Multistage Fracturing Research Articles

Experience in developing carbonate formations with hydraulic fracturing at fields of Gazprom Neft Group

The development of carbonate formations with hydraulic fracturing is a very interesting and controversial process. In contrast to terrigenous formations, zonal stimulation can be performed by both acid and proppant fracturing methods, and the abundance of process variations expands the options even further. Although there is a general concept of choosing hydraulic fracturing technology depending on the geological and physical characteristics of the formation, the qualitative choice is complicated by the fact that effective solutions for one reservoir could not show the same efficiency in similar conditions at another one. For this reason, from the point of view of working with carbonates, to have as extensive experience as possible in various well conditions in order to minimize production risks and costs associated with the choice of approach and zonal stimulation technology. The study aims to provide a technological overview of effective fracturing solutions for carbonate formations, seeking to understand their features and applicability depending on well and geological conditions. An important place is given to the communication of experience in the application of stimulation technologies that have proven themselves at carbonate formations of Gazprom Neft and show the risks and limitations that can be encountered when choosing a particular solution. It describes experience in hydraulic and multistage fracturing, technologies, approaches and their features depending on geological conditions of carbonate formations. The study also outlines the actual experience of using hydraulic fracturing technologies at carbonate formations, their comparative effectiveness, and the most successful practices based on the actual experience of the work performed. Much attention is paid to comparing the effectiveness of acid fracturing, acid-proppant fracturing, and variations of fracturing on viscous acid compositions. The findings not only give an idea of the technological diversity of the types of zonal stimulation, but also highlights their comparative effectiveness in geological and physical conditions of the reservoir. The reflected experience can help to choose more effective solutions in the development of similar formations, reduce risks at early stages of preparation for fracturing and helps in deciding on the choice of stimulation technology, thereby improving the quality and efficiency of fields development.

Analysis of the Impact of Clusters on Productivity of Multi-Fracturing Horizontal Well in Shale Gas

Shale gas reservoirs with nanoporous media have become one of the primary resources for natural gas development. The nanopore diameters of shale reservoirs range from 5 to 200 nm, with permeability ranging from 1 × 10−9 to 1 × 10−6 μm2. The natural gas production from shale gas reservoirs is low, necessitating the use of multi-stage hydraulic fracturing in horizontal wells. Segmented multi-cluster perforation fracturing is an effective method for shale gas extraction in these wells. The number of clusters significantly impacts the productivity of horizontal wells. Therefore, it is essential to analyze the impact of cluster numbers on fracture productivity in shale gas reservoir development. In this study, the equivalent flow resistance method was applied to establish a productivity model for multi-stage hydraulic fracturing horizontal wells in shale gas reservoirs considering diffusion and slip. An approximate analytical solution was obtained, and the effects of cluster length, diffusion coefficient, and fracture network permeability on productivity were analyzed. The results show that gas production gradually increases with the increase in the number of clusters and cluster length. However, as the number of clusters increases, the interference between clusters leads to a decrease in the productivity of individual clusters. As the fracture permeability, fracture network permeability, and diffusion coefficient increase, shale gas production also gradually increases. The permeability of the fracture network has the greatest impact on productivity. These research results are beneficial for the design of clusters in horizontal well fracturing and are of great importance for the development and production of shale gas reservoirs.

Применение новых технологий кислотной обработки пластов для восстановления продуктивности пласта

Oil recovery, measured by the oil recovery factor (ORF), is a key indicator of the efficiency of oil production. In Russia, the ORF decreased to 0.3 while in the United States this indicator increased to 0.4. About 90% of Russian oil is produced by large holdings, the structure of reserves is shifting towards hard-to-recover, which requires the use of new methods to increase oil recovery. Primary and secondary production allows only 20-50% of oil to be extracted, what makes the use of tertiary methods necessary. The development of horizontal wells with multistage hydraulic fracturing contributes to the development of new field sites, but requires careful preparation of wells to minimize risks and cost increases. Cleaning the bottomhole area using acidic formulations is often the only cost-effective way to restore the productivity of a horizontal well. The improved method of acid composition reduction using a guar gel with delayed “crosslinking”, which ensures uniform treatment of all productive zones of the formation is considered in article. The technology allows for continuous multi-stage acid treatment, temporarily blocking highly permeable areas and increasing the coverage of acidic effects on poorly drained areas. The calculation of the diverter volume considers the average efficiency of the liquid after mini-fracturing, adjusting the volume depending on the efficiency of the liquid at each port.

