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Limited by the computing capacity of current computer and difficulty in inversion of large quantity of reservoir parameters for large scale reservoir history matching, the current automatic history matching methods are still hard to be applied in real fields. A parameterization method based on matrix decomposition is proposed to reduce the computational cost and improve the efficiency of history matching without decreasing the precision by mapping the original optimization problem from high dimensional space to low dimensional space. Base on the updated reservoir model after history matching, a reservoir production optimization control model is established. Considering the complexity of gradient calculation for history matching and production optimization objective function, a new general upscaling stochastic approximation (GUSA) algorithm is given based on the approximation perturbation gradient algorithm. The GUSA algorithm aims to get maximum increment of an objective function in unit step by obtaining an optimal lower triangular matrix in each iterative step. Toy problem results show that the calculation efficiency is improved much compared with the simultaneous perturbation stochastic approximation (SPSA) algorithm. For application of a real reservoir, a good history matching result is obtained for historic production data that verifies the validity of parameterization method and GUSA algorithm. An optimal control for production optimization performs an increase of oil production and a decrease of water cut. Besides, the optimal production scheme is accordant with the practical characteristics of dynamic production, which also proves the availability of GUSA algorithm.

As a crucial factor affecting water flooding in tight sandstone reservoirs, dynamic capillary pressure (DCP) has significant impact on the production performance during oil-water flow. In this work, a novel numerical simulation method with DCP is developed to study oil displacement in tight sandstone reservoirs. Based on this new model, the impacts from DCP to water/oil displacement (or water flooding effects) are analysed. The results of this work show that the effects brought by dynamic capillary pressure cannot be neglected. The more significant dynamic effects of capillary pressure correspond to the sample with lower permeability. The effect of DCP is probably a major contributor to non-linear flow (non-Darcy flow) in tight sandstone reservoirs during water flooding process. Compared with the conventional flow theory (e.g., static capillary pressure theory), our derived model with DCP can help to reduce the uncertainty in water/oil flow in tight sandstone reservoirs.

Non-uniform fracture aperture not only might affect initial reservoir fluids in place, but also production behavior. In addition, previous lab experiment has already demonstrated the importance of nonuniform aperture on permeability and residual oil distribution. This study investigates the impact of aperture averaging techniques on production performance of complex fracture networks in unconventional liquid reservoirs through fracture generation, unstructured gridding and reservoir simulation of hydraulically fractured horizontal wells. First, complex fracture networks are generated from microseismic-constrained stochastic algorithms. We reduce uncertainties of natural fracture length, center, and strike distributions by incorporating outcrop analysis and microseismic event locations. Hydraulic fractures are generated by randomly connecting natural fractures and by honoring material balance equations. Then, stress-dependent nonuniform fracture aperture distributions were taken from previously CT-scanning experiment. Moreover, in order to evaluate production performance, nonuniform apertures are sampled from the lab-measured lognormal distributions and then populated along complex fracture networks. Nonuniform aperture is explicitly gridded up and discretized using unstructured grids for reservoir simulations. Finally, numerous aperture-averaging techniques are investigated considering whether or not to honor input fracture conductivity distributions. Numerical simulations show that the same aperture distribution yields similar cumulative oil curves. With the increase of overburden stresses, the lab measured lognormal aperture peaks shift to the left. Correspondingly, it is observed decreased cumulative oil production. In addition, if fracture conductivity remains the same, the cubic law–based averaging approach yields the best production performance. If the fracture conductivity is not kept the same, the arithmetic averaging method provides us with the best production performance, which is followed by the base, geometric and harmonic cases. This paper demonstrated how to simulate production performance of stress-dependent nonuniform aperture in complex fracture networks. The crucial impact of nonuniform fracture aperture and averaging techniques are highlighted through comparison with the uniform fracture aperture.

Experimental equipment is designed to investigate single-phase oil/water flow in ultra-low permeability cores, using capillary flow meter to achieve accurate measurement of fluid volume. The results confirm that the single-phase oil/water flow in ultra-low permeability cores is not consistent with Darcy's Law. Typical flow curve is a combination of straight line and concave curve. The lower permeability the core has, the stronger non-linearity the concave curve shows. Pseudo (minimum) threshold pressure gradient exists widely in utra-low permeability cores for different fluid. Physical simulation and theoretical studies have shown that the relationship between threshold pressure gradient and permeability is a power function with the power of − 1. Nonlinear factor is defined to describe nonlinear flow characteristics. Higher viscosity leads to larger nonlinear factor and wider distribution of pressure. The minimum threshold pressure gradient can be calculated by pseudo threshold pressure gradient and nonlinear factor.

