Pressure Behavior Of Wells Research Articles

Estimation of characteristics of naturally fractured reservoirs by pressure transient analysis

PurposeThis paper aims to analyze the pressure behavior in dual porosity reservoirs using different techniques in an attempt to correctly characterize reservoir properties. Pressure transient tests in naturally fractured reservoirs often exhibit non-uniform responses.Design/methodology/approachThe pressure transient tests in naturally fractured reservoirs were analyzed using conventional semi-log analysis, type curve matching (using commercial software) and Tiab’s direct synthesis (TDS) technique. In addition, the TDS method was applied in case of a naturally fractured formation with a vertical hydraulic fracture. These techniques were applied to a single-layer, naturally fractured reservoir under pseudosteady state matrix flow. By studying the unique characteristics of the different flow regimes appear on the pressure and pressure derivative curves, various reservoir characteristics can be obtained such as permeability, skin factor and fracture properties.FindingsFor naturally fractured reservoirs, a comparison between the results semi-log analysis, software matching and TDS method is presented. In case of wellbore storage, early time flow regime can be obscured that lead to incomplete semi-log analysis. Furthermore, the type curve matching usually gives a non-uniqueness solution, as it needs all the flow regimes to be observed. However, the direct synthesis method used analytical equation to calculate reservoir and well parameters without type curve matching. For naturally fractured reservoirs with a vertical fracture, the pressure behavior of wells crossed by a uniform flux and infinite conductivity fracture is analyzed using TDS technique. The different flow regimes on the pressure derivative curve were used to calculate the fracture half-length in addition to other reservoir properties.Originality/valueThe results of different field cases showed that TDS technique offers several advantages compared to semi-log analysis and type curve matching. It can be used even if some flow regimes are not observed. Direct synthesis results are accurate compared to the available core data and the software matching results. It can be used to confirm the software matching results and to give reliable reservoir characteristics when there is lack of data.

Analysis of Pressure Transient Tests in Naturally Fractured Reservoirs

Pressure transient tests in naturally fractured reservoirs often exhibit non-uniform responses. Different techniques can be used to analyze the pressure behavior in dual porosity reservoirs in an attempt to correctly characterize reservoir properties. In this paper, the pressure transient tests in naturally fractured reservoirs were analyzed using conventional semi-log analysis, type curve matching (using commercial software) and Tiab’s direct synthesis (TDS) technique. In addition, the TDS method was applied in case of a naturally fractured formation with a vertical hydraulic fracture. These techniques were applied to a single layer naturally fractured reservoir under pseudosteady state matrix flow. By studying the unique characteristics of the different flow regimes appear on the pressure and pressure derivative curves, various reservoir characteristics can be obtained such as permeability, skin factor, and fracture properties. For naturally fractured reservoirs, a comparison between the results semi-log analysis, software matching, and TDS method is presented. In case of wellbore storage, early time flow regime can be obscured that lead to incomplete semi-log analysis. Furthermore, the type curve matching usually gives a non-uniqueness solution as it needs all the flow regimes to be observed. However, the direct synthesis method used analytical equation to calculate reservoir and well parameters without type curve matching. For naturally fractured reservoirs with a vertical fracture, the pressure behavior of wells crossed by a uniform flux and infinite conductivity fracture is analyzed using TDS technique. The different flow regimes on the pressure derivative curve were used to calculate the fracture half-length in addition to other reservoir properties. The results of different cases showed that TDS technique offers several advantages compared to semi-log analysis and type curve matching. It can be used even if some flow regimes are not observed. Direct synthesis results are accurate compared to the available core data and the software matching results.

Pressure transient analysis of arbitrarily shaped fractured reservoirs

Reservoir boundary shape has a great influence on the transient pressure response of oil wells located in arbitrarily shaped reservoirs. Conventional analytical methods can only be used to calculate transient pressure response in regularly shaped reservoirs. Under the assumption that permeability varies exponentially with pressure drop, a mathematical model for well test interpretation of arbitrarily shaped deformable reservoirs was established. By using the regular perturbation method and the boundary element method, the model could be solved. The pressure behavior of wells with wellbore storage and skin effects was obtained by using the Duhamel principle. The type curves were plotted and analyzed by considering the effects of permeability modulus, arbitrary shape and impermeable region.

