Two-Phase Flow Interporosity Effects on Pressure Transient Test Response in Naturally Fractured Reservoirs

1991 ◽  
Author(s):  
A.S. Al-Bemani ◽  
I. Ershaghi
Keyword(s):  
Two Phase Flow ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Phase Flow ◽  
Two Phase ◽  
Pressure Transient ◽  
Test Response ◽  
Naturally Fractured ◽  
Pressure Transient Test

Upscaling two-phase flow in naturally fractured reservoirs

AAPG Bulletin ◽  
2009 ◽  
Vol 93 (11) ◽  
pp. 1621-1632 ◽  
Author(s):  
Stephan K. Matthäi ◽  
Hamidreza M. Nick
Keyword(s):  
Two Phase Flow ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Phase Flow ◽  
Two Phase ◽  
Naturally Fractured

scholarly journals A Two-Phase Flow Model for Pressure Transient Analysis of Water Injection Well considering Water Imbibition in Natural Fractured Reservoirs

2018 ◽  
Vol 2018 ◽  
pp. 1-12
Author(s):  
Mengmeng Li ◽  
Qi Li ◽  
Gang Bi ◽  
Jiaen Lin
Keyword(s):  
Transient Analysis ◽  
Two Phase Flow ◽  
Fractured Reservoirs ◽  
Water Injection ◽  
Injection Well ◽  
Phase Flow ◽  
Two Phase ◽  
Pressure Transient Analysis ◽  
Pressure Transient ◽  
Water Imbibition

The pressure injection falloff test for water injection well has the advantages of briefness and convenience, with no effect on the oil production. It has been widely used in the oil field. Tremendous attention has been focused on oil-water two-phase flow model based on the Perrine-Martin theory. However, the saturation gradient is not considered in the Perrine-Martin method, which may result in errors in computation. Moreover, water imbibition is important for water flooding in natural fractured reservoirs, while the pressure transient analysis model has rarely considered water imbibition. In this paper, we proposed a semianalytical oil-water two-phase flow imbibition model for pressure transient analysis of a water injection well in natural fractured reservoirs. The parameters in this model, including total compressibility coefficient, interporosity flow coefficient, and total mobility, change with water saturation. The model was solved by Laplace transform finite-difference (LTFD) method coupled with the quasi-stationary method. Based on the solution, the model was verified by the analytical method and a field water injection test. The features of typical curves and the influences of the parameters on the typical curves were analyzed. Results show that the shape of pressure curves for single phase flow resembles two-phase flow, but the position of the two-phase flow curves is on the upper right of the single phase flow curves. The skin factor and wellbore storage coefficient mainly influence the peak value of the pressure derivatives and the straight line of the early period. The shape factor has a major effect on the position of the “dip” of pressure derivatives. The imbibition rate coefficient mainly influences the whole system radial flow period of the curves. This work provides valuable information in the design and evaluation of stimulation treatments in natural fractured reservoirs.

Numerical Simulation of Water-Oil Flow in Naturally Fractured Reservoirs

1976 ◽  
Vol 16 (06) ◽  
pp. 317-326 ◽  
Author(s):  
H. Kazemi ◽  
L.S. Merrill ◽  
K.L. Porterfield ◽  
P.R. Zeman
Keyword(s):  
Finite Difference ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Phase Flow ◽  
Two Phase ◽  
Flow Equations ◽  
Difference Grid ◽  
Naturally Fractured ◽  
Matrix Blocks ◽  
The Matrix

