Staged Fracturing of Horizontal Wells in Continental Tight Sandstone Oil Reservoirs: A Case Study of Yanchang Formation in Western Ordos Basin, China

Characteristics and resource prospects of tight oil in Ordos Basin, China

Characteristics and controlling factors of lacustrine tight oil reservoirs of the Triassic Yanchang Formation Chang 7 in the Ordos Basin, China

Controls on reservoir heterogeneity of tight sand oil reservoirs in Upper Triassic Yanchang Formation in Longdong Area, southwest Ordos Basin, China: Implications for reservoir quality prediction and oil accumulation

Study of tight oil reservoir flow regimes in different treated horizontal well

ABSTRACTDeep tight sandstone oil and gas reservoirs are exerting an increasingly crucial role in the augmentation of fossil energy reserves and the provision of energy. On account of the intricate geological conditions and the deficiency of a comprehensive set of exploration and development engineering technologies as well as supporting processes, the present development of deep tight sandstone oil and gas reservoirs remains in its nascent stage. Through the analysis and generalization of the horizontal well development technology for deep tight sandstone oil and gas reservoirs, a series of technologies have been established, encompassing reservoir geological evaluation and modeling, horizontal well development reservoir engineering validation, horizontal well geological design, and enhanced oil recovery processes. By taking the C 6 reservoir in Ordos basin, China as the research subject, in light of the research outcomes regarding the damage mechanisms and potential damage factors of tight sandstone oil and gas reservoirs, a geological evaluation approach based on the well log response characteristics was constructed, clarifying the porosity and permeability features of the C 6 reservoir, establishing the numerical model of the oil reservoir, and further elaborating the methods for dividing the development layers, selecting the development well pattern, and determining the development well density. The design parameters of horizontal well‐segmented hydraulic fracturing were meticulously optimized, resulting in a minimum cluster spacing of 7 m and a maximum cluster spacing of 20 m. Given the influence of horizontal stress differences, the optimum fracturing density was ascertained to be 16 perforations per meter, and the optimal fracturing fluid volume was identified through simulation to range from 12 to 25 m3/m. The crucial technologies for the development of tight sandstone oil and gas reservoirs in horizontal wells have been clearly identified, offering theoretical direction for the efficient exploitation of deep tight sandstone oil and gas reservoirs.

Comprehensive research on reservoir rock mechanics and in-situ stress properties combined with petrophysical experiments, logging models and numerical simulation is an important means to achieve efficient development of tight sandstone oil reservoirs. In this study, a large number of rock mechanics and acoustic experiments, full-wave train array acoustic wave tests, hydraulic fracturing data and three-dimensional finite element simulations were used to study the rock mechanical properties and in-situ stress characteristics of continental tight oil reservoirs in the Yanchang Formation. The results show that under uniaxial conditions, the tight sandstone samples mainly suffer from tensional ruptures. With the increase of confining pressure, the tight sandstone samples undergo obvious shear ruptures. When the confining pressure is loaded to 35 MPa, a typical vertical shear fracture will be formed. The hydraulic fracturing calculation results show that the in-situ stress state of the target layer satisfies σv (vertical principal stress)>σH (maximum horizontal principal stress)>σh (minimum horizontal principal stress). Based on the results of rock mechanics and acoustic tests, we have constructed the dynamic and static mechanical parameter conversion models of tight oil reservoirs and the logging interpretation model of current in-situ stress. Furthermore, the finite element method is used to simulate the three-dimensional structural stress field of the target layer. The simulations show that the horizontal principal stress distribution in the work area is consistent with the applied environmental stress. The σH of the target layer is mainly distributed in 32–50 MPa, and the σh is mainly distributed in 20–34 MPa. Both σH and σh are relatively high in the southern uplift of the work area; among them, σH is usually greater than 44 MPa, and σh is usually greater than 24 MPa. The northern part of the study area developed several grooved areas with relatively low stress values. The regions with high stress values are often distributed in bands, which may be related to the compression caused by the deformation of the strata. For shear stress, left-handed and right-handed regions usually alternate with each other. However, the extent of the left-handed area in the southern uplift area is larger than that of the right-handed area, indicating that the tight oil reservoirs in the study area are mainly affected by left-handed activities.

