Development Of Hydraulic Fracturing Research Articles

A Study on Three-Dimensional Multi-Cluster Fracturing Simulation under the Influence of Natural Fractures

Multi-cluster fracturing has emerged as an effective technique for enhancing the productivity of deep shale reservoirs. The presence of natural bedding planes in these reservoirs plays a significant role in shaping the evolution and development of multi-cluster hydraulic fractures. Therefore, conducting detailed research on the propagation mechanisms of multi-cluster hydraulic fractures in deep shale formations is crucial for optimizing reservoir transformation efficiency and achieving effective development outcomes. This study employs the finite discrete element method (FDEM) to construct a comprehensive three-dimensional simulation model of multi-cluster fracturing, considering the number of natural fractures present and the geo-mechanical characteristics of a target block. The propagation of hydraulic fractures is investigated in response to the number of natural fractures and the design of the multi-cluster fracturing operations. The simulation results show that, consistent with previous research on fracturing in shale oil and gas reservoirs, an increase in the number of fracturing clusters and natural fractures leads to a larger total area covered by artificial fractures and the development of more intricate fracture patterns. Furthermore, the present study highlights that an escalation in the number of fracturing clusters results in a notable reduction in the balanced expansion of the double wings of the main fracture within the reservoir. Instead, the effects of natural fractures, geo-stress, and other factors contribute to enhanced phenomena such as single-wing expansion, bifurcation, and the bending of different main fractures, facilitating the creation of complex artificial fracture networks. It is important to note that the presence of natural fractures can also significantly alter the failure mode of artificial fractures, potentially resulting in the formation of small opening shear fractures that necessitate careful evaluation of the overall renovation impact. Moreover, this study demonstrates that even in comparison to single-cluster fracturing, the presence of 40 natural main fractures in the region can lead to the development of multiple branching main fractures. This finding underscores the importance of considering natural fractures in deep reservoir fracturing operations. In conclusion, the findings of this study offer valuable insights for optimizing deep reservoir fracturing processes in scenarios where natural fractures play a vital role in shaping fracture development.

Quantitative characterization and fracture morphology in reservoirs with various lithologies: An experimental investigation

Accurately quantifying the development of hydraulic fractures is pivotal for further elucidating the relationship between reservoir physical properties and hydraulic fracture propagation. In this research, we centered on reservoirs featuring diverse lithologies, procured downhole full-diameter cores, conducted triaxial hydraulic fracturing experiments, and employed CT scanning and electron microscopy to characterize fracture morphology. The primary findings are summarized as follows: sandstones specimens typically exhibit bi-wing fractures inclined at a certain angle to σH, with internal microfractures predominantly comprised of corrugated shear fractures traversing mineral grains. Conversely, conglomerate specimens display a higher prevalence of branching fractures, with fracture zones forming in areas of gravel densities and weak heterogeneous matrices, along with the development of multiple microfractures. Volcanic rock specimens fractures primarily propagate via deflection following NF activation, showcasing two modes of microfracture propagation: through and alongside the NF. Quantitative parameters of fracture morphology indicate that the fractal dimension ranges from 2.02 to 2.08 for sandstone fractures, 2.19 to 2.22 for conglomerate fractures, and 2.11 to 2.13 for volcanic rock fractures. Notably, the NF filler in volcanic rock undergoes erosion by fracturing fluid, accumulating non-uniformly on the surface of rock crystals, thereby augmenting fracture tortuosity. Additionally, the fracture surface area of conglomerates surpasses that of sandstones and volcanic rocks by 1.3 times, with the stripping rate of conglomerate fracture surfaces exceeding 10%. Furthermore, the average normal width of conglomerate fractures surpasses 2 mm, whereas volcanic rock and sandstone measure 1.6 mm and 1.1 mm, respectively. Notably, sandstone fractures exhibit uniform normal width distribution, while conglomerate fractures, especially those around gravels and eroded by fracturing fluid, manifest larger widths. Moreover, NF influenced volcanic rock fractures also exhibit wider widths. Elucidating the quantitative attributes of fracture morphology in lithologically diverse reservoirs holds significant implications for formulating hydraulic fracturing and targeted optimization strategies aimed at enhancing fracturing efficacy.

