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This article is a systematic review that evaluates the acidizing of carbonate rocks under various reservoir conditions and damage scenarios. Acidizing is a technique used to enhance hydrocarbon production in carbonate reservoirs, but its effectiveness can be influenced by different factors. In this review, studies addressing reservoir parameters, physical, compositional, and mechanical properties of carbonate rocks, types of acids used and their properties, as well as approaches for mitigation and remediation of damages are analyzed. The aim is to provide a comprehensive and up-to-date overview of acidizing evaluation, aiding in understanding the key aspects involved in this stimulation process. [ABSTRACT FROM AUTHOR]

The development of oil and gas deposits in compacted rocks is a promising area of development in the oil and gas industry. The object of research in this paper is the filtration properties of compacted rocks. To develop such deposits, special extraction technologies are required. Compacted carbonate rocks are easily dissolved by most acids, but for effective use, it is necessary that working solutions have very low viscosity and surface tension coefficient. Special filtration equipment has been developed for the research, which allows pumping various liquids and gases through rock samples and measuring permeability at pressures up to 1,000 bar. To determine the effectiveness of the acid solution, three groups of samples were studied: silty sandstone with clay-carbonate cement with a permeability of 0.2–0.95 mD, compacted organogenic-detrital light gray limestone with a permeability of 0.001–0.004 mD, and organogenic-detrital gray limestone with a permeability of 0.04–0.06 mD. In the course of the study, the stimulation fluid was pumped through the samples at a pressure of 200–300 bar and a temperature of 120 °C. The efficiency was determined by the change in nitrogen permeability of the samples before and after the experiments. In general, the studied stimulation fluid allowed increasing the permeability of rocks up to 3–7 times, depending on the rock and research conditions. The solution retains its reactivity for a long time and, due to its low viscosity and surface tension, penetrates deeply into the rock and significantly increases the well treatment radius compared to conventional acid treatments. The use of the developed acid solution for well stimulation will increase the efficiency of hydrocarbon production from compacted reservoirs without the use of hydraulic fracturing. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing technology coupled with horizontal well advancements has played a major role in the development of unconventional oil and gas resources in the USA. Despite the large economic and resource potentials, public concerns have been raised over the fast growth of the US shale developments. This work shows the trend of fracturing chemicals used in the USA from 2012 to 2019 using the FracFocus database. The results showed that mostly there is one dominating chemical ingredient that is used for a specific purpose. Corrosion inhibitors were among the largest purpose group with undisclosed chemicals. Some major chemicals were “generally recognized as safe” by the US food and drug administration to be used in food additives or food contact substances. Besides, the findings showed that 93% of fracturing fluid in the FracFocus database is water, 3% proppant, and 4% other chemicals. This work will serve as a guideline for future work related to the FracFocus database. Furthermore, this work can be used as a baseline that provides the amount of each chemical used in hydraulic fracturing in the USA as well as addressing the potential toxicity and tracking of environmentally friendly fracturing chemicals. [ABSTRACT FROM AUTHOR]

The over dependence on fossil fuels for human energy requirements together with the resultant adverse environmental effects in the form of greenhouse gas discharges has redirected our attention towards renewable energy sources. Researchers have identified hydrogen, a non-carbonaceous energy source holding the capacity to substitute fossil fuels, as a viable fuel option that has the potential to be generated utilizing eco-friendly techniques. Studies have identified underground sites that are operational or have the potential to be used for hydrogen storage. Shale formations, characterized by their low permeability, offer promising opportunities for underground hydrogen storage. These formations require stimulation techniques to generate flow channels. Pumping frac-fluid into these formations at high pressure induces fractures in them and the engineered fractures are supported by the proppants injected along with the fluid. Propped fractures form a vital conduit in unconventional gas reservoirs, which are a potential medium for storage of hydrogen. Cryogenic fracturing is an innovative approach that aims to enhance and broaden the capabilities of conventional hydraulic fracturing processes. The transmission and settlement of proppants are influenced by certain critical aspects including their density, size and volume fraction and fluid velocity, which are investigated in this contribution. This study incorporates water and cryogenic fluids like liquid nitrogen (LN 2) and liquid helium (LHe) as fracturing fluids. The primary objective of this effort is to analyze proppant transportation phenomenon and the key influential factors in LN 2 and LHe. The proppant volume fraction contour, equilibrium dune level (EqDL) and dune height (EqDH) data are illustrated in this research for better understanding of proppant migration. It was observed that when the fracturing fluid is given a higher velocity, the proppant grains experience increased drag force, causing them to penetrate deeper into the fracture. The desired range of proppant volume fraction for improved grain transmission was determined as 0.45 to 0.50 and the critical proppant density that significantly affected the EqDL as 187.2839 lb/ft3. • Fracturing of impermeable formations for enhanced underground hydrogen storage. • Eulerian-Granular model for studying the proppant bearing ability of cryogenic fluids. • Desired proppant volume fraction range for improved grain transmission is 0.45–0.50 • Higher fluid velocity enables better proppant transportation. • Cryo-fluids carry low-diameter, low-density proppants deeper into the fractures. [ABSTRACT FROM AUTHOR]

