Reservoir Stimulation Techniques Research Articles

Fracture propagation and evaluation of dual wells, multi-fracturing, and split-time in Fuyu oil shale

Reservoir stimulation is crucial for in-situ exploitation, it can promote a fracture network and increase the heat transfer area. Therefore, it directly affects heat injection and products transportation efficiencies. Conventional reservoir stimulation techniques, such as hydraulic fracturing are widely used. However, hydraulic fracturing in a vertical well tends to generate simple fractures that are unfavorable for heat transfer, and real-time fracture propagation is difficult to monitor, thus failing to precisely control the hydraulic fracturing scale. In addition, there are few qualitative and quantitative criteria in reservoir-scale fracture evaluations for interpreting the overall hydraulic fracturing effect. Consequently, in this study, dual wells, multi-fracturing, and split-time technology (DMS) were designed and conducted based on microseismic monitoring in field experiment to find real-time fracture propagation. Furthermore, based on Hugot's research on connecting microseismic events by spatiotemporal sequences, we proposed a step index and path intensity considering microseismic event intensities to evaluate the effect on hydraulic fracturing. The results showed that a three-dimensional fracturing zone with a 60 × 30 × 8 m length, width, and height was generated at a 476–484 m depth, which corresponded to the designed hydraulic fracturing and facilitated heat transfer and product migration. Higher pump pressure and rate harmed hydraulic fracturing, blocking proppant migration during which the FK1-4 coefficient of viscosity reached 70 N⋅s/m2, 1.4 times greater than that of FK1-2 and FK1-5 according to Poiseuille's law. The hydraulic fracturing effect in FK1-4 was superior than that in FK1-2 and FK1-5. This study serves as a reference for monitoring oil shale exploitation via in-situ pyrolysis.

Effect of weakening characteristics of mechanical properties of granite under the action of liquid nitrogen

Liquid nitrogen fracturing and hot dry rock geothermal development are both emerging technologies in the field of energy. However, during the extraction of geothermal energy, it can cause the evolution of geological fractures, leading to the diffusion of groundwater and pollutants, thereby causing environmental pollution issues. Currently, geothermal energy has become a focal point in the global development of renewable energy. However, traditional hydraulic fracturing methods used in harnessing geothermal resources suffer from limitations such as limited fracture creation, uncertain initiation points, and environmental pollution. In contrast, liquid nitrogen has emerged as a promising reservoir stimulation technique, exhibiting significant effects on rock fracturing. In this study, we conducted three-point bending tests on granite samples subjected to liquid nitrogen treatment at temperatures of 300°C, with varying numbers of cooling cycles. Changes in fundamental mechanical parameters were analyzed. Additionally, through acoustic emission monitoring, we studied the variations in characteristic parameters of acoustic emissions under different cooling cycle conditions. Furthermore, based on the theory of energy evolution, we analyzed the energy evolution process during sample failure under different cooling cycle conditions. Using a compact scanning electron microscope, we observed changes in the microstructure of granite and analyzed the influence of cooling treatment on its surface characteristics and failure modes, thereby revealing the thermal damage process of granite. Moreover, by employing a non-metallic ultrasonic testing analyzer, we scanned the fracture surface morphology of granite and investigated the variations in fracture surface morphology features and surface roughness parameters caused by cooling treatment. The results indicate that liquid nitrogen cooling treatment can more effectively reduce the mechanical properties of rocks, and this effect is further enhanced at high temperatures. Under the condition of 300°C, after undergoing different cycles of liquid nitrogen cooling, granite will exhibit a more diverse macroscopic and microscopic structural failure characteristics, consistent with the expected formation of fluid flow channels in high-temperature rock formations.