Hydraulic fracture initiation and propagation in deep coalbed methane reservoirs considering weak plane: CT scan testing

Hydraulic fracturing technology in coal reservoirs helps increase coalbed methane (CBM) production, and the development of hydraulic fractures (HFs) is influenced by in situ stress and original fractures. Therefore, in this study, triaxial HF tests and computed tomography (CT) were used to determine HF initiation and propagation in coal, considering weak structural planes and in situ stress. The experimental results show that weak structural planes control HF initiation and propagation in coal under a deep-stress environment. Most HFs occurred along bedding planes, followed by exogenetic fractures. The influence of the horizontal stress difference coefficient k, which is equal to the maximum horizontal stress minus the minimum horizontal stress and divided by the minimum horizontal stress, on the propagation of the HF was studied. When k increases to 1.04, the HF becomes perpendicular to the direction of the minimum principal stress. When k < 1.04, the main controlling factor of HF propagation is a weak structural plane, and when k ≥ 1.04, the main controlling factor of HF propagation is in situ stress. Based on the CT reconstruction model, the average aperture distributions of the discrete bedding fractures and exogenetic fractures of coal in this experiment were calculated to be 0.0947 mm and 0.1940 mm, respectively. This determines the different strength properties of exogenetic fractures and bedding planes, and determines the priority initiation position of HF in coal. During the HF initiation and propagation, the average energy along the exogenous fracture was lower than that along the bedding planes. On this basis, this study predicts that the main factor controlling HF propagation in a deep coal seam in the Qin-Shui Basin, China, is the weak structural plane in the coal seam.

Integrated multipole acoustic modeling and processing in general stressed formations, Part 2: A well case study

Stress-induced borehole multipole waveform characterization and processing interpretation are critical for borehole stabilization and hydraulic fracturing development. In the first paper (Part 1), an effective approach was presented to simulate the multipole acoustic responses of a stressed formation. In this second paper (Part 2), the objective is to analyze the shear (S)-wave slowness and anisotropy processing methods for stressed formations using the borehole acoustic logging data from the Mesopotamia Basin, Iraq. An integrated approach for evaluating acoustic slowness and anisotropy is presented. This approach combines a time-domain controlled slowness-time-coherence (TCSTC) method for the monopole logging, waveform inversion and frequency-domain processing methods for the four-component (4C) data from the cross-dipole acoustic logging measurement, to provide an overall assessment of acoustic characteristics around borehole under stress. The results of single depth point and interval data processing demonstrate that the proposed TCSTC can be well applied to the slowness extraction of monopole fast and slow shear waves, especially in the case of fast formation where the slowness of fast and slow transverse waves is difficult to distinguish. Meanwhile, the anisotropy results show that stress-induced S-wave anisotropy results from dipole logging data based on frequency domain processing methods are generally larger than those from dipole and monopole logging data based on time domain methods. Integrating the slowness results of the fast and slow shear waves extracted from the monopole and dipole measurements allows us to assess the velocity variations at radial distances along the borehole under stress, which can be well interpreted using the radial shear-wave velocity profile. A potential limitation of this integration approach is the need for analysis of acoustic multipole logging data, which can be available as part of routine logging measurements. The processing and analysis results can be used as a guideline for understanding and interpreting acoustic measurements in stressed formations.

Study on formation process and reservoir damage mechanism of blockages caused by polyacrylamide fracturing fluid in production wells

In the process of the large-scale hydraulic fracturing development in oil and gas fields, reservoir damage caused by polymer fracturing fluid is inevitable. The real oil and gas field reservoir conditions make the causes of reservoir damage more complicated, and few reports have provided an in-depth analysis of the composition and structure of actual blockages generated in production wells after hydraulic fracturing. In this work, we innovatively obtained reservoir blockages from production wells after fracturing in oil and gas fields, analyzed their physical and chemical properties by SEM, XRD, IR and other methods, then reproduced the blockages formation process in the laboratory through ampoule aging experiments, and evaluated their impact on the reservoir damage rate and fracture flow capacity by core flow physical simulation experiments. The results indicate that the blockages primarily consist of polyacrylamide and iron ions complexes. For the formation process of blockages, the gel breaker solution will release iron ions after reacting with iron calcite existed in the reservoir. The carboxyl group of polyacrylamides and Fe3+ ions can further form highly stable -(COO)3Fe bonds. The physical simulation results revealed that the generation of Fe3+ ions significantly enhanced the extent of reservoir damage and reduction rate of fracture conductivity associated with polyacrylamide fracturing fluid. In addition, after complete gel breaking, the weak interactions between the short-chain molecular groups and Fe3+ ions result in limited molecular flocculation and entanglement, leading to the reduction in reservoir damage. By identifying the specific formation causes of blockages, we revealed the reservoir damage mechanism from a novel perspective, which is of great significance for guiding the development of low damage fracturing fluid system and further improving oil and gas recovery.