Acidification, a widely employed technique for well stimulation, utilizes a variety of acid systems. However, the literature provides limited insights into the economic and oil recovery implications of these treatments. Therefore, this work aims to analyze the economic impact on the oil recovery of different acid treatment designs in formations with varying degrees of heterogeneity and flow capacity. For this purpose, matrix acidization simulations were conducted using Matrix software to obtain the skin profile for each type of treatment. Subsequently, numerical simulations were performed using IMEX software from the CMG Group to analyze oil production and compare the economic results of different acid treatments. The main findings indicate that reservoirs with low flow capacities benefit more from stimulation operations, yielding a higher financial return when stimulated compared to untreated wells. In fact, there seems to be a range of flow capacity values, from around 20,000 to 40,000 mD.m, above which the net present value (NPV) of stimulated wells is equal to or even lower than that of damaged untreated wells. [ABSTRACT FROM AUTHOR]

In cryogenic fracturing, a rock surface exposed to cryogenic fluids undergoes a large thermal gradient, and the resultant local tensile stress overcomes rock strength and initiates fractures. This study investigates the development of cracks generated from the cryogenic treatment of a borehole under no external confining stress on specimens. The experiments were performed on transparent PMMA specimens to observe fracture proliferation around boreholes. Liquid nitrogen was flowed through the boreholes to cool the borehole surface. The results show that initial fracture growth is characterized by abrupt starts and stops, and as the fracture propagates outward, the growth appears more continuous. In an early stage, horizontal/radial fractures and vertical fractures are the defining patterns. Horizontal fractures tend to be separated by a specific exclusion distance (i.e., spacing between cracks). While distinct horizontal/vertical fractures and exclusion distance manifest themselves at an early stage, fractures resulting from fracture interactions and curvatures can develop into complex shapes at later stages. Cryogenic thermal loading induces distinctively curved fractures. The tendency of curvature may prevent greater penetration. An increase in the borehole pressure during liquid nitrogen flow, however, can lessen fracture tortu-osity and facilitate radial propagation. A high flow pressure and rate are also advantageous in that they accelerate cooling and fracture propagation.

Stimulation of production (or injection) wells in subterranean formations with acid has been widely used to improve well productivity (or injectivity). Hydrogen chloride (HCl) acid has historically been the common choice of acid used for acidizing carbonate reservoirs due to it providing exceptional results while being inexpensive and readily available. The downside to HCl use is its extremely high reaction and corrosion rates at elevated temperatures, significantly limiting the conditions in which it can be applied. To combat these reaction rates, reaction and corrosion inhibitors are added which act to slow down these rates at elevated temperatures. While previous investigations still had moderately low-temperature limitations, this investigation analyzed just how drastically these rates can be reduced through the addition of a recently developed aqueous phase retarded acid system. Changes in wormhole morphology were able to be observed at elevated temperatures up to 138 °C, but also increased acid concentrations (up to 25 wt%) with this system. This investigation extended upon previous industry work by using longer (30.48 × 10−2 m) cores to better understand wormhole propagation and morphology and reduce the gap between the field and core scale. Through CT imaging and pressure drop interpretation, an optimum injected rate at various temperatures could be estimated to achieve wormhole breakthrough after approximately 0.5 injected pore volumes of acid solution. This required injected pore volume for breakthrough was shown to be even further reduced if acid concentrations were increased above the commonly industry used concentration of 15 wt%. Article Highlights: Wormhole morphology in carbonate rock by hydrochloric acid (HCl) reaction at high temperature (280 °C) was visualized. Optimal volume of retarded acid required for deep wormhole penetration decreases with increasing temperature up to 280 °C. No significant effect of acid concentration (15–25 wt% HCl) on the optimal retarded acid volume. [ABSTRACT FROM AUTHOR]

