Browsing by Subject "Carbonate Reservoirs"
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Item Acidizing High-Temperature Carbonate Formations Using Methanesulfonic Acid(2015-03-25) Ortega, AlexisHydrochloric acid (HCl) is the most commonly used stimulation fluid for high-temperature wells drilled in carbonate reservoirs due to its high dissolving power and low cost. However, the high corrosion rate of HCl on well tubulars could make its use in deep wells non-viable. The current study introduces the novel application of methanesulfonic acid (MSA), a strong organic acid, to increase the permeability of carbonate formations, specifically at temperatures above 200?F. The objective of the experimental study is to evaluate the performance of MSA as stand-alone stimulation fluid for high-temperature limestone and dolomite formations. Coreflood studies were conducted at temperature up to 320?F using limestone and dolomite cores and diluted MSA aqueous solutions. A constant injection rate, ranging from 1 to 25 cm3/min, was maintained during the coreflood tests and the differential pressure through the core was measured until acid breakthrough. Samples of the effluent fluids were collected and analyzed using Inductively Coupled Plasma (ICP) to measure the calcium and magnesium concentrations, and a computed tomography (CT) scan of each core was performed after the acid injection to study the characteristics of the generated wormholes. MSA was found effective in creating wormholes in carbonate cores at the temperatures tested. At low injection rates, face dissolution and conical channels were observed in the cores. At intermediate injection rates, the tendency was to create a few dominant wormholes. At high injection rates, ramified wormhole structures were found, with increased branching for increased flow rates. For each condition tested, an optimum flow rate was identified. Additionally, analysis of the coreflood effluent samples showed no sign of methanesulfonate salts precipitation. Demonstration of the effectiveness of MSA in propagating wormholes in carbonate cores will offer the petroleum industry with another alternative strong acid to HCl for stimulating high-temperature carbonate formations. MSA?s high acidity, solubility of its salts, and thermal stability, along with its readily biodegradable composition provide a beneficial use for MSA as a stimulation fluid in carbonate acidizing techniques. MSA also has a more favorable corrosion profile on metals, such as high chromium alloys, than usual mineral acids employed in well stimulation.Item Relationship between pore geometry, measured by petrographic image analysis, and pore-throat geometry, calculated from capillary pressure, as a means to predict reservoir performance in secondary recovery programs for carbonate reservoirs.(2009-05-15) Dicus, Christina MarieThe purpose of this study was first to develop a method by which a detailed porosity classification system could be utilized to understand the relationship between pore/pore-throat geometry, genetic porosity type, and facies. Additionally, this study investigated the relationships between pore/pore-throat geometry, petrophysical parameters, and reservoir performance characteristics. This study focused on the Jurassic Smackover reservoir rocks of Grayson field, Columbia County, Arkansas. This three part study developed an adapted genetic carbonate pore type classification system, through which the Grayson reservoir rocks were uniquely categorized by a percent-factor, describing the effect of diagenetic events on the preservation of original depositional texture, and a second factor describing if the most significant diagenetic event resulted in porosity enhancement or reduction. The second part used petrographic image analysis and mercury-injection capillary pressure tests to calculate pore/pore-throat sizes. From these data sets pore/pore-throat sizes were compared to facies, pore type, and each other showing that pore-throat size is controlled by pore type and that pore size is controlled primarily by facies. When compared with each other, a pore size range can be estimated if the pore type and the median pore-throat aperture are known. Capillary pressure data was also used to understand the behavior of the dependent rock properties (porosity, permeability, and wettability), and it was determined that size-reduced samples, regardless of facies, tend to show similar dependent rock property behavior, but size-enhanced samples show dispersion. Finally, capillary pressure data was used to understand fluid flow behavior of pore types and facies. Oncolitic grainstone samples show unpredictable fluid flow behavior compared to oolitic grainstone samples, yet oncolitic grainstone samples will move a higher percentage of fluid. Size-enhanced samples showed heterogeneous fluid flow behavior while the size-reduced samples could be grouped by the number of modes of pore-throat sizes. Finally, this study utilized petrographic image analysis to determine if 2- dimensional porosity values could be calculated and compared to porosity values from 3-dimensional porosity techniques. The complex, heterogeneous pore network found in the Grayson reservoir rocks prevents the use of petrographic image analysis as a porosity calculation technique.