Reservoir Volume Fracturing Research Articles

Study on the Optimal Volume Fracturing Design for Horizontal Wells in Tight Oil Reservoirs

The application of horizontal well volume fracturing technology is an important method for enhancing oil recovery in tight oil reservoirs. However, the influence mechanism of the fracture placement scheme (FPC) on postfracturing productivity is still unclear. Based on the theory of the black oil model, combined with the reservoir stimulation characteristics of horizontal well volume fracturing in tight oil reservoirs, this paper established a postfracturing reservoir production simulation model. History fitting was used to verify the accuracy of the production model simulations. A series of numerical simulations was carried out to study the influence mechanisms of the fracture parameters and FPC on productivity. The simulation results show that compared with the fracture conductivity, the fracture length and number are the main parameters affecting tight oil reservoir productivity. Selecting a reasonable fracture length and number can realize the economical and efficient production of tight oil reservoir volume fracturing. Compared with the traditional fracture equal-length scheme, an FPC with an uneven fracture length can increase the cumulative oil production of oil wells. Under the condition of the same total fracture length, the scheme with a staggered distribution of long fractures and short fractures has the largest cumulative oil production over five years. A reasonable well spacing can greatly reduce the impact of interwell interference on postfracturing dual branch horizontal well productivity. When dual branch horizontal well fractures are alternately distributed, the postfracturing productivity is higher. The production simulation model established in this paper provides a method to accurately evaluate the productivity of horizontal wells after volume fracturing, which can provide guidance for the optimization of hydraulic fracturing operation parameters.

Study on Pressure Propagation in Tight Oil Reservoirs with Stimulated Reservoir Volume Development

The stimulated reservoir volume fracturing development in tight oil reservoirs is characterized by multiscale flow of the reservoir matrix, fracture network, and hydraulic fracture. Therefore, the flow field structure is extremely complex. Multiscale flow characteristics have been revealed through the systematical experiments including the threshold pressure gradient and the stress sensitivity. Based on the theory of elliptical flow, a comprehensive and practical mathematical model of multiregion coupling flow is established to characterize the multiscale flow, and the pressure distribution equation is derived. The calculation method of moving boundary is established to simulate the dynamic supply boundary and the dynamic pressure distribution by using the steady-state sequential replacement method. The characteristics of multiscale flow, multistage development state, and stress sensitivity are considered, especially the different stress sensitivity characteristics in different regions. Finally, the pressure propagation in tight reservoirs is clarified and the influence of matrix permeability, stress sensitivity characteristics, and drawdown pressure on the distance at the dynamic supply boundary are revealed. The research results provide theoretical basis for the development effect evaluation.

Productivity Prediction Model for Stimulated Reservoir Volume Fracturing in Tight Glutenite Reservoir Considering Fluid-Solid Coupling

At present, the main development mode of well + volume is adopted in the tight glutenite reservoir. Due to the existence of conglomerate, the seepage characteristics are more complex, and the production capacity after volume fracturing is difficult to predict. In order to solve this problem, a dual media unstable seepage model was established for matrix seepage and discrete fracture network seepage when considering the trigger pressure gradient. By considering the Poisson's ratio of stress sensitivity in an innovative way, the coupling model of permeability and stress is improved, and the production prediction model of volume fracturing horizontal well in tight glutenite reservoir based on the fluid-solid coupling effect is formed. The finite element method is used to numerically solve the model, and the fitting verification of the model is carried out; the impact of stress sensitivity, producing pressure difference, fracture length, number of fracture clusters and fracture flow capacity conductivity on productivity is analyzed,, which has certain guiding significance for the efficient development of volume fracturing in tight glutenite reservoir.

Formation Applicability Analysis of Stimulated Reservoir Volume Fracturing and Case Analysis

Stimulated Reservoir Volume (SRV) fracturing is a key technology of unconventional oil and gas exploration and development. To gain a deeper understanding of tight sandstone reservoirs and draw on the development experience of hydraulic fracturing, the authors conduct a large number of detailed investigations of geological characteristics in the regions that have implemented SRV fracturing. Based on the data of rock mechanics parameters, in-situ stress characteristics, brittleness characteristics and natural fractures, the influencing factors of SRV fracturing in tight oil reservoirs were analyzed. The results show that the SRV fracturing is suitable for geological reservoirs with the characteristics of medium to high elastic modulus, low to medium Poisson’s ratio, low stress difference, medium to high brittleness and naturally fractured reservoirs, where natural fractures have a significant impact. Region A, a tight sandstone region, has moderate elastic modulus, low Poisson’s ratio, low ground stress difference and medium brittleness, and has the feasibility of volume fracturing. The field case of the Y325 well shows that SRV fracturing technology has obvious effect on increasing production. This technology is applicable to the Region A.

Application of Temporary Plugging Stimulated Reservoir Volume Fracturing in Mahu Conglomerate Tight Oil

On account of the influence of early technical level and transformation concept, the production of the test horizontal wells has been improved to a certain extent, but there are still some problems, such as low pressure decline, low sustainable and stable production capacity. Refracturing technology is one of the main measures to improve the output of old wells in domestic and foreign oilfields at the moment. However, the horizontal wells put into production in early stage of Mahu were segmented with open hole packer and ball sliding sleeve. Restricted by the current wellbore conditions, forced mechanical segmented refracturing could not be achieved. People make use of the high-strength temporary plugging system to automatically select geological dessert, realize multiple inter-layer and intra-layer steering, improve the complexity and sweep volume of artificial fractures, and achieve the partial function of stimulated reservoir volume fracturing, which has become the effective increase production technology and means.