Cryogenic fracturing has been explored in recent years as a waterless fracturing method for well stimulation to avoid issues encountered in water-based hydraulic fracturing. Cryogenic stimulation using liquid nitrogen applies large thermal gradients on reservoir rocks to induce fractures. This study investigates the initiation and proliferation of cryogenic fractures from boreholes under external stress on specimens. We flowed liquid nitrogen through boreholes drilled through the center of transparent PMMA cylinders under uniaxial stress and monitored fracture proliferation, temperatures, and borehole pressures. Our results show that the effect of stress resembles that of hydraulic fractures such that fractures propagate more in the direction of the stress. Under loading perpendicular to the borehole axis, a cloud of annular and longitudinal fractures extends more in the direction of loading. Under loading parallel to the borehole axis, longitudinal fractures dominate, and annular fractures become more suppressed and more sparsely distributed than those of unconfined specimens. Even if fractures are driven to initiate against the influence of stress, such as those from a boundary edge of a high stress concentration, they gradually deflect in the direction of stress, similar to hydraulic fractures from perforation holes that curve toward a direction perpendicular to the minimum stress direction. [ABSTRACT FROM AUTHOR]

The relevance. According to the resource potential estimates, the Bazhenov formation has great potential and it is characterized by unique properties that make it difficult to develop. Nowadays, there is no single concept for development of hard-to-recover hydrocarbon deposits. Therefore, the cost-effective development of the Bazhenov formation resources is associated with the creation of effective methods for increasing oil recovery and oil well stimulation. The main aim: summarization and analysis of scientific and technical literature regarding to advanced technologies for enhanced oil recovery and well stimulation at conditions of the Bazhenov formation and foreign shale deposits with similar characteristics and properties. Objects: technologies increasing the efficiency of oil recovery from the Bazhenov formation reservoirs or other formations with similar characteristics, including thermal, gas, chemical and combined methods of enhanced oil recovery, hydraulic fracturing, acid treatment; results of laboratory experiments, physical and mathematical modeling, pilot tests of the considered technologies. Methods: analysis of domestic and foreign literature and patent information relating to technologies for the development of hard-to-recover hydrocarbon deposits. Results. Characteristics and description of reservoir stimulation mechanisms using the most common methods of enhanced oil recovery, hydraulic fracturing, acid treatments and their combined technologies are given. On the example of the pilot field and laboratory tests results, the effect obtained from the reservoir stimulation at different deposits is described. It is noted that advanced technologies are combined methods, including techniques using chemical reagents. The efficiency of technological fluids at the Bazhenov formation can be increased with complex chemical systems containing various organic solvents and surfactants.

Sandstone formations are yet stimulated with mud acid when matrix acidizing is most competent. In terms of high-pressure high-temperature (HP-HT) conditions, the corrosive impact of hydrochloric (HCl) acid prompted the need to explore other alternatives to mud acid. This study examines the efficiency of organic acids in stimulating Sarah sandstone, a tight gas formation of potential.The optimum injection of acid volume was tested on Berea cores. Besides, the mineralogy of outcrop rocks of Sarah formation was identified using X-ray diffraction (XRD) aided by Scanning Electron Microscopy (SEM). Formation mineralogy led to the selection of acetic-hydrofluoric (C₂H₄O₂-HF) and oxalic-HF (C₂H₂O₄-HF) as proper acids for stimulation experiments. Bentonite water-base mud was used to alter the permeability of three fresh Sarah sandstone core samples. The organic-HF acids were used to stimulate two core samples, while mud acid (HCl-HF) was tested in the third core for comparison. Energy-dispersive X-ray spectrometer (EDX) and SEM were utilized to study the impact of acids on porous media.Experiments conducted in Berea core samples led to the execution of five pore volumes (PV) of preflush and one PV of main treatment as the optimum volume during the acidizing trials. XRD and SEM identified pore-filling clay minerals causing the low permeability of Sarah formation. Furthermore, the water-base mud injected decreased the permeability further by 80%. Oxalic-HF and acetic-HF mixtures recovered the initial permeability of core samples by 46% and 35% respectively. SEM-EDX results showed how organic acids have partially unblocked the pathways of the structural pores leading to permeability enhancement.This research not only recommends the use of oxalic-HF acid for acidizing Sarah sandstone formation but also spotlights the ability of organic acids employment as preflush in hydraulic fracturing operations.

