Multiphase-flow properties of fractured porous media

Water–air imbibition and oil–water drainage displacements were conducted using a laboratory flow apparatus in fractured sandstone systems. During the experiments, porosity and saturation were measured along the core using a Computerized Tomography (CT) scanner. 3-D saturation images were reconstructed to observe matrix–fracture interactions. Differences in fluid saturations and relative permeabilities caused by changes of fracture width have also been analyzed. In the case of water–air imbibition, narrower fracture apertures showed more stable fronts and delayed water breakthrough compared to the wide fracture systems. However, the final water saturation was higher in wide fracture systems, thus showing that capillary pressure in the narrow fracture has more effect on fluid distribution in the matrix. During oil–water drainage, oil saturations were higher in the blocks near the thin fracture, again showing the effect of fracture capillary pressure. Oil fingering was observed in the wide fracture. Fine-grid simulations of the experiments using a commercial reservoir simulator were performed. Relative permeability and capillary pressure curves were obtained by history matching the experiments. The results showed that the assumption of fracture relative permeability equal to phase saturation is incorrect. It was found that both capillary and viscous forces affect the process. The matrix capillary pressure obtained by matching an experiment showed lower values than those reported in the literature.     

Analysis of counter-current gas–water capillary imbibition transfer at different temperatures

Gas water counter-current matrix–fracture interaction due to capillary forces was studied. The focus was on the rate of capillary imbibition and the development of residual gas phase under low (20 °C) and high temperatures (90 °C). Berea sandstone and Indiana limestone samples with different shape factors were obtained by cutting the plugs 1, 2.5, and 5 cm in diameter and 2.5, 5, and 10 cm in length. All sides were coated with epoxy except one end. Static imbibition experiments were conducted on vertically and horizontally situated samples where the matrix–fracture interaction took place upward and lateral directions, respectively. The effects of the matrix shape factor, wettability, surface tension, and core position on the recovery rate and ultimate recovery were investigated.The experimental scheme followed was useful in identification of the development of residual gas saturation for fully counter-current matrix–fracture interaction. We investigated and clarified to what degrees the rock/fluid properties (wettability and matrix shape factor) and existing conditions (temperature, causing lowered IFT and brine viscosity, and gravity) become effective on the residual gas saturation. It was observed that the residual gas saturation is sensitive to the matrix shape factor. The effect of surface tension on the recovery rate and ultimate recovery was also critical. The vertical cases yielded different recovery rates and ultimate recoveries with increasing temperature. Lower residual gas saturation with increasing temperature was obtained only for large diameters. That was attributed to the reduction in surface tension.Finally, critical matrix and fluid properties were correlated to the residual gas saturation and different dimensionless groups were tested for scaling.     

天然裂缝性油藏的离散裂缝网络数值模拟方法

针对裂缝性油藏中大裂缝、微细裂缝和孔隙等多种储渗介质共存的现象,将大裂缝作为控制流体流动的一维实体,组成离散裂缝网络,进行显式表示,将孔隙和微细裂缝组成的系统作为基岩介质,建立了天然裂缝性油藏两维两相数值模拟模型。采用加权余量法,建立有限元方程并进行了求解。对油藏有无裂缝及大裂缝的方位、长度和分布对水驱油的影响进行了研究。结果表明：大裂缝的存在会严重改变水驱油藏中注入水前缘的前进方向和速度,大裂缝与注采井间连线夹角越小及长度越大,都会导致注入水窜进越严重,从而使得油井见水早,含水率高;多条大裂缝的存在会造成剩余油分布的极度非均质及剩余油富集区的形成。     

Matrix-to-fracture transfer functions derived from the data of oil recovery, and it's derivative and integral

It is demonstrated that using integrals, derivatives, and inflection points of the oil recovery data measured by imbibition tests on cores improves the accuracy of correlations of the matrix-to-fracture oil transfer data. The tri-exponential transfer functions with the present numerical approach yield a reliable technique to represent the experimental imbibition data. Accurately estimated function parameters allow the laboratory results to be scaled to field applications. Several issues pertaining to spontaneous imbibition as a recovery mechanism while waterflooding naturally fractured reservoirs are addressed. The contribution of the wettability and dead-end pores is also determined. The triple-exponential function for double-porosity systems is able to adjust to actual spontaneous imbibition trends observed in experiments conducted in naturally fractured cores. The analysis and interpretation of the results verify the considerations of the proposed mechanisms for fluid transfer from matrix to fracture.     

Naturally fractured hydrocarbon reservoir simulation by elastic fracture modeling

Accurate fluid flow simulation in geologically complex reservoirs is of particular importance in construction of reservoir simulators. General approaches in naturally fractured reservoir simulation involve use of unstructured grids or a structured grid coupled with locally unstructured grids and discrete fracture models. These methods suffer from drawbacks such as lack of flexibility and of ease of updating. In this study, I combined fracture modeling by elastic gridding which improves flexibility, especially in complex reservoirs. The proposed model revises conventional modeling fractures by hard rigid planes that do not change through production. This is a dubious assumption, especially in reservoirs with a high production rate in the beginning. The proposed elastic fracture modeling considers changes in fracture properties, shape and aperture through the simulation. This strategy is only reliable for naturally fractured reservoirs with high fracture permeability and less permeable matrix and parallel fractures with less cross-connections. Comparison of elastic fracture modeling results with conventional modeling showed that these assumptions will cause production pressure to enlarge fracture apertures and change fracture shapes, which consequently results in lower production compared with what was previously assumed. It is concluded that an elastic gridded model could better simulate reservoir performance.     

