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.
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.
This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author (s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author (s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright. topology may result in significant deviations in the quality of reservoir characterization and simulation results. In this context, proper multi-Gaussian decomposition and the introduction of a new multi-Gaussian universal J** -function are therefore crucial for carbonate reservoir simulations.The proposed truncated multi-Gaussian pore-throat-size decomposition presents significant additional benefits when compared to Thomeer's method. It also improves dynamic-reservoir-rock-typing and reservoir simulation processes. The new universal J** -function can be used to reconstruct capillary pressure curves from the information provided by multi-Gaussian pore-throat-size decomposition. Therefore, the new concepts presented in this paper have a clear potential to enhance the simulation of IOR and EOR in complex carbonate and clastic reservoirs.
This paper will describe the improvement made to the reamer cutter blocks to enhance its durability and optimize the Pre-salt Well Construction Currently, most of the Brazilian's Pre-Salt wells have the last phase built-in 12.25in. In some situations, it is necessary to drill oil wells in a giant offshore field wells with five phases, enlarging the third phase from 18.125in to 22in. The high abrasiveness encountered at this phase increased the number of runs needed to drill it and, consequently, time and costs that encouraged the development of solutions. This work relates what has been observed during the last years about reaming difficulties, specifically, in the enlargement from 18.125in to 22in when facing abrasive formations. Petrobras specialists analyzed these events and concluded the matrix of the reamer's cutter blocks was wearing faster and losing the capacity to hold the PDC cutters. The hole enlargement company, that Petrobras works for nowadays, developed a process that increased the resistance of the cutter blocks by increasing the hardness of the surface material prior to the brazing of the cutters. Then, Petrobras has had the opportunity to use both modified and common cutter blocks in a challenging operation to compare their durability and the results were completely satisfactory. The modified cutter blocks had much less wearing on the same formations. Based on this operation, we can conclude this process is validated since improved the reamer cutter blocks quality and its lifetime. This paper can serve as a guide to reduce operations costs and to optimize well construction when there are concrete possibilities to enlarge abrasive formations.
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