Acidification, a widely employed technique for well stimulation, utilizes a variety of acid systems. However, the literature provides limited insights into the economic and oil recovery implications of these treatments. Therefore, this work aims to analyze the economic impact on the oil recovery of different acid treatment designs in formations with varying degrees of heterogeneity and flow capacity. For this purpose, matrix acidization simulations were conducted using Matrix software to obtain the skin profile for each type of treatment. Subsequently, numerical simulations were performed using IMEX software from the CMG Group to analyze oil production and compare the economic results of different acid treatments. The main findings indicate that reservoirs with low flow capacities benefit more from stimulation operations, yielding a higher financial return when stimulated compared to untreated wells. In fact, there seems to be a range of flow capacity values, from around 20,000 to 40,000 mD.m, above which the net present value (NPV) of stimulated wells is equal to or even lower than that of damaged untreated wells.

Sandstone formations are yet stimulated with mud acid when matrix acidizing is most competent. In terms of high-pressure high-temperature (HP-HT) conditions, the corrosive impact of hydrochloric (HCl) acid prompted the need to explore other alternatives to mud acid. This study examines the efficiency of organic acids in stimulating Sarah sandstone, a tight gas formation of potential. The optimum injection of acid volume was tested on Berea cores. Besides, the mineralogy of outcrop rocks of Sarah formation was identified using X-ray diffraction (XRD) aided by Scanning Electron Microscopy (SEM). Formation mineralogy led to the selection of acetic-hydrofluoric (C₂H₄O₂-HF) and oxalic-HF (C₂H₂O₄-HF) as proper acids for stimulation experiments. Bentonite water-base mud was used to alter the permeability of three fresh Sarah sandstone core samples. The organic-HF acids were used to stimulate two core samples, while mud acid (HCl-HF) was tested in the third core for comparison. Energy-dispersive X-ray spectrometer (EDX) and SEM were utilized to study the impact of acids on porous media. Experiments conducted in Berea core samples led to the execution of five pore volumes (PV) of preflush and one PV of main treatment as the optimum volume during the acidizing trials. XRD and SEM identified pore-filling clay minerals causing the low permeability of Sarah formation. Furthermore, the water-base mud injected decreased the permeability further by 80%. Oxalic-HF and acetic-HF mixtures recovered the initial permeability of core samples by 46% and 35% respectively. SEM-EDX results showed how organic acids have partially unblocked the pathways of the structural pores leading to permeability enhancement. This research not only recommends the use of oxalic-HF acid for acidizing Sarah sandstone formation but also spotlights the ability of organic acids employment as preflush in hydraulic fracturing operations. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing has been widely used in the petroleum industry for exploiting tight and ultra-tight formations. Although conventional hydraulic fracturing techniques have advanced significantly over time, it is still challenging to achieve separate intervals within multilayered formations, target the right layers and accurately fracture in succession. Hydra-jet-assisted fracturing, which involves boosting pressure in the cavity behind the casing to enable successful fracture initiation, is a technique often practiced to overcome this. However, there exists limited research regarding the pressure field within the cavity; therefore, this study aims to establish a mathematical model for predicting boosting pressure in the cavity under various reservoir conditions. In this paper, the authors present a numerical model to investigate the effects of nozzle differential pressure ratio of nozzle diameter to cavity diameter, annulus pressure and cavity length on boosting pressure. It is observed that the boosting pressure increases linearly with nozzle differential pressure and diameter ratio, respectively, while retaining other parameters as constant. However, simulations also indicate that annulus pressure and cavity length have minimal effect on the boosting pressure. In addition, the relationship between the boosting pressure coefficient and dimensionless standoff distance is also developed for specific diameter ratios, along with an insightful sensitivity analyses. A mathematical model is established to predict the final boosting pressure at different diameter ratios. As a result, this advances understanding of the design of treatment parameters in hydra-jet-assisted fracturing. Furthermore, this investigation is another step forward toward the global application of hydra-jet fracturing technology in developing deeper and layered tight gas sands. [ABSTRACT FROM AUTHOR]

