Search Results (20)

In the shale oil reservoirs, sandstone and shale often overlie each other. This significantly affects the vertical propagation of hydraulic fractures (HFs); however, the underlying mechanisms still remain unclear. This study employs Xsite software to investigate the influence of rock fracture toughness, tensile strength, elastic modulus, Poisson’s ratio, interlayer stress contrast, and the flow rate and viscosity of fracturing fluid on the propagation behaviour of HFs in sandstone–shale interbeds. As the type-I fracture toughness of the shale layer increases, the area of the vertical HF decreases and the average HF width becomes smaller. As the tensile strength of the sandstone layer increases, the distribution range of fluid pressure at the interface expands. The HF prefers to propagate in the softer rock rather than the harder one. A relatively narrower HF width is created in the layer with a higher elastic modulus resulting in a higher flow resistance to fracturing fluid. A shale layer with a high Poisson’s ratio is more likely to undergo a lateral expansion, causing stress at the fracture tip to be dispersed. When the effect of lithological interfaces is considered, an increasing interlayer stress contrast causes HFs to gradually transition from penetrating the interfaces to becoming confined between the two interfaces. When the influence of the lithological interface is not considered, an increasing interlayer stress contrast causes the HF to gradually transition from a penny-shaped fracture to a blade-shaped fracture. The HF penetrates the interfaces more easily at a higher injection rate and fluid viscosity, because most of the injected energy is used to create new fractures rather than leakoff into the interfaces. Understanding the influence of these factors on the HF propagation behaviour is of great significance for optimising hydraulic fracturing design. Full article

Controlling fluid loss during acid fracturing remains challenging, as acid may partially or completely leak into reservoir pores and fractures, preventing effective flow within the formation and thereby reducing stimulation effectiveness. The acid leakoff mechanism is fundamentally distinct from that of non-reactive pad fluid (fracturing fluid), with the most critical distinction manifested through wall-confined acid-etched wormholes formed during reactive flow processes, which exert a dominant influence on acid filtration behavior. To address this challenge, a modified dual-scale continuum model based on the Brinkman equation was developed. This model establishes a numerical simulation framework for acid fracturing–etching processes in dolomite reservoirs of the Xi Xiangchi Formation. The study systematically reveals acid leakoff patterns at fracture walls under the influence of operational parameters (injection rate, acid concentration, acid viscosity) and reservoir characteristics (porosity heterogeneity). For field operations, medium-viscosity acid initially enhances distal fracture communication, followed by viscosity reduction to promote non-uniform etching. Prioritizing acid concentration over injection rate optimizes fracture connectivity, while minimizing leakoff. In high-porosity reservoirs, process parameters require optimization through acid retardation and leakoff control strategies. Full article

Optimizing well spacing is crucial for enhancing the production efficiency and economic returns of tight oil development. The limited understanding of hydraulic fracture geometry and properties poses significant challenges in designing well spacing for tight oil reservoirs. In this study, we proposed an integrated workflow for optimizing well spacing in tight oil reservoirs. Geological and geomechanical models were established to form the basis for numerical reservoir simulation and dynamic fracture modeling. A multi-staged, multi-clustered fracture propagation simulation of horizontal wells was conducted by a hydraulic fracturing simulator with matched actual field pumping schedules. The differences between fracture propagation simulation results and field monitoring results, including micro-seismic testing and distributed temperature sensing (DTS) monitoring, were analyzed. The geological model and fracture propagation simulation results were integrated into an efficient numerical reservoir simulator. A material balance method for fracturing fluids leak-off was proposed and utilized to equivalently calculate the actual oil–water distribution after fracturing and to complete the historical matching water cuts of all wells. Subsequently, the inter-well drainage area and pressure interference were evaluated. By employing this integrated workflow, the production performance of six wells (three well pairs) at different well spacings was simulated over a 15-year period, and their estimated ultimate recoveries (EURs) were predicted. When well spacing was less than the optimal distance, oil production dropped significantly. Ultimately, it was determined that reasonable well spacing for this block was 250 m. In future well pattern designs, well spacing smaller than the current value should be used. Full article