Water coning in bottom water drive reservoirs, which will result in earlier water breakthrough, rapid increase in water cut and low recovery level, has drawn tremendous attention in petroleum engineering field. As one simple and effective method to inhibit bottom water coning, shut-in coning control is usually preferred in oilfield to control the water cone and furthermore to enhance economic performance. However, most of the water coning researchers just have been done on investigation of the coning behavior as it grows up, the reported studies for water cone subsidence are very scarce. The goal of this work is to present an analytical model for water cone subsidence to analyze the subsidence of water cone when the well shut in. Based on Dupuit critical oil production rate formula, an analytical model is developed to estimate the initial water cone shape at the point of critical drawdown. Then, with the initial water cone shape equation, we propose an analysis model for water cone subsidence in bottom water reservoir reservoirs. Model analysis and several sensitivity studies are conducted. This work presents accurate and fast analytical model to perform the water cone subsidence in bottom water drive reservoirs. To consider the recent interests in development of bottom drive reservoirs, our approach provides a promising technique for better understanding the subsidence of water cone.

High-velocity fluid flow, which will result in the region of the wellbore or fracture, is generally in the turbulent flow regime and has drawn tremendous attention in petroleum engineering field. Turbulent factor is the key parameter, which is widely used to describe high-velocity flow in porous media. In this work, a theoretical model for turbulent factor in fractal porous media in the high-velocity fluid flow regime is developed. Moreover, a novel analytical expression for the permeability in porous media based on Wu's resistance model is also derived. Then, the analytical Kozeny-Carman constant with no empirical constant is obtained. The predictions of permeability-porosity relation by the current mathematical models have been validated by comparing with available experimental data. Furthermore, the effects of structural parameters of porous media on the curve of velocity and pressure drop are discussed in detail.

The great difference in density between steam and liquid during wet steam injection always results in steam override, that is, steam gathers on the top of the pay zone. In this article, the equation for steam override coefficient was firstly established based on van Lookeren’s steam override theory and then radius of steam zone and hot fluid zone were derived according to a more realistic temperature distribution and an energy balance in the pay zone. On this basis, the equation for the reservoir heat efficiency with the consideration of steam override was developed. Next, predicted results of the new model were compared with these of another analytical model and CMG STARS (a mature commercial reservoir numerical simulator) to verify the accuracy of the new mathematical model. Finally, based on the validated model, we analyzed the effects of injection rate, steam quality and reservoir thickness on the reservoir heat efficiency. The results show that the new model can be simplified to the classic model (Marx-Langenheim model) under the condition of the steam override being not taken into account, which means the Marx-Langenheim model is corresponding to a special case of this new model. The new model is much closer to the actual situation compared to the Marx-Langenheim model because of considering steam override. Moreover, with the help of the new model, it is found that the reservoir heat efficiency is not much affected by injection rate and steam quality but significantly influenced by reservoir thickness, and to ensure that the reservoir can be heated effectively, the reservoir thickness should not be too small.

Horizontal wells have been applied in bottom-water reservoir since their advantages were found on distribution of linear dropdown near wellbore, higher critical production, and more OOIP (original oil in place) controlled. In the paper, one 3D visible physical model of horizontal physical model is designed and built to simulate the water cresting process during the horizontal well producing and find water breakthrough point in homogenous and heterogeneous reservoir with bottom water. Water cresting shape and water cut of horizontal well in between homogenous and heterogeneous reservoir are compared on the base of experiment’s result. The water cresting pattern of horizontal well in homogeneous reservoir can be summarized as “central breakthrough, lateral expansion, thorough flooding, and then flank uplifting.” Furthermore, a simple analysis model of horizontal well in bottom water reservoir is established and water breakthrough point is analyzed. It can be drawn from the analysis result that whether or not to consider the top and bottom border, breakthrough would be located in the middle of horizontal segment with equal flow velocity distribution.