Multistage Fracturing Research Articles

Failure Analysis of Casing in Shale Oil Wells under Multistage Fracturing Conditions

During the multistage fracturing in shale oil and gas wells with tieback and liner, one of the major challenges is the wellbore temperature variation due to the high-rate fracturing. In such a case, the axial shrinkage trend of the casing string could be caused due to the sudden drop in temperature, but the actual axial length of the casing string would not change due to the cement constraints. Therefore, this could lead to cementation damage between the casing and cement due to excessive load from the casing string. A wellbore seal that is out of control often leads to irreversible consequences, even well abandonment. In order to study the mechanism of casing deformation in shale oil and gas wells with tieback and liner quantitatively, in this paper, take LS1 well (a typical shale oil and gas well with tieback and liner, and casing deformation is caused) for example, the transient changes of temperature and pressure in the whole wellbore during multistage fracturing are studied. Moreover, the cementing strength test of the interface between casing and cement is also tested. Then, the testing results are carried out and extended to model the finite element (FE) model with the whole vertical section casing string with tieback and liner. The model is used to simulate the internal force changes under fracturing conditions with different stages of fracturing. Meanwhile, the casing deformation mechanism in LS1 well is analyzed and studied in detail. Our simulation results indicated the failure process and mechanism of cementation between casing and cement in shale oil and gas wells with tieback and liner. Our work can provide a detailed theoretical reference and a basis for field application.

FLOW DIVERTING AGENTS FOR WELL TREATMENT IN THE OIL AND GAS INDUSTRY

Within well life, well treatments are carried out to increase productivity by stimulating initially unproductive zones. These measures include hydraulic fracturing, multi-stage hydraulic fracturing, matrix acid treatment, acid fracturing, etc. These processing methods allow existing wells to support hydrocarbon production without drilling new wells. During these treatments, certain specialized particles or technical devices are used for isolating an already existing perforation or for liquid flow diverting. These particles or devices are usually called flow diverters, which can prevent the use of a drilling rig to create temporary physical barriers, reducing the overhaul cost. Recent improvements in flow deflection technology allow the use of various decomposable particles that act as a temporary bridge either at the perforation entrance or inside an existing crack. The basic principles of the injected compounds flow deflection are to create filtration resistance to the advance of the acid composition in the highly permeable part of the collector and the coating of untreated cracks. This article discusses rejecting agents, their origin, types, applications, and some case studies in which the use of rejecting agents has proven to be the most effective.

DEVELOPMENT OF LOW PERMEABLE RESERVOIRS AT THE PRIOBSKOYE FIELD (WESTERN SIBERIA)

The main problem in the development of the Priobskoye field is the search and implementation of technological solutions for the most efficient development of layers of ultra-low permeable reservoirs. A factor complicating the hydrocarbon production for such facilities is the low impact of flooding. These restrictions lead to high rates of decline in oil production, therefore, the most urgent issue is the search for an up-to-date technological solution aimed at improving the efficiency of field development.
 This article is devoted to improving the efficiency of the development system in areas with low filtration and capacitance properties. It presents the results of research on the study of the construction of horizontal wells longitudinally and transversely to regional stress, followed by multi-stage hydraulic fracturing in the conditions of one of the largest fields in Western Siberia. The results of the research made it possible to determine an effective strategy for designing development systems in future areas.
 The relevance of this work: the demand for the extraction of hard-to-recover reserves from reservoirs characterized by low permeability.