Unconventional Fracture Networks Simulation and Shale Gas Production Prediction by Integration of Petrophysics, Geomechanics and Fracture Characterization

The proficient application of multistage fracturing methods enhances the status of the Duvernay shale formation as a highly esteemed shale reservoir on a global scale. Nevertheless, the challenge is in accurately characterizing unconventional fracture behavior and predicting shale productivity due to the complex distributions of natural fractures, pre-existing faults, and reservoir heterogeneity. The present study puts forth a Geo-Engineering approach to comprehensively investigate the Duvernay shale reservoir in the vicinity of Crooked Lake. To begin with, on the basis of the experimental results and well-logging interpretations, a high-quality petrophysical and geomechanical model is constructed. Subsequently, the establishment of an unconventional fracture model (UFM) takes into account the heterogeneity of the reservoir and the interactions between hydraulic fractures and pre-existing natural fractures/faults and is further validated by 18,040 microseismic events. Finally, the analysis of well productivity is conducted by numerical simulations, revealing that the agreement between the simulated and observed production magnitudes exceeds 89%. This paper will guide the efficient development of increasingly important unconventional shale resources.

Integrated Modeling of Multi-Stage Hydraulic Fracturing of Low-Permeable Reservoirs

Integrated Modeling of Multi-Stage Hydraulic Fracturing of Low-Permeable Reservoirs

Contrasting fracturing and cementation timings during shale gas accumulation and preservation: An example from the Wufeng-Longmaxi shales in the Fuling shale gas field, Sichuan Basin, China

The marine shales in southern China are characterized by high thermal evolution and intensive deformation during multistage burial and uplift. Fracturing and cementation, associated with tectonic activity, diagenesis, hydrocarbon generation and migration processes, are widely and variably distributed in shale reservoirs experiencing different tectonic evolution. In this study, we utilized cross-cutting relationships, fluid inclusion microthermometry, and laser Raman spectroscopy of fluid inclusions, along with U-Pb dating of fracture-filling calcite veins, integrated with burial history modeling, to elucidate the timing and mechanism of fracturing in the Paleozoic Wufeng-Longmaxi shale reservoir, as well as regional variations in the Fuling shale gas field. Bedding-parallel fractures (BFs) in shale reservoirs are filled with calcite and quartz veins. The timing of fracturing, as determined by minimum homogenization temperatures and U-Pb dating, is estimated to have occurred during ca. 191 -122 Ma, during which some short vertical (or high-angle) fractures (VFs) opened around 163.4 Ma and 137 Ma, subsequently sealed by calcite veins, respectively. All calcite and quartz veins within these fractures contain high-density methane inclusions, while shale reservoirs were in a high-over-mature evolutionary stage. This suggests that fracturing was primarily driven by gas generation overpressure during deep burial. In shale reservoirs near fault belt folds, multistage fractures developed, including three stages of intersecting fractures (IFs) and one-stage of long VFs. The timing of fracturing and cementation corresponds to the Yanshanian tectonic uplift (ca. 83 - 69 Ma) with intense tectonic movement likely being the direct cause of fracture opening. The presence of abundant gas inclusions in veins recorded shale gas expulsion during rapid tectonic uplift, reflecting the destruction of shale gas preservation conditions. In contrast, no significant fracturing or cementation processes have been observed in the tectonically gentle zones. The different fracturing and cementation processes indicated that preservation conditions declined with increased fracture openings during uplift, correlating with the gas enrichment.

