Transition Zone Behaviour: The Measurement of Bounding and Scanning Relative Permeability and Capillary Pressure Curves at Reservoir Conditions for a Giant Carbonate Reservoir

2014 ◽  
Author(s):  
Michael Spearing ◽  
Medhat K. Abdou ◽  
Gregory Azuka Azagbaesuweli ◽  
Mohammed Zubair Kalam
Keyword(s):  
Capillary Pressure ◽  
Transition Zone ◽  
Relative Permeability ◽  
Carbonate Reservoir ◽  
Reservoir Conditions ◽  
Capillary Pressure Curves

Improved Characterization and Modeling of Capillary Transition Zones in Carbonate Reservoirs

2007 ◽  
Vol 10 (02) ◽  
pp. 191-204 ◽  
Author(s):  
Shehadeh K. Masalmeh ◽  
Issa M. Abu-Shiekah ◽  
Xudong Jing
Keyword(s):  
Capillary Pressure ◽  
Transition Zone ◽  
Relative Permeability ◽  
Dynamic Properties ◽  
Carbonate Reservoirs ◽  
Oil Saturation ◽  
Transition Zones ◽  
Heterogeneous Reservoirs ◽  
Oil Water ◽  
Capillary Pressure Curves

Summary An oil/water capillary transition zone often contains a sizable portion of a field's initial oil in place, especially for those carbonate reservoirs with low matrix permeability. The field-development plan and ultimate recovery may be influenced heavily by how much oil can be recovered from the transition zone. This in turn depends on a number of geological and petrophysical properties that influence the distribution of initial oil saturation (Sor) against depth, and on the rock and fluid interactions that control the residual oil saturation (Sor), capillary pressure, and relative permeability characteristics as a function of initial oil saturation. Because of the general lack of relevant experimental data and the insufficient physical understanding of the characteristics of the transition zone, modeling both the static and dynamic properties of carbonate fields with large transition zones remains an ongoing challenge. In this paper, we first review the transition-zone definition and the current limitations in modeling transition zones. We describe the methodology recently developed, based on extensive experimental measurements and numerical simulation, for modeling both static and dynamic properties in capillary transition zones. We then address how to calculate initial-oil-saturation distribution in the carbonate fields by reconciling log and core data and taking into account the effect of reservoir wettability and its impact on petrophysical interpretations. The effects of relative permeability and imbibition capillary pressure curves on oil recovery in heterogeneous reservoirs with large transition zones are assessed. It is shown that a proper description of relative permeability and capillary pressure curves including hysteresis, based on experimental special-core-analysis (SCAL) data, has a significant impact on the field-performance predictions, especially for heterogeneous reservoirs with transition zones. Introduction The reservoir interval from the oil/water contact (OWC) to a level at which water saturation reaches irreducible is referred to as the capillary transition zone. Fig. 1 illustrates a typical capillary transition zone in a homogeneous reservoir interval within which both the oil and water phases are mobile. The balance of capillary and buoyancy forces controls this so-called capillary transition zone during the primary-drainage process of oil migrating into an initially water-filled reservoir trap. Because the water-filled rock is originally water-wet, a certain threshold pressure must be reached before the capillary pressure in the largest pore can be overcome and the oil can start to enter the pore. Hence, the largest pore throat determines the minimum capillary rise above the free-water level (FWL). As shown schematically in Fig. 2, close to the OWC, the oil/water pressure differential (i.e., capillary pressure) is small; therefore, only the large pores can be filled with oil. As the distance above the OWC increases, an increasing proportion of smaller pores are entered by oil owing to the increasing capillary pressure with height above the FWL. The height of the transition zone and its saturation distribution is determined by the range and distribution of pore sizes within the rock, as well as the interfacial-force and density difference between the two immiscible fluids.

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

1971 ◽  
Vol 11 (01) ◽  
pp. 63-71 ◽  
Author(s):  
K.H. Coats ◽  
J.R. Dempsey ◽  
J.H. Henderson
Keyword(s):  
Capillary Pressure ◽  
Transition Zone ◽  
Relative Permeability ◽  
Three Dimensional ◽  
Three Dimensions ◽  
Dimensionless Group ◽  
Machine Time ◽  
Vertical Equilibrium ◽  
Time Requirements ◽  
Capillary Pressure Curves

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

Simultaneous Interpretation of Three-Phase Relative Permeability and Capillary Pressure for a Tight Carbonate Reservoir From Wireline Formation Testing

2019 ◽  
Vol 142 (6) ◽  
Author(s):  
Xiangnan Liu ◽  
Daoyong Yang
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
History Matching ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Fluid Saturation ◽  
Three Phase ◽  
Tight Carbonate ◽  
Wet Condition ◽  
Oil Gas