Applications of sodium silicate in oil and gas well operations

Silica and silicates are the most abundant minerals in the Earth's crust and mantle. They are critically important as both raw materials and finished products. Nanosodium silicate (SS) has been shown to increase the effectiveness and efficiency of several standard well operations now in use. The precipitation and polymerization of silicate colloid particles makes this whole thing possible. Nanosilicate is advantageous since it is inorganic, safe, inexpensive, water-soluble, nonflammable, and nonexplosive. Nanosodium silicate (SS) has been used since the 16th century and finds major applications in the building and paper industries as well as in water purification and cleaning products. Nanosodium silicate is studied in this article for its manufacture, chemistry, health and safety (HSE) benefits, existing applications, and potential future applications in oil and gas well operations. Drilling fluids using nanosodium silicate have been shown to be more effective at working tough shales and restoring circulation after it has been lost than traditional oil-based muds (OBM). Borehole zonal isolation and improved primary cementing results can be attained with the use of nanosidum silicate as a spacer in the preflush. When used as an accelerator to shorten thickening time and a lightweight extender when cementing, nanosodium silicate is a common cement addition. Nanosodium silicate techniques are commonly used in restoring casing integrity, enhancing EOR compliance, and shutting off water. Reservoir stimulation techniques like acidizing and hydraulic fracturing benefit greatly from the addition of nanosodium silicate to the stimulation fluids. Nanosodium silicate improves the efficiency of well abandonment. Learning the chemistry behind the processes improves our comprehension of their many practical uses. In addition, this technology paves the way for a wide variety of upcoming improvements in well operations.

Influences of confining pressure and injection rate on breakdown pressure and permeability in granite hydraulic fracturing

AbstractHot dry rock (HDR) geothermal resource is a renewable green energy source with great exploitation potential. The burial depth of HDR generally exceeds 2500 m and is typically under high in situ stress conditions, resulting in an ultralow permeability of the rock formations. To enhance the permeability of these formations, hydraulic fracturing is widely used as a reservoir stimulation technique in HDR geothermal resource exploitation. The differences in burial depth, in situ stress, and geological environment require different engineering designs when implementing hydraulic fracturing. Therefore, the confining pressure and injection rate play significant roles in determining the effectiveness of hydraulic fracturing, as they affect the propagation and distribution of fractures in the rock formation. To quantify the impact of these factors on the effectiveness of hydraulic fracturing, simulation experiments, and permeability tests were conducted using granite specimens under various confining pressure and injection rate conditions. The results of these experiments revealed the relationships among the confining pressure, injection rate, breakdown pressure, and permeability enhancement of the granite. The breakdown pressure of granite increased with the confining pressure, while the injection rate had little effect on the breakdown pressure. The hydraulic fractured sample produced new penetrating fractures, which increased the reservoir permeability, and owing to the higher complexity of hydraulic fractures under low confining pressure, the increase of permeability is correspondingly higher. The research results can provide an important reference for efficient stimulation development technology of deep HDR geothermal resources.

Kontrola niestabilności kapilarnej w warunkach hydrodynamicznego oddziaływania na złoże

The paper presents the results of studies on optimisation of water impact on a reservoir by means of sequential periodic increase in hydrodynamic pressure in order to extract capillary trapped oil. The method provides a coordinated account of both displacement conditions and capacitive-filtration characteristics of fluid-saturated reservoirs. The results of experimental, theoretical and field studies of mass transfer processes in the presence of hydrodynamic nonequilibrium in heterogeneous porous media are presented. This paper considers a case where capillary forces are the determining factor for the displacement of immiscible liquids. Laboratory test results have shown that the formation of CO2 in the reaction of an alkaline solution with naphthenic components can make an additional contribution to the control of surface tension in porous media. A series of experimental studies were carried out on a core sample model to simulate the oil displacement by in-situ generated CO2 gas-liquid system. The article offers an analytical and technological solution to the problem of ensuring the value of “capillary number” and capillary penetration corresponding to the most complete extraction of trapped oil by regulating the “rate” of filtration (hydrodynamic injection pressure). The paper presents the field cases of implementing the new reservoir stimulation techniques to increase sweep efficiency. For effective residual oil recovery in fluid flow direction, conditions of stepwise (staged) maintenance of specified hydrodynamic water pressure at the boundary of injection contour are considered. Estimated calculations allow to determine time duration and stage-by-stage control of injection pressure as a requirement for reaching the expected increase in oil recovery.

