Rock-pore-space geometry and network topology have a great impact on dynamic reservoir characteristics, in particular on capillary pressure and relative permeability curves. Hydraulic tortuosity is a key independent measurement relating the pore-space geometry and topology to the rock's effective porosity and absolute permeability. Therefore, hydraulic tortuosity can be an important concept for dynamic reservoir characterization and reservoir simulation. Our objectives are to recommend a new dynamic rock-typing process and to assess the corresponding improvement on reservoir simulation processes. We introduce an innovative dynamic reservoir-rock-typing (DRRT) index, using absolute permeability, porosity and hydraulic tortuosity data, derived from mercury-injection capillary pressure (MICP) experiments. For correlation purposes, we also derived electric tortuosity data from formation-resistivity experiments. We used the experimental data from the Worldwide Rock Catalog (WWRC) provided by a joint-industry project (Core Lab, 2014), for both carbonate and clastic rocks. Based on the new proposed DRRT index and on corresponding dynamic reservoir properties, we prepared a comprehensive sensitivity study on the impact of hydraulic tortuosity heterogeneity on oil recovery results. This sensitivity study was done by incorporating the concept of hydraulic tortuosity in a synthetic carbonate- reservoir simulation model. The analysis of the MICP and formation-resistivity data showed both greater average tortuosity and greater tortuosity variability for carbonates, when compared with clastic rocks. It also showed good correlation between hydraulic and electric tortuosity values. The sensitivity study results showed a significant impact of hydraulic tortuosity heterogeneity on oil in place and reserves estimates for improved oil recovery (IOR) / enhanced oil recovery (EOR) processes in typical complex carbonate reservoirs, such as the ones found in the Brazilian Pre-Salt. It also showed the importance of applying proper corrections while deriving dynamic reservoir properties from capillary pressure and relative permeability experiments. The new DRRT index shows a much stronger correlation with pore-space geometry when compared with traditional reservoir-quality (RQI) and flow-zone (FZI) indexes. Therefore, it has clear potential to enhance the dynamic rock-typing process for reservoir simulation of IOR / EOR in complex carbonate rocks. We also discuss the importance of an integrated laboratory test and well log program to enable the proper characterization, population, and upscaling of dynamic rock properties. In complex carbonate reservoirs under IOR / EOR, overlooking the rock-pore-space geometry and network topology may result in significant errors in reservoir characterization and simulation processes. In this context, proper DRRT in carbonates, including tortuosity, is therefore crucial for reservoir simulation; enabling correspondence between core, well log and reservoir-scale dynamic properties. The presented correlation between hydraulic and electric tortuosity significantly increases the potential of dielectric measurements for dynamic reservoir characterization of complex carbonates on both core and well log scales.
Hydrocarbon production optimization in Pre-Salt carbonate reservoirs is a main focus for oil and gas research in Brazil. Stimulation treatment design optimization requires good knowledge of the reservoir properties and excellent understanding of the interaction between rock formation and treating fluid. This paper investigates these interactions through laboratory tests determining the compatibility of fluids used in matrix stimulation with different Pre-Salt carbonate rock types. The objective of this work is to relate the geology, petrophysics, and geomechanics of the Pre-Salt reservoirs to their expected stimulation response. Because of the difficulty in obtaining downhole cores and the destructive nature of most tests, the study focused on samples collected from a Pre-Salt carbonate analog: the Coquinas formation (Schafer 1973) from the Sao Miguel quarry, northeast Brazil (Chagas de Azambuja Filho et al. 1998). A thorough geology-based study of the Coquinas formation, including routine core analysis (FZI) microtomography, and thin section study was conducted. Usually these grain-supported carbonates show different amounts and types of primary porosity, closed and reopened by multiple diagenetic phases. Throughout the 25-m thick Coquinas reservoir, five rock types in 13 layers with permeability ranging from microdarcy to almost 1 darcy were identified. All rock types were subjected to routine mineralogy evaluation and various petrophysical, geomechanical, and spectroscopic measurements. Six of the thirteen layers were selected to perform core flow tests with a viscoelastic surfactant technology based diverting acid fluid (Al-Mutawa et al. 2005; Chang et al. 2001; Samuel et al. 1997). This is the first extensive study reporting the efficiency of a viscoelastic diverting acid system in the Pre-Salt analogue Coquinas carbonate formation outcrop cores. Spectroscopic measurement showed wormhole creation and, in some cases, rock texture alteration or fine migration. Through the study we identified the flow units and characterized the rock behavior when chemically stimulated. The conclusions from this study will enable us to tailor and optimize stimulation treatments of Pre-Salt carbonate reservoirs. Introduction The offshore Pre-Salt in Brazil comprises a group of recently discovered fields with promising oil reserves in the Coquinas formation or the above the microbialites section. For example, Lula (ex-Tupi) field, the lead field of the Santos cluster, is believed to hold between 5 to 8 billions barrels of oil equivalent (Beltrao et al. 2009). The Pre-Salt reservoirs are currently the focus of research in Brazil; however, the scarceness of downhole samples collected makes destructive tests very difficult to perform, and so analysis must be performed on analogues. The onshore Coquinas formation from northeast Brazil is taken here as analogue of the Pre-Salt carbonates.
