Shawn M. Fullmer

Mapping facies distributions on modern carbonate platforms through integration of multispectral Landsat data, statistics-based unsupervised classifications, and surface sediment data

Benthic sediment facies maps were constructed for a series of large, isolated carbonate platforms, including (1) Great and Little Bahamas Banks; (2) Caicos Platform, British West Indies; (3) Chinchorro Bank, Mexico; (4) Glovers Reef, Belize; (5) south Cocos (Keeling) atoll, Indian Ocean; and (6) Bu Tini shoal, Persian Gulf. Facies maps were generated by applying statistics-based image analysis algorithms, called unsupervised classifications, to Landsat 7 multispectral satellite data. Classification results were subsequently validated with sediment data to create geologic facies maps. Landsat-derived facies maps demonstrate 82–85% agreement when compared to sediment data. At the platform scale, Landsat-derived facies maps accurately capture the principal depositional facies observed on each platform and are in general agreement with published maps generated through conventional mapping techniques. Examination at more detailed scales reveals that Landsat-derived maps differ from conventional maps with respect to the spatial dimensions and shapes of facies bodies. Landsat-derived maps show a level of complexity and heterogeneity that is more realistic than shown in previously published maps, which are characterized by broad, homogeneous facies belts. These results suggest that application of statistical algorithms to Landsat data, coupled with sediment data, provides a cost- and time-efficient method for quantitatively mapping spatial variability of depositional facies in modern carbonate environments. Landsat-derived facies maps, like the ones presented here, provide depositional analogs for subsurface carbonate reservoirs as well as a global data set for extracting predictive relationships between the occurrence and distribution of carbonate sediments that can aid in global hydrocarbon exploration and production.

Resurrection of a reservoir sandstone from tomographic data using three-dimensional printing

Three-dimensional (3-D) printing provides an opportunity to build lab-testable models of reservoir rocks from tomographic data. This study combines tomography and 3-D printing to reproduce a sample of the Fontainebleau sandstone at different magnifications to test how this workflow can help characterization of transport properties at multiple scales. For this sandstone, literature analysis has given a porosity of 11%, permeability of 455 md, mean pore throat radius of 15 μm, and a mean grain size of 250 μm. Digital rock analysis of tomographic data from the same sample yielded a porosity of 13%, a permeability of 251 md, and a mean pore throat radius of 15.2 μm. The 3-D printer available for this study was not able to reproduce the sample’s pore system at its original scale. Instead, models were 3-D printed at 5-fold, 10-fold, and 15-fold magnifications. Mercury porosimetry performed on these 3-D models revealed differences in porosity (28%–37%) compared to the literature (11%) and to digital calculations (12.7%). Mercury may have intruded the smallest matrix pores of the printing powder and led to a greater than 50% increase in measured porosity. However, the 3-D printed models’ pore throat size distribution (15 μm) and permeability (350–443 md) match both literature data and digital rock analysis. The powder-based 3-D printing method was only able to replicate parts of the pore system (permeability and pore throats) but not the pore bodies. Other 3-D printing methods, such as resin-based stereolithography and photopolymerization, may have the potential to reproduce reservoir rock porosity more accurately.