Characteristics of hydraulic fracture penetration behavior in tight oil with multi-layer reservoirs

The tight oil reservoirs of Fuyang and Gaotaizi in the Daqing Oilfield exhibit characteristics such as thin layers and distributed barriers, which pose challenges for maintaining drilling accuracy within the desired geological sweet spot. Hydraulic fracturing has emerged as the optimal method to connect production wells with target layers effectively. Understanding the behavior of hydraulic fracture propagation in multiple thin layers with significant differences in mechanical properties is crucial for assessing the extent of effective drainage. In this study, a finite element numerical simulation model incorporating cohesive elements is employed to investigate and quantify the effects of stress differences and rock mechanical parameters on fracture penetration. The results indicate that the stress difference between the reservoir and barrier layers plays a key role in controlling hydraulic fracture penetration and height. Moreover, the flow rate and viscosity of the fracturing fluid have a noticeable impact on fracture progression. Hydraulic fractures tend to propagate along the interface of layers with low flow rate and fluid viscosity, thereby hampering the penetration performance in those layers. To achieve a comparable penetrated fracture length in low permeability reservoirs, it is necessary to increase the volume of fracturing fluid in high permeability reservoirs. Furthermore, the barriers layers, which possess relatively weaker mechanical properties, can constrain the width development of hydraulic fractures. This limitation may result in the risk of excessive liquid without sufficient proppant (commonly known as “over liquid but no sand”). Therefore, appropriate measures should be implemented to increase the net pressure and avoid encountering this complex situation.

Combined finite-discrete element modelling of hydraulic fracturing in reservoirs with filled joints

Hydraulic fracturing (HF) is known to be the most effective stimulation to enhance fractured reservoir permeability. The efficiency of an HF fluid injection largely depends on the pre-existing discontinuities or sources of heterogeneities. These features need to be considered in an HF operation design. Amongst these features, rock masses with filled joints are largely ignored despite their presence in deep rocks. This study focuses on HF development in such ground conditions and simulates their hydro-mechanical behavior by using the combined finite-discrete element method (FDEM), which is fully capable of modelling HF propagation in heterogeneous rocks. First, the interaction mechanism between an HF and a closed joint with approaching angles of 30, 60, and 90° is studied. The influences of flow rate, fluid kinematic viscosity, and confining in-situ stresses are evaluated. Then models with a single filled joint with approaching angles of 30, 60, and 90° are studied, interaction types explored, and failure types revealed by varying flow rate, fluid kinematic viscosity, and in-situ stresses. Having explored the interaction mechanism between an HF and a filled joint, three models with complex joint sets are considered; Voronoi filled joint, orthogonal filled joints, and randomly distributed discrete fracture networks (DFNs). The results show a complex interaction mechanism between the HFs and the filled joints. It is revealed that increasing approaching angle, flow rate, or fluid kinematic viscosity causes the development of more shear failure than tensile in models with Voronoi or orthogonal filled joints. However, it is shown that HF's interaction with the DFN is minimal and tensile failure governs considerably.

Изучение изменений структуры пустотности горных пород при создании напряженного состояния методами электронной микроскопии

On the example of an oil deposit of the Vereisk age which is one of the deposits in the Volga-Urals, lithotypes of rocks are distinguished, characterized by a fundamentally different structure of the void space. For selected lithotypes experiments were carried out on core samples with a change in the stress state of rocks under conditions of volumetric (pseudo-triaxial) compression. The pressure created in the experiments is identified with the development of processes at a distance from the epicenter of the hydraulic fractures appearance. Core samples were studied before and after exposure by non-destructive testing methods. The study of the sample structures by standard and tomographic methods did not allow us to establish significant changes during loading of the samples. At the same time, some increase in rock permeability was established in experiments. With this in mind, the samples were studied according to a technique specially developed by the authors using electron microscopy. The use of microscopic studies made it possible to obtain quantitative information about the change in the void space at a level inaccessible to X-ray tomography. As a result, it was found that both for potential reservoirs and for impermeable rocks, there is an increase in the length and opening of pre-existing fractures, which can be considered as the formation of additional effective fluid filtration channels. The experiments performed have changed the idea of ​​the process of hydraulic fracture development and can be used in geological and technological calculations.

