Multiscale Fracture Research Articles

Quantitative multiparameter prediction of fault-related fractures: a case study of the second member of the Funing Formation in the Jinhu Sag, Subei Basin

In this paper, the analysis of faults with different scales and orientations reveals that the distribution of fractures always develops toward a higher degree of similarity with faults, and a method for calculating the multiscale areal fracture density is proposed using fault-fracture self-similarity theory. Based on the fracture parameters observed in cores and thin sections, the initial apertures of multiscale fractures are determined using the constraint method with a skewed distribution. Through calculations and statistical analyses of in situ stresses in combination with physical experiments on rocks, a numerical geomechanical model of the in situ stress field is established. The fracture opening ability under the in situ stress field is subsequently analyzed. Combining the fracture aperture data and areal fracture density at different scales, a calculation model is proposed for the prediction of multiscale and multiperiod fracture parameters, including the fracture porosity, the magnitude and direction of maximum permeability and the flow conductivity. Finally, based on the relationships among fracture aperture, density, and the relative values of fracture porosity and permeability, a fracture development pattern is determined.

A new method of multi-scale fracture identification in tight gas sandstone reservoir

ABSTRACTIdentification of fractures is an important guide for the selection of well location as well as improvement of single-well recovery. In this paper, large-scale fractures of Su 48 block (target well) located in Sulige gas field were predicted using the coherence, curvature and anti-tracking analysis while small-fractures prediction were performed using R/S fractal statistical method. The observations revealed that, development of large-scale fractures were not that significant, whilst those of a smaller scale were distributed across the near-wellbore formation constituted of mudstone. Moreover, predicted results using the multi-scale fusion fracture developed model showed good agreement of the existence of fractures during horizontal well drilling in real time. Furthermore, the predicted fractures matched well with those observed in the field. Hence, reflecting the significance of tight gas sandstone reservoir fracture identification method.

An Efficient Numerical Hybrid Model for Multiphase Flow in Deformable Fractured-Shale Reservoirs

Summary After hydraulic fracturing, a shale reservoir usually has multiscale fractures and becomes more stress-sensitive. In this work, an adaptive hybrid model is proposed to simulate hydromechanical coupling processes in such fractured-shale reservoirs during the production period (i.e., the hydraulic-fracturing process is not considered and cannot be simulated). In our hybrid model, the single-porosity model is applied in the region outside the stimulated reservoir volume (SRV), and the matrix and natural/induced fractures in the SRV region are modeled using a double-porosity model that can accurately simulate the matrix/fracture fluid exchange during the entire transient period. Meanwhile, the fluid flow in hydraulic fractures is modeled explicitly with the embedded-discrete-fracture model (EDFM), and a stabilized extended-finite-element-method (XFEM) formulation using the polynomial-pressure-projection (PPP) technique is applied to simulate mechanical processes. The developed stabilized XFEM formulation can avoid the displacement oscillation on hydraulic-fracture interfaces. Then a modified fixed-stress sequential-implicit method is applied to solve the hybrid model, in which mixed-space discretization [i.e., finite-volume method (FVM) for flow process and stabilized XFEM for geomechanics] is used. The robustness of the proposed model is demonstrated through several numerical examples. In conclusion, several key factors for gas exploitation are investigated, such as adsorption, Klinkenberg effect, capillary pressure, and fracture deformation. In this study, all the numerical examples are 2D, and the gravity effect is neglected in these simulations. In addition, we assume there is no oil phase in the shale reservoirs, thus the gas/water two-phase model is used to simulate the flow in these reservoirs.

