Capillary Transition Zone Research Articles

Oil and Water Production in a Reservoir With Significant Capillary Transition Zone

Summary Analytical and numerical methods are used to investigate the mechanism of water production in a high-permeability sandstone reservoir that has a capillary transition zone height comparable to formation thickness. Production rates are well above those for transition-zone water production alone. Consequently all wells are affected production alone. Consequently all wells are affected by coning shortly after the start of production. It is found that water cut is largely insensitive to total fluid production rate for the same recovery. The depth of well penetration and the effect of radial capillary pressure gradients are shown to be of secondary importance pressure gradients are shown to be of secondary importance in these circumstances. The predictions are confirmed by the results of a long-term pilot production test. Introduction This paper considers the mechanism of water production in a highly permeable sandstone reservoir with a 22API [0.9-g/cm3] under saturated oil and a strong edge aquifer drive. The findings are drawn from a study recently performed on the M-1 Sand reservoir of the Fanny field, performed on the M-1 Sand reservoir of the Fanny field, which is located on the eastern flank of the Oriente basin in Ecuador. M-1 Sand belongs to the Napo formation of the Cretaceous Age and consists of moderately to poorly cemented quartzose sands of high permeability. Reservoir depth is approximately 7,700 ft [2347 m]. A characteristic feature of the reservoir is the wells' predisposition to develop substantial water cuts after predisposition to develop substantial water cuts after short periods of production. Attempts have been made in the past to reduce water production by squeeze cement jobs and recompletions. However, these operations have not been effective but for the very short term and consequently the study has concentrated on attempting to define the nature of fluid movement within the drainage area of the wells. Reservoir Description M-1 Sand shows lithological features characteristic of a fluvial channel depositional environment. These features are exemplified by the Induction Electrical Survey of Well 18-B-2 (Fig. 1), which shows a basal unit 45 to 55 ft [14 to 17 m] thick, overlain by a variable number of smaller units that are separated by shale breaks and tight streaks. These upper units are of poor quality and limited lateral continuity. In contrast the basal unit contains no correlatable shale breaks although thin shales were encountered in some wells and early completion practices attempted unsuccessfully to make use of them. Because of this early experience and the absence of correlation it has been concluded that such shale breaks are of limited lateral extent and do not contribute materially to the prevention of water-cone development. prevention of water-cone development. The basal unit contains more than 90% of the original oil in place, estimated at 48 × 10(6) STB [7.6 × 10(6) stocktank m3]. Currently all wells are completed in this unit, which has provided all production to date. The upper units have been neglected for the purposes of this paper. The structural configuration of the reservoir is a faulted asymmetrical anticline of low structural amplitude. Fig. 2 represents the structure on top of the basal sand unit and shows the intersection of the oil/water contact (OWC) with this surface, giving rise to a maximum oil column of 65 to 70 ft [20 to 21 m]. A comparison of sand thickness with oil column height indicates that the base of the sand is everywhere close to the OWC and that all wells have high basal water saturations. Pressure support is by edge aquifer influx, but with strong underrunning giving behavior characteristic of a bottom aquifer. Reservoir and Fluid Properties The basal unit is variable in quality but characterized by high porosity and permeability averaging 20 to 25% and 2 to 3 darcies, respectively. Figs. 3 and 4 are capillary-pressure and relative-permeability curves representative of the basal unit. These curves are typical of a sandstone that contains large, well-interconnected pores. Sands of this unit are generally poorly cemented and friable. No fractures are evident from either cores or logs. There is no evidence of any fracture-induced effects on pressure buildup data, which correspond to a single permeability intergranular system. Average oil and water fluid properties are presented in Table 1. The oil and water viscosities at reservoir conditions are 12 and 0.35 cp [12 and 0.35 mPas] respectively, which give a very unfavorable endpoint mobility ratio. The displacement of oil by the encroaching aquifer is thus an unstable displacement and the strong underrunning of water quickly results in high producing water cuts in the wells. JPT P. 1559

The Use of Vertical Equilibrium in Two-Dimensional Simulation of Three-Dimensional Reservoir Performance