Combined finite-discrete element modelling of hydraulic fracturing in deep geologically complex reservoirs

Hydraulic fracturing is known to be one of the most effective stimulation techniques to enhance reservoir permeability. A hydraulic fracture (HF) fluid injection's efficiency largely depends on the pre-existing sources of heterogeneities. Amongst these features, conglomerate reservoirs containing blocks in a matrix and rock masses with filled joints are largely ignored despite their presence in deep rocks. This study focuses on the HF development in such reservoir conditions using the combined finite-discrete element method (FDEM). First, the capabilities of the FDEM are verified against available analytical solutions and experimental data. The influence of a single or multiple types of blocks is studied in the conglomerate models. Various controlling parameters including in-situ stresses, flow rate, fluid viscosity, directional HF (DHF), distance between the injection points, properties of the block and matrix interface are considered, and their effects on the hydraulic fracturing path are investigated. In the second scenario, the effect of the joints' filling material is studied, models containing randomly distributed filled joints are built and several controlling factors including different filling materials, angle of approach, in-situ stresses, flow rate and fluid viscosity are considered. The analysis results show a significant influence of both blocks in the matrix and filled joints on the HF pattern. The HF interaction with these features is shown to be complex, and six interaction types for the blocks and nine interaction types for the filled joints are identified based on the close examination of the results.

Coupled Thermo-hydro-mechanical Simulation of Hydraulic Fracturing in Deep Reservoirs Using Finite-Discrete Element Method

Hydraulic fracturing (HF) is one of the most effective stimulation techniques to enhance reservoir permeability. The efficiency of an HF fluid injection depends on the pre-existing discontinuities or sources of heterogeneities and these features need to be considered in a HF operation treatment. Moreover, deep reservoirs are usually located in hot dry rocks (HDR). Hence, thermal conduction through the rock and fluid and advection and convective heat transfer in the fluid can affect the fluid–rock interaction. This study focuses on HF development in deep reservoirs under a high-temperature field. Two separate scenarios are considered: a reservoir containing discrete fracture networks (DFN) and another considering blocks in a matrix as conglomerate reservoirs (there is no relation between the scenarios considered). The study discusses each reservoir separately and simulates their thermo-hydro-mechanical (THM) behaviour using the combined finite-discrete element method (FDEM). First, the capabilities of the FDEM are verified against the existing analytical solutions, and then the FDEM is employed to model HF development. The effects of controlling factors, including flow rate, fluid kinematic viscosity and DFN aperture for jointed reservoirs and flow rate, fluid kinematic viscosity and block strength in conglomerate ones, are studied. The results show that the high fracture density DFNs strongly affect the HF propagation pattern and fluid pressure rise. Moreover, the DFN’s aperture significantly alters the HF treatment behaviour. The controlling factors are observed to influence the HF pattern strongly, and a successful HF treatment requires careful consideration of all the factors. In the conglomerate reservoirs, the strength of the blocks strongly dominates the HF mechanism, in which soft blocks break and allow for uniform fluid pressure distribution and longer HFs, while hard blocks stop fluid from flowing over longer distances accumulating high fluid pressure around the injection. This mechanism excessively breaks the matrix and reduces HF efficiency. Crack branching frequently occurs in conglomerate reservoirs due to thermal exchange between the blocks, matrix, and fluid.