Multi-scale fracture damage associated with underground chemical explosions

Understanding rock damage induced by explosions is critical for a number of applications including the monitoring and verification of underground nuclear explosions, mine safety issues, and modeling fluid flow through fractured rock. We use core observations, televiewer logs, and thin section observations to investigate fracture damage associated with two successive underground chemical explosions (SPE2 and SPE3) in granitic rock at both the mesoscale and microscale. We compare the frequency and orientations of core-scale fractures, and the frequency of microfractures, between a pre-experiment core and three post-experiment cores. Natural fault zones and explosion-induced fractures in the vicinity of the explosive source are readily apparent in recovered core and in thin sections. Damage from faults and explosions is not always apparent in fracture frequency plots from televiewer logs, although orientation data from these logs suggests explosion-induced fracturing may not align with the pre-existing fracture sets. Core-scale observations indicate the extent of explosion-induced damage is 10.0 m after SPE2 and 6.8 m after SPE3, despite both a similar size and location for both explosions. At the microscale, damage is observed to a range distance of 10.2 ± 0.9 m after SPE2, and 16.6 ± 0.9 and 11.2 ± 0.6 in two different cores collected after SPE3. Additional explosion-induced damage, interpreted to be the result of spalling, is readily apparent near the surface, but only in the microfracture data. This depth extent and intensity of damage in the near-surface region also increased after an additional explosion. This study highlights the importance of evaluating structural damage at multiple scales for a more complete characterization of the damage, and particularly shows the importance of microscale observations for identifying spallation-induced damage.

A Semianalytical Method for Modeling Two-Phase Flow in Coalbed-Methane Reservoirs With Complex Fracture Networks

Summary Coalbed-methane (CBM) reservoirs are naturally fractured formations with cleats surrounding the coal matrix. Analyzing and predicting CBM-production performance is challenging, especially for early-time production, because of the complex fracture networks and gas/water two-phase flow. In this study, we develop an efficient semianalytical model to predict gas and water production in CBM reservoirs with multiscale fracture networks. The activated large-scale or interconnected cleats and hydraulic fractures are modeled explicitly as discretized segments with connected nodes. The small-scale cleats and disconnected natural fractures are described implicitly as “enhanced matrix permeability.” We incorporate critical gas-flow mechanisms and stress sensitivity of the fracture network in the model. The two-phase-flow mechanism is considered by iteratively correcting the relative permeability to gas/water for each fracture segment and capillary pressure at each node with the reservoir depletion. We verified the model against a numerical reservoir simulator, field data, and an analytical solution. Subsequently, we apply the model to quantify the effects of fracture-network complexity/connectivity and stress sensitivity on gas/water-production behavior. This work presents an accurate and fast semianalytical model to perform two-phase flow of gas and water in CBM wells with complex fracture networks. The approach is easier to set up and less data-intensive than using a numerical reservoir simulator, and more flexible in handling the complex-fracture networks than full analytical models. This method provides a promising technique for better understanding the effect of the cleats and fracture networks present in CBM reservoirs on gas and water production.

An efficient hydro-mechanical model for coupled multi-porosity and discrete fracture porous media

In this paper, a numerical model is developed for coupled analysis of deforming fractured porous media with multiscale fractures. In this model, the macro-fractures are modeled explicitly by the embedded discrete fracture model, and the supporting effects of fluid and fillings in these fractures are represented explicitly in the geomechanics model. On the other hand, matrix and micro-fractures are modeled by a multi-porosity model, which aims to accurately describe the transient matrix–fracture fluid exchange process. A stabilized extended finite element method scheme is developed based on the polynomial pressure projection technique to address the displacement oscillation along macro-fracture boundaries. After that, the mixed space discretization and modified fixed stress sequential implicit methods based on non-matching grids are applied to solve the coupling model. Finally, we demonstrate the accuracy and application of the proposed method to capture the coupled hydro-mechanical impacts of multiscale fractures on fractured porous media.

Physics-preserving averaging scheme based on Grünwald-Letnikov formula for gas flow in fractured media

The heterogeneous natures of rock fabrics, due to the existence of multi-scale fractures and geological formations, led to the deviations from unity in the flux-equations fractional-exponent magnitudes. In this paper, the resulting non-Newtonian non-Darcy fractional-derivatives flux equations are solved using physics-preserving averaging schemes that incorporates both, original and shifted, Grünwald-Letnikov (GL) approximation formulas preserving the physics, by reducing the shifting effects, while maintaining the stability of the system, by keeping one shifted expansion. The proposed way of using the GL expansions also generate symmetrical coefficient matrices that significantly reduces the discretization complexities appearing with all shifted cases from literature, and help considerably in 2D and 3D systems. Systems equations derivations and discretization details are discussed. Then, the physics-preserving averaging scheme is explained and illustrated. Finally, results are presented and reviewed. Edge-based original GL expansions are unstable as also illustrated in literature. Shifted GL expansions are stable but add a lot of additional weights to both discretization sides affecting the physical accuracy. In comparison, the physics-preserving averaging scheme balances the physical accuracy and stability requirements leading to a more physically conservative scheme that is more stable than the original GL approximation but might be slightly less stable than the shifted GL approximations. It is a locally conservative Single-Continuum averaging scheme that applies a finite-volume viewpoint.

