Comprehensive Analysis of Acid Stimulation in Carbonates

Most wells in conventional carbonate reservoirs are stimulated with acid, either by acid fracturing or by matrix acidizing. Both methods can result in effective stimulation in carbonate reservoirs, but currently there is no published scientific criterion for selecting one technique or the other. The objectives of this study are to define ways to estimate the well performance that can be obtained from each of these treatments, and finally to define a decision criterion to select the best acid stimulation technique for a given scenario. Improvements in the modeling of both matrix acidizing and acid fracturing are proposed in this study. A new upscaled global model of wormhole propagation is proposed, based on experimental results and simulations using the Two-Scale Continuum Model. The proposed model represents experiments in different scales and field treatments. The wormhole propagation in anisotropic formations and in limited entry completions was also studied, and new analytical equations to calculate the post-acidizing skin factor for these cases were presented. In terms of acid fracturing modeling, a productivity model was developed for acid fractures, coupled to an in-house acid fracturing simulator. A leak-off model accounting for efficient wormholing was also developed, improving the prediction of high leak-off observed in acid fracturing treatments. Comparing the predicted productivity of matrix acidized and acid fractured wells, this study proposes a criterion for selection of the acid stimulation technique that results in the most productive well, for a given scenario and volume of acid. For all scenarios studied, there is a cutoff permeability above which a matrix acidized well is more productive than an acid fractured well. The value of this cutoff permeability, however, changes significantly for different scenarios. For example, in shallower reservoirs with small horizontal stresses, the cutoff permeability is much higher than in deeper reservoirs subject to high horizontal stresses. For hard rocks, the cutoff permeability is higher than for softer rocks. Concise analytical decision criteria were proposed to select the best acid stimulation method for both vertical and horizontal wells

Comprehensive Analysis of Acid Stimulation in Carbonates

Most wells in conventional carbonate reservoirs are stimulated with acid, either by acid fracturing or by matrix acidizing. Both methods can result in effective stimulation in carbonate reservoirs, but currently there is no published scientific criterion for selecting one technique or the other. The objectives of this study are to define ways to estimate the well performance that can be obtained from each of these treatments, and finally to define a decision criterion to select the best acid stimulation technique for a given scenario. Improvements in the modeling of both matrix acidizing and acid fracturing are proposed in this study. A new upscaled global model of wormhole propagation is proposed, based on experimental results and simulations using the Two-Scale Continuum Model. The proposed model represents experiments in different scales and field treatments. The wormhole propagation in anisotropic formations and in limited entry completions was also studied, and new analytical equations to calculate the post-acidizing skin factor for these cases were presented. In terms of acid fracturing modeling, a productivity model was developed for acid fractures, coupled to an in-house acid fracturing simulator. A leak-off model accounting for efficient wormholing was also developed, improving the prediction of high leak-off observed in acid fracturing treatments. Comparing the predicted productivity of matrix acidized and acid fractured wells, this study proposes a criterion for selection of the acid stimulation technique that results in the most productive well, for a given scenario and volume of acid. For all scenarios studied, there is a cutoff permeability above which a matrix acidized well is more productive than an acid fractured well. The value of this cutoff permeability, however, changes significantly for different scenarios. For example, in shallower reservoirs with small horizontal stresses, the cutoff permeability is much higher than in deeper reservoirs subject to high horizontal stresses. For hard rocks, the cutoff permeability is higher than for softer rocks. Concise analytical decision criteria were proposed to select the best acid stimulation method for both vertical and horizontal wells