Microbial induced mechano-petrophysical modified properties to improve hydrocarbon recovery in carbonate reservoirs

This study focuses on the impact of a microbial-induced process on mechanical and petrophysical properties of tight carbonate hydrocarbon reservoirs and its implication for hydrocarbon recovery from carbonate reservoirs. Tight carbonate core samples were treated with cultured microbial media of Clostridium acetobutylicum at 42 °C for 14 days. The before- and after-treatment mechanical (unconfined compressive strength, UCS; fracture toughness, Ks) and petrophysical (porosity and permeability) properties of the core samples were investigated and analyzed. The scratch test method was used for assessing the geomechanical properties. The results indicate that in tight carbonate reservoirs, post-treatment microbial-induced alterations could degrade its mechanical integrity with −30% UCS and −28% Ks. The post-treatment improvement in petrophysical properties of the tight carbonate rocks yielded a 355% increase the porosity and ＋734% in permeability. The application of the technology presented in this study can potentially enhance the susceptibility for induced fractures to nucleate and propagate during reservoir stimulation in tight carbonate reservoirs, and enhance flow pathways to improve hydrocarbon recovery. This study provides insight into microbial-induced alteration technology that can be incorporated with other reservoir-stimulation techniques to further enhance hydrocarbon recovery from carbonate reservoirs.

Basin-scale multi-decadal analysis of hydraulic fracturing and seismicity in western Canada shows non-recurrence of induced runaway fault rupture

Hydraulic fracturing (HF) is a reservoir stimulation technique that has been widely deployed in recent years to increase the productivity of light oil and/or natural gas from organic-rich, low-permeability formations. Although the process of fracturing a rock typically results in microseismic events of magnitude < 0, many cases of felt seismic events (typically magnitude 3.0 or larger) have also been reported. In the Western Canada Sedimentary Basin (WCSB), where more than 40,000 wells have been drilled and hydraulically fractured in the past two decades, the occurrence of HF-induced events has surged in some areas. Yet, many other areas of the WCSB have not experienced a significant increase in induced seismicity, despite a sharp increase in both the number of HF wells and the volumes of injected fluid. The relationship between injected volume and induced magnitudes can be quantified using the seismic efficiency ratio (SEFF), which describes the ratio between the net seismic moment release and the injected fluid volume. Runaway rupture, in which the fault rupture is dominated by the release of accumulated tectonic stresses, is inferred to be marked by an abrupt increase in SEFF to a value > 0.5. Most previous studies of induced earthquakes have been limited to a single operation and/or seismicity sequence. To better understand the observed variability of the seismic response to HF stimulations at a basin scale, we compiled HF data for all unconventional wells hydraulic fractured in the WCSB between 2000 and 2020, together with the seismicity reported during the same period. We grouped these observations into bins measuring 0.2° in longitude and 0.1° in latitude, or approximately 13 by 11 km. We identified 14 areas where large magnitude events resulted in high SEFF values, implying runaway rupture had taken place. However, we find that in these areas, sustained fluid injection did not lead to persistent high SEFF values. Instead, as injection continued, SEFF values returned to values less than 0.5. This suggests that there is a limited budget of tectonic strain energy available to generate runaway rupture events: once this is released, event magnitudes decrease even if high volume injection persists.