Horizontal wells and hydraulic fracturing are the key technologies that allow commercial production from tight oil and gas reservoirs. However, rigorous analysis of production data from these reservoirs requires incorporation of the impacts of stress-dependent permeability and multi-phase flow. Changes in the stress state of the system during production may reduce the absolute permeability. Furthermore, gas phase formation and flow in presence of supersaturated oil phase affects fluid dynamics in tight oil reservoirs. This study provides a rigorous methodology for incorporation of the effects of non-static permeability and multi-phase flow in rate transient analysis (RTA) of tight oil and gas reservoirs producing at variable rate/flowing pressures during transient linear flow period. Analytical solutions for the approximate linearized form of the flow equation have been widely used as the basis for RTA tools for conventional reservoirs during transient flow period. However, they lead to considerable error when applied to tight oil and gas reservoirs. In particular, during the transient linear flow period, the slope of the square -root-of-time plot obtained from numerical solution differs from the slope calculated by analytical methods. Efforts have been made by some researchers to obtain a correction factor from the numerical solution of the flow equation to correct the slope of the square-root-of-time plot for single phase flow of gas during transient linear flow period. In this study, an iterative method is used for evaluation of the slope correction factor in the presence of multi-phase flow and non-static permeability for constant-pressure production during transient linear flow period. Further, the correction factor is used for analysis of production data from tight oil and gas reservoirs producing at variable rate/flowing pressures. The correction factor is used in the analysis of different sets of synthetic production data for tight oil and gas reservoirs. The results show that the correction factor can reduce/eliminate the considerable errors associated with the conventional analytical methods in initial permeability estimation. For multi-phase flow cases, the producing gas -oil ratio (GOR) is used to estimate the oil saturation-pressure relationship in the reservoir, which is required for calculation pseudo-pressure and the correction factor. The method developed in this study alleviates the need for using numerical simulation models to generate empirical correlations for the correction factor for the square -root-of-time plot. The easy-to-implement iterative procedure of this method only requires the pressure dependencies of the constituent elements of the hydraulic diffusivity. Therefore, this method is applicable for analysis of production profiles for variety of reservoirs with nonlinear flow equations.

A new approach to calculate permeability stress sensitivity in tight sandstone oil reservoirs considering micro-pore-throat structure

CO2 huff and puff has been continuously considered as an import EOR method for tight oil reservoirs. However, the large number of evaluation parameters for reservoir screening has limited its application. This paper proposed a multi-index evaluation function for CO2 huff and puff method to facilitate the reservoir screening. By the means of orthogonal experimental design, it concludes the main controlling factors for screening a tight sand oil reservoir with multi-stage fractured horizontal wells. In addition, we built a calculation model for this multi-index evaluation function with Box-Benhken experimental design method. And this model has been successfully applied to screen wells for CO2 huff and puff of Y oilfield in Ordos.

Evaluation criteria, major types, characteristics and resource prospects of tight oil in China

Multi-stage fractured horizontal well is currently the most effective way to exploit tight oil reservoirs. The stimulated reservoir volume in the Multi-stage fractured horizontal well can be regarded as fractal porous media. Anomalous diffusion models have been proposed to investigate pressure transient behaviors in fractal porous media. However, these models pay little attention to the effect of the unstimulated reservoir volume. An anomalous diffusion model based on five flow region model for multi-stage fractured horizontal wells in tight oil reservoirs is presented in this paper. Execpt the extending from trilinear anomalous-diffusion to five-linear anomalous-diffusion model, this model also considers the effect of threshold-pressure gradient (TPG) in unstimulated reservoir volume. The Laplace transform is applied to obtain the Laplace space solution of a single crack at a closed boundary under fixed production conditions. Through the Stehfest numerical inversion calculation, the bottom hole pressure and pressure derivative values of the volume fracturing horizontal well are obtained. The differences and similarities of dimensionless wellbore pressure and pressure derivative curves between our solution and the classical trilinear dual-porosity model are delineated. Effect of fractional derivative of time and TPG on tight oil transient behavior are investigated. The model is tested with field cases and verified that the five-linear anomalous-diffusion model presented in this paper is useful for performance predictions and pressure transient analysis of fractured horizontal wells in tight oil reservoirs, which is of great significance for fracturing construction effect analysis and reservoir understanding.KeywordsRactal theoryVolume-fractured horizontal wellFive-linear flow modelParameter inversion