Formation Characterization for Acid Stimulation

Matrix acidizing is an effective stimulation technique for carbonate reservoirs and it has been practiced for years in the industry. By injecting acid below the formation fracturing pressure, highly permeable paths called “wormholes” are created to bypass the near wellbore damage and penetrate the formation as deep as possible to improve flow conditions. For various types of carbonate formation, it is important to design the volume of acid needed and the optimal acid injection rate to achieve minimum acid consumption. Besides, acid type, acid concentration, core size, mineralogy and petrophysical properties of the carbonate rocks affect the optimal conditions for matrix acidizing. This research focuses on the characterization of carbonate formation at multiple scales to investigate how the petrophysical parameters affect matrix acidizing. The study covers three different scales: micro scale, core scale, and log scale. For micro-scale study, three types of rock samples (Indiana Limestone, Desert Pink, and Travertine) was selected and micro-Computer Tomography (micro-CT) technique was adopted to capture the microscopic heterogeneity in the pore structure. Image processing was performed and important petrophysical parameters quantified, including pore size distribution, pore connectivity, and the surface-area-to-volume ratio of the rock. The quantified parameters were used to correlate to the optimal conditions obtained by physical experiments and rock permeability. A concept named equivalent pore radius was defined. This study determined that this parameter, equivalent pore radius, is tightly related to the permeability of rock and can be used to improve the optimal conditions prediction model for matrix acidizing. For the core-scale study, the optimal conditions for one type of the Travertine, a highly heterogeneous carbonate rock, is measured with core flooding test in the laboratory. The optimal conditions for various rock types under different experimental conditions are collected and sets of curves for optimal conditions are generated. The results of this study indicate that the optimal conditions for most carbonate rocks lie in a narrow range, which is useful for guiding matrix acidizing design. Finally, the characterization for carbonate formation at log scale mainly focuses on the most important petrophysical properties (porosity and permeability). The methods for porosity estimation, lithology estimation, and permeability estimation are discussed. The depth-by-depth porosity profile, permeability profile, and lithology are integrated with a horizontal well acid stimulation software (HWAS), which helps customize matrix acidizing design. Field application based on true formation properties are demonstrated

Acidizing High-Temperature Carbonate Formations Using Methanesulfonic Acid

Hydrochloric 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

An Experimental and Numerical Investigation into Permeability and Injectivity Changes during CO2 Storage in Saline Aquifers

CO2 storage appears as one of the best solutions to effectively decrease carbon emissions into the atmosphere in the short to medium term. CO2 can be stored in different types of geological formations. Among the various storing options, deep saline aquifers have the greatest capacity. As supercritical CO2 is injected in the aquifers, a number of strongly coupled chemical and physical processes occur. Among these various mechanisms, dissolution and precipitation of minerals, in particular carbonates, and halite deposition due to vapourisation of water require particular attention as they can lead to significant reduction in injectivity. This research investigated the mechanisms involved in injectivity losses through experimental and theoretical methods. The impact on injectivity of permeability changes occurring at various distances from the wellbore was studied using an idealised 1-D CO2 injection well flow model. A new experimental set-up was used to investigate the effect on dissolution/precipitation mechanisms of the pressure and temperature changes that the fluid is subjected to as it advances from the wellbore. Additional CO2 core flooding experiments were conducted on limestone and sandstone cores saturated with saline water in order to study the effects of water vapourisation. These vapourisation experiments aimed to provide a relationship between porosity changes and resulting permeability variations representing the effect of salt precipitation due to vapourisation. Such relationship was used to obtain more accurate results from a 2-D radial CO2 injection well flow model studying the effect of salt precipitation on the field. Numerical modelling of the injection wellbore have shown that changes in the petrophysical properties of the reservoir several metres away from the wellbore can still have a significant impact on injectivity. As indicated by the experimental research carried out, pressure and temperature gradients that exist inside the reservoirs may lead to re-precipitation in the far field, however no significant permeability and porosity changes were detected to suggest major losses of injectivity due to these effects. The results of vapourisation experiments have shown that small reduction in porosity can induce significant impairments in permeability. Results of the 2-D model showed that without appropriate injection strategies the technical and economical feasibility of CO2 storage projects can be compromised due to this effect. The numerical study also highlighted the possibility of the progressive formation of a layer of halite scaling in the interface between host-rock and cap-rock which would work as an extra sealing protection in the near wellbore area

Dissolução de rochas carbonáticas em sistemas de CO2/salmoura em alta pressão : efeitos na porosidade e permeabilidade