Numerical analysis of unstable propagation of three-dimensional parallel hydraulic fractures induced by interferences of adjacent perforation clusters and thermal diffusion

PurposeThe purpose of this study is to investigate the unstable propagation of parallel hydraulic fractures induced by interferences of adjacent perforation clusters and thermal diffusion. Fracture propagation in the process of multistage fracturing of a rock mass is deflected owing to various factors. Hydrofracturing of rock masses in deep tight reservoirs involves thermal diffusion, fluid flow and deformation of rock between the rock matrix and fluid in pores and fractures.Design/methodology/approachTo study the unstable propagation behaviours of three-dimensional (3D) parallel hydraulic fractures induced by the interferences of adjacent perforation clusters and thermal diffusion, a 3D engineering-scale numerical model is established under different fracturing scenarios (sequential, simultaneous and alternate fracturing) and different perforation cluster spacings while considering the thermal-hydro-mechanical coupling effect. Stress disturbance region caused by fracture propagation in a deep tight rock mass is superimposed and overlaid with multiple fractures, resulting in a stress shadow effect and fracture deflection.FindingsThe results show that the size of the stress shadow areas and the interaction between fractures increase with decreasing multiple perforation cluster spacing in horizontal wells. Alternate fracturing can produce more fracture areas and improve the fracturing effect compared with those of sequential and simultaneous fracturing. The larger the temperature gradient between the fracturing fluid and rock matrix, the stronger the thermal diffusion effect, and the effect of thermal diffusion on the fracture propagation is significant.Originality/valueThis study focuses on the behaviours of the unstable dynamic propagation of 3D parallel hydraulic fractures induced by the interferences of adjacent perforation clusters and thermal diffusion. Further, the temperature field affects the fracture deflection requires could be investigated from the mechanisms; this paper is to study the unstable propagation of fractures in single horizontal well, which can provide a basis for fracture propagation and stress field disturbance in multiple horizontal wells.

Estimation of multistage hydraulic fracturing parameters using 4D simulation

At the present stage, most oil and gas condensate fields in the southern part of the East Siberian oil and gas province are characterized by an increasing proportion of difficult oil reserves in tight reservoirs. Multistage hydraulic fracturing (MHF) is proposed for the offshore Challenger Sea field (Southeast Dome). The implementation of this technique at a shelf will be a source of additional risks. For example, the properties of the RR-2 overlying seal have not been unambiguously assessed, and there are a number of geological uncertainties, such as the tectonic regime. However, there are a number of arguments in favor of MHF: heterogeneity of the reservoir; low permeability; low water cut of the field; sufficient thickness of the pay zone; and the overlying seal. One more positive factor is that sand ingress is not observed in the process of oil production. The selection of a principal well completion scheme on the eastern side of the RR-7 formation is aimed at effectively recovering the remaining reserves. The objectives of the study performed are: to create a geological and hydrodynamic model of the Challenger Sea (Southeast Dome); develop 1D and 3D geomechanical models; evaluate oil production forecasts based on fundamentally different well completion schemes; and determine the optimum parameters for multistage hydraulic fracturing. The research methods included: petrophysical methods; logging methods; core studies; drilling reports and formation testing data; and 3D, 4D geomechanical simulation. Other geophysical methods included acoustic logging, density logging, and gamma-ray logging. After building a geomechanical model of the reservoir at the beginning of drilling, a hydrodynamic calculation was performed. This established the reservoir pressures and saturations at certain points in time. The results made it possible for the principal stress directions, the values of effective and principal stresses, and the values of elastic strains to be determined. In order to assess MGF process efficiency, production forecasts were made using a hydrodynamic model for an exploration well with conventional completion (perforated liner) and with five-stage MGF. In the first case, the accumulated production was 144 kt over 15 years, and in the second case, 125 kt over 17 years. The difference in cumulative production is due to different initial well flow rates, as well as the rate of oil withdrawal during the first few years of development. Thereafter, the production and daily flow rate curves showed similar behavior. In order to select the most effective option, an economic analysis of the efficiency was performed.