In hydraulic fracturing tests, the initial crack length and the compressibility of the injection system have a significant effect on the initiation and propagation of the fracture. Numerical or theoretical models that ignore the compressibility of the injection system are unable to accurately predict fracture behavior. In this paper, a 2D analytical/numerical model based on linear elastic fracture mechanics is presented for the initiation and propagation of hydraulic fracturing from two transversely symmetrical cracks in a borehole wall. It is assumed that the fracture is driven by compressible inviscid fluid in a permeable medium. To solve the problem, the governing equations are made dimensionless and the problem is solved in the compressibility–toughness-dominated propagation regime. According to the results, the initial crack length and the compressibility of the injection system have a significant effect on fracture initiation behavior. When the initial flaw length is small or compressibility effects are important, the initiation of the fracture is accompanied by instability and the occurrence of a sudden decrease in borehole pressure and a sudden increase in crack length. If the initial crack length is large or the compressibility effects are negligible, the crack propagation is stable. The leak-off coefficient has no effect on the pressure level required for crack propagation, but with an increase in leak-off, more time is required to reach the conditions for crack propagation. The results obtained in this paper provide good insights into the design of hydraulic fracturing processes. Full article

This study reviews methods for detecting fracture closure pressure in both unconventional and conventional reservoirs using mathematical models and fluid flow equations. It evaluates techniques such as the Nolte method, tangent method, and compliance method. The investigation relies on observing changes in fluid flow regimes from preclosure to postclosure using fluid flow equations to examine the postclosure flow regime effect on the G function. Reverse calculations model pressure decline across synthesized flow regimes, facilitating a detailed investigation of the closure process. The analysis reveals that the tangent method is sensitive to postclosure fluid flow, while the compliance method is less effective in reservoirs with significant tortuosity or natural fractures. This paper recommends assessing natural fractures’ characteristics and permeability to identify the source of leak-off before selecting a technique. It proposes integrating various methods to comprehensively understand subsurface formations, combining their strengths for accurate fracture closure identification and a better understanding of subsurface formations. The new proposed workflow employs the continuous wavelet transform (CWT) technique for fracture closure detection, avoiding physical model preassumptions or simplifications to confirm the results. This approach offers guidance on selecting appropriate methods by integrating different techniques. Full article

During the hydraulic fracturing process of coalbed methane (CBM) reservoirs, significant amounts of secondary coal fines are generated due to proppant grinding and crack propagation, which migrate with the fracturing fluid into surrounding fracture systems. To investigate whether coal fines can form plugs to reduce fluid leak-off during the hydraulic fracturing stage, we conducted physical simulation experiments on coal seam plugging and unplugging to demonstrate that coal fines indeed contribute to reducing fluid leak-off during hydraulic fracturing. We also explored the plugging mechanisms of coal fines under different concentrations and particle sizes in fracturing fluids, and revealed the damage law of coal fines of temporary plugging on reservoir permeability. Research results indicate the leak-off volume of fracturing fluids containing coal fines is lower than an order without coal fines, demonstrating a significant effect of coal fines in decreasing fluid leak-off. The temporary plugging rate of coal fines increases with higher concentrations and decreases with larger particle sizes, achieving rates exceeding 90%. The high temporary plugging effect of coal fines results from the superposition of internal and external filter cakes. Under conditions of small particle size and high concentration, the damage to fractures during the fine return process is minimized. Considering the potential damage of coal fines to propping fractures and wellbore, the concentration of coal fines in fracturing fluids should be kept relatively low while ensuring a high temporary plugging effect. Overall, these findings provide crucial insights into optimizing the temporary plugging performance of coal fines during the hydraulic fracturing stage and controlling their behavior during the fracturing fluid flow-back stage, thereby enhancing reservoir fracturing effectiveness and improving CBM production rates. Full article