Abstract In this paper, techniques have been developed to interpret three-phase relative permeability and water–oil capillary pressure simultaneously in a tight carbonate reservoir from numerically simulating wireline formation tester (WFT) measurements. A high-resolution cylindrical near-wellbore model is built based on a set of pressures and flow rates collected by dual packer WFT in a tight carbonate reservoir. The grid quality is validated, the effective thickness of the WFT measurements is examined, and the effectiveness of the techniques is confirmed prior to performing history matching for both the measured pressure drawdown and buildup profiles. Water–oil relative permeability, oil–gas relative permeability, and water–oil capillary pressure are interpreted based on power-law functions and under the assumption of a water-wet reservoir and an oil-wet reservoir, respectively. Subsequently, three-phase relative permeability for the oil phase is determined using the modified Stone II model. Both the relative permeability and the capillary pressure of a water–oil system interpreted under an oil-wet condition match well with the measured relative permeability and capillary pressure of a similar reservoir rock type collected from the literature, while the relative permeability of an oil–gas system and the three-phase relative permeability bear a relatively high uncertainty. Not only is the reservoir determined as oil-wet but also the initial oil saturation is found to impose an impact on the interpreted water relative permeability under an oil-wet condition. Changes in water and oil viscosities and mud filtrate invasion depth affect the range of the movable fluid saturation of the interpreted water–oil relative permeabilities.

scholarly journals Pore-scale X-ray imaging with measurement of relative permeability, capillary pressure and oil recovery in a mixed-wet micro-porous carbonate reservoir rock

Fuel ◽  
2020 ◽  
Vol 268 ◽  
pp. 117018 ◽  
Author(s):  
Amer M. Alhammadi ◽  
Ying Gao ◽  
Takashi Akai ◽  
Martin J. Blunt ◽  
Branko Bijeljic
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Pore Scale ◽  
X Ray ◽  
X Ray Imaging

Improvements in the Selection Criteria for the Representative Special Core Analysis Samples

2006 ◽  
Vol 9 (06) ◽  
pp. 647-653 ◽  
Author(s):  
Shameem Siddiqui ◽  
Taha M. Okasha ◽  
James J. Funk ◽  
Ahmad M. Al-Harbi
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Selection Criteria ◽  
Sample Selection ◽  
Upper Jurassic ◽  
Carbonate Reservoir ◽  
Core Analysis ◽  
Core Samples ◽  
Representative Samples ◽  
Special Core Analysis

Summary The data generated from special-core-analysis (SCAL) tests have a significant impact on the development of reservoir engineering models. This paper describes some of the criteria and tests required for the selection of representative samples for use in SCAL tests. The proposed technique ensures that high-quality core plugs are chosen to represent appropriate flow compartments or facies within the reservoir. Visual inspection and, sometimes, computerized tomography (CT) images are the main tools used for assessing and selecting the core plugs for SCAL studies. Although it is possible to measure the brine permeability (kb), there is no direct method for determining the porosity (f) of SCAL plugs without compromising their wettability. Other selection methods involve using the conventional-core-analysis data (k and f) on "sister plugs" as a general indicator of the properties of the SCAL samples. A selective technique ideally suited for preserved or "native-state" samples has been developed to identify reservoir intervals with similar porosity/permeability relationships. It uses a combination of wireline log, gamma scan, quantitative CT, and preserved-state brine-permeability data. The technique uses these data to calculate appropriate depth-shifted reservoir-quality index (RQI) and flow-zone indicator (FZI) data, which are then used to select representative plug samples from each reservoir compartment. As an example application, approximately 400 SCAL plugs from an Upper Jurassic carbonate reservoir in the Middle East were tested using the selection criteria. This paper describes the step-by-step procedure to select representative plugs and criteria for combining the plugs for meaningful SCAL tests. Introduction The main goal of coring is to retrieve core samples from a well to get the maximum amount of information about the reservoir. Core samples collected provide important petrophysical, petrographic, paleontological, sedimentological, and diagenetic information. From a petrophysical point of view, the whole-core and plug samples typically undergo the following tests: CT scan, gamma scan, conventional tests, SCAL tests, rock mechanics, and other special tests. The data are combined to get information on heterogeneity, depth shift between core and log data, whole-core and plug porosity and permeability, porosity/permeability relationship, fluid content (Dean-Stark), RQI, FZI, wettability, relative permeability, capillary pressure, stress/strain relationship, and compressibility. The petrophysical data generated in this way play important roles in reservoir characterization and modeling, log calibration, reservoir simulation, and overall field production and development planning. Among all the petrophysical tests, the SCAL tests (which include wettability, capillary pressure, and relative permeability determination) are critical and time-consuming. A reservoir-condition relative permeability test can sometimes run for several months when mimicking the actual flow mechanisms taking place in the field. Therefore, it is very important to design these tests properly and, in particular, to select the samples that ensure meaningful results. In short, the samples must be "representative samples," which can capture the overall variability within the reservoir in a more scientific way. Unfortunately, the most important aspect of all SCAL procedures, the sample selection, is one of those least discussed. According to Corbett et al. (2001), API's RP40 (Recommended Practices for Core Analysis) makes very little reference to sampling; similarly, textbooks on petrophysics do not have sections on sampling. The Corbett et al. paper reviewed the statistical, petrophysical, and geological issues for sampling and proposed a series of considerations. This has led to the development of a method (Mohammed and Corbett 2002) using hydraulic units in a relatively simple clastic reservoir. In this paper, some issues related to sample-selection criteria (with special focus on carbonate reservoirs) will be discussed. A large data set of conventional, whole-core, and special-core analyses on a well in an Upper Jurassic carbonate reservoir was used to characterize representative samples for SCAL tests.

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