Guest Editorial: Four Real-World Challenges in Hydraulic-Fracture Modeling

The development of theoretical hydraulic-fracturing models started several decades ago, setting a basis for hydraulic-fracture design, optimization, and diagnostics. As a reservoir stimulation technique, the problem of hydraulic fracturing in essence is the prediction of the geometric shape and dimensions (length, width, and height) of the growing fracture as a function of time. This mathematically translates to a set of nonlinear, integro-differential equations with moving boundaries, solved numerically over a number of time-steps (SPE 168600). When it comes to multistage fracture treatments (Fig. 1), where many fractures are being “pumped” simultaneously within each stage, the problem’s complexity increases exponentially. The old adage of four inputs being necessary for optimal fracture design (reservoir permeabilities, in-situ stress distributions, a sound geological model, and a fluid-loss model in naturally fractured rocks) is no longer the case as multiple-fracture (multi-frac) interactions and interference (intra-stage, intra-well, and inter-well) should also be incorporated (SPE 1210-0034-JPT). Classic treatment-design software, although convenient to use, struggle to predict multi-frac growth geometries with sufficient certainty, leading to significant disparities between simulations and field observations. Four real-world challenges associated with multi-frac modeling from horizontal well operations are described below. Although each formation presents its own set of challenges rendering it necessary for operators to learn from experience, the development of computational techniques to facilitate the simulation of these common occurrences will yield more-realistic models. 1. Nonsimultaneous fracture initiation within a stage Fracture-propagation pressures are significantly smaller than fracture-initiation pressures (approximated by the recorded “formation-breakdown” pressures) in the same rock. Hence, earlier fracture initiation from one perforation provides a low-energy pathway for the fracturing fluid, which would “prefer” to enter an existing fracture and propagate it rather than initiating new fractures from nearby perforations. 2. Dominant (or “runaway”) fracture creation Dominant (or runaway) fractures are those whose growth is significantly larger compared to that of the other fractures. Laboratory-scale experiments where more than one fracture was pumped from a single fluid source displayed dominant fracture creation as a consistent observation (Michael). This observation qualitatively agrees with acoustic sensing data from the field-scale operations (Fig. 2). Dominant fractures end up receiving the entire fracturing fluid by the end of a stage (SPE 194334), while the remaining fractures cease propagating. The contribution of these few dominant fractures in the post-stimulation well productivity could be major. 3. Inactive perforation clusters Fracturing fluid can bypass entire perforation clusters, initiating fractures from perforation clusters further downstream along the horizontal lateral (SPE 194334). This occurs both by inactive perforation clusters located between active clusters and by inactive perforation clusters located adjacent (upstream or downstream) of active clusters (Michael). There are many possible causes of a perforation cluster failing to generate fractures, including nonsimultaneous fracture initiation and dominant fracture creation. Limited-entry techniques accomplished by varying perforation numbers and diameters (SPE-530-PA), later proposed for mitigating interference between simultaneously growing fractures from horizontal wells (“stress-shadowing”), can potentially be effective in eliminating inactive perforation clusters if specific patterns are detected.

Uncertainty analysis for heat extraction performance from a stimulated geothermal reservoir with the diminishing feature of permeability enhancement

An enhanced geothermal system (EGS) has two critical features in the stimulated reservoir volume (SRV): random distribution of permeability and definite diminishing enhancement of permeability. However, the effects of these two critical features on heat extraction simulations of hot dry rock (HDR) reservoirs have been rarely studied. This paper will propose a theoretical framework to incorporate these two features into an uncertainty study of heat extraction performance. First, five sets of random fluctuations are generated with turning bands method (TBM) to characterize the uncertainty feature of permeability. Five descend trends in an elliptic SRV are constructed to characterize the definite diminishing feature of permeability. Then, nine hundred stimulated virtual reservoirs are constructed in two groups by assigning the superposition of random fluctuations and descend trends to the permeability. Third, a thermal-hydraulic-mechanical coupling model is established to simulate the heat extraction from these virtual reservoirs. Finally, several indices are defined for the elevation of EGS performance. The statistical analysis on production flux and thermal breakthrough time of these simulations identified three modes of EGS performances. Larger correlation length and variance result in higher uncertainty of EGS performance. Larger permeability enhancement in the SRV zone consistently increases the production flux of a stimulated reservoir. Small flux induced by large impedance is the first barrier to a satisfactory EGS performance of low permeability HDR reservoirs with current reservoir stimulation techniques.