Feasibility of CO2 storage and enhanced gas recovery in depleted tight sandstone gas reservoirs within multi-stage fracturing horizontal wells

Injecting CO2 when the gas reservoir of tight sandstone is depleted can achieve the dual purposes of greenhouse gas storage and enhanced gas recovery (CS-EGR). To evaluate the feasibility of CO2 injection to enhance gas recovery and understand the production mechanism, a numerical simulation model of CS-EGR in multi-stage fracturing horizontal wells is established. The behavior of gas production and CO2 sequestration is then analyzed through numerical simulation, and the impact of fracture parameters on production performance is examined. Simulation results show that the production rate increases significantly and a large amount of CO2 is stored in the reservoir, proving the technical potential. However, hydraulic fractures accelerate CO2 breakthrough, resulting in lower gas recovery and lower CO2 storage than in gas reservoirs without fracturing. Increasing the length of hydraulic fractures can significantly increase CH4 production, but CO2 breakthrough will advance. Staggered and spaced perforation of hydraulic fractures in injection wells and production wells changes the fluid flow path, which can delay CO2 breakthrough and benefit production efficiency. The fracture network of massive hydraulic fracturing has a positive effect on the CS-EGR. As a result, CH4 production, gas recovery, and CO2 storage increase with the increase in stimulated reservoir volume.

Quantitative Study on the Anticollapse Ability of Casing in Shale Gas Wells under Complex Load Conditions.

Implementing novel technologies, including the "well factory" model and zipper fracturing techniques, has become prevalent in shale gas development. During completion operations such as lowering casing and multistage fracturing, the casing is subjected to many complex loads, reducing its strength and increasing the risk of casing deformation. By establishing a casing wear model and conducting multistage cyclic loading experiments and numerical simulations, we analyzed the change rule of casing anticollapse strength under complex loads, developed a calculation method for casing comprehensive anticollapse ability under complex loads, and applied the method to an illustrative calculation. The study shows that the wear effect during completion has a negligible impact on the strength of the casing. The casing anticollapse strength exhibits a linear decline in correlation with the number of cycles. The zipper fracturing operation resulted in a nonuniform distribution of geo-stress around the well, and the casing anticollapse strength demonstrated a nearly linear decline in correlation with the nonuniformity of geo-stress. In the presence of both internal and external effects, the casing anticollapse strength exhibited a decline exceeding 15%, thereby increasing the risk of casing deformation. This research method can provide computational guidance for preventing casing deformation in field fracturing construction.

Evaluation of Fluid Distribution and Perforation Erosion in Multistage Fracture Treatment

Summary Fracture monitoring and diagnosis by fiber-optic sensing technology provides invaluable information about stimulation efficiency. This technology becomes more critical for multistage fracturing over long horizontal wells. The combined analysis of distributed temperature sensing (DTS) and distributed acoustic sensing (DAS) measurements has been used to map the fluid distribution during hydraulic fracturing, and fracture volume at the cluster level and at the stage level can be estimated from the analysis. In this paper, based on the interpretation of models for DTS and DAS, we extend the application to fluid containment and stage isolation evaluation. In plug and perforation hydraulic fracturing, when a stage is finished pumping, the stage is isolated by a plug, and the next stage is perforated and then fractured. If the plug is not functioning correctly, fracture fluid enters the previous stage, causing an uneven fluid distribution, and possibly more severe perforation erosion. Both DAS and DTS monitoring can record this phenomenon when it happens. Interpretation models are built to quantify the fluid distribution with the effect of plug leakage included. From DTS measurements, cooling below the stage being completed is counted as the fluid from the current stage. Given this information, the reservoir thermal model can estimate the volume of leakage. From the DAS measurement, we interpret the volume distribution based on frequency band energy to compare with the DTS interpretation. Perforation erosion measurements from a downhole camera are used to confirm the estimation. With this approach, we assess the fluid distribution, plug performance, and the importance of stage isolation on perforation erosion during a multistage fracture treatment. The information can then be used to analyze and optimize completion and fracture treatment design. Field examples are presented in the paper to support the discussion, findings, and conclusions. Based on the results of the fluid distribution estimated, we observed that higher injection rate and larger fluid volumes may create more uniformly distributed fluid between clusters in a stage. When considering communication between stages, the DTS and downhole camera show that there is a correlation between fluid distribution and perforation eroded area. An inconsistency of eroded area and fluid received is observed at toe-side clusters from DTS, DAS, and downhole images. This could be caused by a short erosion time at the toe-side clusters. In the completion design, only a few parameters show a strong impact on fluid distribution and perforation erosion.