Propagation of multiple hydraulic fractures in a transversely isotropic shale formation

Shale anisotropy can lead to deviated patterns of hydraulic fractures in multi-stage hydraulic fracturing (MSHF) operations, significantly hindering hydrocarbon production. Such deviation usually occurs in formations where the induced fractures interfere with natural bedding planes or where the stress shadow is created. In this work, the elastic behavior of a transversely isotropic shale rock during MSHF is investigated using the extended finite element method (XFEM) in conjunction with the cohesive zone model (CZM) in ABAQUS. In comparison to the linear elastic fracture mechanics approach, the CZM considers the plasticity and softening effects at the fracture tip, and therefore, leads to a more accurate prediction of fracture geometry. The XFEM model is capable of simulating fractures with an arbitrary path without requiring re-meshing. The 2D numerical model is first verified against the Kristianovich-Geertsma-de Klerk (KGD) analytical solutions. Five injection clusters in a single fracturing stage are simulated to analyze the effects of the material isotropy, the dip angle of shale bedding, and the fracture spacing on the geometry of multiple hydraulic fractures. The transversely isotropic poroelasticity model predicts narrower and longer hydraulic fractures than the isotropic poroelasticity model. The bedding dip angle plays a crucial role in the deviation and the shape of multiple hydraulic fractures. Increasing the dip angle from zero to 90° results in an increase in the average fracture width and an increase-peak-decrease trend in the fracture length. A strong correlation is observed between the fracture spacing and the fracture geometry, and a spacing of 75 m is considered optimal because it results in no discernible stress shadow at all dip angle cases.

A novel high-dimension shale gas reservoir hydraulic fracture network parameters optimization framework

Optimization design of hydraulic fracture network parameters significantly reduces the high investment risk in the production of shale gas. This is also a numerical simulation-based optimization problem. Surrogate-assisted optimization method which adopts a simple-yet-accurate approximate model to facilitate the optimization workflow is one of the most promising methods to lessen the computational burden. However, due to multi-stage fracturing and “well factory” production model, the dimension of variables in hydraulic fracture network parameters optimization increases sharply, and a significant number of data are required to ensure the performance of the surrogate model. To address this problem, a novel surrogate-assisted multi-objective optimization method using the tri-training strategy and variable-length non-dominated sorting genetic algorithm-II (VL-NSGA-II) is proposed for high-dimension hydraulic fracture network parameters optimization in shale gas reservoir. The proposed method is called HDWHF. In this HDWHF method, the tri-training strategy is adopted to infill solutions with the highest-confidence fitness as new samples to retrain the surrogate model during each iteration while VL-NSGA-II is adopted as the optimizer. This strategy enables the increase of samples without numerical simulation runs, which realizes a decrease of the numerical simulation runs and enhance the performance of the surrogate model. The superior performance of the HDWHF against conventional surrogate-assisted methods is verified using three high-dimension examples with various numbers of wells and fracture types. This proposed HDWHF workflow provides an intelligent means for efficient optimization and decision-making of high-dimension hydraulic fracture network parameters in shale gas reservoirs.

Investigation on Invasion Depth of Fracturing Fluid during Horizontal Fracturing in Low-Permeability Oil Reservoirs with Experiments and Mathematical Models

Multistage fracturing in horizontal well has become one of the important techniques for the efficient development of low-permeability sandstone reservoirs. In multistage hydraulic fractured horizontal wells (MHFHWs), the depth of fracturing fluid invasion into the formation is a key parameter evaluating the imbibition enhancement after fracturing. However, few studies have been conducted on the invasion depth of fracturing fluids combining experiments and mathematical models under high-pressure differences in MHFHWs. Therefore, in this work, a mathematical model with experimental validation is proposed for evaluating the fracturing fluids invasion under high pressure. We first conducted a series of displacement experiments under different pressure differences to obtain the breakthrough time and invasion velocity. All core samples are taken from the block X of Xinjiang oilfield. A mathematical model of fracturing fluid injection was then established, considering the two-dimensional filtration of fracturing fluid. Then, the calculated invasion velocity was validated against the experimental data. Afterward, the invasion depth and invasion volume were determined for this typical horizontal well. Results show that at the end of 72 min, the invasion depth reaches 1.516 m when measured by core experiments and 1.434 m when calculated by the proposed model. The total invasion volume of all fracturing stages is estimated as 21,560.05 m3 and the actual total fluid volume injected is 24,019.6 m3. The paper formed a scientific and reasonable evaluation method of fracturing fluid invasion depth during the fracturing of horizontal wells, which provides solid theoretical support for the effective evaluation of fracturing to improve oil recovery.