Reservoir formation damage is a major problem that the oil and gas industry has to mitigate in order to maintain the oil and gas supply. A case study is presented that identifies the impacts of formation damage and their causes in the Nubian 'C' hydrocarbon reservoir within Sidki field located in the Southern Gulf of Suez, Egypt. In addition, a formation damage mitigation program was designed and implemented involving an effective stimulation treatment for each well experiencing reservoir damage. The data available for this study include core analysis to provide rock mineralogy and lithology; analysis of production fluid data; water chemistry; drilling fluid composition; perforations and well completion details; workover operations; and stimulation history. The diagnosis of formation damage based on the integrated assessment of the available data is associated with several benefits, (1) The integration of the data available helps provide a robust analysis of formation damage causes and in establishing suitable remediation actions, (2) Workover fluid is confirmed as the primary cause of reservoir damage in the studied well, (3) Several reservoir damage mechanisms were identified including water blockage, solids and filtrate invasion, fluid/rock interaction (deflocculation of kaolinite clay), salinity shock and/or high-sulfate content of the invaded fluid, (4) Irrespective of the potential causes of formation damage, the primary objective of a gas production company is to mitigate its effects and the integrated dataset helps to design appropriate and effective stimulation treatments to overcome formation damage, and (5) In gas reservoirs, especially low permeability ones, extra precautions are necessary to avoid potential reservoir damage due to workover fluid invasion. [ABSTRACT FROM AUTHOR]

The concept of cryogenic fracturing is that a sharp thermal gradient developed by applying a cryogenic fluid on a rock surface causes a strong local tensile stress that initiates fractures. Prior field tests suggest that field application with special equipment rated for cryogenic temperatures may deliver potential benefits. The tests did not, however, identify the fracture mechanisms at work in downhole conditions. In this study, we present our laboratory designs and procedures developed for studying cryogenic fracturing mechanisms in a well environment, and examine typical data indicative of the performance of the system. The experimental apparatus and procedures were specifically designed to conduct cryogenic fracturing tests in specimens under confining stress, with integrated cryogen transport, measurements, and fracture characterization. A true-triaxial loading system was built to simulate reservoir stress levels and anisotropic stress application, and was designed to avoid thermal stresses in tests involving cryogen by arranging discrete components in an open chamber. To maximize thermal shock on the wellbore surface, tubing and wellhead are configured so that liquid nitrogen enters the borehole and flow out after contributing to thermal shock. The temperature at boreholes and along flow lines, borehole pressure, and liquid nitrogen consumption are monitored throughout treatments. Acoustic transmission and pressure-decay measurements are used to characterize fractures before and after the experiments. Breakdown tests performed on un-stimulated specimens and stimulated specimens compare breakdown pressures of the two groups and thus evaluate the performance of thermal fracturing. The laboratory design was able to effectively apply cryogenic stimulations to laboratory rock specimens. The characterization methods were able to capture fracture creation and rock property changes due to cryogenic fracturing.

Chemical additives used for hydraulic fracturing and matrix acidizing of oil reservoirs were reviewed and priority chemicals of concern needing further environmental risk assessment, treatment demonstration, or evaluation of occupational hazards were identified. We evaluated chemical additives used for well stimulation in California, the third largest oil producing state in the USA, by the mass and frequency of use, as well as toxicity. The most frequently used chemical additives in oil development were gelling agents, cross-linkers, breakers, clay control agents, iron and scale control agents, corrosion inhibitors, biocides, and various impurities and product stabilizers used as part of commercial mixtures. Hydrochloric and hydrofluoric acids, used for matrix acidizing and other purposes, were reported infrequently. A large number and mass of solvents and surface active agents were used, including quaternary ammonia compounds (QACs) and nonionic surfactants. Acute toxicity was evaluated and many chemicals with low hazard to mammals were identified as potentially hazardous to aquatic environments. Based on an analysis of quantities used, toxicity, and lack of adequate hazard evaluation, QACs, biocides, and corrosion inhibitors were identified as priority chemicals of concern that deserve further investigation.