Multiscale Fractures Characterization Based on Ant Colony Optimization and Two-Dimensional Variational Mode Decomposition

Hydrocarbon exploration in fractured reservoirs requires accurate estimates of fracture characteristics such as fracture orientations and fracture development degrees. The coherence method, which measures the degree of similarity between the multichannel seismic data, can image fractures by detecting variation anomalies in the seismic signals. However, it is weak in precisely positioning fractures and is sensitive to noise. We use an improved ant colony optimization (ACO) algorithm that adopts both coherence data and edge detection data as heuristic factor to refine the coherence data. As a distinctive time–frequency analysis method, variational mode decomposition (VMD) is a flexible method with excellent time–frequency resolution. We propose a measure factor combining mutual information and energy entropy to judge how many intrinsic mode functions to be decomposed are most suitable. Since fracture characterization is similar to image analysis, we propose a novel method combining ACO-coherence with a two-dimensional VMD (2D-VMD) to meticulously depict fractures at different scales and different directions. First, the seismic coherence data are obtained via a dip scanning coherence algorithm. Then, the coherence data are refined by the improved ACO algorithm. We extract the slice along the target stratum from the ACO-coherence data, and the slice is decomposed into different frequency band images using the 2D-VMD method. After applying the method to real seismic data from a typical fractured reservoir, it is clear that the method we propose is capable of revealing fractures at different scales and different directions with high precision.

Multiscale Fracture Analysis in a Reservoir-Scale Carbonate Platform Exposure (Sorrento Peninsula, Italy): Implications for Fluid Flow

We derive the discrete fracture network (DFN) of a Lower Cretaceous carbonate platform succession exposed at Mt. Faito (Southern Apennines), which represents a good outcrop analogue of the coeval productive units of the buried Apulian Platform in the Basilicata oilfields. A stochastic distribution of joints has been derived by sampling at two different scales of observation. At the outcrop scale, we measured fracture attributes by means of scan lines. At a larger scale, we extracted fracture attributes from a 3D model. This multiscale survey showed the occurrence of an arresting bed for through-going fractures, which is characterized by a low relative permeability, determining a vertical compartmentalization. The DFN model, obtained by integrating fieldwork and numerical modelling by means of the 3D-Move® software, shows a well-defined relationship of permeability and fracture porosity with the relative connectivity of the fracture network. The latter is influenced by the length and aperture and to a lesser extent by the fracture intensity. The permeability distribution obtained for our outcrop analogue can be used to inform modelling of the Basilicata oilfield reservoirs, although the different burial history between the exposed Apennine Platform and the buried Apulian Platform must be taken into account.

Dimensional threshold for fracture linkage and hooking

Fracture connectivity in rocks depends on spatial properties of the pattern including length, abundance and orientation. When fractures form a single-strike set, they hardly cross-cut each other and the connectivity is limited. Linkage probability increases with increasing fracture abundance and length as small fractures connect to each other to form longer ones. A process for parallel fracture linkage is the “hooking”, where two converging fracture tips mutually deviate and then converge to connect due to the interaction of their crack-tip stresses. Quantifying the processes and conditions for fracture linkage in single-strike fracture sets is crucial to better predicting fluid flow in Naturally Fractured Reservoirs. For 1734 fractures in Permian shales of the Lodève Basin, SE France, we measured geometrical parameters in 2D, characterizing three stages of the hooking process: underlapping, overlapping and linkage. We deciphered the threshold values, shape ratios and limiting conditions to switch from one stage to another one. The hook set up depends on the spacing (S) and fracture length (Lh) with the relation S ≈ 0.15 Lh. Once the hooking is initiated, with the fracture deviation length (L) L ≈ 0.4 Lh, the fractures reaches the linkage stage only when the spacing is reduced to S ≈ 0.02 Lh and the convergence (C) is < 0.1 L. These conditions apply to multi-scale fractures with a shape ratio L/S = 10 and for fracture curvature of 10°–20°.