Present-Day In Situ Stress Analysis in Shale Reservoir of Haiba Block, Southern Sichuan Basin, South China

Natural gas from shale gas reservoirs has been an important contributor for reserve growth, deliverability construction, and profits growth in natural gas industry in the world. Hydraulic fracturing is commonly required in the shale gas commercial development, and thus understanding the present-day in situ stress field is greatly significant for the hydraulic fracturing and efficient development in shale gas reservoirs. However, there are no systematic investigations on the present-day in situ stress field in the Haiba Block from the Sichuan Basin, South China. In this study, the present-day in situ stress orientations and magnitudes in shale reservoir of Haiba Block are investigated based on the well interpretations from borehole image log and geomechanical modeling. Then, the effects of stresses on hydraulic fracturing, horizontal wells, and natural fracture reactivation were discussed. The results indicate that the horizontal maximum principal stress (SHmax) orientation is mainly in the NE-SW-trending, NW-SE-trending, and WNW-ESE-trending in the Haiba Block. The magnitudes of horizontal maximum and minimum principal stresses are 13.5 MPa~85.5 MPa and 2.8 MPa~31.6 MPa, respectively. In the Haiba Block, the differential stress is generally low in the northern part, which indicates that complex hydraulic fracture networks may be produced. While the natural fractures are generally stable under the present-day in situ stress field. When the increase of pore pressure gradient is about 30 KPa/m, nearly all natural fractures in the Longmaxi Formation may be reactivated. The results can provide the insights into a better understanding of the present-day in situ stress distribution so as to optimize perforation orientation, hydraulic fracturing design, and enhance gas production in shale gas reservoirs.

Hydraulic fracture development in conglomerate reservoirs simulated using combined finite-discrete element method

Hydraulic fracturing is known to be the most effective stimulation to enhance fractured reservoir permeability by creating hydraulic fractures (HFs). The efficiency of a HF fluid injection largely depends on the pre-existing discontinuities or sources of heterogeneities. These features need to be considered in a HF operation design. Amongst these features, conglomerate reservoirs containing blocks in a matrix are largely ignored despite their presence in deep rocks. This study focuses on the HF development in such grounds and simulates their hydro-mechanical behaviour by using the combined finite-discrete element method (FDEM), which is fully capable of modelling HF propagation in heterogeneous rocks. First, the capabilities of the FDEM are verified against existing analytical solutions and experimental fluid injection and then employed to model HF development. In the conglomerate models, three blocks with low to high strength properties are simulated to assess the effect of block strength on the HF development pattern. Various controlling parameters, including in-situ stresses, flow rate, fluid kinematic viscosity, directional HF (DHF), properties of the interface between the blocks and matrix, and their effects on the HF path are investigated. The results show a significant influence of blocks in a matrix on the HF pattern. The HF interaction with the blocks of different shapes and dimensions is shown to be complex, and six interaction types for the blocks are identified based on the close observation of the results. It is also found that to achieve a successful HF injection in such grounds, a low flow rate with a low viscous fluid can be a good strategy. Also, it is shown that the blocks' strength significantly affects the type of failure (tensile or shear) and the breakdown pressure.

Rate-transient analysis for estimating the linear flow parameters of communicating wells using the dynamic drainage area (DDA) concept

Development of unconventional reservoirs using multi-fractured horizontal wells (MFHWs) has led to closer well and hydraulic fracture spacing. Tighter placement of MFHWs has consequently led to increased instances of well interference, particularly through hydraulic fractures. In addition to possible problems posed for development, fracture communication that persists during production complicates rate-transient analysis (RTA) because models/methods for RTA have mostly been developed for single-well analysis. Availability of RTA methods specifically developed for communicating wells can reduce errors associated with hydraulic fracture and reservoir characterization and can lead to improved decision making.A semi-analytical method for history matching MFHWs communicating through hydraulic fractures has recently been developed using the dynamic drainage area (DDA) concept. In the current work, the DDA concept is employed to develop a new straight-line analysis (SLA) method for the transient linear flow regime that can be applied to two communicating MFHWs. The change in the drainage area of a single well due to communication challenges the use of the DDA concept. However, when the second well comes on production, reinitialization of the calculations for the first well helps to facilitate the implementation of the DDA concept.The new DDA-corrected RTA (SLA) method for communicating wells is verified against the results of numerical simulation. Several synthetic cases are generated using numerical simulation to verify the accuracy of the developed method using various reservoir/fracture properties. The new method applied to the simulated cases allows the fracture half-length (xf) to be estimated within 10% of simulation model input. The DDA-corrected RTA method has also been applied to a field dataset, previously analyzed by the authors using the DDA approach to history match well production data. This dataset consists of six wells, drilled into two separate reservoir layers (three wells per layer) and from two adjacent pads, which exhibit strong well-pair communication. For this dataset, the calculated linear flow parameters for these wells are compared. The results demonstrate that there is a difference between the linear flow parameters of wells completed in the upper layer and lower layers, which could be attributed to either differences in effective fracture area or permeability.This new approach can help practitioners quickly and accurately estimate reservoir and fracture properties in these scenarios. The method can therefore be used to improve hydraulic fracture design, well forecasting and development planning where persistent well communication through hydraulic fractures is occurring.