Abstract This paper discusses the use of the Vertical Equilibrium (VE) concept in simulating heterogeneous reservoirs. Where VE criteria are met, this technique allows two-dimensional (2-D) simulation of three-dimensional (3-D) problems with equivalent accuracy, and with attendant substantial savings in data preparation and machine time. The paper presents the VE concept itself and a new dimensionless group as a possible criterion for the validity of VE as applied to thick reservoirs or to reservoirs where the capillary transition zone is a small fraction of thickness. A description of the generation of the appropriate pseudo relative permeability and capillary pressure curves is permeability and capillary pressure curves is presented. presented. In addition to the dimensionless group criterion, an actual comparison of the results of an x-z cross-section and a one-dimensional (1-D) areal run with VE illustrates the validity of the VE concept. Numerical results of such a comparison along with the attendant machine-time requirements are presented. More than an order of magnitude difference in machine-time requirements was experienced. Finally, an actual field case example shows the utility of VE as applied to a reservoir containing one or multiple gas pools residing on a common aquifer. Introduction Numerical simulation of reservoir performance currently encompasses a wide variety of recovery processes, reservoir types and purposes or questions processes, reservoir types and purposes or questions to which answers are sought. A feature common to virtually all reservoir simulation studies, however, is the choice of simulation in one, two or three dimensions. Most frequently this choice is one between an areal (x-y) study and a 3-D study. While the areal study is considerably cheaper than a 3-D simulation, the validity or accuracy of the former is often questioned in light of its apparent inability to simulate flow and fluid saturation distributions in the vertical direction. Areal studies are frequently performed with little attention to or understanding of the extent to which the x-y calculations do or can be made to account for this vertical flow and fluid distribution. Previous papers describe a VE assumption or concept which leads to the definition of pseudo relative permeability and capillary pressure curves to be used in areal studies to simulate 3-D flow. A dimensionless group proposed as a criterion for the assumptions validity primarily treats the case of a reservoir where the capillary transition zone is an appreciable fraction of reservoir thickness. This paper neats the case of a reservoir where the capillary capillary transition zone is a small fraction of reservoir thickness (e.g., less than 10 percent). We propose to describe the VE concept as percent). We propose to describe the VE concept as applied to thick reservoirs or to reservoirs where capillary transition zone is a small fraction of thickness; to describe the generation of appropriate relative permeability and capillary pressure curves for such reservoirs to represent 3-D performance by 2-D areal calculations; to propose a new dimensionless group as a criterion for the VE assumptions' validity, obtained from an analysis of countercurrent gravity segregation; and finally, to present a cross-sectional vs 1-D (VE) comparison and a 2-D areal field case study. THE VERTICAL EQUILIBRIUM CONCEPT Most oil and gas reservoirs extend distances areally which are at least two orders of magnitude greater than reservoir thickness. Viewed in perspective, these reservoirs appear as "blankets" perspective, these reservoirs appear as "blankets" For a variety of reasons, some valid and some invalid, numerical simulations of such reservoirs are performed occasionally in three dimensions as opposed to only two areal (x-y) dimensions. SPEJ P. 63

Two-Phase Flow in Two-Dimensional Systems - Effects of Rate, Viscosity and Density on Fluid Displacement in Porous Media

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 81–87. Abstract This report is concerned with fluid displacement in porous media, in those cases where viscous and gravitational forces control the displacement. Such a system would usually be found in a sand body of large physical dimensions such as an oil reservoir, although it is possible to create such a system in the laboratory. It is shown that the position of the fluid interface can be predicted by numerical calculations using a basic idea presented by Dietz. Fluid flow is considered in a vertical plane in a homogeneous, porous medium of sufficient thickness that the capillary transition zone is small in comparison with the total reservoir. A theory developed by Dietz is used to make numerical calculations of the position of the fluid interface. The results for several conditions are compared with scaled model experiments. The results show that, for gas drive in a reservoir of steep dip, a relatively low flow rate can displace large volumes of oil before gas breakthrough. On the other hand, water injection at favorable mobility ratio and low dip may show best performance at high rates. Water tends to underride the oil and, given sufficient time, well break through without much oil displacement. For certain conditions, which include relatively low flow rate, the interface is a straight line and its behavior is simple to calculate. At higher flow rates, the interface is unstable, and a numerical solution was programed for an automatic computer. In general, good agreement is shown between the fluid model and the computed results so long as gravitational forces have control. For a water drive at very unfavorable mobility ratio, many small water fingers appear. These viscous fingers are not controlled by the relatively small gravitational forces. When viscous fingering becomes the controlling factor, the mathematical model is oversimplified, and results do not check the fluid flow model.