天然裂缝性油藏渗吸规律

为了研究渗吸作用对天然裂缝性油藏的影响,改善该类油藏的开发效果,以数值模拟为手段,通过建立概念地质模型,以静态和动态2种方式研究了毛细管压力、孔隙均匀程度、相渗曲线、基质和裂缝渗透率、原油黏度和基质含油饱和度对基质渗吸速度的影响,并在静态下对相关参数进行了公式拟合.静态下,渗吸速度与毛细管压力、基质渗透率、残余油饱和度、束缚水饱和度下的油相相对渗透率呈直线关系,与束缚水饱和度呈指数关系,与原油黏度呈幂指数关系;动态下,对于不同润湿性的油藏提出了不同的开发方式.     

Effective Permeability Calculation Using Boundary Element Method in Naturally Fractured Reservoirs

A model is presented to calculate the effective permeability tensor in naturally fractured reservoirs using Boundary Element Methods (BEM). Arbitrary fractures of different scales based on their length are considered. Interface boundary condition is used to model the short fractures as an enhancement of matrix permeability. Long fractures, on the other hand are treated as source/sink in the corresponding blocks. Periodic boundary condition is applied to the grid-block boundaries to calculate the elements of effective permeability tensor. Darcy's law and Navier-stoke's equation are applied to fluid flow in rock matrix and fractures, respectively. An important feature of this approach is that the fluid flow in matrix-fracture interface is coupled by Poisson's equation and fluid flow in the rest of the matrix is formulated by Laplace's equation. This paper also presents an innovative approach to optimization and parallelization of the model by High Performance Computing (HPC) techniques. The model has been validated against analytical results and applied to a typical case where arbitrary fractures of different sizes are assumed within the grid blocks. The effective block permeability tensors can be implemented into a reservoir simulator to calculate fluid flow through the naturally fractured reservoirs.     

Effective Permeability Calculation Using Boundary Element Method in Naturally Fractured Reservoirs

Abstract

A model is presented to calculate the effective permeability tensor in naturally fractured reservoirs using Boundary Element Methods (BEM). Arbitrary fractures of different scales based on their length are considered. Interface boundary condition is used to model the short fractures as an enhancement of matrix permeability. Long fractures, on the other hand are treated as source/sink in the corresponding blocks. Periodic boundary condition is applied to the grid-block boundaries to calculate the elements of effective permeability tensor. Darcy's law and Navier-stoke's equation are applied to fluid flow in rock matrix and fractures, respectively. An important feature of this approach is that the fluid flow in matrix-fracture interface is coupled by Poisson's equation and fluid flow in the rest of the matrix is formulated by Laplace's equation. This paper also presents an innovative approach to optimization and parallelization of the model by High Performance Computing (HPC) techniques. The model has been validated against analytical results and applied to a typical case where arbitrary fractures of different sizes are assumed within the grid blocks. The effective block permeability tensors can be implemented into a reservoir simulator to calculate fluid flow through the naturally fractured reservoirs.     

TRACER RESPONSE IN PARTIALLY FRACTURED RESERVOIRS

There is considerable interest in the petroleum industry to characterize partially fractured reservoirs and to develop an increased understanding of the physics of fluid flow in these types of reservoirs. This is because fractured reservoirs have different behavior and there exist a large number of these reservoirs that are not fully developed. This paper presents a numerical simulation study that was performed to investigate the effect of rock properties on the tracer response in partially fractured reservoirs using a finite difference numerical simulator. These properties include fracture intensity, fracture porosity and matrix permeability. The functional relationships between these parameters and the calculated effective permeabilities are also investigated. Several images, each with different probability of fracture intensity, were generated randomly. Numerical simulations of single-phase tracer transport were then performed in each of the generated fractured models. Results show that the fracture intensity, fracture porosity and matrix permeability have a significant effect on the tracer response in naturally fractured reservoirs. Depending on the reservoir properties, the results also show that the flow in partially fractured reservoirs can be either matrix-dominated or fracture-dominated. The characteristics of each regime and the conditions for its occurrence are presented.     

Beneficial effects of wettability altering surfactants in oil-wet fractured reservoirs

In fractured reservoirs, an effective matrix-fracture mass transfer is required for oil recovery. Surfactants have long been considered for oil recovery enhancement, mainly in terms of their ability to reduce oil–water interfacial tension. These surfactants are effective when the fractured formations are water-wet, where capillary imbibition of surfactants from the fracture into the matrix contributes to oil recovery. However, another beneficial aspect of surfactants, namely their ability to alter wettability, remains to be explored and exploited. Surfactants capable of altering wettability can be especially beneficial in oil-wet fractured formations, where the surfactant in the fracture diffuses into the matrix and alters the wettability, enabling imbibition of even more surfactant into the matrix. This sequential process of initial diffusion followed by imbibition continues well into the matrix yielding significant enhancements in oil recovery.In order to test this hypothesis of sequential diffusion–imbibition phenomenon, Dual-Drop Dual-Crystal (DDDC) contact angle experiments have been conducted using fractured Yates dolomite reservoir fluids, two types of surfactants (nonionic and anionic) and dolomite rock substrates. A new experimental procedure was developed in which crude oil equilibrated with reservoir brine has been exposed to surfactant to simulate the matrix-fracture interactions in fractured reservoirs. This procedure enables the measurements of dynamic contact angles and oil–water interfacial tensions, in addition to providing the visual observations of the dynamic behavior of crude oil trapped in the rock matrix as it encounters the diffusing surfactant from the fractures. Both the measurements and visual observations indicate wettability alterations of the matrix surface from oil-wet to less oil-wet or intermediate wet by the surfactants. Thus this study is of practical importance to oil-wet fractured formations where surfactant-induced wettability alterations can result in significant oil recovery enhancements. In addition, this study has also identified the need to include contact angle term in the dimensionless Bond number formulations for better quantitative interpretation of rock–fluids interactions.