Orientador: Osvair Vidal TrevisanDissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica, Instituto de GeociênciasResumo: Descobertas recentes no pré-sal brasileiro revelaram quantidades significativas de petróleo associadas a grandes quantidades de CO2 em reservatórios carbonáticos. O CO2 produzido não pode ser liberado para a atmosfera devido ao efeito estufa. Injeção de Água Alternada com Gás CO2 é um método conhecido de Recuperação Melhorada de Petróleo utilizado para aumentar a recuperação de campos de óleo e pode ser aplicado nos campos do pré-sal. O CO2 injetado pode interagir com os fluidos no reservatório e mudar as propriedades da rocha carbonática. Quando o CO2 dissolve na água, forma o ácido carbonico, causando a dissolução dos minerais carbonáticos na rocha (principalmente calcita e dolomita). Isto pode causar mudanças nas propriedades de escoamento na rocha, principalmente a porosidade e permeabilidade, e o seu impacto não foi quantificado nas condições do pré-sal brasiliero (9.000 psi e 64oC). Tendo isso em mente, este trabalho experimental tem como objetivo principal o de avaliar como a porosidade e permeabilidade de rochas carbonáticas mudam devido à exposição de CO2 e água em condições próximas às dos reservatórios do pré-sal. Um objetivo secondário também foi definido como o de delinear as melhores práticas para a medição de porosidade e permeabilidade em condições de laboratório. O primeiro objetivo foi alcançado através de dois estudos experimentais em reatores: o primeiro, projetado para avaliar como a permeabilidade e porosidade de amostras de coquina e dolomita varia em sistemas de água fresca/CO2, com variação de pressão (até 9.000 psi) e temperatura constante; o segundo, para avaliar a variação das mesmas propriedades nas mesmas amostras de rocha, em sistemas de salmoura/CO2 em alta pressão (9.000 psi), temperatura constante e salmoura de salinidade variável. Foi concluído que a taxa dissolução diminiu com o tempo, aumenta com a pressão e porosidade inicial. Também foi constatado que a taxa de dissolução é inversamente proporcional com a salinidade da salmoura. A taxa de dissolução de coquina é maior que a da dolomita. Foi observado que a despressurização do reator de alta pressão poderia causar diminuições na porosidade e permeabilidade da rocha. O procedimento experimental proposto no segundo estudo experimental diminuiu este efeito. Em geral, quando a taxa de dissolução aumenta, a porosidade e permeabilidade das rochas aumentam também. O segundo objetivo foi alcançado comparando os valores de permeabilidade à gás e líquido medidos em laboratório de amostras de coquina e dolomita, assim como, avaliando medidas de porosidade e permeabilidade à gás de amostras de coquina, dolomita e arenito. Foi visto que, com o aparato experimental utilizado, não foi possível realizar a análise de Klinkenberg para converter permeabilidade à gás em permeabilidade à liquido. Também foi visto que a diminuição de permeabilidade com o aumento do diferencial de pressão utilizado na medade é mais evidente em rochas carbonáticas e que a permeabilidade média a gás da mesma amostra, medida nas mesmas condições, pode ser utilizada para avaliar a variação da permeabilidade da amostraAbstract: Recent discoveries in brazilian pre-salt fields revealed significant quantities of oil associated with high quantities of CO2 in carbonate reservoirs. The produced CO2 may not simply be liberated in the atmosphere due to the Greenhouse Effect. Water alternating Gas (WAG) injection together with CO2 is a well know Enhanced Oil Recovery (EOR) Method used to increase recovery in oil fields and may be applied in the pre-salt fields. The injected CO2 will interact with the fluids in the reservoir and change the carbonate rocks properties. When CO2 dissolves in water, it forms carbonic acid, causing the dissolution reaction of the carbonate minerals in the rock (mainly calcite and dolomite). This will change the rock flow properties, mainly porosity and permeability, and its impact has not been fully quantified in pre-salt conditions (9,000 psi and 64oC). Therefore, this experimental work has the main objective of evaluating how permeability and porosity of carbonate rocks changes due to exposure of CO2 and water at conditions close to that of the pre-salt reservoirs. A secondary objective was also defined as to delineate the best practices for measuring porosity and permeability in laboratory conditions. The first objective was achieved by two batch dissolution experimental studies: the first one, designed to evaluate how the permeability and porosity of coquina and dolomite outcrop rocks varies in fresh water/CO2 systems, with increasing pressure (up to 9,000 psi) at constant temperature (64oC); and the second, to evaluate the variation of the same properties for the same rock types, in high pressure (9,000 psi) brine/CO2 systems at constant temperature and varying brine salinity. It was concluded that dissolution rate decreases with time, it increases with the pressure and with initial porosity. Also, dissolution rate is inversely proportional with brine salinity. Coquina¿s dissolution rate is higher than Dolomite¿s. It was found that the depressurization of the high pressure vessel could cause decreases in porosity and permeability of the rock. The experimental procedure proposed in the second experimental study decreased this effect. In general, as the dissolution rate increases, the permeability and porosity of the rocks increases as well. The secondary objective was achieved by comparing gas permeability and liquid permeability measured in laboratory of coquina and dolomite rock samples and assessing gas porosity and permeability measurement of coquina, dolomite and sandstone samples. It was found that with the used experimental set-up it was not possible to perform Klinkenberg¿s analysis to convert gas permeability into liquid permeability. It was also found that the decrease in permeability with increase in measuring pressure differential is more evident in carbonate rocks and the average gas permeability of the same sample, measured at the same conditions can be used to evaluate the variation of the sample¿s permeabilityMestradoReservatórios e GestãoMestre em Ciências e Engenharia de Petróle