An enhanced understanding of the Basinal Bowland shale in Lancashire (UK), through microtextural and mineralogical observations

Variability in the Lower Bowland shale microstructure is investigated here, for the first time, from the centimetre to the micrometre scale using optical and scanning electron microscopy (OM, SEM), X-Ray Diffraction (XRD) and Total Organic Carbon content (TOC) measurements. A significant range of microtextures, organic-matter particles and fracture styles was observed in rocks of the Lower Bowland shale, together with the underlying Pendleside Limestone and Worston Shale formations encountered the Preese Hall-1 Borehole, Lancashire, UK. Four micro-texture types were identified: unlaminated quartz-rich mudstone; interlaminated quartz- and pyrite-rich mudstone; laminated quartz and pyrite-rich mudstone; and weakly-interlaminated calcite-rich mudstone. Organic matter particles are classified into four types depending on their size, shape and location: multi-micrometre particles with and without macropores: micrometre-size particles in cement and between clay minerals; multi-micrometre layers; and organic matter in large pores. Fractures are categorized into carbonate-sealed fractures; bitumen-bearing fractures; resin-filled fractures; and empty fractures. We propose that during thermal maturation, horizontal bitumen-fractures were formed by overpressuring, stress relaxation, compaction and erosional offloading, whereas vertical bitumen-bearing, resin-filled and empty fractures may have been influenced by weak vertical joints generated during the previous period of veining. For the majority of samples, the high TOC (>2 wt%), low clay content (<20 wt%), high proportion of quartz (>50 wt%) and the presence of a multi-scale fracture network support the increasing interest in the Bowland Shale as a potentially exploitable oil and gas source. The microtextural observations made in this study highlight preliminary evidence of fluid passage or circulation in the Bowland Shale sequence during burial.

A Comprehensive Model Coupling Embedded Discrete Fractures, Multiple Interacting Continua, and Geomechanics in Shale Gas Reservoirs with Multiscale Fractures

Shale gas has become one of the primary energy resources during the past few years, and its impact has been profound in many countries. Hydraulic fracturing treatments are required for the development of shale gas reservoirs, and the consequent hydraulic fractures usually connect with the original small-scale natural fractures forming complex fracture networks in these reservoirs. Therefore, a model for numerical simulation, which is capable of accurately modeling naturally and hydraulically fractured reservoirs, is essential in optimization and management of such reservoirs. In this paper, we develop a comprehensive model that couples embedded discrete fractures, multiple interacting continua, and geomechanics to accurately simulate the fluid flow in shale gas reservoirs with multiscale fractures. Large-scale hydraulic fractures are described by an embedded discrete fracture method, while middle-scale and small-scale natural fractures are modeled by a multiple interacting continua method. Usually, the co...

The study on fracture network development in shale fracturing with considering capillary effect

Natural fractures widely exist in shale reservoirs with different scales, ranging from nano scale to micro scale, even to macro and engineering scale. These multi-scale natural fractures have a great influence on the fracture network propagation during a fracturing treatment. Meanwhile, the fracturing fluid flowing into these natural fractures will result in the co-existence of fracturing fluid and natural gas. As a result, the capillary force occurs at the gas-liquid interface in natural fractures. If the sizes of these natural fractures are different, the capillary force in the natural fractures is different as well. In particular, when the natural fracture is small, the capillary force will be very large and even affect the natural fracture initiation and propagation. As a consequence, the fracturing fluid flowing in natural fractures and the fracture network development will be significantly affected by these multiscale natural fractures. In this paper, a model about fracture network propagation was built which considered natural fractures sizes and fracturing fluid wettability. Besides, different methods were adopted to calculate the stress intensity of hydraulic fracture and natural fracture, respectively. In addition, the competitive growth theory of multi fractures is considered to describe the fracture network propagation. The studies found that with long length, small width natural fractures and strong wettability fracturing fluid, natural fractures were more likely to propagate, which resulted in a large fracture network. Besides, when the sizes of natural fractures were different, a more complex fracture network was tended to come out. An experimental study about fracture network propagation in shale was introduced from Suarez-Rivera’s work, in which a “fish bone” shape fracture propagation was observed. By comparing the numerical simulation with Suarez-Rivera’s work, it could be concluded that the simulation was in accordance with shale fracturing experiments results.

