimposed and developed continuously in the upper part of Liang 2 and Liang 3 Members, and the source-reservoir configuration is good, with the characteristics of near-source hydrocarbon accumulation and overpressure hydrocarbon enrichment. Fourth, for the channel sandstones with multi-stage vertical superimposition, lateral migration, thin reservoir and strong heterogeneity, the reservoir prediction technology of “high-frequency sequence stratigraphy slice, seismic frequency decomposition and facies-constrained seismic waveform indication inversion” is developed to precisely characterize the “sweet spot” target of narrow channel sandstone, and the key fracturing technology of “dense cutting + composite temporary plugging + high-intensity proppant injection + imbibition and oil-increasing” is formed to realize the large-scale reconstruction of channel sandstone reservoir. In conclusion, the breakthrough of Well Bazhong 1HF in the exploration of Lianggaoshan Formation oil and gas in Bazhong region reveals the huge potential of Jurassic oil and gas exploration in the Sichuan Basin, and plays a positive role in promoting the exploration and development of the Jurassic channel sandstone oil and gas in the Sichuan Basin.

Assessment of the Suitability of Coke Material for Proppants in the Hydraulic Fracturing of Coals.

To enhance the extraction of methane gas from coal beds, hydraulic fracturing technology is used. However, stimulation operations in soft rocks, such as coal beds, are associated with technical problems related mainly to the embedment phenomenon. Therefore, the concept of a novel coke-based proppant was introduced. The purpose of the study was to identify the source coke material for further processing to obtain a proppant. Twenty coke materials differing in type, grain size, and production method from five coking plants were tested. The values of the following parameters were determined for the initial coke: micum index 40; micum index 10; coke reactivity index; coke strength after reaction; and ash content. The coke was modified by crushing and mechanical classification, and the 3-1 mm class was obtained. This was enriched in heavy liquid with a density of 1.35 g/cm3. The crush resistance index and Roga index, which were selected as key strength parameters, and the ash content were determined for the lighter fraction. The most promising modified coke materials with the best strength properties were obtained from the coarse-grained (fraction 25-80 mm and greater) blast furnace and foundry coke. They had crush resistance index and Roga index values of at least 44% and at least 96%, respectively, and contained less than 9% ash. After assessing the suitability of coke material for proppants in the hydraulic fracturing of coal, further research will be needed to develop a technology to produce proppants with parameters compliant with the PN-EN ISO 13503-2:2010 standard.

Applications of Differential Effective Medium (DEM)-Driven Correlations to Estimate Elastic Properties of Jafurah Tuwaiq Mountain Formation (TMF)

Organic-rich mud rocks are being developed on a large scale worldwide, including in the Middle East. The Jurassic Tuwaiq Mountain Formation (TMF) in the Jafurah Basin is a potential world-class unconventional play. Based on a petrophysical evaluation of the Jafurah basin, the TMF exhibits exceptional and unconventional gas characteristics, such as a high total organic content (TOC) and low clay content. Additionally, the TMF is in the appropriate maturity window, indicating that it has reached the required level of thermal maturity to generate hydrocarbons. Plans for the development of the Jafurah unconventional field use multistage hydraulic fracturing technology. The elastic properties of the shale formation, particularly its Young’s modulus and Poisson’s ratio, dictate how the rock responds to stress and deformation. These properties strongly impact the growth of hydraulic fractures in shale formations. Without a comprehensive understanding of the elastic properties, predicting the bulk mechanical response of the target zones and surrounding layers would be challenging. Therefore, this study aims to predict the elastic characteristics of the Jafurah shale play considering the variations in carbonate facies, the kerogen volume fraction, and the pore’s geometry. Petrophysical and XRD data were used to estimate the elastic properties of various tiers (geological units) of the TMF (Tiers 1, 2, and 3). Inclusion-based, differential effective medium (DEM) rock physics models were used to estimate the formation’s elastic and velocity properties as a function of the kerogen volume fraction and the pore’s geometry. The results showed that the Young’s modulus as well as the mineral and elastic brittleness indices increase as the volume fraction of calcite increases. At the same time, they decrease due to intensified clay and kerogen volumes. The effect of the TMF’s elastic parameters on the rock brittleness behavior was also investigated by considering the formation’s mineralogy, as well as clay and kerogen contents. The results led to the development of physics-based correlations of the mineral brittleness index as function of the Young’s modulus and Poisson’s ratio for various tiers of the TMF.