Fractured horizontal wells are widely used to produce tight oil. But different fracture patterns could be generated in different reservoirs, which results in different well performances. How to identify the flow regimes and their impacts on performance is still challenging. This paper provides a method for flow regime identification of horizontal wells with different hydraulic fracture patterns in tight reservoirs. First, four different fracture patterns of hydraulically fractured horizontal wells in different types of tight oil reservoirs are classified, according to the fracture network identified from micro-seismic observation and laboratory experiments. Then, corresponding well performances are simulated based on various conceptual reservoir simulation models. The simulation results are further used for rate transient analysis. Finally, flow regimes and corresponding production periods of each pattern are identified and classified, and well performances are also analyzed. Flow regimes of different fracture patterns are identified based on rate transient analysis with input of reservoir simulation results. Different patterns have different flow regimes. For instance, there are linear flow, radial flow and boundary dominated flow in Pattern A, while bilinear flow, linear flow, radial flow and boundary dominated flow are prevail in Pattern C. The corresponding production phase of each flow regime is also classified. It can be seen that different scales of pores and fractures have different impacts on different patterns and production phases. In pattern A and Pattern D, large fractures determines the initial production rate and performance of linear flow, and more oil is produced in linear flow stage than in radial and boundary dominated flow periods. While in Pattern B and Pattern C, micro-nano fractures and pores are much more developed, which have more cumulative production and better performances during radial flow and boundary dominated flow. The results are applied to the tight oil reservoirs in Junggar and Erdos Basin in China. Analysis of all fractured horizontal wells indicates that most are pattern A and Pattern B, and linear flow occurs in the early production period in all the patterns. If hydraulic fractures are long enough, bilinear flow could happen. Well performances are correctly predicted based on the well flow regime identification.

To better evaluate the production performance of tight oil reservoirs, it is urgent to solve the multistage fractured horizontal well production enigma. It is paramount to develop new models to analyze the well performance for tight oil reservoirs. In this paper, a new production prediction model of multistage fractured horizontal well in tight oil reservoir was established. In this model, unsteady transfer flow between fracture and matrix was considered. This model was solved by using Laplace transform method, line source function and Stehfest method comprehensively. The production prediction type curves including pressure transient analysis curves and rate transient analysis curves were then obtained. According to these type curves, eight flow regimes were obtained as early wellbore storage period, skin factor period, bi-linear flow regime, linear flow regime, first radial flow regime, transition flow regime, transfer flow regime and later radial flow regime. In the end, a field case history matching result was given and four key parameters’ effect on tight formation well production was analyzed. This research is of both theoretical significance and practical value for tight oil development. Cited as : Zhao, K., Du, P. A new production prediction model for multistage fractured horizontal well in tight oil reservoirs. Advances in Geo-Energy Research, 2020, 4(2): 152-161, doi: 10.26804/ager.2020.02.04

Fully coupled fluid-solid productivity numerical simulation of multistage fractured horizontal well in tight oil reservoirs

The most commonly used technology for development of unconventional liquid-rich and light oil reservoirs is horizontal wells combined with large multi-stage hydraulic fracture treatments. However, even with these technological advancements, primary recovery factors are generally less than 10% (Shoaib and Hoffman, 2009) of the original oil in place (OOIP). Logically, operators have investigated the use of waterflooding to improve recovery in some tight oil reservoirs, but the success has been mixed. Low matrix permeability in some unconventional (tight) oil reservoirs will not allow effective displacement or movement of water through the reservoir. In some cases, even flooding with a gas will be a challenge, if matrix permeabilities are too low. This study investigates the feasibility of enhanced oil recovery (EOR) in a prominent tight oil reservoir in North America using cyclic solvent injection (CSI, sometimes referred to as "huff-n-puff") with carbon dioxide (CO2) as the solvent. CSI is a single well process, with the solvent remaining in the vicinity of the wellbore, as flow of the solvent through the reservoir to another well is not necessary. This type of process may be attractive from a capital cost point-of-view, as large expenditures on specialized facilities, in-field pipelines and well conversions are unnecessary. In this study, the success and profitability of huff-n-puff is evaluated for the Bakken tight oil reservoir. Knowledge gained from a parallel study (Kanfar and Clarkson, 2017) served to provide guidelines for optimizing the huff-n-puff process. Importantly, a genetic algorithm (GA) is utilized to find the optimum huff-n-puff program that maximizes net present value (NPV). Optimized parameters include: the number of cycles; duration of injection, soaking and production periods; and the start time of huff-n-puff operations. The target reservoir for evaluation is the US Bakken deep tight oil reservoir in North Dakota. The huff-n-puff EOR scheme was found to be successful, but only after the aforementioned operational parameters are optimized with GA. In particular, it is important to delay huff-n-puff until production rates decline and boundary-dominated flow (after fracture interference) is reached. Importantly, as with the parallel study (Kanfar and Clarkson 2017), the gridding scheme used in the simulation is found to have a profound impact on results of huff-n-puff.