Fractures system within Qusaiba shale outcrop and its relationship to the lithological properties, Qasim area, Central Saudi Arabia

The basal Qusaiba hot shale member of Qalibah Formation is considered to be an important source rock in the Paleozoic petroleum system of Saudi Arabia and an exploration target for tight shale as one of the Unconventional resources of petroleum. This work has been carried out to understand the fractures network of Qusaiba shale member in outcrops located to the west of Qusayba' village in Al-Qasim area, Central Saudi Arabia. The main objective of this study is to understand the distribution of natural fractures over different lithological units. Description data sheets were used for the detailed lithological description of Qusaiba shale member on two outcrops. Spot-7 and Landsat ETM+ satellite images were used for lineament mapping and analyses on a regional scale in a GIS environment. Fractures characterization in outcrop-scale was conducted by using linear scanline method. Qusaiba shale member in the study area consists of 5 main lithofacies, divided based on their sedimentary structures and petrographical properties, from base to top in the outcrops, the lithofacies are; fissile shale, very fine-grained micaceous siltstone, bioturbated mudstone, very fine to fine-grained hummocky cross-stratified sandstone, and fine to medium-grained low/high angle cross-stratified sandstone lithofacies. Lineaments interpretation of the Spot-7 and Landsat ETM+ satellite images showed two major directions in the study area; 320° that could be related to Najd fault system and 20° that could be related to the extensional activities which took place after Amar collision. Fractures are much denser in the fissile shale and mudstone lithofacies than sandstones lithofacies, and average spacing is smaller in the fissile shale and mudstone lithofacies than sandstones lithofacies. Lineaments and large-scale fractures are Non-Stratabound fractures and they deal with the area as one big mechanical unit, but small-scale fractures are Stratabound fractures that propose different mechanical units within Qusaiba shale member in the study area. The fractures network in the study area has a wide range of properties related to fractures density, length, spacing, height, and termination degree. The conceptual multi-scale model divides the fractures in the study area into 4 orders depending on the available data that have been observed from satellite images and field. The multi-scale fractures model that was generated in this study could help to understand the distribution of stratigraphically controlled fractures when integrated with flow simulation models. Overall, this work could have a significant contribution to tight shale exploration plans in the subsurface by providing some knowledge about the fractures mechanical behavior of the lower part of Qusaiba shale member of Qalibah Formation.

PROBLEMS AND CHALLENGES OF MECHANICS IN SHALE GAS EFFICIENT EXPLOITATION

Shale gas is unconventional natural gas stored in shale in free or absorbed forms and sometimes in free fluid phase. The exploitation of shale gas has become a promising field of green energy development in China. Although great success has been achieved in shale gas revolution in North America with the technique of hydraulic fracturing, there is only 5%~15% of the stored oil and gas could be exploited, which is still a puzzle for petroleum engineers. Compared with the North America, China's shale gas reservoirs are deep burial, the geologic construction conditions are complicated and natural quality is low, therefore, efficient exploitation is facing more difficulties and challenges. In recent years, aiming at the national major energy strategy and the frontier of technological development, China's academia and industry have carried out the preliminary study on some of the key scientific and technical issues. Around the new issues encountered in the shale gas extraction in Sichuan and Chongqing areas in recent three years, this paper introduces and summarizes the key mechanics problems and challenges that the high efficient shale gas extraction is facing, mainly includes the multifield coupling safe and high quality drilling mechanics, hydraulic fracturing and multi-scale fracture network formation mechanism and multi-scale seepage and desorption mechanism of shale gas, to solve the challenges in deep exploitation below 3500 meters in China, such as geologic sedimentation, different fracture development, increasing overburden pressure, the change of horizontal stress, etc. The deep shale gas exploitation is not only to adapt to the national energy demand, but also has scientific and engineering significance. To realize the efficient exploitation of shale oil and gas, it needs the interdisciplinary collaboration of mechanical engineering, petroleum engineering, geophysics, chemical engineering and environmental engineering to carry out basic theoretical research, physical simulation, numerical simulation and field experiment. It has been recognized that interdisciplinary research is the bridge and the key to breakthrough the technology bottleneck and realize the efficient exploitation of shale gas. It is necessary of the deep collaboration between mechanics, petroleum engineering, earth science and other disciplines to promote the development of shale gas and other unconventional oil and gas resources.