The characteristics and its implications of hydraulic fracturing in hydrate-bearing clayey silt

As a reservoir stimulation technique, hydraulic fracturing is expected to be used in gas hydrate production to overcome the glaring challenge of low gas production rate. Several experimental studies have been carried out in hydrate-bearing sand, which confirmed the frackability of this kind of geomaterial. But for the fine-grained hydrate reservoir, which spreads more widely, contains the majority of the total hydrate resource, and is more difficult to exploit, there is no explicit research studying the fracturing behavior in it. To investigate the characteristics of hydraulic fracturing in fine-grained hydrate-bearing sediments (HBS), we carried out hydraulic fracturing experiments using hydrate-bearing clayey silt specimens with and without confining pressure. Tetrahydrofuran (THF) was used to synthesize hydrate in sediment. The breakdown pressure and its mechanical implications were analyzed. The failure process was visually presented, and the internal structure of the fractured specimen was revealed by X-ray computed tomography (CT). The results indicate that hydrate-bearing clayey silt can also be fractured effectively, and the failure process can be divided into the initial tensile failure stage and the following erosion stage. According to the experimental results, hydraulic fracturing was considered to be an effective stimulation method in gas production from fine-grained hydrate reservoirs but should be implemented with other production countermeasures to ensure long-term and efficient gas production.

Comparative Study on the Reservoir Characteristics and Development Technologies of Two Typical Karst Weathering-Crust Carbonate Gas Reservoirs in China

Carbonate reservoirs are the main reservoir types in China, which occupy the large ratio of reserves and production at present. The high-efficiency development of carbonate reservoirs is of great significance to assure the stability of national energy supply. The Lower Paleozoic reservoir in Jingbian gas field and the Sinian reservoir in Anyue gas field are two typical carbonate gas reservoirs, and their successful development experiences can provide significant references for other similar carbonate gas reservoirs. For Jingbian gas field, it is a lithological-stratigraphic reservoir developed in a westward monocline and multiple rows of nose-fold structures, and is a stable craton basin with simple palaeognomy distribution and stable connectivity, which has complex gas-water distribution. However, for Anyue gas field, it is a lithological-structural reservoir with multiple tectonic high points and multiple fault systems, and is biological dune beach facies under extensional setting with highly differentiated inside of the block in palaeognomy characteristics, which has limited connectivity and tectonic side water is in a local area. The difference of gas reservoir characteristics leads to the diverse development strategies. For these two gas reservoirs, although there are some similar aspects, such as the screen of enrichment areas, the application of irregular well pattern and reservoir stimulation techniques, the criteria of enrichment areas, the well types, and the means of reservoir stimulation are absolutely different. In addition, due to the differences of control reserves and production capacity for these two kinds of reservoirs, the mode of stable production is also different. The effective development of Jingbian gas field can give some references to the future exploitation on the Sinian gas reservoir. Firstly, the sedimentary characteristics should be studied comprehensively. Secondly, the distribution pattern and distribution characteristics of the palaeognomy should be found and determined. Thirdly, the distribution of fracture system in the reservoir should be depicted finely. Finally, dynamic monitoring on the production performance should be strengthened, and the management for this gas field should be improved further. The findings of this study can help for better understanding of the Karst weathering-crust carbonate gas reservoir formation characteristics and the optimal development technologies that should be taken in practice.

Reservoir Stimulation Technique Combines Radial Drilling Technology With Acid Jetting