Effect of In-Situ Stress on Hydraulic Fracturing of Tight Sandstone Based on Discrete Element Method

The tight sandstone reservoir in the Qianfoya formation of well PL-3 of the Puguang gas field in Sichuan, China, obtained a high-yield gas flow after a volume fracturing treatment. However, the stimulated reservoir volume (SRV), fracture morphology, scale and formation law still remain unclear. Based on particle flow discrete-element theory in this paper, we carried out a few trials of the Brazilian splitting test, uniaxial compression and triaxial compression of rock mechanics. Meanwhile, the research also testified to the conversion relationship between macroparameters and microparameters, established the numerical simulation on hydraulic fracturing through PFC2D discrete element software, and finally analyzed the influence of difference coefficients on the fracturing effect, in terms of different in-situ stresses. The conclusions are as follows: firstly, the influence of in-situ stress is essential for the direction, shape and quantity of fracture propagation, and the fractures generated by hydraulic fracturing are mainly tension fractures, accounting for over 90% of the total longitudinal fractures. Secondly, it is indicated that when the difference coefficient is small in the in-situ stress, the fractures formed by hydraulic fracturing expand randomly around the wellbore. When the difference coefficient Kh of in-situ stress is above 0.6, the development of hydraulic fractures is mainly controlled by in-situ stress; as a result, the fractures tend to expand in the vertical direction of the minimum horizontal principal stress and the fracture shape is relatively singular. When the difference coefficient of in-situ stress was 0.3, in total, 3121 fractures were generated by fracturing, and the fractal dimension D value of the fracture network complexity was 1.60. In this case, this fracturing effect was the best and it is the easiest to achieve for the purpose of economical and effective development on large-scale volume fracturing.

Association Between Residential Proximity to Hydraulic Fracturing Sites and Adverse Birth Outcomes

The association between hydraulic fracturing and human development is not well understood. Several studies have identified significant associations between unconventional natural gas development and adverse birth outcomes; however, geology and legislation vary between regions. To examine the overall association between residential proximity to hydraulic fracturing sites and adverse birth outcomes, and investigate whether well density influenced this association. This population-based retrospective cohort study of pregnant individuals in rural Alberta, Canada, took place from 2013 to 2018. Participants included reproductive-aged individuals (18-50 years) who had a pregnancy from January 1, 2013, to December 31, 2018, and lived in rural areas. Individuals were excluded if they lived in an urban setting, were outside of the age range, or were missing data on infant sex, postal code, or area-level socioeconomic status. Oil and gas wells that underwent hydraulic fracturing between 2013 to 2018 were identified through the Alberta Energy Regulator (n = 4871). Individuals were considered exposed if their postal delivery point was located within 10 km of 1 or more wells that was hydraulically fractured during 1 year preconception or during pregnancy. Outcomes investigated were spontaneous and indicated preterm birth, small for gestational age, major congenital anomalies, and severe neonatal morbidity or mortality. After exclusions, the sample included 26 193 individuals with 34 873 unique pregnancies, and a mean (SD) parental age of 28.2 (5.2) years. Small for gestational age and major congenital anomalies were significantly higher for individuals who lived within 10 km of at least 1 hydraulically fractured well after adjusting for parental age at delivery, multiple births, fetal sex, obstetric comorbidities, and area-level socioeconomic status. Risk of spontaneous preterm birth and small for gestational age were significantly increased in those with 100 or more wells within 10 km. Results suggest that individuals who were exposed to hydraulic fracturing within pregnancy may be at higher risk of several adverse birth outcomes. These results may be relevant to health policy regarding legislation of unconventional oil and gas development in Canada and internationally.

