Detailed core characterization is often overlooked in the sampling process for core analysis measurements. Random core sampling is usually performed and the selected plugs are not associated with rock types or the reservoir heterogeneity. The objective of this study is to obtain representative samples for direct simulation of petrophysical and fluid flow properties in complex rock types. A robust sampling strategy was followed in reservoir cores from two successive heterogeneous carbonate and siliciclastic formations in the Raudhatain field in Kuwait. The sample selection criteria were based on statistical distribution of litho-types in the cores to ensure optimum characterization of the main reservoir units. The litho-types were identified based on porosity and mineralogy variations along the core lengths utilizing advanced dual-energy X-ray CT scanning. High resolution micro-CT imaging and subsequent segmentation provided 3D representation of the pore space and geometric fabric of the core samples. Primary drainage and imbibition processes were simulated in numerical experiments using a pore-scale simulator by the Lattice Boltzmann Method. Capillary pressure (Pc) and relative permeability (Kr) curves together with water and oil distributions were investigated for complex geometries by the different rock types. The dual energy CT density was compared with wireline log and provided accurate calibrations to the downhole logs. The different rock types gave distinct capillary and flow properties that can be linked to the rock structure and pore type of the samples. The Lattice Boltzmann based pore-level fluid calculations provided realistic fluid distributions in the 3D rock volume, which are consistent with pore-scale physical phenomena. This characterization method by the dual energy CT eliminates sampling bias and allows for each cored litho-type to be equally represented in the plugs acquired for subsequent petrophysical and fluid flow analyses. It also provides accurate calibration tool for downhole logs. The digital analysis gave reliable SCAL data with improved understanding of the pore-level events and proved its effectiveness in providing advanced interpretations at multiple scales in relatively short timeframes.
The huge original oil in place (OOIP) of heavy oil within the upper Maastrichtian carbonate succession of Tayarat Formation in Kuwait Burgan field lead to paying more attention to its economic value and the necessity of characterizing it at multi-scales for better commercial utilization. However, its high degree of heterogeneity and complexity as a consequence of depositional and diagenetic factors, the presence of fractures in high frequencies, and existence of heavy oil (10 −15° API) with very high viscosity (80,000 cP) and non-movable bitumen in high quantities make the evaluation process very challenging and difficult. This study is aiming at characterizing these carbonate succession using a robust combination between digital and conventional methods. One hundred seventy-seven (177) feet of representative whole core intervals were imaged by Dual Energy (DE) X-ray CT imaging technique to assess heterogeneity and identify main porosity regions within each core section for representative sample selection. The selected and extracted samples were characterized geologically and petrophysically using MICP analysis, porosity-permeability measurements, micro XCT images and petrographical analysis in order to identify main sedimentary textures and reservoir rock types (RRT), and then generate texture-based poroperm trends. The generated poroperm trends were combined with the DE derived logs in order to generate high-resolution porosity and permeability logs. The Dual Energy CT imaging provided bulk density and photoelectric factor data that were critical for the determination of porosity and lithological variation along the core lengths. The petrographical analysis revealed common and distinctive geological textures and RRT's within the main lithological groups of the Tayarat Formation. Unique and distinctive texture-based poroperm trends were generated for each lithological group. The derived porosity and permeability logs showed a very good match with the lab-derived porosity and permeability data. The integrated digital and conventional data at multiple scales were essential in improving our understanding of Tayarat geological and petrophysical properties.
Spontaneous imbibition is one of the key production mechanisms in fractured oil reservoirs. It is also an important process in tight gas formations, which has signi- ficant effects on the gas production after hydraulic fracturing. The objective of this research is to investigate the effects of pore throat sizes and connectivity on spontaneous imbibition behavior in tight carbonate rocks. Many plug samples were selected from various wells in the Middle East. The samples were characterized using X-ray CT imaging, thin-section photomicrographs, Helium porosity and gas permeability. High pressure mercury injection experiments (MICP) were performed in the primary drainage mode to obtain the pore throat size distributions, followed by mercury withdrawal tests to investigate the spontaneous imbibition curve and fluid trapping. The degree of pore connectivity was studied in the samples from thin-section photomicrographs and from primary drainage capillary pressure curves and were found in good relation with the mercury withdrawal behavior and residual fluid saturations. Higher permeability samples were characterized by lower entry pressures that showed higher tendency towards lower fluid (mercury) trapping. These results show important link between the rock nature and spontaneous imbibition and fluid trapping that can be deduced from mercury withdraw testing. Accurate prediction of spontaneous imbibition is crucial in many hydrocarbon reservoirs and such analyses help understand production mechanisms in different carbonate rock types.
Carbonate reservoir rocks of the Najmah formation in Kuwait, with low porosity and low permeability, have been characterized using integrated digital and physical rock analyses methods. High-resolution imaging and analyses determined the microstructural characters of mineral matrix, organic matter (OM) distribution, organic and inorganic pore types, size distribution, and permeability variation within this kerogen-rich Late Jurassic stratigraphic unit. Considerable heterogeneity of porosity and permeability was observed in the 100-ft studied interval of the Najmah Formation. Two-dimensional scanning electron microscopy (2D-SEM) imaging and three-dimensional focused ion beam SEM (3D-FIB-SEM) imaging highlighted the different types of porosities present within the formation rock. At each depth, several 2D-SEM images were used for characterization and selection of representative locations for extracting 3D FIB-SEM volumes. The 3D volumes were digitally analyzed and volumetric percentages of OM and total porosity were determined. The porosity was further analyzed and quantified as connected, nonconnected, and associated with organic matter. Connected porosity was used to compute absolute permeability in the horizontal and vertical directions in the area of interest. Porosity associated with OM is an indicator of OM maturity and flow potential. It has been categorized as pendular type, spongy large grain, spongy small grain, fracture porosity within the OM, grain boundary fractures and intergranular porosity covering the entire OM. Permeability is not only influenced by porosity within OM or even apparent transformation ratio (ATR), it is also dependent on pore connectivity, pore sizes, and heterogeneity (e.g., high-permeability streaks). For high porosity samples, almost all pores are connected and contributing to permeability. For low porosity samples with high permeability, the flow is mainly through microfractures. It is possible that intergranular clay pores in highly thermally mature rocks were originally filled with OM and that, during progressive thermal maturation, transformation of OM to hydrocarbon(s) removed much of the pore filling OM. It has also been observed that, although the total organic carbon (TOC) content of the rocks is significant (up to 18 wt%), and good maturity index (VR0>1), only few examined samples show good connected porosity within the OM. It is essential to evaluate the porosity within the OM thorough high-resolution measurements for pinpointing the prospective layers for future stimulated horizontal wells in this organic-rich source unit. These intervals can be considered as the potential sweet spots after integration with detailed petrophysics and geomechanical parameters for optimized well planning and completion design.
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