UNDERSTANDING IMBIBITION DATA IN COMPLEX CARBONATE ROCK TYPES (original) (raw)
Related papers
Variations in Bounding and Scanning Relative Permeability Curves With Different Carbonate Rock Types
SPE Reservoir Evaluation & Engineering, 2013
Summary Relative permeability curves generally exhibit hysteresis between different saturation cycles. This hysteresis is mainly caused by wettability changes and fluid trapping. Different rock types may experience different hysteresis trends because of variations in pore geometry. Relative permeability curves may also be a function of the saturation height in the reservoir. A detailed laboratory study was performed to investigate relative permeability behavior for a major carbonate hydrocarbon reservoir in the Middle East. Representative core samples covering five reservoir rock types (RRTs) were identified on the basis of whole core and plug X-ray computed tomography (CT), nuclear magnetic resonance (NMR) T2, mercury injection capillary pressure (MICP), porosity, permeability, and thin-section analyses. Primary-drainage (PD) and imbibition water/oil relative permeability (bounding) curves were measured on all the five rock types by the steady-state (SS) technique by use of live fl...
Variations in Bounding and Scanning Relative Permeability Curves With Different Carbonate Rock Type
SPE Reservoir Evaluation & Engineering, 2013
Relative permeability curves generally exhibit hysteresis between different saturation cycles. This hysteresis is mainly caused by wettability changes and fluid trapping. Different rock types may experience different hysteresis trends because of variations in pore geometry. Relative permeability curves may also be a function of the saturation height in the reservoir.
Marine and Petroleum Geology, 2010
Rock typing is used in carbonate reservoir characterisation to group petrophysically similar rocks for reservoir modelling purposes. The focus is often upon bringing together samples with similar porosity, permeability and capillary pressure. To achieve this, rock typing studies are usually conducted primarily on core plugs, using routine core analysis data and thin sections. However, such an approach results in a tendency to focus on grouping samples with consistent petrophysical properties, ignoring the geological controls on pore evolution. This means that modelling rock types predicatively using 3D geocellular models is not easily accomplished. Furthermore, where geological observations are made, they tend to consider only depositional rock properties, and not the effects of diagenesis. In doing so, a key control on the evolution of the carbonate pore network is ignored. This paper addresses these issues using a giant carbonate reservoir in Northern Oman. Rock types were defined on the basis of pore geometry, whilst retaining distinct, geological descriptors. The aim was to ensure that each rock type could be defined on the basis of both its petrophysical properties and behaviour during hydrocarbon recovery. The results show that characterisation of pore heterogeneity is critical to the prediction of flow behaviour under reservoir conditions, and that routine petrophysical parameters are often not good indicators of sweep efficiency.
Digital Rock Physics (DRP) has significantly evolved in the last few years and added invaluable contributions in improving core characterization and in providing high quality advanced SCAL measurements, emphasized through various studies (Al Mansoori et al., 2014 and Kalam et al., 2011). This paper represents a unique DRP relative permeability SCAL study done on two plug samples from a carbonate reservoir in the Middle East. It outlines the DRP method used to determine the relative permeability curves including sub-sample selection, high resolution CT scanning (down to nano level), generation of the 3D rock models, and simulation of fluid flow displacements. The paper will also discuss the power of pore scale imaging and how it helps in understanding macro property variations. The DRP results are comparable to the SCAL results of same formation of nearby fields and are currently being used for the Full Field simulation. The conclusions will be supported by a comparison with physical lab measurements that were done independently on samples of the same formation from the same well's core. Such comparison will demonstrate the added value in using DRP, and will show the effectiveness of the technology in generating advanced SCAL data in a significantly shorter timeframe compared to conventional laboratory measurements.
Reservoir Properties of Low-Permeable Carbonate Rocks: Experimental Features
Energies, 2020
This paper presents an integrated petrophysical characterization of a representative set of complex carbonate reservoir rock samples with a porosity of less than 3% and permeability of less than 1 mD. Laboratory methods used in this study included both bulk measurements and multiscale void space characterization. Bulk techniques included gas volumetric nuclear magnetic resonance (NMR), liquid saturation (LS), porosity, pressure-pulse decay (PDP), and pseudo-steady-state permeability (PSS). Imaging consisted of thin-section petrography, computed X-ray macro- and microtomography, and scanning electron microscopy (SEM). Mercury injection capillary pressure (MICP) porosimetry was a proxy technique between bulk measurements and imaging. The target set of rock samples included whole cores, core plugs, mini cores, rock chips, and crushed rock. The research yielded several findings for the target rock samples. NMR was the most appropriate technique for total porosity determination. MICP por...
Carbonates and Evaporites, 2018
Reservoir permeability and other property variations were investigated in all nine zones of the Bangestan carbonate sequence in the Mansouri oil field located in the southwestern of Iran. The prepared permeability distribution models using RMS method indicated that there are two abnormal high-permeability zones located at the northwestern in Zone 2 and southeastern in Zone 6 of the reservoir. Core data analysis and petrographic thin-section study, electrofacies model, and fluid saturation measurements were used to verify the results of permeability models. Petrographically, the main constituents of the Bangestan carbonate sequence were wackestone and packstone facies. Based on five determined microfacies confirmed the environmental instability from open marine to semi-restricted lagoonal environments while understudied carbonate deposition. Diagenetic processes such as solution (pressure and chemical), dolomitization, and fracturing improved the reservoir quality. Electrofacies (EF) model was also done by gamma ray (GR), water saturation (Sw), acoustic log (DT), neutron porosity, and effective porosity (PHIE) data. Four EFs were determined and reservoir quality was decreased from EF-1 to EF-4. The results showed that the vuggy porosity abundances and electrofacies distribution, as the main controllers of the reservoir quality, are well coincident with the permeability model. The vuggy porosity type was found to be as a fabric selective pore and an individual character of rudist-rich zones. Fluid saturation data are consistent with the permeability model and related high reservoir quality and production zones. The detected anomalies of permeability in the model can be interpreted by three scenarios: (1) basement faults activities, (2) sedimentary environment changes, and (3) combinational effects of faults and sedimentary deposition. It is believed that the third scenario is more logic.