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202661, “Combination of Radial Drilling Technology With Acid Jetting: New Approach in Carbonate Reservoir Stimulation,” by Ayrat Bashirov, Ilya Lyagov, and Ilya Galas, Perfobur, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. The complete paper describes an approach to stimulate carbonate formations with bedding water or a gas cap. The technique is a combination of acid jetting and a radial drilling technology that uses mechanical radial drilling with a slim mud motor. The primary advantages of the technology include controlled trajectory and the possibility of re-entry into channels. The novelty of the technology is in its ability to deploy acids in the rock far away from the wellbore through the mechanically drilled holes with known depths and azimuths. Reservoir Description The mature field is in central Russia in the Republic of Bashkortostan. The field contains both sandstone and carbonate reservoirs. Oil depth is from 780 to 1830 m. Six reservoirs are in development. This study concentrates on projects in a carbonate formation that is a substage of the early Pennsylvanian Period. This formation is highly heterogeneous with closely underlying water. Permeability of the reservoir is approximately 43 md; reservoir pressure is 1,000 psi, and oil density is 0.891 g/cm3. Two adjacent well candidates with identical reservoir properties were selected for the study, with a distance between wells of approximately 136 m. Net oil thickness in Well A is 4.4 m and 3 m in Well B. Mechanical Radial Drilling Technology The technology described by the authors uses mechanical radial drilling with a slim mud motor. The technology allows the drilling of a network of radial channels up to 15 m long with up to four channels of different trajectories on one level. The technical system features a modular construction for ease of assembly at the wellhead area and increased operational efficiency. The main elements of the technical system include the following: - Pipe pusher connected at the top with an overflow valve module and, at the bottom, with a guiding device connected by means of a hydraulic pusher - Flexible pipe assembly with a small (nonstandard) sectional mud motor - Drilling bit (milling cutter for window cutting) - Special whipstock and an anchor module with an orienting funnel connected from below to the pipe frame

Experimental study of the effect of liquid nitrogen penetration on damage and fracture characteristics in dry and saturated coals

Liquid nitrogen (LN2) fracturing is characterized with high rock breaking efficiency, no pollution and no water consumption compared with traditional hydraulic fracturing techniques. So far, LN2 fracturing remains as a new reservoir stimulation technique whose mechanism in breaking formation rocks is still not fully understood. To investigate the effect of LN2 penetration on damage and fracture characteristics in dry and saturated coals, some coal samples were wrapped with plastic film to prevent LN2 penetrating before LN2 cooling. Acoustic and permeability measurements were performed on samples before and after LN2 cooling. Then, scanning electron microscopy (SEM) analyses and mechanical tests were performed on samples with and without LN2 cooling. The results indicate that LN2 penetration has significant influence on the damage of dry coals, while little influence on the damage of saturated coals. The decreasing rate in P-wave velocity, the increasing rate in permeability and the size and number of micro-fractures of dry samples with LN2 penetration are significantly greater than that of samples without LN2 penetration. The saturated samples after LN2 cooling almost show the similar damage and fracture characteristics, and they sustained more serious damage than dry coals. Although the interconnected fracture networks were formed on the surfaces of dry samples, relatively short micro-fractures with poor connectivity and small aperture were formed inside the dry coal rocks, especially inside the dry coal rocks without the penetration of LN2. In contrast, crush areas and major cracks with branches were formed inside the water-saturated coal samples.

Hydraulic and thermal fracturing techniques for successful stimulation in unconventional geothermal energy recovery

Unconventional or enhanced geothermal systems (EGSs) have been recently identified as potential geothermal resources which can be utilized to extract the heat trapped in the deep geological formations. However, due to the low formation porosity in these systems, an underground heat exchanger must be artificially created to enhance reservoir permeability. A number of reservoir stimulation techniques are adopted in EGSs to enhance their permeability, including hydraulic fracturing and thermal fracturing. The aim of the present work is to provide an in-depth understanding of these reservoir stimulation techniques based on our current laboratory experimental work. Recent literature on the topic has been comprehensively reviewed, and advanced laboratory tests have been conducted to understand hydraulic and thermal fracturing techniques under reservoir conditions. Experiments were conducted utilizing the high-temperature high-pressure rock tri-axial apparatus and quenching treatments were performed by injecting cold water into granite rocks heated to different temperatures. Flow-through experiments were also conducted on intact and fractured granite rocks and the results were compared to predict production enhancement upon stimulation. CT scanning technology was employed to determine micro-scale characteristics following stimulation. Experimental work revealed that the propagation paths and apertures of hydraulic and thermal fractures are controlled by the in-situ stress and temperature and the heterogeneity of the rock matrix. Although the induced fractures contributed substantial enhancement of reservoir permeability, they were sensitive to stress and temperature changes due to the larger effective stresses and thermally induced volumetric expansion.

