L.F. Koederitz

Relative permeability of petroleum reservoirs

This book enables petroleum reservoir engineers to predict the flow of fluids within a hydrocarbon deposit. Laboratory techniques are described for both steady-state and unsteady state measurements, and the calculation of relative permeability from field data is illustrated. A discussion of techniques for determing wettability is included, along with theoretical and empirical methods for the calculation of relative permeability, and prediction techniques. Contents include: Measurement of Rock Relative Permeability; Two-Phase Relative Permeability; Factors Affecting Two-Phase Relative Permeability; Three-Phase Relative Permeability; and Index.

Empirical equations for estimating two-phase relative permeability in consolidated rock

The permeability of a porous rock to a saturating fluid is determined by the geometry of the rock pore system and not by the physical properties of the fluid. This general statement assumes the absence of a chemical reaction between the rock and fluid, and a single homogeneous fluid phase. If more than one fluid is present, permeability to any fluid depends not only on the geometry of the rock pore system but also on the fraction and distribution of each fluid phase, the interfacial tensions, the saturation history, and possibly other factors. Although direct prediction of relative permeability from theoretical considerations is a worthwhile objective, the most successful techniques for making these predictions are essentially empirical. Rather than attempting a theoretical solution to the problem, the authors have used an empirical approach. In their study a rather extensive set of relative permeability data was compiled, and conventional stepwise linear regression analysis techniques were used, to develop prediction equations from the laboratory data. This procedure is designed to produce a satisfactory fit of the data with a minimum of terms in the equation; it is not intended to provide the best possible data fit.

Unsteady-State Spherical Flow With Storage and Skin

The general problem of radial-spherical flow in homogeneous and isotropic reservoirs inclusive of wellbore storage and skin effects is presented. New dimensionless space (r /SUB D/ ) and time (t /SUB D/ ) groups are introduced to facilitate the classical transformation from radial flow in the sphere to linear flow in the rod. The solutions obtained are then extended to include wellbore phase redistribution effects. The very early-time behavior of spherical reservoirs was found to be identical to cylindrical reservoirs. New type curves for fully developed spherical flow inclusive of wellbore storage, skin effect and wellbore phase redistribution effects were developed. The general appearance of these curves is similar to those currently used for perfect radial flow, and since the correlating parameters on the new curves are identical to those of References 24 and 31 the matching techniques are the same. A new equation is also developed to approximate the duration of wellbore and near-wellbore effects under spherical flow.

Effect of Texture on Petrophysical Properties of Dolomite: Evidence From the Cambrian-Ordovician of Southeastern Missouri

Two basic textural types of dolomite exist: (1) planar dolomite, which forms in both shallow and burial diagenetic environments; and (2) nonplanar dolomite, which develops at temperatures in excess of 50°C in the burial environment by dolomitization of limestone or neomorphic recrystallization of preexisting dolomite. Variation in dolomite texture is the result of variation in the diagenetic history of the rock unit. Cambrian-Ordovician dolomites were collected from core and outcrop throughout southeastern Missouri. Effective porosity and permeability were determined using helium porosimetry and gas permeability. Total porosity and texture type were determined from thin-section analysis. Pore throat geometry was evaluated using mercury capillary pressure curves and s anning electron microscope (SEM) examination of pore casts. Two porosity-permeability populations exist for planar dolomite: (1) planar-e (euhedral) dolomite, where permeability strongly varies with porosity; and (2) planar-s (subhedral) dolomite, where permeability is lower than in planar-e dolomite and does not increase as rapidly with increasing porosity. In planar-e dolomite, capillary pressure data and SEM pore cast analysis indicate uniform pore throat sizes and well-interconnected pore systems. Uniform throat sizes and well-connected pore systems do not exist in planar-s dolomite. This most likely is due to continued cementation during diagenesis. Nonplanar dolomite shows no significant correlation between permeability and porosity. Capillary pressure curves and SEM examination of pore casts of nonplanar dolomite indicate nonexistent to very poorly interconnected pore systems and large pore to throat ratios. The petrophysical properties of dolomite petroleum reservoirs and aquifers vary depending on the petrographic texture of the dolomite. Understanding diagenetic history, and crystal textures that may result because of various diagenetic conditions, can be a predictor of petrophysical properties of dolomite reservoirs.

Developing a Proficient Relative Permeability Resource From Historical Data

Having reliable and readily accessible relative permeability information is a problem for many reservoir engineers. In the absence of laboratory measured data or in the case when a more general representation of fluid flow in a reservoir is needed, empirical relative permeability correlations become useful. 416 sets of relative permeability data were obtained from published literature and various industry sources, and were modified to fit a common format. The central database thus constructed allows relative permeability data to be easily retrieved and processed. Categorizing and modifying the original data for applicability to similar systems is considered, allowing for variations in connate water, residual oil, and critical gas saturations. Information such as fluid type, wettability, lithology, geographical location, and method of measurement is used to search applicable results. A linear regression model approach is employed to develop prediction equations for water-oil, gas-oil, gas-water, and gascondensate relative permeability from the measured data. Improved equations were developed for water-oil and gas-oil systems based on formation type and wettability. Additionally, general equations for gas-condensate and gas-water systems were formulated. Craig’s rule for determining wettability has been modified to include a wider range of relative permeability data. Available data has increased significantly since the last published work in this area. The prediction equations are compared with previously published correlations. The database and prediction equations may be downloaded at no charge from a University of Missouri-Rolla web site.

Application of an Area of Review Variance Methodology to the San Juan Basin, New Mexico

When the Underground Injection Control (UIC) Regulations were promulgated in 1980, existing Class II Injection wells operating at the time were excluded from Area of Review (AOR) requirements. EPA has expressed its intent to revise the regulations to include the requirement for AORs for such wells, but it is expected that oil and gas producing states will be allowed to adopt a variance strategy for these wells. An AOR variance methodology has been developed under sponsorship of the American Petroleum institute 1 . The general concept of the variance methodology is a systematic evaluation of basic variance criteria that were agreed to by a Federal Advisory Committee. These criteria include absence of USDWs, lack of positive flow potential from the petroleum reservoir into the overlying USDWs, mitigating geological factors, and other evidence. The AOR variance methodology has been applied to oilfields in the San Juan Basin, New Mexico. This paper details results of these analyses, particularly with respect to the opportunity for variance for injection fields in the San Juan Basin.

Suitability Of Dynamic Flux Allocation For Simulation Of Stratfield Reservoirs

Reservoir simulation is used to observe the change in production through varied recovery mechanisms. The most common type of simulator is the black oil or Beta-type model. In studying recovery mechanisms, especially for stratified reservoirs, a cross-sectional model is often preferred to a full 3-dimensional version due to minimal computer requirements (both in speed and storage) and ease of interpretation. Additionally, cross-sectional models have been used for homogeneous reservoirs to study the effects of gas-overriding and/or water underrunning. Usually this type of model is selected for a representative section of the field and no-flow boundaries are assumed to exist across the front and rear faces of the section; however, boundaries may not exist or may be time-variant. One technique for circumventing this problem is to use an areal model to account for a net flux in the cross-sectional model. This technique is severely limited by the presence of reservoir heterogeneity. Another approach to this problem is the use of a dynamic flux allocation scheme. This method maintains zonal integrity and provides for variations in production which would require additional areal simulation. (15 refs.)