Effect of hydration on Pore Structure and Physical Properties of Permian Basalt and tuff in Sichuan Basin during pressurized imbibition

The volcanic rock with developed pores is important reservoir for oil and gas, but its complex pore-fracture structural characteristics lead to the hydration reaction when the volcanic strata is invaded by drilling fluid or fracturing fluid, which brings great challenges to the drilling operation and oil and gas production in volcanic rock reservoir. In order to understand the influence of clay hydration on the pore characteristics and permeability of different types of volcanic reservoirs. In this paper, we selected distilled water as the imbibition solution, and obtained the variation law of pore structure and physical properties of Permian tuff and basalt in Sichuan Basin during pressurized imbibition through a series of indoor test methods. The results show that the clay content of tuff is high, and the clay hydration produces new cracks during soaking, which leads to the increase of nuclear magnetic porosity of tuff after soaking. At the same time, it also makes some unconnected pores connected with each other, resulting in the increase of rock permeability in the later stage of soaking. During soaking, mineral particles peel off, and some clay minerals are transported to pores and fractures under hydrodynamic action, resulting in the reduction of effective porosity of tuff. The basalt is dense with poor physical properties. There are almost no cracks in the rock soaked for 0–24 h. After soaking for 48 h, new cracks are generated in the rock, which may be caused by the increase of pore pressure in the rock. The mineral particles around the crack obviously fall off and block the pore throat, resulting in the reduction of rock permeability after soaking. This study provides not only helps for avoiding the occurrence of lost circulation, well collapse and other accidents, efficient and safe drilling, but also a theoretical basis for the development of hydraulic fracturing in volcanic reservoirs.

Особенности проведения гидроразрыва пласта в отложениях с трудноизвлекаемыми запасами

Introduction. When developing productive deposits containing hard-to-recover oil reserves, the main difficulty is associated with low values of the reservoir properties of the reservoirs and their significant heterogeneity. The use of hydraulic fracturing technology allows solving these problems by increasing the well drainage area, and also as a means of intensifying production. Materials and methods of research. The study of the process of hydraulic fracture development in the deposits of the Bazhenov formation in a vertical well showed that when water is injected, long narrow fractures are formed in the formation, their filling with subsequent supply of a fracturing fluid with proppant leads to an increase in the width and height of the created fracture. Due to the hydrophobic properties and increased brittleness of the rocks of the Bazhenov formation, an effect similar to hydraulic fracturing is also possible during the injection of water into the formation at high pressures, for example, when organizing a waterflooding system. Another direction is multi-zone hydraulic fracturing. The advantage of this method is the greater distribution of fractures over the area compared to point hydraulic fracturing operations. Results and Discussion. On the deposits of the Bazhenov formation, pilot work was carried out to create artificial fracturing by pumping water. The positive effect was expressed in a twofold increase in oil recovery in the pilot area. As a negative side effect, a sharp increase in water cut was noted. The experience of using multi-zone hydraulic fracturing in the conditions of the Bazhenov formation was considered on the example of the deposits of the Surgut arch. The dynamics of flow rates and cumulative oil production by wells during operation is presented. Also, a comparison was made of the main performance indicators of wells with multi-stage hydraulic fracturing with the average indicators of directional wells of the same fields. Conclusion. The pilot work conducted on water injection into the Bazhenov formation deposits unambiguously showed that additional fracturing is formed in the reservoir and the volume of additional fractured capacity is directly proportional to the volume of injected water. The experience of using multi-zone hydraulic fracturing revealed the advantages of this technology compared to directional wells. Under conditions of reservoir reservoir properties uncertainty, the creation of artificial conductivity using hydraulic fracturing may be the only way to ensure well productivity. MSHF in horizontal wells forms a system of fractures in a large volume and seems to be more effective in such conditions compared to conventional hydraulic fracturing.

Directional hydraulic fracturing (DHF) using oriented perforations: The role of micro-crack heterogeneity