Propagation of interfered hydraulic fractures by alternated radial-circumferential extensions and its impact on proppant distribution

The fracture extension mechanisms and proppant transport characteristics play key roles for optimizing hydraulic fracturing in unconventional reservoirs. In this work, the visual physical simulation method was used to analyze the 3D dynamic extension processes of multi-stage hydraulic fractures and the subsequent impact on proppant distribution. The interfered fracture in multi-stage hydraulic fracturing exhibit alternated radial-circumferential extension behavior. More specifically, these behavior changes from unilaterally radial initiation, circumferential extension to radial extension. Unilaterally radial initiation results in the formation of both mirror and conchoidal features, while circumferential extension leads to stepped feature, and radial extension gives rise to feather feature. The four features of hydraulic fractures result in four types of non-uniform proppant distribution: uniform, scattered, cluster, and regional distribution. The proppant transport shifted from linear to radial mode, promoting further fracture extension. The effects of segment spacing and proppant injection sequence were studied. The results showed that the influence on the interfered fracture decreases as the segment spacing increases. In addition, the propped fracture area is larger when the small-size proppant is injected first, followed by large-size one. The research can improve understanding and optimization of multi-stage hydraulic fracturing in unconventional oil and gas reservoirs.

Evolution features and a prediction model of casing perforation erosion during multi-staged horizontal well fracturing

Large-displacement high-intensity sanding hydraulic fracturing operations often cause casing perforation erosion and thus temporary plugging failures, exacerbate the unevenness of fracture initiation and expansion, and induce casing damage. In order to clarify the dynamic evolution of perforation erosion and predict perforation diameter, the effects of different types of proppants, the viscosity of sand-carrying liquids, and large sand-passing quantities on perforation erosion rate were experimentally explored in the study. The evolution of perforation erosion and the particle size distribution of quartz sand and ceramsite were analyzed in the experiment and a prediction model for perforation erosion under various fracturing parameters was established. Compared to ceramsite, quartz sand had the more significant effect on perforation erosion and the more serious particle abrasion and fragmentation under the same sand-passing quantity. Increasing the viscosity of the sand-carrying liquid slowed down perforation erosion and made the edge of perforation entrance more uniform. As the sand-passing quantity through the perforation increased, perforation erosion in the initial stage was concentrated at the perforation edge. Then, the inner wall of the perforation was also eroded, but the average erosion rate was reduced. A prediction model of perforation erosion considering multiple fracturing parameters was established based on the principle of fluid similarity. The errors between predicted values and downhole eagle-eye observation values were less than 15 %. The model provides an important basis for the optimization of fracturing parameters and downhole casing strength design.

Fracture Propagation of Multi-Stage Radial Wellbore Fracturing in Tight Sandstone Reservoir

Radial wellbore fracturing is a promising technology for stimulating tight sandstone reservoirs. However, simultaneous fracturing of multiple radial wellbores often leads to unsuccessful treatments. This paper proposes a novel technology called multi-stage radial wellbore fracturing (MRWF) to address this challenge. A numerical model based on the finite element/meshfree method is established to investigate the effects of various parameters on the fracture propagation of MRWF, including the azimuth of the radial wellbore, the horizontal stress difference, and the rock matrix permeability. The results show that previously created fractures have an attraction for subsequently created fractures, significantly influencing fracture propagation. A conceptual model is proposed to explain the variations in the fracture propagation of MRWF, highlighting three critical effect factors: the attraction effect, the orientation effect of the radial wellbore, and the deflection effect of the maximum horizontal principal stress. Fracture geometry is quantitatively assessed through the deviation distance, which indicates the radial wellbore’s ability to guide fracture propagation along its axis. As the azimuth increases, the deviation distances can either increase or decrease, depending on the specific radial wellbore layouts. Decreasing the horizontal stress difference and increasing the rock matrix permeability both increase the deviation distance.