Designing horizontal wells in carbonate reservoirs using geological and hydrodynamic modeling tools

The paper considers one of the ways to determine the optimal arrangement of production and injection horizontal wells in the Vereisky horizon, which formations are composed of interbedded carbonate and terrigenous rocks. The geological and production analysis of the drilled wells was carried out. Multistage hydraulic fracturing was used to increase the proportion of reserves involved in development. When drilling horizontal wells, using hydraulic fracturing, it is possible not only to increase the drainage zone of the target reservoir, but also to involve the above- and below-lying layers in the development. The performed analysis confirmed the high efficiency of horizontal wells with multistage fracturing. Various variants of arrangement of production and injection horizontal wells were designed and modeled using the geological and hydrodynamic model of one of the object’s sections. Based on the performed analysis and calculations, the most effective schemes of well arrangements were selected. Keywords: carbonate rocks; horizontal well; forecast; modeling; multistage fracturing; injection; pressure maintenance system.

Multi-stage hydraulic fracture monitoring at the lab scale

We introduce a novel experimental and modeling approach to perform lab-scale multistage hydraulic fracturing in Poly-Methyl-Meth-Acrylate (PMMA) and study pressure-based methods to monitor hydraulic fracturing. The approach combines an internal circular V-notch method for fracture initiation with a method for creating hydraulic isolation between subsequent stages. Using high-resolution models of fracturing experiments with injection and monitoring wells, we present novel results of displacement, pressure, and stress evolution around the wells. We identify injection-induced rotational deformation in the domain and asymmetric growth of the hydraulic fracture. We quantify the role of the monitoring well on the rotational deformation and the fracture asymmetry. We analyze the role of undrained deformation in generating the monitor well’s pressure response to individual fracture stages at the injection well. Our results show that lab-scale multistage hydraulic fracturing can be a useful tool to estimate the geometry and property of a hydraulic fracture using pressure data from offset wells in the field.

Application of Micro-Seismic Monitoring in Post-Fracturing Evaluation of Shale Gas: A Case Study of Well X from Puguang Area, China

Multi-stage fracturing of horizontal wells is an indispensable technology to create complex fracture networks, which can unlock production potential and enable commercial productivity for shale gas with low porosity and permeability. Real-time monitoring of fracture networks is essential for adjusting key parameters, mitigating fracturing risks, and achieving optimal fracturing effects. Micro-seismic monitoring technology accurately captures and describes the development of fracture networks by detecting micro-seismic waves generated through rock ruptures, providing valuable insights into the evaluation of post-fracturing. In this study, we first introduced the basic parameters of well X that were obtained by laboratory experiments and logging interpretation, including porosity, gas-bearing properties, mineral composition, rock mechanics, and crustal stress. Then, the hydraulic fracturing scheme was designed on the basis of the geological engineering characteristics of well X. Finally, we conducted a comprehensive analysis of various factors that can affect hydraulic fracturing. This included an examination of the impact of pre-fluid temporary plugging and fracture complexity on the overall effectiveness of the operation. Based on the laboratory experiments and theoretical analysis, the following conclusions can be drawn: (1) fracture size is essentially formed when the fluid strength exceeds 35 m3/m; (2) both preflush with high viscosity and the amount of power sand exceeding 20 cubic meters are conducive to the propagation of fracture height; (3) temporary plugging balls facilitate the balanced propagation of multiple fracture clusters within a stage, whereas temporary plugging particles promote the formation of complex fractures; and (4) geological conditions are a prerequisite for creating a complex network of fractures, and only engineering techniques can facilitate the appropriate enhancement of fracture complexity. This study provides an essential method for the fracturing design of shale gas.