The Impact of Formation Anisotropy and Stresses on Fractural Geometry—A Case Study in Jafurah’s Tuwaiq Mountain Formation (TMF), Saudi Arabia

Multi-stage hydraulic fracturing (MsHF) is the main technology to improve hydrocarbon recovery from shale plays. Associated with their rich organic contents and laminated depositional environments, shales exhibit transverse isotropic (TI) characteristics. In several cases, the lamination planes are horizontal in shale formations with a symmetric axis that are vertical to the bedding plane; hence, shale formations are known as transverse isotropic vertical (TIV) rocks. Ignoring the TIV nature of shale formations leads to erroneous estimates of in situ stresses and consequently to inefficient designs of fractural geometry, which negatively affects the ultimate recovery. The goal of this study is to investigate the effects of TIV medium characteristics on fractural geometry, spacing, and stress shadow development in the Jurassic Tuwaiq Mountain formation (TMF) in the Jafurah basin, which is a potential unconventional world-class play. This formation is the main source for prolific Jurassic oil reservoirs in Saudi Arabia. On the basis of a petrophysical evaluation in the Jafurah basin, TMF exhibited exceptional unconventional gas characteristics, such as high total organic content (TOC) and low clay content, and it was in the proper maturity window for oil and gas generation. The unconventional Jafurah field covers a large area that is comparable to the size of the Eagle Ford shale play in South Texas, and it is planned for development through multi-stage hydraulic fracturing technology. In this study, analytical modeling was performed to estimate the fractural geometry and in situ stresses in the anisotropic medium. The results show that the Young’s modulus anisotropy had a noticeable impact on fractural width, whereas the impact of Poisson’s ratio was minimal. Moreover, we investigated the impact of stress anisotropy and other rock properties on the stress shadow, and found that a large stress anisotropy could result in fractures being positioned close to one another or theoretically without minimal fractural spacing concerns. Additionally, we estimated the fractural aspect ratio in different propagation regimes and observed that the highest aspect ratio had occurred in the fractural toughness-dominated regime. This study also compares the elastic properties and confirms that TMF exhibited greater anisotropic properties than those of Eagle Ford. These findings have practical implications for field operations, particularly with regard to the fractural geometry and proppant placement.

Experimental study of fracture conductivity in dolomite reservoirs treated with different acid fracturing technologies

The acid fracturing stimulation mechanism of dolomite reservoirs is entirely different from that of limestone. Most existing research on dolomite acid fracturing still uses the research method of limestone. There is no unified understanding of dolomite reservoirs' acid rock reaction mechanism and stimulation mechanism. The rock outcrops of the Dengying Formation of the Sinian system in the Sichuan Basin, China, with the size of about 17.8 cm × 3.8 cm × 2.5 cm, were used to test the acid-etching morphology, corrosion volume, reaction kinetic parameters, and conductivity under different acid types, injection modes, displacements, and alternating stages with the acid corrosion experiment. The materials used in the experiment are gelling acid, crosslinking acid, and diverting acid, the dolomite content of the rock sample is about 93.79%. The experimental results show that the diverting acid had a lower viscosity and higher mass transfer rate than gelling acid, so it could form a more effective etching, the dissolution volumes in the two acids were 22.15 and 23.38 cm3, respectively. Compared with the injection mode of a single acid fluid, the alternative injection of two fluids with different viscosities can improve the nonuniform etching effect and conductivity, under the “fracturing fluid + acid fluid” alternate injection mode, the dissolution volume of rock was approximately 17.16 cm3, under the “crosslinking acid + diverting acid” alternate injection mode, the dissolution volume of rock was approximately 20.83 cm3. The reaction rate of dolomite is low, and it may be dissolved along the joint and natural fractures. The research results can provide a reference for optimizing the dolomite reservoir's stimulation technology and injection parameter design.