This study presents numerical investigations about the role of micro-crack heterogeneity in hydraulic fracture (HF) development and directional hydraulic fracturing (DHF) creation. By comparing the results of heterogeneous models (named DFN models) with the associated homogeneous models, the behavior is categorized into three modes: DFN models, which consume more (A), comparable (B), and much lower (C) energy than the associated homogeneous models. Variation of micro-crack distributions, which determines HFs interaction in the stress shadow zone, contributes to the difference in HF morphologies and injection energy consumption. The connection process, where one HF connects the other, predominates the energy cost in the DHF. Offset-related interactions usually occur between HFs and DFN in case of favorable distribution of micro-cracks, which guides the HFs to propagate through the interaction zone, thus favoring the connection process and improving the DHF efficiency. Adverse distribution of local cracks (even a single crack) with dilation-related interactions near the connection zone can produce extremely high stress due to the opening of the cracks, which significantly deteriorates the connection process and reduces the DHF efficiency. Therefore, a limited variation of crack distribution near the connection zone could cause a pronounced effect on HF connection and the associated energy consumption. Due to the limited sizes and shear slips of the micro-cracks in these simulations, deformation energy and fracture energy dissipation dominate the energy conversion during the injection, while frictional energy consumption plays a secondary role. The two-stage injection strategy can be a promising method to weaken the stress shadow effect, i.e., subsequent HFs extend directly to the previous one by taking advantage of the stress state produced in the first stage. The frictional resistance of micro-cracks also plays a significant role in DHF creation. Weak cracks allow the HFs to go through the interaction zone and avert the strict connection process, consequently improving the DHF efficiency.

Advances and challenges in hydraulic fracturing of tight reservoirs: A critical review

The hydraulic fracturing technology has been widely utilized to extract tight resources. Hydraulic fracturing involves rock failures, complex fracture generation, proppant transport and fracture closure. All these behaviors affect the productivity of fractured wells. In this work, the advances and challenges in hydraulic fracturing development of tight reservoirs are summarized from following aspects: the hydraulic fracture propagation, the proppant transport and distribution in hydraulic fractures, the calculation of hydraulic fracture conductivity, and productivity and/or pressure analysis model of multi-stages fractured horizontal wells. Current fracture propagation simulation methods generate only limited propagation paths and cannot truly reflect the complexity of the propagation. The current proppant migration and distribution research is mainly focused on indoor experimental studies of proppant migration in a single fracture or branched fracture, and simulation studies on proppant migration and distribution in a small-scale single slab fracture. Whereas fractures formed after hydraulic fracturing in tight reservoirs are generally complicated. There is a lack of models for calculating complex fracture conductivity that take into consideration the effect of proppant placement and proppant distribution in fractures, fracture surface roughness and dissolution, diffusion, deposition, elastic embedding, and creep caused by stress. The productivity models of fractured horizontal wells are mostly conducted based on the original reservoir fluid saturation and pressure distribution. Most of the studies are focused only on one aspect of the fracturing process. Predications of well performance after fracturing based on these studies are often inconsistent with actual field data. The paper also discusses the future research directions of fracturing in tight reservoirs and the results may be used to promote the development of tight reservoirs.

Analysis of Natural Hydraulic Fracture Risk of Mudstone Cap Rocks in XD Block of Central Depression in Yinggehai Basin, South China Sea

The Yinggehai Basin is an important Cenozoic gas bearing basin in the South China Sea. With the gradual improvement of gas exploration and over-development in shallow layers, deep overpressured layers have become the main target for natural gas exploration. There are no large-scale faults in the strata above the Meishan Formation in the central depression, and hydraulic fracturing caused by overpressure in mudstone cap rocks is the key factor for the vertical differential distribution of gas. In this paper, based on the leak-off data, pore fluid pressure, and rock mechanics parameters, the Fault Analysis Seal Technology (FAST) method is used to analyze the hydraulic fracture risk of the main mudstones in the central depression. The results show that the blocks in the diapir zone have been subjected to hydraulic fracturing in the Huangliu cap rocks during the whole geological history, and the blocks in the slope zone which is a little distant from the diapirs has a lower overall risk of hydraulic fracture than the diapir zone. In geological history, the cap rocks in slope zone remained closed for a longer time than in diapir zone and being characterized by the hydraulic fracture risk decreases with the distance from the diapirs. These evaluation results are consistent with enrichment of natural gas, which accumulated in both the Yinggehai Formation and Huangliu Formation of the diapir zone, but it only accumulated in the the Huangliu Formations of the slope zone. The most reasonable explanation for the difference of the gas reservoir distribution is that the diapirs promote the development of hydraulic fractures: (1) diapirism transfers deep overpressure to shallow layers; (2) the small fault and fractures induced by diapir activities weakened the cap rock and reduced the critical condition for the natural hydraulic fractures. These effects make the diapir zone more prone to hydraulic fracturing, which are the fundamental reasons for the difference in gas enrichment between the diapir zone and the slope zone.