Constant rate solutions for a fractured well with an asymmetric fracture

This paper presents solutions for the pressure response on hydraulically fractured wells flowing at constant flow rate through an asymmetric vertical fracture. The pressure behavior of wells intercepting asymmetric fractures of both infinite and finite conductivity was investigated by solving numerically and analytically the mathematical model. The new solutions developed for the dimensionless wellbore pressure under production at constant flow rate are presented in terms of an asymmetry factor ξ. New curves for these systems were generated and the deviation from the classical solution was readily detected. Some qualitative criteria to interpret the intensity of this effect are provided. Results of our investigation indicated that at early times for fractures of moderate conductivity ( C D<5) the characteristic slope of one fourth is present, except for cases of strong asymmetry (0.85< ξ≤1) where no evidence of straight line having one fourth slope was observed. However, it was also detected that at intermediate fracture conductivities (5< C D<50), even the case of complete asymmetry shows the characteristic slope of one fourth. It was also observed that as the asymmetry factor increases, the end of the bilinear flow occurs earlier. Our results are relevant in improving the fracture characterization of fractured wells.

Wellbore Storage and Skin Effects During the Transient Flow of Non-Newtonian Power-Law Fluids in Porous Media

AbstractA model recently presented by Ikoku and Ramey for non-Newtonian power-law flow in porous media was extended to flow in finite circular reservoirs. A constant flow rate was stipulated at the wellbore, and two boundary conditions were considered: no-flow outer boundary and constant-pressure outer boundary. The results were used to derive a new expression for the stabilization time for power-law flow in porous media.Wellbore storage and skin effects always distort the transient pressure behavior of wells in petroleum reservoirs. It is important to investigate the consequences of these phenomena and be able to interpret real well test information. This paper considers the effects of skin and wellbore storage on the transient flow of non-Newtonian power-law fluids in petroleum reservoirs.A new numerical wellbore storage simulator was used to study the effects of skin and wellbore storage during the transient flow of power-law fluids in infinitely large and finite circular reservoirs. Results are presented both in tabular form and as log-log graphs of dimensionless pressures vs dimensionless times. The log-log graphs may be used in a type-curve matching procedure to analyze short-time well test data.The early period is dominated by wellbore storage effect. A new expression was obtained for the duration of wellbore storage effect when skin exists for infinitely large reservoirs. This criterion is not valid for finite circular reservoirs with no-flow outer boundary or constant-pressure outer boundary. Results indicate that there is no apparent end of wellbore storage effect for the no-flow outer boundary condition for the values of external radius presented. New relationships were derived for skin presented. New relationships were derived for skin factor and "effective well radius" for power-law flow.

Applied Pressure Analysis for Fractured Wells

A number of recent studies have resulted in an increased understanding of fractured-well behavior. Two of these studies provide new information on applying log-log type-curve matching procedures to pressure data obtained from fractured wells. This paper compares the applicability of type-curve and conventional semilog methods. Introduction The pressure behavior of fractured wells is of considerable interest because of the large number of wells that intersect fractures. As a result of a number of studies, an increased understanding of fractured-well behavior has been obtained. Although the shape of actual fractures is undoubtedly complicated, most studies assume that real fractures may be ideally visualized as planes intersecting the wellbore. It is generally believed that hydraulic fracturing normally results in one vertical fracture, the plane of which includes the wellbore; however, it is also plane of which includes the wellbore; however, it is also agreed that, if formations are shallow, horizontal fractures can result. The specific orientation of the fracture plane with respect to the wellbore may be subject to debate if the well intersects a natural fracture. Two recent studies provide new information whereby log-log type-curve matching procedures may be applied to pressure data obtained from fractured (vertical or horizontal) wells. These studies also showed that, under conditions that would appear normal, it is likely that horizontal and vertical fractures would affect well behavior sufficiently such that the orientation, vertical vs horizontal, could be determined. The purpose of this paper is to illustrate the applicability of the results paper is to illustrate the applicability of the results obtained in Refs. 1 and 2. Vertically Fractured Wells As mentioned in Ref. 1, new solutions for the transient pressure behavior of a vertically fractured well were pressure behavior of a vertically fractured well were needed because earlier studies were not blended for type-curve analysis. This study examined two boundary conditions on the fracture plane. The first solution, like earlier studies, assumed that the fracture plane is of infinite conductivity. This implies that there is no pressure drop along the fracture plane at any instant in pressure drop along the fracture plane at any instant in time. The second solution, called the uniform-flux solution, gives the appearance of a high, but not infinite, conductivity fracture. (This boundary condition implies that the pressure along the fracture plane varies.) Application of these solutions to field data indicates that the uniform-flux solution usually matches pressure behavior of wells intersecting natural fractures better than does the infinite-conductivity solution. On the other hand, the infinite-conductivity solution often matches the behavior of hydraulically fractured, propped fractured wells better than does the uniform-flux solution. The Infinite-Conductivity Vertical Fracture in A Square Drainage Region Gringarten et al. have presented drawdown data for an infinite-conductivity vertical fracture located at the center of a closed-square drainage region and producing a lightly compressible constant-viscosity fluid at a constant rate. The solution for the producing pressure at time t is kh PwD (tD, Xe/Xf) = (pi - pwf),......(1) 141,2 qB where 0.000264 kt tD = .........................(2) c Xf2 JPT P. 887