Experimental studies on the performance evaluation of water-soluble polymers used as temporary plugging agents

The performance of the temporary plug is a key factor in determining the success of loss-circulation control and temporary plug diversion fracturing. Due to the complexity of geomechanics and working conditions, current commonly used temporary plug agents face problems such as low plug strength and efficiency, large filtration losses due to failure to form filter cakes, and slow degradation affecting the recovery of fracture conductivity. A novel idea for the development of a novel water-soluble polymer plug for fracking is proposed, namely, low-to middle-molecule weight + reinforced chain rigidity + supramolecular aggregation. Using sodium bisulfite and potassium sulfate as initiators, AA, AM, and AMPS as grafting monomers, and SM as hydrophobic functional monomers, the AM-AA-AMPS-SM copolymer was prepared by polymerization. The developed new temporary plugging agent was completely degraded at 70°C for 5–8 h by carrying out experimental evaluation tests, such as water absorption expansion rate, swelling kinetics, density, post-dissolution viscosity, strength of the temporary plugging agent and post-degradation conductivity. After degradation, the viscosity of the solution is 2.5–3.6 mPa s with good fluidity and no gel remnants. The density of the temporary plug material is about 1.14 g/cm3. The absorption expansion rate was 25.8 g/g. The pressure is 60.1 MPa when the thickness of the granular temporary plug is 0.4 cm. Under experimental conditions, the fracture conductivity was found to be 69–123 D*cm at a closing pressure of 30 MPa after degradation of the temporary plug. The test results demonstrate that the new temporary plug agent, with its high plug strength, temperature-controlled degradation, reflux stability and effective self-support after degradation, can meet the requirements of drilling plug and temporary plug fracturing technologies.

Analytical Investigation on the Shear Propagation Mechanism of Multi-Cracks in Brittle Tight Rocks under Compressive and Shear Loading Conditions

There is abundant shale oil in the ocean and on land. Due to the tight lithology of the reservoir, volume fracturing technology is needed to improve the oil and gas productivity. It is very important to study the expansion law of multiple natural fractures in rock masses and its influencing factors in the process of volume fracturing for the formation of fracture networks. Based on the theory of online elastic fracture mechanics, the calculation method of the stress intensity factor at the end of any I–II composite fracture is established by using effective shear stress and considering the influence of T-stress. The calculation model of the stress intensity factor of any fracture on the main fracture wall or the horizontal section of the main fracture wall is established according to the concrete stress conditions in the process of hydraulic fracturing. Based on the principle of stress superposition, the combined interference stress calculation model of fracture ends is established for the case of multiple penetrating cracks in infinite-plane rock masses. Based on the theory of shear failure and plane strain, a model of the initiation direction and condition of natural cracks on the horizontal section of the main fracture wall and both sides of the main fracture in brittle rock is established when there are many coaxial natural cracks under the action of remote site stress and water pressure on the fracture surface. According to the simulation results, on the main fracture wall, when σH > σv > σh or σH > σh > σv, when the crack angle (CA) is within a certain range and multiple natural cracks (MNC) exist, the required pressure for shear failure decreases. When the fracture angle exceeds a certain size, the required pressure increases. When there are MNC in the horizontal or perpendicular sections of the rock mass on both sides of the main fracture, the required net pressure for shear failure decreases within a certain CA range. When the CA exceeds a certain range, it increases or remains basically unchanged. On the whole, the presence of MNC reduces the net pressure for shear failure, which is conducive to the formation of fracture networks.

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.