As a critical technological approach, multistage fracturing is frequently used to boost gas recovery in compact hydrocarbon reservoirs. Determining an ideal cluster distance that effectively integrates pre-existing natural fractures in the deposit creates a fracture network conducive to gas movement. Fracturing fluid leak-off also impacts water resources. In our study, we use a versatile finite element–discrete element method that improves the auto-refinement of the grid and the detection of multiple fracture movements to model staged fracturing in naturally fractured reservoirs. This computational model illustrates the interaction between hydraulic fractures and pre-existing fractures and employs the nonlinear Carter leak-off criterion to portray fluid leakage and the impacts of hydromechanical coupling during multistage fracturing. Numerical results show that sequential fracturing exhibits the maximum length in unfractured and naturally fractured models, and the leak-off volume of parallel fracturing is the smallest. Our study proposes an innovative technique for identifying and optimizing the spacing of fracturing clusters in unconventional reservoirs. Full article

Natural fractures and wormholes strongly influence the performance of acid fracturing in naturally fractured carbonate reservoirs. This work uses an integrated model to study the effects of treatment parameters in acid fracturing in different reservoir conditions. Hydraulic fracture propagation, wormhole propagation, complex fluid leak-off mediums, and heat transfer are considered in the modeling. The model is validated in several steps by analytical solutions. The simulation results indicated that natural fractures and wormholes critically impact acid fracturing and can change the predicted outcomes dramatically. The high permeability reservoirs with conductive natural fractures or low permeability reservoirs with natural fracture networks showed the highest stimulation potential in applying acid fracturing technology. The optimal acid injection rate depends on natural fracture geometry and reservoir permeability. This study also observed that obtaining a high production index is difficult because natural fractures and wormholes reduce the acid efficiency during acid fracturing. Building an acid-etched fracture system consisting of acid-etched natural fractures and hydraulic fractures may help us better stimulate the naturally fractured carbonate reservoirs. The paper illustrates a better understanding of the effects of the treatment design parameters on productivity. It paves a path for the optimal design of acid fracturing treatment for heterogeneous carbonate reservoirs. Full article

In the last decade, hydrogels for hydraulic fracturing based on viscoelastic surfactants have been actively studied. Interest in these systems is justified by their unique qualities: good viscoelasticity and the ability to form stable suspensions of proppant or sand, destruction without the formation of bridging agents, hydrophobization of the rock surface and metal of technological equipment, as well as oil-cleaning properties. These qualities are most often provided by a minimum set of components—a surfactant and an electrolyte. However, the absence of a polymer limits the use of these gels in formations where fluid leakoff is possible. In this article, a liquid was studied, based on a pseudo gemini surfactant (PGVES) with the addition of a water-soluble polysaccharide. The objects of study were selected based on the assumption of interactions between PGVES and the polymer; interactions which favorably influence the technological characteristics of the fracturing fluid. To confirm the hypothesis, rheological studies were carried out. These included rotational viscometry and oscillatory studies at various temperatures. The settling velocity of particles of various proppant fractions was studied and tests were carried out to assess fluid leakoff. The performed experiments show an improvement in the characteristics of the PGVES-based gel under the influence of the polysaccharide. In particular, the rheological properties increase significantly, the stability of proppant suspensions improves, and the fluid leakoff of systems decreases, all of which expands the possibility of using these fracturing fluids and makes this area of experimentation promising. Full article