Productivity Analysis and Evaluation of Fault-Fracture Zones Controlled by Complex Fracture Networks in Tight Reservoirs: A Case Study of Xujiahe Formation

The development of tight gas reservoirs presents a significant challenge for sustainable development, as it requires specialized techniques that can have adverse environmental and social impacts. To address these challenges, efficient development technologies, such as multistage hydraulic fracturing, have been adopted to enable access to previously inaccessible natural gas resources, increase energy efficiency and security, and minimizing environmental impacts. This paper proposes a novel evaluation method to analyze the post fracturing productivity controlled by complex fault fracture zones in tight reservoirs. In this article, a systematic method to evaluate stimulated reservoir volume (SRV) and fault-fracture zone complexity after stimulation was established, along with the analysis and prediction of productivity through coupled fall-off and well-test analyses. Focusing on the Xujiahe formation in the Tongnanba anticline of northeastern Sichuan Basin, a 3D geological model was developed to analyze planar heterogeneity. The fall-off analytical model, coupled with rock mechanical parameters and fracturing parameters such as injection rates, fracturing fluid viscosity, and the number of clusters within a single stage, was established to investigate the fracture geometric parameters and complexities of each stage. The trilinear flow model was used to solve the well-test analysis model of multi-stage fractured horizontal wells in tight sandstone gas reservoirs, and well-test curves of the heterogeneous tight sandstone gas fracture network model were obtained. The results show that hydraulic fractures connect the natural fractures in fault-fracture zones. An analysis of the relationship between the fracture geometric outcomes of each segment and the net pressure reveals that as the net pressure in the fracture increases, the area ratio of natural fractures to main fractures increases notably, whereas the half length of the main fracture exhibits a decreasing trend. The overall area of natural fractures following stimulation is 7.64 times greater than that of the main fractures and is mainly a result of the extensive development of natural fractures in the target interval. As the opening ratio of natural fractures increases, the length of the main fractures decreases accordingly. Therefore, increasing net pressure within fractures will significantly enhance the complexity of fracturing fractures in shale gas reservoirs. Furthermore, the initial production of Well X1–10, which is largely controlled by fault-fracture zones, and the cumulative gas production after one year, are estimated. The systematic evaluation method in this study proposed a new way to accurately measure fracturing in tight reservoirs, which is a critical and helpful component of sustainable development in the natural gas industry.

Automatic Optimization of Multi-Well Multi-Stage Fracturing Treatments Combining Geomechanical Simulation, Reservoir Simulation and Intelligent Algorithm

Shale reserves have become an ever-increasing component of the world’s energy map. The optimal design of multi-well multi-stage fracturing (MMF) treatments is essential to the economic development of such resources. However, optimizing MMF treatments is a complex process. It requires geomechanical simulation, reservoir simulation, and automatic optimization. In this work, an integrated workflow is proposed to optimize MMF treatments in an unconventional reservoir, and the net present value (NPV) of reserves was treated as the objective function. The forward model consists of two submodels: a hydraulic fracturing model and a reservoir simulation model. The stochastic simplex approximation gradient (StoSAG) is used with the steepest ascent algorithm to maximize the NPV function. The computational results show that optimizing the fracture design can achieve a 20% higher NPV than that obtained with the field reference case. The drainage area of the optimal design is larger than that of the initial design. The maximum gas production rate increases from 23.75 MMSCF/day to 34.43 MMSCF/day and the maximum oil production rate increases from 497 STB/day to 692 STB/day. Therefore, new optimization paths can accelerate fracture design and help increase well production. This paper innovatively proposes a coupled workflow that can reduce the waste of manpower and improve the optimization results.