Abstract A three-dimensional, multiple-well, numerical simulator for simulating single- or two-phase flow of water and oil is developed for fractured reservoirs. The simulator equations are two-phase flow extensions of the single-phase flow equations derived by Warren and Root. The simulator accounts for relative fluid mobilities, gravity force, imbibition, and variation in reservoir properties. The simulator handles uniformly and nonuniformly properties. The simulator handles uniformly and nonuniformly distributed fractures and for no fractures at all. The simulator can be used to simulate the water-oil displacement process and in the transient testing of fractured reservoirs. The simulator was used on the conceptual models of two naturally fractured reservoirs: a quadrant of a five-spot reservoir and a live-well dipping reservoir with water drive. These results show the significance of imbibition in recovering oil from the reservoir rock in reservoirs with an interconnected fracture network. Introduction Numerical reservoir simulators are being used extensively to simulate multiphase, multicomponent flow in "single-porosity" petroleum reservoirs. Such simulators generally cannot be used to petroleum reservoirs. Such simulators generally cannot be used to study flow behavior in the naturally fractured reservoirs that are usually classified as double-porosity systems. In the latter, one porosity is associated with the matrix blocks and the other porosity is associated with the matrix blocks and the other represents that of the fractures and vugs. If fractures provide the main path for fluid flow from the reservoir, then usually the oil from the matrix blocks flows into the fracture space, and the fractures carry the oil to the wellbore. When water comes in contact with the oil zone, water may imbibe into the matrix blocks to displace oil. Combinations of large flow rates, low matrix permeability, and weak imbibition may result in water fingering permeability, and weak imbibition may result in water fingering through the fractures into the wellbore. Once fingering of water occurs, the water-oil ratio may increase to a large value. None of the published theoretical work on multiphase flow in naturally fractured systems has been applied directly to the simulation of a reservoir as a whole. Usually, only a segment of the reservoir was simulated, and the results were extrapolated to the entire reservoir. To simulate a reservoir as a whole, we have developed a mathematical formulation of the flow problem that has been programmed as a three-dimensional, compressible, water-oil reservoir simulator. The simulator equations are two-phase flow extensions of the single-phase flow equations derived by Warren and Root. The theory is based on the assumption of double porosity at each point in a manner that the fractures form a continuum filled by the noncontinuous matrix blocks. In other words, the fractures are the boundaries of the matrix blocks. The flow equations are solved by a finite difference method. A typical finite-difference grid cell usually contains one or several matrix blocks. In this case, all the matrix blocks within the finite-difference grid cell have the same pressure and saturation. Gravity segregation within individual matrix blocks is not calculated, but the over-all gravity segregation from one grid cell to another is accounted for. In many practical problems, this approximation is acceptable. In some situations, a matrix block encloses several finite-difference grid cells. In this case, the gravity segregation within the matrix block is calculated. To include heterogeneity, a redefinition of local porosities and permeabilities provides a method for simulating situations where part of the reservoir is fractured and where part is not fractured. The above description points to the complexity of the situations that one encounters. Therefore, the judicious choice of the number of finite difference grid cells with respect to the number of matrix blocks becomes a critical engineering decision. Later sections will provide insight to alleviate such decisions. SPEJ P. 317

Pressure-Transient Tests and Flow Regimes in Fractured Reservoirs

2015 ◽  
Vol 18 (02) ◽  
pp. 187-204 ◽  
Author(s):  
Fikri Kuchuk ◽  
Denis Biryukov
Keyword(s):  
History Matching ◽  
Fractured Reservoirs ◽  
Flow Regimes ◽  
Naturally Fractured Reservoirs ◽  
Dual Porosity ◽  
Hydraulic Fractures ◽  
Fractured Reservoir ◽  
Pressure Transient ◽  
Matrix Block ◽  
Naturally Fractured

Summary Fractures are common features in many well-known reservoirs. Naturally fractured reservoirs include fractured igneous, metamorphic, and sedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones, and are connected to numerous fractures that have varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (rather than connected-network dual-porosity systems). In this paper, we investigate the pressure-transient behavior of continuously and discretely naturally fractured reservoirs with semianalytical solutions. These fractured reservoirs can contain periodically or arbitrarily distributed finite- and/or infinite-conductivity fractures with different lengths and orientations. Unlike the single-derivative shape of the Warren and Root (1963) model, fractured reservoirs exhibit diverse pressure behaviors as well as more than 10 flow regimes. There are seven important factors that dominate the pressure-transient test as well as flow-regime behaviors of fractured reservoirs: (1) fractures intersect the wellbore parallel to its axis, with a dipping angle of 90° (vertical fractures), including hydraulic fractures; (2) fractures intersect the wellbore with dipping angles from 0° to less than 90°; (3) fractures are in the vicinity of the wellbore; (4) fractures have extremely high or low fracture and fault conductivities; (5) fractures have various sizes and distributions; (6) fractures have high and low matrix block permeabilities; and (7) fractures are damaged (skin zone) as a result of drilling and completion operations and fluids. All flow regimes associated with these factors are shown for a number of continuously and discretely fractured reservoirs with different well and fracture configurations. For a few cases, these flow regimes were compared with those from the field data. We performed history matching of the pressure-transient data generated from our discretely and continuously fractured reservoir models with the Warren and Root (1963) dual-porosity-type models, and it is shown that they yield incorrect reservoir parameters.

Sign in / Sign up

Export Citation Format

Share Document