2017
Carbonate reservoir rocks are often highly complex, exhibiting extreme heterogeneity in the size, shape, connectivity and wettability of the pore space. In turn this variability strongly impacts the behavior of the capillary pressure and relative permeability and hence the oil recovery. Special core analysis cannot describe or separate these effects since the measurements are limited in the number of samples that can be handled, as well as the displacement cycles and wettabilities that can be considered. We study 16 samples from two large Middle Eastern carbonate reservoirs (both limestones and dolomites). Static and dynamic properties of these rocks were determined through a combination of nano to cm scale sample selection and imaging to capture microporosity, macro-porosity and vugs, and multi-scale generalized network modeling and upscaling to capture the four orders of magnitude variation in pore size. The pore-scale distribution of contact angle was tuned to match one set of waterflood capillary pressure curves, which indicated mixed-wet characteristics with a tendency to be weakly oil-wet. On benchmark samples, the measured waterflood relative permeability was compared successfully to the predicted results. Samples with the widest range of connected pore sizesprincipally the limestones with a mix of micro-, macro-and vuggy-porositytended to display oil-wet type waterflood behavior, implying poor recovery, whereas the dolomite samples with a more restricted range of pore size showed mixed-wet characteristics in their flow response with more favorable recoveries. This study shows the value of digital rock technology, which aids the identification of multiphase flow rock types and quantifies how the pore size distribution, connectivity, mineralogy and wettability impact local displacement efficiency.
Integration of rock typing methods for carbonate reservoir characterization
Journal of Geophysics and Engineering, 2013
Reservoir rock typing is the most important part of all reservoir modelling. For integrated reservoir rock typing, static and dynamic properties need to be combined, but sometimes these two are incompatible. The failure is due to the misunderstanding of the crucial parameters that control the dynamic behaviour of the reservoir rock and thus selecting inappropriate methods for defining static rock types. In this study, rock types were defined by combining the SCAL data with the rock properties, particularly rock fabric and pore types. First, air-displacingwater capillary pressure curues were classified because they are representative of fluid saturation and behaviour under capillary forces. Next the most important rock properties which control the fluid flow and saturation behaviour (rock fabric and pore types) were combined with defined classes. Corresponding petrophysical properties were also attributed to reservoir rock types and eventually, defined rock types were compared with relative permeability curves. This study focused on representing the importance of the pore system, specifically pore types in fluid saturation and entrapment in the reservoir rock. The most common tests in static rock typing, such as electrofacies analysis and porosity-permeability correlation, were carried out and the results indicate that these are not appropriate approaches for reservoir rock typing in carbonate reservoirs with a complicated pore system.
TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract A fundamental component in the construction of most reservoir performance models is an empirical relationship between permeability as measured in a limited number of cored wells and other petrophysical properties measured in well logs. This paper presents a permeability model specially designed for carbonates. The model relates permeability to interparticle porosity, makes special accommodation for separate-vug porosity, and includes a rock-fabric classification scheme with an important dual petrophysical-geological significance. Methods to estimate the separate-vug porosity from sonic logs and the rock-fabric from initial saturation are presented. The dual petrophysical-geological significance of the rock-fabric classification is important for providing a link to geological models for use in distributing permeabilities between wells. Porosity and permeability are highly variable and difficult to predict spatially in most carbonate reservoirs, but rock-fabric changes tend to be systematically organized in a predictable manner within a sequence stratigraphic framework. Introduction Reservoir characterization and modeling is primarily a problem of understanding the 3D spatial arrangement of petrophysical properties. Petrophysical measurements must be linked to spatial information when building a reservoir model, and geologic models contain vital spatial information to be applied in interwell areas where direct petrophysical measurements are difficult. The link is best accomplished through the integration of geologic rock-fabric descriptions and petrophysical measurements.
Abu Dhabi International Petroleum Exhibition and Conference, 2014
A sizable oil reserves are held in a thick oil/ water capillary transition zones in the carbonate reservoirs, but it is an ongoing challenge to accurately describe the relationship between capillary pressure, relative permeability and oil/water saturation due to the complex wettability variation, pore geometry and heterogeneity throughout the reservoir column. It has been shown that a proper interpretation of relative permeability and capillary pressure including hysteresis has a substantial influence on the prediction and optimization of field production, especially for a heterogeneous carbonate reservoir with a thick transition zone. The conventional models, such as Corey method and Leverett J-function, cannot precisely present the behaviors of capillary pressure and relative permeability of transition zones in carbonate reservoirs. In the present work, a study has been conducted to provide an improved understanding of capillary pressure and relative permeability of the transition zones in carbonate reservoirs by implementing and optimizing recently developed models considering mixed-wet property and geological heterogeneity. For single core plug and each reservoir rock typing classified on the basis of petrophysical properties, the applicability to generate bounding drainage and imbibition curves of the models was tested with fitting parameters by comparing with experimental data. Also, a comprehensive assessment was provided about the feasibility and efficiency of the models along with an evaluation of the hysteresis between bounding drainage and imbibition curves. The results showed excellent matches in the case of Masalmeh model (SPE Reserv Eval Eng 10(02):191-204, 2007) with a correlation coefficient value of 0.95, in which mixed-wet and pore size distribution are taken into account. Therefore, it can be stated that the work conducted in this study could be used as a guide for further investigation and understanding of transition zones in carbonate reservoirs.