The existing pump-stopping pressure drop models for the hydraulic fracturing operation of tight oil reservoirs only consider the main hydraulic fracture and the single-phase flow of fracturing fluid. In this paper, a new pump-stopping pressure drop model for fracturing operation based on coupling calculation of the secondary fracture and oil-water two-phase flow is proposed. The physical model includes the horizontal wellbore, the fracture network and the tight oil reservoir. Through the numerical simulation and calculation, the wellbore afterflow performance, the crossflow performance between the main hydraulic fracture and the secondary fracture, the fracturing fluid leakoff and the oil-water replacement after termination of pumping are obtained. The pressure drop characteristic curve is drawn out by the bottom-hole flow pressure calculated through the numerical simulation, and a series of analyses are carried out on the calculated pressure drop curve, which is helpful to diagnose the -oil-water two-phase flow state and the fracture closure performance under the control of the fracture network after hydraulic fracturing pumping. Finally, taking a multi-stage fractured horizontal well in a tight oil reservoir in the Junggar basin, China as an example, the pump-stopping pressure drop data of each stage after hydraulic fracturing are analyzed. Through the history fitting of the pressure drop characteristic curve, the key parameters such as fracture network parameters, which include the half-length of main hydraulic fracture, the conductivity of main hydraulic fracture and the density of secondary fracture, the fracture closure pressure are obtained by inversion, thus, the hydraulic fracturing effect of fractured horizontal well in tight oil reservoirs is further quantified. Full article

Fractured reservoirs are widely distributed and rich in hydrocarbon resources. When encountering fractured reservoirs during the drilling process, it is often accompanied by formation losses characterized by high leak-off rates, causing severe damage to the reservoir and hindering the detection of oil and gas layers, which is not conducive to the accurate and efficient development of the reservoirs. Conventional plugging materials have poor retention effects in the fractures, resulting in the low stability of the sealing layer. The treatment of malignant lost circulation in fractured formations is an urgent problem to be solved in drilling engineering. This article focuses on improving the success rate of formation plugging through the combined use of multiple plugging materials and develops a composite hydrogel that can effectively reduce leakage rates. This hydrogel is mainly composed of materials such as polyvinyl alcohol, borax, and sodium silicate. It has good temperature resistance, maintains good gel strength at 60 °C, and can maintain long-term performance stability under simulated geological water conditions with salinity of 12,500 mg/L. For immersion corrosion by water or gasoline, the amount of corrosion is small and its fundamental performance remains largely unchanged. Through indoor simulation of a leak formation scenario, the hydrogel demonstrates commendable sealing pressure-bearing capacity. In terms of delaying fluid leakage, mixing the hydrogel with cement slurry at a ratio of 1:1 can delay the leakage rate of the cement slurry by a factor of 5.29. Full article

Oil and gas resources are closely related to daily life and are an important support for the economy of a city or even a country. Hydraulic fracturing is an indispensable technique to economically develop oil and gas resources through creating complex fractures. Temporary plugging and diverting fracturing (TPDF) can generate diversion fractures perpendicular to the initial fractures and enhance the stimulated area. The aperture of the diversion fractures determines its conductivity and the oil/gas production. However, it is difficult to evaluate the aperture of the diversion fracture due to the complex physical process of hydraulic fracturing. This work established a fluid–solid fully coupled simulation model to investigate the fracture aperture influenced by various factors during TPDF. The model can simulate the propagation of the initial fracture and the diversion fracture. Various factors include the tight plug’s permeability, the tight plug’s length, Young’s modulus, rock tensile strength, in situ stress contrast, the leak-off coefficient of the fracture surface, and fluid injection rate. The results show that the aperture of the previous fracture can be enlarged, and the aperture of the diversion fracture can be decreased by the tight plug. The aperture at the diversion fracture mouth is much smaller than that along the diversion fracture. Reservoirs with low Young’s modulus values and high rock tensile strength can generate the diversion fracture with a wider aperture. Moreover, increasing the fluid injection rate can effectively increase the fracture mouth aperture. In this way, the risk of screenout can be lowered. This work is beneficial for the design of the TPDF and ensures safe construction. Full article