The concept of cryogenic fracturing is that a sharp thermal gradient developed by applying a cryogenic fluid on a rock surface causes a strong local tensile stress that initiates fractures. Prior field tests suggest that field application with special equipment rated for cryogenic temperatures may deliver potential benefits. The tests did not, however, identify the fracture mechanisms at work in downhole conditions. In this study, we present our laboratory designs and procedures developed for studying cryogenic fracturing mechanisms in a well environment, and examine typical data indicative of the performance of the system. The experimental apparatus and procedures were specifically designed to conduct cryogenic fracturing tests in specimens under confining stress, with integrated cryogen transport, measurements, and fracture characterization. A true-triaxial loading system was built to simulate reservoir stress levels and anisotropic stress application, and was designed to avoid thermal stresses in tests involving cryogen by arranging discrete components in an open chamber. To maximize thermal shock on the wellbore surface, tubing and wellhead are configured so that liquid nitrogen enters the borehole and flow out after contributing to thermal shock. The temperature at boreholes and along flow lines, borehole pressure, and liquid nitrogen consumption are monitored throughout treatments. Acoustic transmission and pressure-decay measurements are used to characterize fractures before and after the experiments. Breakdown tests performed on un-stimulated specimens and stimulated specimens compare breakdown pressures of the two groups and thus evaluate the performance of thermal fracturing. The laboratory design was able to effectively apply cryogenic stimulations to laboratory rock specimens. The characterization methods were able to capture fracture creation and rock property changes due to cryogenic fracturing.

• Two-Well EGS Approach : Demonstrated a promising method for extracting heat from hot dry rock (HDR) systems using a two-well injection-production system. • Comparative Analysis : A comparative study between the Utah FORGE project and Fervo Energy's efforts showcases an interplay of advancements and methodologies in the field of Enhanced Geothermal Systems (EGS). • Laboratory Core Analysis : Utilized comprehensive core sample analysis to underpin field data interpretations, confirming key geothermal parameters like permeability and porosity. • Advanced Analytical Techniques : Utilized analytical techniques, routinely used in unconventional oil and gas reservoirs, to precisely measure effective formation permeability from pressure falloff analysis. • Numerical Modeling Insights : Provided critical insights through numerical modeling, particularly on the permeability enhancement via hydraulic fracturing of EGS systems for heat extraction purposes. In this paper, we present analyses of laboratory and field data indicating that the current two-well, injection-production system, connected with multiple hydraulic fractures, is a very promising method for extracting heat from hot dry rock (HDR) systems to generate electricity. The current two-well system could be expanded to a three-well system consisting of one injection well and two symmetric producing wells connected via the central hydraulic fracture emanating from the injection well. To improve a uniform distribution of the injected fluid among all hydraulic fracture stages in the injection well, we advocate for field implementation of a newly designed well stimulation technique, the GeoThermOPTIMAL. We first present an analysis of the post-fracturing flow data obtained from an HDR geothermal injection well at the Utah FORGE Enhanced Geothermal System (EGS) research field site. The site is adjacent to the Roosevelt hydrothermal (HT) field. The objective of the study is to assess the effectiveness of well stimulation in extracting heat from the low-permeability, hot dry granitoid rock in the Utah FORGE research site. The study includes interpreting pressure falloff data obtained during the well stimulation process and employing laboratory-measured core data as a major input in the interpretation of the field falloff data. As a confirmation of the robustness of our analysis in Utah FORGE, we reviewed and analyzed the flow test results published for an injection-production doublet at the Blue Mountain EGS (Project Red) commercial site in Nevada. From the analyses of these two field tests, we have concluded that the interpretation and findings of the Blue Mountain EGS pilot test are consistent with the interpretation and findings from the Utah FORGE field research project test results. In summary, our engineering assessments began with laboratory experiments conducted on various core samples, including those from a granite outcrop and the Utah FORGE geothermal reservoir. These experiments aimed to measure key parameters such as matrix and fracture permeabilities, and porosities (k m ≈ 10 − 18 m 2 , k f , e f f ≈ 10 − 15 m 2 , ϕ m ≈ 10 − 1 , and ϕ f ≈ 10 − 4 ). These data served as guides and inputs for analytical and numerical solutions used to match the field pressure response of the geothermal wells. While we did not have core samples from the Blue Mountain EGS wells, we successfully applied the Utah FORGE analysis approach to the Blue Mountain site with cautious optimism. [ABSTRACT FROM AUTHOR]