Explicit Fracture Network Modelling: From Multiple Point Statistics to Dynamic Simulation

This paper addresses the problem of explicit fractured media modelling in an operational case. On one side, realistic fracture models are mainly used for research purposes in order to investigate better the flow behaviour impacted by the complex multi-scale fracture network. Often, a very fine grid and hence an increased computation time are needed. On the other hand, an operational fractured reservoir is still generally modelled using an implicit fracture media representation. The upscaled petrophysical properties and dual media are defined on a coarse grid to limit the computational time of dynamic simulation. The challenge of this work is to demonstrate that an explicit fracture modelling is not reserved only for the research domain, but can be applied to an operational case study. The static model is constructed using a multiple point statistics approach in order to represent complex interaction patterns of fractures and faults observed at the analogue outcrop. The dynamic behaviour is simulated based on this spatial fracture network representation.

Ground penetrating radar for fracture mapping in underground hazardous waste disposal sites: A case study from an underground research tunnel, South Korea

Secure disposal or storage of nuclear waste within stable geologic environments hinges on the effectiveness of artificial and natural radiation barriers. Fractures in the bedrock are viewed as the most likely passage for the transport of radioactive waste away from a disposal site. We utilize ground penetrating radar (GPR) to map fractures in the tunnel walls of an underground research tunnel at the Korea Atomic Energy Research Institute (KAERI). GPR experiments within the KAERI Underground Research Tunnel (KURT) were carried out by using 200MHz, 500MHz, and 1000MHz antennas. By using the high-frequency antennas, we were able to identify small-scale fractures, which were previously unidentified during the tunnel excavation process. Then, through 3-D visualization of the grid survey data, we reconstructed the spatial distribution and interconnectivity of the multi-scale fractures within the wall. We found that a multi-frequency GPR approach provided more details of the complex fracture network, including deep structures. Furthermore, temporal changes in reflection polarity between the GPR surveys enabled us to infer the hydraulic characteristics of the discrete fracture network developed behind the surveyed wall. We hypothesized that the fractures exhibiting polarity change may be due to a combination of air-filled and mineralogical boundaries. Simulated GPR scans for the considered case were consistent with the observed GPR data. If our assumption is correct, the groundwater flow into these near-surface fractures may form the water-filled fractures along the existing air-filled ones and hence cause the changes in reflection polarity over the given time interval (i.e., 7days). Our results show that the GPR survey is an efficient tool to determine fractures at various scales. Time-lapse GPR data may be essential to characterize the hydraulic behavior of discrete fracture networks in underground disposal facilities.

Simulation-Based Unitary Fracking Condition and Multiscale Self-Consistent Fracture Network Formation in Shale

Hydraulic fracturing (fracking) technology in gas or oil shale engineering is highly developed last decades, but the knowledge of the actual fracking process is mostly empirical and makes mechanicians and petroleum engineers wonder: why fracking works? (Bažant et al., 2014, “Why Fracking Works,” ASME J. Appl. Mech., 81(10), p. 101010) Two crucial issues should be considered in order to answer this question, which are fracture propagation condition and multiscale fracture network formation in shale. Multiple clusters of fractures initiate from the horizontal wellbore and several major fractures propagate simultaneously during one fracking stage. The simulation-based unitary fracking condition is proposed in this paper by extended finite element method (XFEM) to drive fracture clusters growing or arresting dominated by inlet fluid flux and stress intensity factors. However, there are millions of smeared fractures in the formation, which compose a multiscale fracture network beyond the computation capacity by XFEM. So, another simulation-based multiscale self-consistent fracture network model is proposed bridging the multiscale smeared fractures. The purpose of this work is to predict pressure on mouth of well or fluid flux in the wellbore based on the required minimum fracture spacing scale, reservoir pressure, and proppant size, as well as other given conditions. Examples are provided to verify the theoretic and numerical models.