Pressure transient analysis for multi-stage fractured horizontal wells considering threshold pressure gradient and stress sensitivity in tight sandstone gas reservoirs

Tight sand gas reservoirs are characterized with low porosity and low permeability. The threshold pressure gradient (TPG) and stress sensitivity effect are particularly apparent during gas production in tight sand gas reservoirs, causing the pressure transient analysis (PTA) curves of multi-stage fracturing horizontal wells (MFHWs) in tight sand gas reservoirs to be abnormally upward and making it challenging to match current PTA models. Therefore, in this work, a new PTA model for MFHW considering TPG and stress sensitivity was established. Based on the point source function, a semi-analytical solution of the model could be obtained using the properties of series function, variable substitution, perturbation technique, Poisson superposition formula, Laplace transform, and numerical inversion. Moreover, the effects of TPG, stress sensitivity, well parameters, and fracture parameters on the PTA curves were analyzed. Overall, we believe that the results of this study can guide the pressure transient analysis of MFHWs in tight sand gas reservoirs and provide help for engineers with regard to evaluating the parameters of reservoirs and fractures more accurately.

Analysis of casing stress during multistage fracturing of shale gas horizontal wells considering thermo‐hydro‐mechanical coupling

AbstractDuring the multistage fracturing of shale gas horizontal wells, casing damage frequently occurs, making it essential to evaluate casing stress and deformation. This paper establishes a mathematical model of thermo‐hydro‐mechanical coupling and a finite element model of casing‐cement sheath‐formation (CCF). This paper examines the effects of temperature, casing thickness, nonuniform in situ stress, mechanical properties of cement sheath, and treating pressure on the stress and deformation of CCF. Finally, the study investigates the variation of local in situ stress at the heel and casing stress from toe to heel. The results show that the low temperature of CCF, high elastic modulus of cement sheath, small casing thickness, high treating pressure, and large nonuniform in situ stress can exacerbate casing stress. After pumping off, the local in situ stress and its nonuniformity near heel gradually increased, and the effective stress of casing increases compared with the pumping on the process. As the fracturing stages increase, the effective stress of casing at heel increases, and the casing at heel preferentially damages. The results provide a theoretical basis and guidance for maintaining wellbore integrity and preventing casing damage in the multistage fracturing of shale gas horizontal wells.

Study Investigates Ineffectiveness of Acid Fracturing for Tight Reservoir Rock

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209264, “Ineffectiveness of Acid Fracturing for Stimulating a Tight Fractured Reservoir Rock: A Case Study,” by Huda R. Al-Enezi, Kuwait Oil Company, and Iraj Ershaghi, SPE, University of Southern California. The paper has not been peer reviewed. _ The complete paper describes the analysis of actual performance data for acid fracturing in a tight carbonate formation and the ineffectiveness of the process as measured by the performance responses of the producing wells. An included case study relates to a tight formation that is considered a reservoir rather than a source rock. The formation permeability is in the range of 0.1–5 md. Development has been through numerous horizontal wells with limited multistage acid stimulation. Analysis of performance data for more than 30 wells indicates no fracture flow and very limited stimulated production. Background A category of tight conventional reservoir rocks exists that has not been subjected to horizontal drilling and multistage fracturing. The objective of the authors’ study is to analyze the ineffectiveness of treatment response under acid fracturing and explore the potential of implementing multistage fracturing for a tight reservoir rock using experience gained from unconventional resources. The subject reservoir is a tight carbonate of the Middle Cretaceous age with porosity ranges between 15 and 19% and an average thickness of approximately 90 ft. Oil viscosity ranges between 2.06 and 2.54 cp and average oil gravity is 25° API. The reservoir is a depletion-drive type where the main natural energy is provided by gas in solution. Among the initial wells, only six were successful. The field is very complex, based on stratigraphic and structural characteristics. The first horizontal well was drilled during 2015–16 and was subjected to seven-stage acid fracturing. This resulted in a substantial increase of well cumulative production compared with that of vertical wells. The development plan of this field was implemented with horizontal wells with laterals extending approximately 3,000 ft. Each well was subjected to multistage acid fracturing. Examination of performance data indicated that producing wells suffered from rapid pressure depletion after a production period of 3–6 months. Wells cease natural flow and cannot sustain production even after what is considered acid fracturing without the help of artificial lift. Conventional production plots show that typical performance begins with a high initial rate for a short duration followed by a sharp decline before a stabilization period. To improve and recommend a proper hydraulic fracture design, the authors studied the effectiveness of current stimulation to develop alternative improvement procedures. Methodology The effectiveness of acid stimulation was analyzed and evaluated by using historical production for 4 years. To study the initial rates seen on these horizontal wells, a productivity-prediction tool was used to inversely compute the effective formation-permeability responsible or the observed initial production on these wells. Production data were used to inversely calculate the geometrical averaged permeability from initial field-production data assuming that the initial conditions followed a steady-state regime.