Numerical simulation of multiple hydraulic fracture propagation in heterogeneous coal reservoirs based on combined finite-discrete element method

Multi-stage fracturing in Horizontal well increases the permeability of coalbed methane by generating multiple fractures. However, the heterogeneity of coal reservoirs is a crucial factor that cannot be ignored in the study of multiple hydraulic fracture propagation. Therefore, we established a two-dimensional model for multiple hydraulic fracture propagation based on the combined finite-discrete element method (FDEM) and assigned a Weibull distribution function to the heterogeneity of the physical parameters of the cohesive elements in the model. The objective was to simulate and study the fracture propagation law of multi-cluster fracturing in horizontal wells in heterogeneous coal reservoirs. The research results indicated that: 1) as the heterogeneity of the coal reservoir weakened, the deflection angle of the main fracture increased. More secondary fractures were generated in the coal reservoir, leading to significant discontinuity. 2) The fracturing disturbance area was always concentrated at the tip of the main fracture, with a double wing shape. However, the fracturing disturbance areas at the tips of multiple main fractures could easily converge, with a square shape; 3) It is recommended to use a moderate injection rate and increase the perforation spacing appropriately when hydraulic fracturing is carried out in coal reservoirs with a heterogeneity coefficient m=5.

Improving the technology for Inflow Profile Evaluation in horizontal Wells by temperature changes Due to calorimetric Mixing

The paper is devoted to the problem of increasing the effectiveness of temperature logging quantitative interpretation for the inflow profile evaluation in horizontal production wells draining heterogeneous reservoirs with low permeability. Such wells are characterized by an extremely uneven distribution of inflow along the length of the wellbore. One of the ways of quantitative interpretation of temperature logging is based on the effect of calorimetric mixing. It’s widely used to quantify the share of local producing intervals in the total flow rate.The low accuracy of interpretation is associated with the lack of reliable information about the temperature of the fluid flowing into the wellbore. The authors propose an estimate of this parameter based on the similarity of the behavior of the temperature field vs time in the near-wellbore zone of a reservoir during periods of stable production and the periods of the well shut-in. This relationship is confirmed by the results of modeling the temperature field of the “well – reservoir” system, taking into account changes in a wide range of reservoir permeability and thermal properties of the reservoir, the geometry of hydraulic fractures in the reservoir, the flowing fluids, as well as the parameters of the well production targets. The logging technology recommended by the authors involves the registration of several temperature profiles along the length of the wellbore at the beginning of the well production with the maximum rate and drawdown and during the well shut-in. Their integrated analysis based on the behavior of the temperature field features in time identified on the basis of modeling makes it possible to evaluate with a high degree of certainty the dynamics of the temperature of the gas-liquid mixture coming from reservoirs to the wellbore during production periods. This provides the required accuracy in the quantitative assessment of the inflow profile from mixing anomalies.The proposed approaches to the interpretation of thermograms are applicable in the analysis of the results of non-stationary temperature logging results in horizontal and vertical wells during the production from heterogeneous reservoirs both through perforation and multi-stage hydraulic fracturing.

ANALYSIS OF OIL RESERVES PRODUCTION AT THE BP8 DEVELOPMENT OBJECT OF THE TARASOVSKOYE OIL AND GAS CONDENSATE FIELD

Based on the example of the analysis of the development of the oil facility BP8 of the Tarasovskoye oil and gas condensate field, geological and technological factors that can cause a low current oil recovery factor with a high water cut of the product are considered. It is assumed that: 1) the low waterflood coverage coefficient is associated with artificial fracturing at the initial stage of development which led to a change in the type of reservoir from primary pore to porous-fractured; 2) a decrease in the displacement coverage coefficient is associated with the permeability heterogeneity of the object; 3) swelling of clay particles under the influence of injected fresh water led to a decrease in the displacement coefficient. An analysis of the development of the facility shows that without the use of new effective technological solutions for involving in the development of capillary-pinched oil reserves of the porous-fractured reservoir of the BP8 object, the final technological oil recovery factor will not exceed 0.240 instead of the approved 0.425. To increase development efficiency, it is recommended to carry out pilot work on drilling horizontal wells with multi-stage hydraulic fracturing, equipped with inflow control devices based on intelligent inflow indicators.

