Most carbonate reservoirs are heterogeneous at multiple-length scales. These heterogeneities strongly influence the outcome of acid stimulation treatments which are routinely performed to improve well productivity. However, most previous studies reported in the literature have focused on investigating the effects of injection rate, temperature, and fluid properties and few have focused on the influence of rock properties on stimulation treatments. This study primarily explores the influence of pore scale heterogeneities on stimulation treatments. Some results on the influence of core scale heterogeneities are also presented. Core samples from eight different carbonate rocks were selected for the study. Samples were characterized for mineralogy, texture, fabric, porosity and density distribution using Nuclear Magnetic Resonance (NMR), Computed Tomography (CT) scanning, Scanning Electron Microscopy (SEM), mercury injection as well as resistivity measurements, chemical testing, etc. Each sample was then classified into a Reservoir Rock Type (RRT) which is primarily based on the porosity spatial distribution (PSD) in the carbonate. Each RRT represents a group of carbonate rocks with similar porosity spatial distribution and is expected to exhibit similar behavior to fluid flow and, therefore, to acid dissolutions. The 8 carbonate rocks investigated in this study represent 6 different RRTs. Each carbonate type was treated with reactive fluids. Two different sets of coreflow tests were performed on 6 × 1.5 inch plugs. The first set of experiments involved determination of the evolution of permeability with porosity for the RRT. In these experiments the core was treated at high injection rates with a fluid of low reactivity. Injection at a high flow rate ensured uniform dissolution of the medium. Porosity was monitored by analysis of the effluent and permeability was monitored by the pressure drop across the cores. The second set involved determining the acid breakthrough curves for each of the carbonate types using HCl (hydrochloric acid) as the reacting fluid. The characteristic pore-volume to breakthroughs (PVBT) and the wormhole velocities were obtained for each carbonate by injecting acid at different flow rates. The results of the tests confirm the original hypothesis that the response of the carbonate rock to acid depends on the RRT it belongs to. In other words, rock samples with similar PSD exhibit similar trends in PVBT. The significance of the results to the design of matrix treatments in carbonate reservoirs is discussed. Introduction Carbonate reservoirs are routinely stimulated with acid to improve production. Several experimental and modeling studieson the response of carbonate cores to various acids under varying conditions of injection rate, temperature and concentrations have been reported in the literature 1,2. However, few studies on the influence of rock properties on the acidization process have been reported 3, 4. Previous studies on the influence of injection rate have shown that characteristic dissolution patterns are observed at different injection rates 5, 6. These patterns are categorized as face dissolution, wormholing and uniform dissolution patterns depending on their shape and speed of propagation. By increasing the flow rate from a low to a high value, the dissolution pattern changes from a face dissolution, to a wormhole and then to a uniform dissolution pattern. In the wormholing regime a maximum permeability increase can be achieved for a given volume of acid. Therefore the flow rate at the wormholing regime is termed as the optimum flow rate and the corresponding volume of acid is known as minimum pore volume required to breakthrough.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractMost carbonate reservoirs are heterogeneous at multiplelength scales. These heterogeneities strongly influence the outcome of acid stimulation treatments which are routinely performed to improve well productivity. However, most previous studies reported in the literature have focused on investigating the effects of injection rate, temperature, and fluid properties and few have focused on the influence of rock properties on stimulation treatments. This study primarily explores the influence of pore scale heterogeneities on stimulation treatments. Some results on the influence of core scale heterogeneities are also presented.Core samples from eight different carbonate rocks were selected for the study. Samples were characterized for mineralogy, texture, fabric, porosity and density distribution using Nuclear Magnetic Resonance (NMR), Computed Tomography (CT) scanning, Scanning Electron Microscopy (SEM), mercury injection as well as resistivity measurements, chemical testing, etc. Each sample was then classified into a Reservoir Rock Type (RRT) which is primarily based on the porosity spatial distribution (PSD) in the carbonate. Each RRT represents a group of carbonate rocks with similar porosity spatial distribution and is expected to exhibit similar behavior to fluid flow and, therefore, to acid dissolutions. The 8 carbonate rocks investigated in this study represent 6 different RRTs.Each carbonate type was treated with reactive fluids. Two different sets of coreflow tests were performed on 6 × 1.5 inch plugs. The first set of experiments involved determination of the evolution of permeability with porosity for the RRT. In these experiments the core was treated at high injection rates with a fluid of low reactivity. Injection at a high flow rate ensured uniform dissolution of the medium. Porosity was monitored by analysis of the effluent and permeability was monitored by the pressure drop across the cores.The second set involved determining the acid breakthrough curves for each of the carbonate types using HCl (hydrochloric acid) as the reacting fluid. The characteristic pore-volume to breakthroughs (PVBT) and the wormhole velocities were obtained for each carbonate by injecting acid at different flow rates.The results of the tests confirm the original hypothesis that the response of the carbonate rock to acid depends on the RRT it belongs to. In other words, rock samples with similar PSD exhibit similar trends in PVBT. The significance of the results to the design of matrix treatments in carbonate reservoirs is discussed.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis case study demonstrates a new method to compute continuous permeability and estimate reservoir rock type from logs in a complex, heterogeneous, Middle Eastern carbonate reservoir. The 795 ft conventionally cored interval consists of interbedded limestones and dolomites with anhydrite cement and features a wide variety of textures. In some intervals the depositional textures are preserved, in others they are highly altered by diagenesis. Vugs are developed in several intervals. Computation of permeability from porosity alone yields scatter of a factor of 700.Rock typing using only conventional logs was unsatisfactory due to the poor permeability estimation. The effect of geological complexity on the log based prediction is overcome by including pore size distribution data from a combination of NMR and borehole electrical image logs. This data is sufficient to partition the porosity according the pore size, compute permeability and assess the rock types, independently of mineralogy, facies, and other variables. The results are validated by comparison to core derived properties and formation tester mobilities. Incorporation of the pore size information into the log based interpretation reduces the scatter in computed permeability to a factor of less than 10. The assumptions and principles of the log analysis method were validated in the lab through extensive characterization of the pore system over a range of scales. Data from a variety of methods including MICP, lab NMR, BET surface area, thin section analysis, continuous vuggy porosity analysis from the core slab, minpermeametry and other advanced research methods are included.A key result of this study is that a relatively simple method for log derived permeability and rock type analysis in carbonates, first developed in high porosity limestones, can be successfully applied in this lower porosity (10 -20 p.u.) carbonate. This gives us confidence to project that the method could be applicable to many other carbonates worldwide.
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.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractComplex pore size distributions encountered in carbonate rocks have a large impact on the fluid flow characteristics of carbonate reservoirs. Consequently, although nuclear magnetic resonance (NMR) has been frequently used for characterization of clastic reservoirs, it has not been widely applied to carbonates. This paper describes a case study from the Shuaiba carbonate reservoir of the Al Shaheen field, offshore Qatar. Core data from a study well were used to establish an NMR carbonate rock-typing model for permeability estimation. The rock-typing model was verified in the study well with a wireline NMR logging tool. Core analysis included thin-section petrography, NMR surface relaxivity, mercury injection, porosity and permeability measurements. NMR distributions determined on core were partitioned and linked to pore body size and pore throat size distributions. Several rock types were also defined based on their NMR and petrographic characteristics. To improve permeability prediction in the cored interval of the study well, an NMR-based permeability equation was derived. The core-calibrated NMR carbonate rock typing model was applied to noncored sections of horizontal wells drilled in the Shuaiba formation having logging-while-drilling (LWD) NMR data to improve rock typing and permeability estimation, thus, providing valuable input data for reservoir modeling.
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