Postfracturing permeability prediction for CBM well with the analysis of fracturing pressure decline

AbstractHydraulic fracturing is a widely used reservoir stimulation technique to exploit CBM in China. Compared with the original permeability of coal reservoir, the postfracturing permeability is more critical for the productivity evaluation of CBM wells. Based on hydraulic fracturing, microseismics monitoring, and well test data of the CBM wells in Zhengzhuang block of Qinshui Basin, this paper proposes a simple method to obtain the fitting pressure by the classic fracturing pressure decline analysis theory under the condition of corrected dynamic overall leakoff coefficient. In addition, the postfracturing permeability of coal reservoir is predicted by the injection well testing theory. The morphology of hydraulic fractures in the study area is mainly determined by in‐situ stress, and most fractures are vertical ones propagating along the direction of the maximum principal stress. The fracturing curves of the study area can be classified into stable curves, stably fluctuating curves, descending curves, ascending curves, and fluctuating curves, where the stable and descending fracturing curves represent better fracturing effect. The length of hydraulic fractures is much greater than the height. The PKN model has been selected as the hydraulic fracture propagation model to analyze the fracturing pressure decline. The slope value of liner segment of G(δ,0) curve is proposed as the criterion for the fitting pressure calculation. The postfracturing permeabilities of coal reservoir range from 1.55 to 8.83 × 10−3 μm2, all of which are remarkably higher than that of the original reservoir.

An innovative experimental equipment for liquid nitrogen fracturing.

Due to the unique physical and chemical properties of liquid nitrogen (LN2), LN2 fracturing has been considered as a promising reservoir stimulation technique. In order to further investigate the feasibility of LN2 fracturing, a new device is designed to research the effect of LN2 fracturing under different conditions, such as different specimen sizes, temperatures, and confining pressures. The setup consists of three units: a high-pressure LN2 generating system, a true-triaxial loading and heating system, and a control and data acquisition system. Now, a series of experiments have been successfully carried out based on the setup. The results have proven the excellent fracturing effect of LN2 and the applications of this setup. The apparatus lays a foundation for the application of LN2 fracturing in both conventional and geothermal reservoirs.

Mineralogical variability of the Permian Roseneath and Murteree Shales from the Cooper Basin, Australia: Implications for shale properties and hydrocarbon extraction

Brittleness and plasticity indices in hydrocarbon reservoirs are calculated to understand how rocks behave under stress, and for assessing the fracturing performance of clay-rich shale reservoirs and assessing borehole stability. Evaluating shale plasticity/brittleness requires careful analysis of clay mineral composition in target shales and the development of fracking strategies for optimal shale stimulation. Here we report on the mineralogical variability of two Permian lacustrine shale units, the Roseneath and Murteree shales in the Cooper Basin, Australia, that are considered to have potential as unconventional hydrocarbon producers. The study involved a combination of X-ray diffraction, scanning electron microscopy and petrophysical modelling of the Roseneath and Murteree shales in order to obtain a better understanding of the compositions and microfabrics of these two units. This is part of a larger investigation of the shale gas potential of these two units in the Cooper Basin, and the results presented here may ultimately lead to improved reservoir stimulation techniques in both units. Core data has been integrated with wireline logging data to better identify brittle and plastic zones within the Roseneath and Murteree shales. Mineralogical analysis shows that both units are composed mainly of detrital quartz and clay/mica minerals with siderite cement. The clay mineral composition is dominated by illite/mica, and kaolinite in both units. However, based on the relative mineralogical differences between the two units, the Murteree Shale has more favourable brittle properties than the Roseneath Shale, and is considered to be more amenable to hydraulic fracturing for gas exploitation. However, the Roseneath Shale also has potential for gas stimulation, especially in intervals where siderite cement is prevalent.