Downhole Hydrogen-Generation System Stimulates Challenging Formations in Kuwait

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 34832, “Successful Trial of Innovative Downhole Hydrogen-Generator System To Stimulate Hard-to-Recover Formations: First in Onshore Kuwait,” by Mustafa Al-Hussaini, Hamad S. Al-Rashedi, and Nada Al-Saleh, SPE, Kuwait Oil Company, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ The objective of the pilot trial described in the complete paper was to provide an economic solution to develop tight and hard-to-recover formations within the operator’s fields. These assets represent a major challenge because of their low recovery factor (1–3%), the high cost of available conventional stimulation technologies, low revenue, and inability to sustain production rates. Introduction To establish an integrated stimulation solution for tight and heavy oil formations, the concept of using active single-atom hydrogen power to enhance near-wellbore permeability was evolved. This technology is based on downhole hydrogen generation from an in-situ exothermic multistage chemical reaction between two unique hydroreacting agents (HRAs). This reaction generates a huge amount of thermal energy, active hydrogen, and other hot active gases and acid vapors. The selection of HRA compounds, and their amount and concentration, is customized for each field. Development of Business Cases West Kuwait (WK) Business Case. The M formation in the WK region is a carbonate, multifractured tight reservoir that had been producing for years but had begun experiencing a low recovery factor. Some of its wells had low-productivity issues related to tight formation characteristics and low pressure. Production could not be sustained for long periods of time even after conventional acid stimulation. The reservoir featured a carbonate reservoir thickness of 300 ft, with 70% of oil in place at the top section. The reservoir is classified as tight (less than 0.1–10 md average permeability and 10–25% porosity), with 10 fractured multilayers. Only 1–3% recovery could be achieved despite many vertical, horizontal, and multilateral wells having been drilled in the M formation. Oil is considered nonviscous (28 cp, 21 °API). Current stimulation approaches included conventional acid stimulation, which elicited a poor response, and multistage fracturing, which encountered mixed results at best. North Kuwait (NK) Business Case. The tight T formation in this region featured poor reservoir connectivity. Minimal aquifer support led to a rapid decline in reservoir pressure. In general, low mobility of oil, poor API gravity, and low permeability were the main obstacles in draining oil from the T formation, in addition to reservoir heterogeneities such as facies distribution, fracture patterns, and pressure regimes. The formation consisted of tight limestone deposited on a carbonate ramp. The reservoir is divided into three main stratigraphic units (Upper, of approximately 110 ft; Middle, of approximately 60 ft; and Lower, of approximately 16 ft). The reservoir exhibits porosity of approximately 14% and permeability of approximately 14 md and is filled with relatively-low-API hydrocarbon (19–22 °API).