Microporosity: Characterization, Distribution, and Influence on Oil Recovery

Microporosity is very common in limestone reservoirs globally and is especially significant in many large Mesozoic reservoirs in the Middle East. Despite its common occurrence there is: 1) Wide variation in its definition, 2) Uncertainty around characterization, genetic controls, and distribution 3) A rudimentary understanding of its influence on reservoir performance and hydrocarbon recovery. The results of this study, based on a global survey of microporosity and specific Middle Eastern case studies, provide clarity on each of these topics. One volumetrically significant type of microporosity occurs between micron size subhedral crystals of low magnesium calcite in matrix and within grains. This micro-pore system is very homogenous in terms of pore size distribution with 90% of pores between 1 and 3 microns in diameter. Pore throat radii range between 0.1 and 1.5 microns. Porosity, permeability, and capillarity relationships reflect this homogeneity for rocks dominated by microporosity. Rocks with less than approximately 80% microporosity exhibit a marked increase in pore system heterogeneity. A pore geometry characterization approach incorporating digital image analyses of petrographic thin-sections was developed and provides a very effective means of rapidly characterizing and quantifying the total pore system, including microporosity. The lateral and stratigraphic distribution of microporosity is systematically related to the distribution of depositional facies and the regional extent of burial diagenetic processes. Factors that inhibit burial diagenesis, such as hydrocarbon charge, also have a strong influence on the nature and distribution of microporosity. Remaining oil saturation in microporous limestone, as measured from centrifuge capillary pressure and steady state (SS) core flood experiments, is negatively correlated with the percent fraction of microporosity. Due to the homogenous nature of the micro-pore system, rocks dominated by microporosity have more favorable oil recovery than rocks with mixed pore systems. In the specific cases studied here, water provides more favorable recovery than gas. These results have implications for resource assessment, field development planning and optimization of ultimate recovery in limestone reservoirs with significant microporosity.

Facies-independent reservoir characterization of the micropore-dominated Word field (Edwards Formation), Lavaca County, Texas

Micropore-dominated carbonate reservoirs remain challenging for accurate hydrocarbon evaluation and production as conventional reservoir models using depositional textures and petrophysical properties to distribute porosity and permeability cannot be applied. Nevertheless, understanding the distribution of pore systems and predicting the fluid flow behavior of microporous reservoirs is fundamental as micropores constitute a significant percentage of the total porosity and storage capacity. We present the results from an integrated study on the producing micropore-dominated Word Field characterized by a facies independent, diagenetically controlled pore system that approaches 100% microporosity. Four cored wells through the Albian Edwards Formation were described and correlated using stacking patterns and vertical facies trends; pore type characterization was done through thin section petrography, routine core analyses, SEM and MICP data. This study is an example of a permeable reservoir in which intergrain pores are cemented during burial diagenesis and micropores, being more resistant to cementation, remain open to depths greater than 4000 m (13,000 ft). A unique relationship exists between porosity, permeability, median pore-throat size and microcrystalline textures, independent of facies and fabrics. Cumulative gas production data show there is a correlation between the total porosity and the structural position of the wells – wells high on the structure have the highest production. We demonstrate that an equally well-connected micropore network exists in mud-dominated rocks via the matrix, and via grain-to-grain contacts in grain-dominated rocks. The here described intragrain micropore network through grain-to-grain contacts in cemented grainstones is a new carbonate flow path that will likely become more important as more unconventional carbonate reservoirs are explored.

Study Geophysical Response of Middle East Carbonate Reservoir using Computational Rock Physics Approach

Summary Development of carbonate rock physics model is difficult because pore systems are more complex in carbonate than they are in clastics. The best way to describe pore structure is through 3D µCT image of rock pore space. Instead of traditional effective medium based modeling by taking assumption of pore geometry, we adopt computational rock physics approach in this study. Multi-resolution µCT images are taken for carbonate cores belonging to different facies from middle east carbonate reservoir. Electrical conductivity and elastic properties (Vp, Vs) are computed on 3D rock micro-tomographis using finite difference (FD) and finite element method (FEM). To further extend predicting capability, a family of 3D model granular porous media with different porosity, pore (grain) aspect ratio, pore (grain) size distribution, pore connectivity and spatial arrangement are built to represent different carbonate petrophysical pore types. Modeling results compare well with core, log measurements. Direct link between rock microstructure and its elastic, electrical behavior is built up using computational rock physics. Finally, AVO forward modeling is built to quantify porosity, fluid saturation and lithology (facies) effect on seismic response for middle east carbonate reservoir.

Impact of Reservoir Heterogeneity on Field Development and Reservoir Management of the Mishrif Reservoir, West Qurna I, Southern Iraq

The Mishrif reservoir comprises the main discovered developed reservoir at West Qurna I field in southern Iraq and has been on production intermittently since 1999. Core, log and dynamic reservoir data are being integrated to characterize and model the impact of reservoir heterogeneity on reservoir performance and development plans, including waterflood response.