Migration and distribution of complex fracture proppant in shale reservoir volume fracturing

In this paper, a large-scale experimental system was established to identify the migration and distribution laws of complex fracture proppant in shale reservoir volume fracturing. With this system, the effects of secondary fracture angle, fluid displacement, proppant concentration and size, fracturing fluid viscosity and other factors on the migration and distribution of proppant were tested, and the migration and distribution of proppant in primary/secondary fractures were analyzed. The following results were obtained. First, the fluid flow pattern in fractures transforms gradually from laminar flow into turbulent flow with the increase of fracture supporting height. Second, the migration modes of proppant in fractures mainly include suspended migration and gliding migration. Third, the distribution form of proppant in primary fractures before branching is related to secondary fracture angle, fluid displacement and proppant concentration and size, among which the fluid displacement is the most important factor. Fourth, the mass ratio of proppant in primary fractures after branching is proportional to the secondary fracture angle, fluid displacement, fracturing fluid viscosity and proppant concentration and size, and is inversely proportional to the flow ratio between secondary fractures and primary fractures. Fifth, the mass ratio of proppant in secondary fractures after branching is proportional to fluid displacement, fracturing fluid viscosity and flow ratio between secondary fractures and primary fractures, and is inversely proportional to secondary fracture angle and proppant concentration and size. Sixth, the angle at the leading edge of proppant bank in the primary fractures after branching is proportional to the proppant concentration and size and the flow ratio between secondary fractures and primary fractures, but is inversely proportional to secondary fracture angle, fluid displacement and fracturing fluid viscosity. Seventh, the angle at the leading edge of proppant bank in the secondary fractures after branching is proportional to the secondary fracture angle and the proppant concentration and size, but is inversely proportional to the fluid displacement, fracturing fluid viscosity and flow ratio between secondary fractures and primary fractures. In conclusion, the research results can provide a theoretical support for proppant optimization and program design of shale reservoir volume fracturing.

Modeling of quantifying proppants for stimulation reservoir volume fracturing in a shale hydrocarbon reservoir

Massive hydraulic fracturing (MHF) technology is widely used to increase the stimulation reservoir volumes in the development of shale hydrocarbon reservoirs by pumping large amounts of fracturing fluids and proppants at a high injection rate. However, fresh water dissipation and the flowback fluid pollution created by this technology brings serious environmental problems. Moreover, the post-production of MHF is uncertain and some fractured wells keep a low production level all the time. It is therefore necessary to find an economical treatment size to satisfy the actual geology position of shale reservoirs, such as mountainous and water shortage regions. The amount of proppant for MHF are a key parameter of treatment size, which also effect the volume of fracturing fluids and injection rate directly. A proppant quantifying model for MHF in a shale hydrocarbon reservoir was developed. In this model, the complex fracture network was characterized as the enhanced permeability area (EPA), and then a correlation was built between the amount of proppants and the EPA based on the Warren–Root model. When the EPA parameters were optimized by a reservoir simulator according to the post-production and net present value, the optimum volume of proppants for a specific shale well can be obtained easily. The new model has been applied at the first horizontal well in Jianghan shale oil field and three horizontal and eighteen vertical wells in Western Sichuan shale gas field successfully. Compared with the results of the early empirical design method used in Western Sichuan, this approach shows a better post-production.

Technical difficulties in the cementing of horizontal shale gas wells in Weiyuan block and the countermeasures

When well cementing is conducted in horizontal shale gas wells in Weiyuan block of the Weiyuan–Changning State Shale Demonstration Area, Sichuan Basin, the oil-based drilling fluid is not compatible with cement slurry, is difficult to be displaced because of its high density, and cement sheath tends to be broken in the situations of large-scale stimulated reservoir volume fracturing. In view of these problems, a series of studies were carried out specifically on the theoretical basis of cement sheath sealing mechanical parameters, oil-displacement preflush improving the interface cementation quality, toughness set cement satisfying large-scale fracturing requirements and cementing technology conducive to the wellbore integrity. The following achievements were made. First, the theoretical model of cement sheath mechanical integrity taking into account the plastic characteristics and interface cementation strength of cement sheath is instructive to the mechanical design of set cement for horizontal shale gas wells, avoiding the micro-annulus as much as possible. Second, oil-displacement preflush is developed and it is well compatible with oil-based drilling fluids and cement slurry with the flushing efficiency on oil-based drilling fluids higher than 90%. Third, the tough set cement which is developed based on the theoretical model of cement sheath sealing integrity not only guarantees higher compressive strength, but decreases Young's modulus by 30%. Forth, it is confirmed that water displacement cementing technology suitable for shale gas wells is conducive to improving the wellbore seal integrity. These research findings were applied in 12 horizontal wells. It is indicated that the quality cementing ratio of horizontal segment reaches 92% and the post fracturing effect is very good, which guarantees the sealing integrity of wellbores and provides a technical support for the highly efficient development of shale gas reservoirs.

The Experience & Enlightenment from Low-Cost Strategy of Shale Gas Development in America

The experience of shale gas low-cost development in America provided production organization and management methods including horizontal well drilling, cluster well drilling, pad drilling, batch drilling, factory drilling, and reservoir volume fracturing. The policy of finance and taxation has played a positive role in promoting and encouraging shale gas development. The development of shale gas in China is different from America in sides of resource features, development process, the technical levels and the policy environment. We should learn from the technical means, management method and encouraging fiscal and financial policy of low-cost development strategy of America, study and formulate policy suitable to China's own characteristics, to promote low-cost development of shale gas.