Extended Laterals and Hydraulic Fracturing Redevelop Tight Fractured Carbonates

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216292, “Redevelopment of Tight Fractured Carbonates Through Extended Laterals and Hydraulic Fracturing,” by Antonio Buono, Cameron Taylor, and Alyssa Dordan, SPE, ExxonMobil, et al. The paper has not been peer reviewed. _ In the complete paper, the authors compare development scenarios in a fractured carbonate play between historic vertical and short horizontal development and modern hydraulically fractured extended lateral development. Because of its long production history and recent redevelopment efforts, the Austin Chalk was chosen as a natural laboratory to test how recent artificial stimulation techniques can lead to additional production from a wider range of pore systems. Development of the Austin Chalk In recent years, application of modern unconventional multistage hydraulic fracturing techniques, coupled with adding proppant to support induced fracture networks, mitigated the steep decline seen in historic production profiles. These improvements were exemplified in a recent Austin Chalk redevelopment where modern completions led to an increase in estimated ultimate recovery (EUR) by 250% on average. In the targeted area of development, historic, short Austin Chalk laterals without modern completions exhibited a wide range of well performance. Some outlier wells achieved high recoveries from accessing an existing natural fracture network with the original completion, whereas others, after only a few months of economic production, were unable to achieve continuous flow without a propped stimulation. The differences in performance partially can be explained by the fact that the reservoir quality of different intervals within the Austin Chalk is likely highly variable. This is exemplified in the B-2 Zone, which contains a well-developed vertical fracture network with variable lengths. Data suggest that the natural fractures are confined within the B-2 and it is geomechanically less-susceptible to wellbore collapse than zones with higher clay concentrations. The B-2 is likely a stiffer interval than the E Zone. This implies that differences exist in the properties of these units that are caused by changes in mineralogy and cementation. The authors aim to characterize reservoir quality and hydrocarbon distributions of the fractured relatively clean zones compared with the hydraulically stimulated reservoir in relatively “dirty” chalky zones, and evaluate geomechanical properties and production expectations from each zone. Depositionally, these units can be characterized broadly as carbonate-rich with subordinate siliciclastic detritus composed of clay minerals and silt-sized quartz and plagioclase grains. These units all contain distinctive stylolite seams. The most-favorable hydrocarbon shows typically are in the lower members of the Austin Chalk. Production data show that natural-fracture-only production (heritage) generally has lower total EUR with highly variable well-to-well production profiles vs. fracture and matrix production, which the authors write that they believe is achieved when unconventional technology is applied to these reservoirs. To project from heritage chalk production to expected EUR using modern completions, the authors used a risked EUR scaling factor of 1.5×. Consequently, the potential uplift in economic viability was recognized through a multiwell Austin Chalk appraisal to assess well-to-well communication with Eagle Ford codevelopment. The authors’ appraisal evaluated reservoir-quality differences between the main landing zones in the Austin Chalk with those from the E Zone of the Austin Chalk and Upper Eagle Ford, respectively, to demonstrate how significant economic uplift can be realized in mature, tight carbonate fields with unconventional technology.

Numerical simulation study on propagation mechanism of fractures in tight oil vertical wells with multi-stage temporary plugging at the fracture mouth

The multi-stage temporary plugging and diverting fracturing technique stands as a pivotal method for enhancing production in tight oil reservoirs. At present, fracture propagation models in temporary plugging and diverting fracturing primarily focus on single-stage temporary plugging, disregarding intricate mechanisms influenced by multi-stage temporary plugging and inter-fracture interference on the redirection and propagation of artificial fractures. To address this gap, this study employs the extended finite element method and establishes a mechanical model for the propagation of multi-stage temporary plugging fractures in tight oil reservoirs based on the maximum circumferential stress criterion. Relevant numerical simulations are conducted, considering key factors such as horizontal stress differences, fracturing fluid viscosity, injection rate, and initial fracture angle, all of which influence the morphology of diversion fracture propagation. The study rigorously analyzes and compares characteristics such as the radius of diversion fractures, diversion angle, and fracture width profile corresponding to different numbers of temporary plugging stages. Numerical simulations reveal that the primary controlling factor influencing the extension of fractures is the horizontal stress difference. A smaller horizontal stress difference makes fracture diversion easier, resulting in larger redirection radii. The impact of fracturing fluid viscosity on the diversion radius and diversion angle of fractures can be deemed negligible. Larger injection rates during construction facilitate easier diversion, leading to larger diversion radii. Furthermore, when the initial fracture angle exceeds 90°, the diversion radius of fractures is significantly larger compared to cases where the initial fracture angle is less than 90°, indicating a more facile diversion of fractures.