Volume fracturing of deep shale gas horizontal wells

Deep shale gas reservoirs buried underground with depth being more than 3500 m are characterized by high in-situ stress, large horizontal stress difference, complex distribution of bedding and natural cracks, and strong rock plasticity. Thus, during hydraulic fracturing, these reservoirs often reveal difficult fracture extension, low fracture complexity, low stimulated reservoir volume (SRV), low conductivity and fast decline, which hinder greatly the economic and effective development of deep shale gas. In this paper, a specific and feasible technique of volume fracturing of deep shale gas horizontal wells is presented. In addition to planar perforation, multi-scale fracturing, full-scale fracture filling, and control over extension of high-angle natural fractures, some supporting techniques are proposed, including multi-stage alternate injection (of acid fluid, slick water and gel) and the mixed- and small-grained proppant to be injected with variable viscosity and displacement. These techniques help to increase the effective stimulated reservoir volume (ESRV) for deep gas production. Some of the techniques have been successfully used in the fracturing of deep shale gas horizontal wells in Yongchuan, Weiyuan and southern Jiaoshiba blocks in the Sichuan Basin. As a result, Wells YY1HF and WY1HF yielded initially 14.1 × 104 m3/d and 17.5 × 104 m3/d after fracturing. The volume fracturing of deep shale gas horizontal well is meaningful in achieving the productivity of 50 × 108 m3 gas from the interval of 3500–4000 m in Phase II development of Fuling and also in commercial production of huge shale gas resources at a vertical depth of less than 6000 m.

Mechanism and influencing factors of EOR by N2 injection in fractured-vuggy carbonate reservoirs

Multi-scale fractures and karst caves are the main reservoir bodies in fractured-vuggy carbonate reservoirs, and there are still various types of remaining oil after water flooding. Oilfield development practices demonstrate that the method of N2 injection can enhance oil recovery effectively. However, the development effect of a single well with gas injection is highly different, and the mechanism and influencing factors of gas injection for enhanced oil recovery are not clear. To reveal the mechanism and influencing factors of enhanced oil recovery through physical experiments and numerical simulation, we have produced a series of physical models of fracture and cave combinations based on the characteristics of this type of reservoir, established a visual physical simulation experimental apparatus and process, and analyzed the main factors affecting the production efficiency of gas injection wells in combination with the actual development of oilfields. The research results demonstrate that the primary types of remaining oil after water flooding in fractured-vuggy carbonate reservoirs are oil at the top of karst caves, oil shielded from high flow channels and oil not swept by the wells. The mechanism of gas injection-enhanced oil recovery is primarily composed of three aspects. First, the injected gas forms a secondary gas cap because of the effect of gravitational differentiation, and the gas cap can displace the remaining oil on top of the karst cave that the injected water cannot drive; Then, injected gas can change the pressure field distribution and the direction of fluid flow after water injection, driving the remaining oil that is shielded by high flow diversion channels; in addition, the injected gas has a certain effect on the reservoir energy supply. The geological conditions, such as the remaining reserves of injecting gas wells, filling level, well-reservoir position relationship and bottom water energy, have great influence on the development effect. The starting time of gas injection has an optimal point, and injecting too early or late will affect the oil recovery. The cyclic gas injection quantity and gas injection velocity are the primary injection production parameters that influence the production effect of a gas injection well. Finally, the principle of selecting a well for gas injection according to the research results is discussed, which can provide reference for selecting gas injection wells and injection methods of fractured-vuggy reservoirs in Tahe Oilfield.