The Effect of Vertical Fractures on Transient Pressure Behavior of Wells

Abstract Transient pressure behavior of wells intersected by a single vertical fracture has been examined by means of a heat flow analogy. Results are correlated in terms of dimensionless pressure change and dimensionless transient time. The resulting curves are found to lie between the dimensionless curves for a cylindrical well and a line source when effective well radius is expressed as one-fourth of the total fracture length. Results are also shown for various degrees of afterflow. Use of the curves provides a means of determining reservoir permeability, wellbore radius, and thereby fracture length, even when the final slope of the transient curve is not obtained. Superposition of curves may be used to confirm existence of vertical fractures in the reservoir adjacent to the well or to indicate a damaged zone on the fracture face. Introduction Hydraulic fracturing has become a standard well completion practice for the purpose of increasing flow. Results are normally gauged in terms of some sort of "stabilized" flow rate established before and after the treatment. This procedure may be misleading because pressures in or around the well do not become "stabilized" during the test period. Transient pressure tests on fractured wells can overcome the objections to stabilized flow tests by indicating when a stable pressure gradient is reached. In addition, the transient pressure tests can be used to determine formation flow capacity and effective wellbore radius. The effective wellbore radius may be used as a measure of the success of the fracturing operation. The slope and position of the transient pressure-log time curve may be used to determine the flow capacity and wellbore size after sufficient lapse of time so that the pressure gradient in the vicinity of the fractures becomes constant. However, in tight reservoirs or in short tests this condition may not be reached. Presence of the fractures in tight reservoirs may cause a constantly increasing slope to the transient pressure curve. If this slope is picked too soon, formation flow capacity will appear high and the fracture size will appear too small. This paper is intended to clarify the early transient behavior of vertically fractured wells. It shows how formation flow capacity and wellbore size can be determined even though the maximum slope of the transient pressure curve is not obtained during the test. BASIC THEORY Development of the techniques of transient pressure analysis for wells has been summarized by Perrine. He reviews the various definitions of wellbore effects such as skin effect, productivity ratio, damage factor and condition ratio.In the present paper, use of these terms is avoided by defining an effective wellbore size. For the fractured well this effective wellbore size is larger than the actual wellbore. Assumptions made are constant flow rate at the well, constant fluid compressibility, constant fluid mobility and uniform porosity and formation thickness. From the basic differential equations of flow, two different solutions may be obtained. The first, the line source solution, is commonly used in transient pressure analysis. It expresses the change in pressure at any radius due to withdrawal or injection of fluid at the line source from an infinite reservoir at uniform initial pressure. This equation, in oil field units, is (1) or, after a long time: (2) The second solution frequently used in transient pressure analysis is based on a finite reservoir. In this case, flow between the reservoir boundary and the well has occurred long enough for a pressure gradient constant in time to exist. Shut-in of the well results in pressure change in the well which, after a sufficiently long time, exhibits a straight-line behavior when plotted against the log of time. For a constant pressure at a circular, concentric drainage boundary with radius, the difference in well pressure and drainage pressure in the straight-line portion is approximately: (3) Expressing the initial pressure difference at steady flow as (4) the resulting change in well pressure by combining Eqs. 3 and 4 is (5) Comparison of Eq. 5 with Eq. 2 shows that they are identical if in either case represents the change in well pressure following the interruption of the stabilized reservoir pressure condition. JPT P. 1365^