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.

Simulation and Analysis of Proppant Transport Patterns in Wellbore-Fracture Systems

Staged multi-cluster fracturing of horizontal wells is one of the most important tools to achieve efficient development of unconventional oil and gas reservoirs. The multi-stage fracturing technique forms complex fractures with multiple clusters and branches in the formation, causing competing diversions leading to more complex proppant transport patterns, and the proppant placement method determines the flow conductivity of complex fractures, so it is necessary to investigate the proppant transport patterns in complex fractures. To address this issue, a field-scale geometric model is established for numerical simulation, and the multiphase flow diversion pattern in the wellbore, the proppant distribution pattern under different network conditions, and the optimization of different construction parameters are investigated. The results are obtained as follows: the distribution of solid and liquid phases in each cluster of the well conforms to the trend of variable mass flow; the proppant is distributed at the heel end in multiple clusters of fractures, and the sand and liquid are unevenly distributed among clusters of fractures, and the number of branching affects the proppant transport; through sensitivity analysis of the influencing factors, the pumping displacement, fracturing fluid viscosity and proppant particle size are optimized, and the construction parameters of 14 m3/min, 5 mPa·s, 70/140 mesh, 12% sand ratio are determined. This study has a certain guiding significance for the optimization of fracturing parameters in this block.

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.

Experimental Study on the Distribution and Height of Spontaneous Imbibition Water of Chang 7 Continental Shale Oil

After multi-stage volume hydraulic fracturing in a shale oil reservoir, massive amounts of water can be imbibed into the matrix pores. One of the key imbibition characteristics of a shale reservoir is the imbibition water and its height distribution. Based on high pressure mercury injection (HPMI) experiments and nuclear magnetic resonance (NMR) analyses, this study quantitatively evaluated the pore-size distribution of Chang 7 continental shale oil reservoirs in Yanchang Formation, Ordos Basin. The pores could be divided into three types as micropores (≤0.1 μm), mesopores (0.1–1.0 μm), and macropores (>1.0 μm), while the volume of micropores and mesopores accounted for more than 90%. This demonstrated that there were strong heterogeneity and micro–nano characteristics. According to the spontaneous imbibition (SI) experiments, the cumulative proportion of imbibition water content was the largest in micropores, exceeding 43%, followed by mesopores around 30%, and that of macropores was the lowest, and basically less than 20%. The negative values of stage water content in the macropore or mesopore indicated that these pores became a water supply channel for other dominant imbibition pores. Additionally, combining the fractal theory with the NMR T2 spectrum, the relative imbibition water and actual height were calculated in different pores, while the height distribution varied with cores and shale oil. The shorter the core, the higher was the relative height, while the radius of macropores filled with imbibition water was reduced. This indicates that the height distribution was affected by the pore structure, oil viscosity, and core length.