The challenges of diversion during the stimulations of carbonate formations have been widely studied for decades. It has been shown that viscoelastic surfactants (VES) are among the effective diverting solutions which can be used during the stimulation of carbonate formations. These chemicals benefit from the reaction products between the acid and the calcite to increase the viscosity of the acid, therefore reducing, temporarily, the permeability of the first invaded rock layer, which holds the highest permeability. This temporary blockage steers the remaining acid to the layers with lower permeability that need treatment. This is usually called self‐diverting acidizing treatment. However, the same approach may not necessarily be applied for sandstone formations that are not calcite rich. In such cases, combining acid stages with batches of diverting agents is still feasible. For this approach, VES is also a suitable, non‐damaging solution that is often overlooked. In this study, the application of VES as a diverting agent was investigated during the chemical treatment operations in sandstone formations. Several dual core‐flooding experiments were performed at high pressure and high temperature (HPHT) conditions using sandstone core samples with high permeability contrast. [ABSTRACT FROM AUTHOR]

Exploration and development of biosiliceous mudstone has been carried out in California, USA, Sakhalin, Russia, and Japan. Although the exploration scale of biosiliceous mudstone differs between Japan and California, both exploration activities have similar histories. By 1950, fracture-developing porcelanite had been explored in both regions, and since then, fracture-developing cherts became particularly important in California. From around 1970, it began to be studied and recognized that the pore properties of porcelanite were improved by opal CT / quartz transition of biogenic silica, which led to the discovery of diagenetic traps in the 1990s. After that, it was influenced 'by the Shale Revolution, for better or worse, the attention was focused on the thermally-matured parts of biosiliceous mudstone. The evaluation was downgraded significantly for the matured parts of the Monterey biosiliceous mudstones, but it is ongoing for the thermally-matured basinal depressions of the Onnagawa biosiliceous mudstones. The productivity of biosiliceous mudstone may be significantly improved by well stimulation. Since there are large variations in reservoir and physical properties of biosiliceous mudstone, the effect of well stimulation differs depending on the geological condition. Therefore, optimization of well stimulation requires detailed understanding of geological conditions and preliminary simulations that reflect them. [ABSTRACT FROM AUTHOR]

A technical and economic analysis is done from simulations of propped hydraulic fracturing in low permeability reservoirs, as tight oil, in which the production from the well varies due to different well completion, each one is evaluated to determine the greatest economic performance. Working with a defined semi-integral system from the reservoir to the wellhead and focusing on well productivity; a method of analytic solution for diffusivity equation, alongside the nodal analysis method, and a multiphasic flow correlation for inclined tubing; allows estimating production on the wellhead. The cases studied demonstrate that hydraulic fracturing operations are very profitable before taxes, also, due to the high costs of these stimulation techniques, it is important to have an analytical tool that allows for a quick and precise evaluation of diverse scenarios, based on production analysis and its corresponding profit calculated by an economic analysis. This study could be adapted to analyze various tight oil reservoirs, providing results that justify investing in exploration and/or reactivation of them. [ABSTRACT FROM AUTHOR]

Abstract As conventional hydrocarbon reserves have gone into depletion state, oil companies around the world have turned their attention to heavy oil reserves, which were previously overlooked due to their less prolific capability compared to conventional hydrocarbon reservoirs. Bituminous heavy oil resources are known to be plentiful in quantity and size, but not without disadvantages, in which the astronomical viscosity is a troublesome aspect to be considered in exploiting the reservoir. It is not seldom that the viscosity itself is so high that bituminous oil would appear as solid-like substance under reservoir pressure and temperature. Electromagnetic heating has long been touted as the solution to overcome viscosity barrier in exploiting bituminous heavy oil reservoirs. The introduction of heat from electromagnetic wave propagation enables more efficient well stimulation technique compared to resistive heating. However, as sophisticated as the models are, they seem to be lacking a techno-economic model to consider feasibility of the project. This mathematical presentation incorporates technical aspects of heating and EM propagation model to properly model unsteady-state temperature and heat propagation as a function of time. The model is then tested on a sample bituminous heavy oil reservoir with thinly layered production zone and it has been highly reliable to swiftly predict project feasibility of nanoparticle-assisted EM heating.