Technology Focus: Unconventional and Tight Reservoirs (July 2024)

Unconventional reservoirs bear a unique perplexity in that, at every scale, they are different from their conventional counterparts and even one another. Small nuances in any one parameter can result in a vastly different well result, which may affect how an area, or even an entire play, is interpreted. This month’s selection of papers is all about those differences, in recognition that it is technology that drives innovation through understanding what these differences mean and how best to extract value from these vast resources. Starting at the well scale and looking at the benefits of knowing the efficacy of each stimulation stage, paper URTeC 3864145 is from the Ordos Basin in China. Investigating hydraulic fracture performance on a stage-by-stage basis proves time and time again that understanding the details can improve overall development outcomes. The case study reviews two hydraulic fracture diagnostic techniques used in combination to determine water breakthrough and shutoff plans. Zooming out to the play scale, paper SPE 216292 is focused on the most variable of unconventional reservoirs: the carbonate reservoir. This case study of the Austin Chalk formation in Texas analyses the production uplift from application of horizontal, multistage fracture stimulation technology in tight or fractured carbonate reservoirs. The application of unconventional technology in carbonate reservoirs can extended field life, and the deployment of this technology should be considered for any redevelopment or reassessment of potential resources trapped in tight carbonate reservoirs. Finally, paper OTC 34832 draws on the concept of innovation that is required to unlock unconventional resources. Novel methods of stimulation are the cornerstone of unconventional technology in that well stimulation is a basic requirement of all low-permeability reservoirs. The paper describes a trial pilot from idea through execution from Kuwait Oil Company for enhanced oil recovery in tight formations using downhole hydrogen generation from in-situ exothermic multistage chemical reactions between two unique hydroreacting agents. The paper also provides lessons learned and optimization insights from the trial, concluding that a successful, low-cost alternative stimulation technique was demonstrated and repeatable. Recommended additional reading at OnePetro: www.onepetro.org. SPE 216139 Tight Gas Reservoir Characterization and Comparison of PLT Methods: Microseismic Monitoring, Fiber-Optical Production Logging, and Tracer-Coated Sand Monitoring Applied in the Same Well by Xiao Yao, Petrochina, et al. SPE 216149 New Insight in Developing Tight Fractured Carbonate Reservoirs, Mishrif Formation, West Kuwait by M. El-Jeaan, Kuwait Oil Company, et al. SPE 215712 Successful Utilization of In-Situ Dune Sands in Saudi Arabian Unconventional Frac Operations by Nahar Qahtani, Saudi Aramco, et al.

Utilizing well-reservoir pseudo-connections for multi-stage hydraulic fracturing modeling in tight gas saturated formations

Purpose. Research is aimed at integrating multi-stage hydraulic fracturing in horizontal wells with hydrodynamic simulation as a mandatory part of planning the mining of any shale oil or gas reservoir. Methods. Geological and hydrodynamic reservoir modeling is part of the research. The properties and geometries of the hydraulic fracture network and its representation in the dynamic reservoir model were assessed. The comparative characterization was carried out based on the two methods of fracture modeling: cell dimension reduction for explicit fracture modeling (LGR – local grid refinement) and implicit fracture modeling method, presented in this paper, with additional pseudo-connections between well and reservoir. Findings. A hydrodynamic model for low-permeable reservoir, produced by horizontal well, hydraulically fractured with 5 stages, has been generated. This model is calibrated to the production history and flowing bottom hole pressure by applying two methods of fracture modeling. Modeling results show that it is possible to replicate historical well production by using both methods. However, the proposed method with pseudo connections has several advantages compared to the generally accepted, local grid refinement (LGR) method. Originality. For the first time, a system of pseudo connections between well and reservoir was constructed to model a multi-stage hydraulic fracturing for a hydrodynamic model of tight reservoir. Hydrodynamic simulation results were refined and calibrated to the history of hydrocarbon production and flowing bottom hole pressure data using the pseudo-connections and LGR methods. The similarity of the results by applying LGR and pseudo-connections methods was revealed. Practical implications. The use of pseudo connections for hydraulic fracturing modeling can reduce simulation run time for cases where multi-stage hydraulic fracturing has already been carried out or is planned in the future. Additionally, the use of this method allows testing a larger number of realizations and scenarios, including hydraulic fracturing design (number of stages, size and conductivity of resulted fracture systems, fracture orientation, etc.), well placement and fracture growth relative to well trajectory. Also, there is no need to rebuild a model every time for each realization, as is the case with the LGR method.