Modeling of Waterflood in a Vuggy Carbonate Reservoir

Abstract

Abstract A methodology was developed to model and successfully history match the primary and waterflood phases in a 15 well, 100 acre vuggy portion of a carbonate field in west Texas. This method is based on a derived log trace of secondary porosity calculated by subtracting sonic porosity (matrix only) from a core calibrated total porosity transformed from Density and Neutron-logs. Log signatures of vugular intervals were developed by recognizing significant differences in matrix and total porosity. A detailed geostatistical distribution of total porosity was first generated and permeability was assigned using a cloud transform of core data from nearby wells. Two geostatistical distributions of secondary porosity with different correlation lengths were then generated using the developed secondary porosity trace. Vugular zones were assumed to have a secondary porosity of 8% or greater. These models were superimposed on the permeability cube by assigning exceptional high permeability values to the vuggy zones. Using a general scale up method, the detailed permeability cubes were scaled-up for simulation studies. The models incorporating vuggy permeability distributions showed a far superior history match of primary and waterflood performance than those without vuggy permeability distributions. Good history match was also obtained on individual well basis. Sensitivity of the match to vuggy zone permeability and correlation length was analyzed. Results from these simulation runs provides insight into the spatial distribution and permeabilities of the vuggy zones. Introduction Dissolution is one of the major diagenetic processes adding porosity in carbonate reservoirs. Vugs in carbonate reservoirs are the result of carbonate dissolution, evaporite (gypsum or anhydrite) dissolution, or some combination of both. Routine core measurements for porosity and permeability are problematic for characterizing vuggy zones in these reservoirs because (1) plug type samples are generally chosen from intact core and therefore generally away from vuggy zones, and (2) whole core samples are not often sampled systematically with vuggy zones in mind. When building models, the distribution of porosity is usually obtained from log data. This data is considered fairly accurate. However, permeability distributions will be skewed to the low end because the porosity to permeability transform developed from core plug measurements does not honor reservoir-scale vuggy-interval permeabilities. Flow in high conductivity vuggy intervals is the dominating factor affecting the overall displacement efficiency in any secondary recovery process of a vugular carbonate reservoir. Honoring the permeability and distribution of secondary porosity features in reservoir characterization is crucial for a successful prediction of recovery for this type of reservoir. The objective of this study was to develop a methodology for reservoir characterization and modeling of a waterflood in a vugular carbonate reservoir setting. The reservoir selected for this study was the McElroy Field; one of the Permian basin carbonate reservoirs with a complex diagenetic overprint and a long history of waterflood Field History and Geology The McElroy Field, which is one of the larger fields in the U. S. Permian Basin, is part of a major productive trend lying along the eastern edge of the Central Basin Platform (Figure 1). The field was discovered in 1926 during the initial exploration along the Central Basin Platform and is located in Crane and Upton Counties, Texas. The reservoir is a stratigraphic-structural trap with oil production coming primarily from heterogeneous dolomites of the Grayburg Formation. P. 703^