Despite the significant advancements in geomodelling techniques over the past few decades, it is still quite challenging to obtain accurate assessments of hydraulic fracture propagation. This work investigates the effect of fluid leak-off in a dual-porosity system on the hydraulic fracture propagation geometry, which, in turn, affects hydrocarbon recovery from tight and unconventional reservoirs. Fracture propagation within tight reservoirs was analyzed using the Pseudo Three-Dimensional-Carter II model for single- (P3D-C) and dual-porosity systems (P3D-C-DP). Previous studies have accounted for leak-off in single-porosity models; however, studies within dual-porosity systems are still quite limited. We present a novel approach to coupling fluid leak-off in a dual-porosity system along with a fracture-height growth mechanism. Our findings provide important insights into the complexities within hydraulic fracturing treatment design using our new and pragmatic modeling approach. The simulation results illustrate that fluid leak-off in dual-porosity systems contributes to a confined fracture half-length ($x_f)$, that is 31% smaller using the P3D-C-DP model as opposed to the single-porosity model (P3D-C). As for the fracture height growth ($h_f)$, the P3D-C-DP model resulted in a 40% shorter fracture height compared to the single-porosity model. Full article

The fracturing crossing coal seam roof is a technology that fulfills the fracturing of a coal seam through the vertical propagation of fractures. Geological conditions are the key factors determining the effect of this kind of fracturing, but there is hardly any research on this aspect. To determine the favorable geological conditions for through-roof fracturing, based on a 3D fracture propagation model, and considering the interlayer vertical fracture toughness and leak-off heterogeneity, a mathematical model of fracturing through a horizontal well in a coal seam roof was established, and the calculation method of fractures crossing layer propagation was determined. In this method, the effect of fracture communication with the coal seam is evaluated by taking the area and the area ratio of fractures in the coal seam as the objective functions. The effects of parameters such as in situ stress combination profile, coal seam fracture toughness, and fluid loss coefficient on fracturing results were evaluated. The reasonable distance from the horizontal well to the coal seam’s top surface was determined in this work. The study results show that: (i) the fracturing effect is better when the coal seam is lower in in situ stress; (ii) the distance between the horizontal well and the top surface of the coal seam is recommended to be less than 4 m to obtain the ideal fracturing effect; and (iii) the combination of the in situ stress profile is the key factor, and the fracture toughness and fluid loss coefficient of the coal seam, fluid viscosity, and the number of perforations in one cluster are the secondary factors affecting the fracturing effect. Full article

Stranded gas emission from the field production because of the limitations in the pipeline infrastructure has become one of the major contributors to the greenhouse effects. How to handle the stranded gas is a troublesome problem under the background of global “net-zero” emission efforts. On the other hand, the cost of water for hydraulic fracturing is high and water is not accessible in some areas. The idea of using stranded gas in replace of the water-based fracturing fluid can reduce the gas emission and the cost. This paper presents some novel numerical studies on the feasibility of using stranded natural gas as fracturing fluids. Differences in the fracture creating, proppant placement, and oil/gas/water flowback are compared between natural gas fracturing fluids and water-based fracturing fluids. A fully integrated equation of state compositional hydraulic fracturing and reservoir simulator is used in this paper. Public datasets for the Permian Basin rock and fluid properties and natural gas foam properties are collected to set up simulation cases. The reservoir hydrocarbon fluid and natural gas fracturing fluids phase behavior is modeled using the Peng-Robinson equation of state. The evolving of created fracture geometry, conductivity and flowback performance during the lifecycle of the well (injection, shut-in, and production) are analyzed for the gas and water fracturing fluids. Simulation results show that natural gas and foam fracturing fluids are better than water-based fracturing fluids in terms of lower breakdown pressure, lower water leakoff into the reservoir, and higher cluster efficiency. NG foams tend to create better propped fractures with shorter length and larger width, because of their high viscosity. NG foam is also found to create better stimulated rock volume (SRV) permeability, better fracturing fluid flowback with a large water usage reduction, and high natural gas consumption. The simulation results presented in this paper are helpful to the operators in reducing natural gas emission while reducing the cost of hydraulic fracturing operation. Full article