Influence of Reservoir Stimulation on Marine Gas Hydrate Conversion Efficiency in Different Accumulation Conditions

In this paper, we used a method of combining reservoir stimulation technique (RST) with depressurization to investigate the conversion efficiency of marine natural gas hydrate (NGH) reservoirs in the Shenhu area, on the northern slope of the South China Sea, which differ in intrinsic permeability and initial NGH saturation conditions. We also analyzed the influence of the variable-stimulation effect on marine NGH conversion efficiency in different accumulation conditions, providing a reference scheme for improving the NGH conversion efficiency in the Shenhu area. In this work, we performed calculations for the variations in CH4 production rate and cumulative volume of CH4 in different initial NGH saturation, intrinsic permeability, and stimulation effect conditions. Variance analysis and range analysis methods were used to analyze the significance of these key factors and their interaction. Furthermore, we investigated the sensitivity of stimulation effect on NGH conversion efficiency. The simulation results showed that the stimulation effect has a significant influence on NGH conversion efficiency, and the influence of interaction between these three factors was not obvious. Possibly most importantly, we clarified that the sparsely fractured networks (N = 3) had a better effect for higher NGH conversion efficiency under higher saturation conditions. For lower permeability cases, the influence between sparsely (N = 3) and densely (N = 5) fractured networks were similar.

Seismicity Induced by Hydraulic Fracturing in Shales: A Bedding Plane Slip Model

AbstractPassive seismic monitoring of microseismic events induced in oil or gas reservoirs is known as microseismic monitoring. Microseismic monitoring is used to understand the process of hydraulic fracturing, which is a reservoir stimulation technique. We use a new geomechanical model with bedding plane slippage induced by hydraulic fractures within shale reservoirs to explain seismicity observed in a typical case study of hydraulic fracturing of a shale gas play in North America. Microseismic events propagating from the injection point are located at similar depths (within the uncertainty of their locations), and their source mechanisms are dominated by shear failure with both dip‐slip and strike‐slip senses of motion. The prevailing dip‐slip mechanisms have one nearly vertical nodal plane perpendicular to the minimum horizontal stress axis, while the other nodal plane is nearly horizontal. Such dip‐slip mechanisms can be explained by slippage along bedding planes activated by the aseismic opening of vertical hydraulic fractures. The model explains the observed prevailing orientation of the shear planes of the microseismic events, as well as the large difference between seismic and hydraulic energy.

Numerical simulation of the environmental impact of hydraulic fracturing of tight/shale gas reservoirs on near-surface groundwater: Background, base cases, shallow reservoirs, short-term gas, and water transport.

Hydrocarbon production from unconventional resources and the use of reservoir stimulation techniques, such as hydraulic fracturing, has grown explosively over the last decade. However, concerns have arisen that reservoir stimulation creates significant environmental threats through the creation of permeable pathways connecting the stimulated reservoir with shallower freshwater aquifers, thus resulting in the contamination of potable groundwater by escaping hydrocarbons or other reservoir fluids. This study investigates, by numerical simulation, gas and water transport between a shallow tight-gas reservoir and a shallower overlying freshwater aquifer following hydraulic fracturing operations, if such a connecting pathway has been created. We focus on two general failure scenarios: (1) communication between the reservoir and aquifer via a connecting fracture or fault and (2) communication via a deteriorated, preexisting nearby well. We conclude that the key factors driving short-term transport of gas include high permeability for the connecting pathway and the overall volume of the connecting feature. Production from the reservoir is likely to mitigate release through reduction of available free gas and lowering of reservoir pressure, and not producing may increase the potential for release. We also find that hydrostatic tight-gas reservoirs are unlikely to act as a continuing source of migrating gas, as gas contained within the newly formed hydraulic fracture is the primary source for potential contamination. Such incidents of gas escape are likely to be limited in duration and scope for hydrostatic reservoirs. Reliable field and laboratory data must be acquired to constrain the factors and determine the likelihood of these outcomes.Key Points:Short-term leakage fractured reservoirs requires high-permeability pathways Production strategy affects the likelihood and magnitude of gas release Gas release is likely short-term, without additional driving forces