Observations from Experimental Acid Jetting on Limestone Carbonates

Well stimulation is a common practice in petroleum engineering, applied when the production does not meet expectations. Acid jetting is one of the acid stimulation methods, used in carbonate reservoirs where formation damage is present. In acid jetting, an acid solution is “jetted” unto the wellbore surface in the producing zone with the objective of removing the mud filter cake and bypassing the damaged zone by creating wormholes. As for any other stimulation treatments, experimental core studies are performed to get a better understanding of the process and how it can be controlled to achieve successful treatments. Previous experimental studies have revealed a trend in the experimental results of high velocity acid jetting, namely the formation of a cavity in the vicinity of the injection nozzle, often followed by wormhole propagation from the cavity, throughout the core. These observations have raised the need for a thorough study. For this study, more experiments are run with the objective of qualitatively identify the key parameters affecting the dissolution pattern observed and compare their relative impact. Experiments are conducted on Indiana limestone and Winterset limestone cores of dimension with 15 wt% hydrochloric acid. Different injection rates were used in the experiments, while holding a constant pressure differential across the core, determined from a desired initial interstitial velocity. Permeability values of the cores range from 0.70 mD to 11.50 mD with porosity values between 12% and 25%. The experimental results show that the key parameters to acid jetting experiments are interstitial velocity across the core, pressure difference across the core, rock permeability, rock heterogeneity and/or pore structure, and acid injection rate. The interstitial velocity across the core appears to be the governing parameter, at all injection rates used. CT scans of the cores after experiments also suggest the existence of optimum conditions for the pressure difference, corresponding interstitial velocity and flux, at which the acid forms a minimal cavity and a less-branched, straight wormhole to breakthrough. These optimum conditions vary with the acid injection rate

Development of a Compact Core Flooding Apparatus for Matrix Acidizing Applications

Matrix Acidizing is defined as a well stimulation technique in which the acid is injected into the formation with the purpose of dissolving the minerals present and thus enhancing the permeability of the formation and facilitating the extraction of oil and/or gas from the formation. The primary goal of acid diversion is the creation of wormholes and ramification paths that allow the fluid to flow from the higher to the lower permeability zones of the limestones, sandstones or carbonate reservoirs. Naturally, as the injected acid will follow vugs, fractures and pores, HCl is used because of its quick reaction and fast limestone dissolution. Matrix acidizing is one of the most utilized well stimulation techniques because of its low cost when compared to other techniques. It is known that there are four main parameters affecting the test performance: Injection rate of the acid, the reaction type, the heterogeneity, and the calcite concentration. To conduct experiments simulating real field conditions, a core flooding laboratory setup was developed. Acid is injected at high pressures using a continuous flow syringe pump. The acid and the brine are injected at pressures below the fracture pressure, this will remove any existing damage in the formation, restore and improve the well productivity. Furthermore, to simulate the overburden pressure, self-weight of the soil or hydrostatic pressure, an overburden pressure pump was added. Finally, it is also important to add the back pressure exerted by the well, this with the use of a backpressure regulator. The main goal of the laboratory development is to study, analyze and understand the optimum conditions for wormhole creation. Multiple parameters such as injection rate, temperature, injection pressure will be studied and tested to find optimum parameters. The core flooding apparatus was design to test at pressures as high as 5000 psi, stainless steel tubing, valves and fittings were utilized in order to support the corrosive nature of the Hydrochloric Acid. As temperature plays an important role in matrix acidizing, a heating tape around the core holder was added to perform tests at different temperatures. A compact design was developed as one of the main goals is to reduce the length of the tubing and thus reduce the amount of fluid loss by the pipes