With the increase in activity in deep and ultra-deep water exploration, the need for geological information is penalized by its cost. Acquiring full core data in the current economic context is difficult to justify and encourages the development of less costly alternative methodologies to compensate the lack of information when coring is not included in exploration programs. This is particularly true in oil- or synthetic-base muds (OBM) where such alternative technology is still under development as opposed to the water-base mud (WBM) environment where the technology is more mature and the interpretation workflows are better established. New state-of-the-art electric wireline technologies including large-volume rotary sidewall coring, and photorealistic OBM-adapted formation imaging combined with powerful software tools for visualization and interpretation are demonstrated to provide a viable substitute for whole conventional core for a wide range of applications, especially in clastic environments.
Irreducible water saturation is a key property for the estimation of original oil and gas-in-place. It is also key to end-point scaling of capillary pressure and relative permeability, with significant impact on simulation results of reservoirs under improved/enhanced oil recovery (IOR/EOR). Several definitions of irreducible water saturation exist, based on different experimental measurements and standard estimation methods. We propose a comprehensive model and a new method for improved estimation of irreducible water saturation. The model considers rock wettability; the thin film of water that coats portions of the rock grains; the pore size distribution; the tortuosity; and the ratio between pore-throat and pore-body sizes (BTR). Different components of the irreducible water saturation are identified for multimodal, heterogeneous rocks: a nano-porosity system completely filled with water and other pore systems with their walls coated by water. The model also considers an additional residual water saturation resulting from laboratory experimental limits as the maximum applied pressure and duration. The method adjusts the model parameters by fitting to a set of irreducible saturation data, obtained from both mercury injection (MICP) and air-brine drainage capillary pressure experiments. The method estimates the irreducible water saturation for the asymptotic ideal condition - very high capillary pressure and reservoir geological times – as well as for other laboratory and reservoir conditions. We applied the proposed method to experimental data from Corelab's worldwide rock catalog. The fraction of nano-porosity not revealed by MICP experiment was estimated by comparing MICP porosity with routine effective porosity. Hydraulic tortuosity and truncated multi-Gaussian decomposition of pore-throat-size distribution were also obtained from MICP data. BTR range was estimated from NMR data, thin sections, and hydraulic tortuosity data. Water thin film thickness range was estimated from the literature. Model parameters were then successfully estimated using data from 49 carbonate and 106 clastic samples from all over the world. The results showed that, in several cases, the asymptotic irreducible water saturation might be significantly smaller than the observed value from the air-brine experiment. Therefore, the corresponding reservoir irreducible water saturation could also be overestimated. The relative importance of the different components of the irreducible water saturation varied from one sample to the other, confirming the relevance and completeness of the proposed method. When compared to traditional methods, the proposed method significantly improves irreducible water saturation estimates, resulting in better saturation-height and end-point scaling functions, and more accurate reserves. It is particularly important for simulation of IOR/EOR processes. The method may also be integrated with dielectric and NMR well log measurements, increasing the resolution of dynamic reservoir characterization, with particular importance to mixed-wet rock environments.
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