Abstract A wide and comprehensive understanding of the chemical reactions and mechanisms of HBF4 is crucial as it significantly influences its performance in stimulating a sandstone formation. In general, it is well-known that HBF4 is able to provide a deeper penetration into the sandstone matrix before being spent due to its uniquely slow hydrolysis ability to produce HF. In the present study, a 3D numerical modelling and simulation were conducted to examine the capability of HBF4 in enhancing the porosity and permeability of the sandstone matrix. The model is built in COMSOL® Multiphysics commercial software of computational fluid dynamics (CFD) to simulate the acid core flooding process on sandstone core. The model had been validated against the experimental data in the literature. The results matched with the measured plot data very well. The effect of temperature on the performance HBF4 sandstone acidizing is evaluated in this study. The simulation results indicated that at low temperature of 25 °C, HBF4 is not very effective, as justified in its poor porosity and permeability increments of only 1.07 and 1.23, respectively. However, at elevated temperatures, the porosity and permeability enhancement also become increasingly more significant, which showed 1.26 and 2.06, respectively, at 65 °C; and 1.67 and 7.06, respectively, at 105 °C. Therefore, one can conclude that HBF4 acid treatment performed better at elevated temperatures due to increased hydrolysis rate, which is a governing function in HBF4 sandstone acidizing. Overall, this model had provided a reliable alternative to optimize various other parameters of HBF4 acid treatment.

Abstract Matrix acidizing is a broadly developed technique in sandstone stimulation to improve the permeability and porosity of a bottom-hole well. The most popular acid used is mud acid (HF–HCl). It is a mixture of hydrofluoric acid and hydrochloric acid. However, one of the conventional problems in sandstone acidizing is that mud acid faces significant issues at high temperature such as rapid rate of reaction, resulting in early acid consumption. This downside has given a negative impact to sandstone acidizing as it will result in not only permeability reduction, but can even extend to acid treatment failure. So, the aim of this study is to provide a preliminary screening and comparison of different acids based on the literature to optimize the acid selection, and targeting various temperatures of sandstone environment. This paper has comprehensively reviewed the experimental works using different acids to understand the chemical reactions and transport properties of acid in sandstone environment. The results obtained indicated that fluoroboric acid (HBF4) could be useful in enhancing the sandstone acidizing process, although more studies are still required to consolidate this conclusion. HBF4 is well known as a low damaging acid for sandstone acidizing due to its slow hydrolytic reaction to produce HF. This would allow deeper penetration of the acid into the sandstone formation at a slower rate, resulting in higher porosity and permeability enhancement. Nevertheless, little is known about the effective temperature working range for a successful treatment. Considering the pros and cons of different acids, particularly those which are associated with HF and HBF4, it is recommended to perform a comprehensive analysis to determine the optimum temperature range and effective working window for sandstone acidizing before treatment operation. Prior to sandstone acid stimulation, it is essential to predict the feasibility of acid selected by integrating the effects of temperature, acid concentration and injection rate. Therefore, this manuscript has thrown light into the research significance of further studies.

We explore different aspects of the multi-stage fracturing process such as stress interaction between growing hydraulic fractures, perforation friction, as well as the wellbore flow dynamics using a specifically developed numerical solver. In particular, great care is taken to appropriately solve for the fluid partition between the different growing fractures at any given time. We restrict the hydraulic fractures to be fully contained in the reservoir (fractures of constant height) thus reducing the problem to two dimensions. After discussions of the numerical algorithm, a number of verification tests are presented. We then define via scaling arguments the key dimensionless parameters controlling the growth of multiple hydraulic fractures during a single pumping stage. We perform a series of numerical simulations spanning the practical range of parameters to quantify which conditions promote uniform versus non-uniform growth. Our results notably show that, although large perforations friction helps to equalize the fluid partitioning between fractures, the pressure drop in the well along the length of the stage has a pronounced adverse effect on fluid partitioning as a result on the uniformity of growth of the different hydraulic fractures. [ABSTRACT FROM AUTHOR]

The oil produced from underground reservoirs and its rates are highly dependent on the porosity, permeability, rock container to those reservoirs, And has encouraged the modern technological developments special in the injection techniques, vibration survey, exploratory and horizontal drilling, and hydraulic fracturing on the exploitation of oil resources cannot be accessed previously. This study concluded that the technical developments have been helped to raise production and oil reserves and traditional rock and reduce drilling and surface system network connections, we should be taking considerations reserves and mechanical design at the well to reach the highest levels in Material Handling, owner a technology to extract oil shale production starts despite the presence of large reserves of it, interest in these ten countries in particular comes from because it owns more than half of the world's oil production and reserves. [ABSTRACT FROM AUTHOR]