Horizontal wells are drilled to achieve improved reservoir coverage, high production rates, and to overcome water coning problems, etc. Many of these wells often produce at rates much below the expected production rates. Low productivity of horizontal wells is attributed to various factors such as drilling induced formation damage, high completion skins, and variable formation properties along the length of the wellbore as in the case of heterogeneous carbonate reservoirs. Matrix acidizing is used to overcome the formation damage by injecting the acid into the carbonate rock to improve well performance. Designing the matrix acidizing treatments for horizontal wells is a challenging task because of the complex process. The estimation of acid distribution along wellbore is required to analyze that the zones needing stimulation are receiving enough acid. It is even more important in cases where the reservoir properties are varying along the length of the wellbore. A model is developed in this study to simulate the placement of injected acid in a long horizontal well and to predict the subsequent effect of the acid in creating wormholes, overcoming damage effects, and stimulating productivity. The model tracks the interface between the acid and the completion fluid in the wellbore, models transient flow in the reservoir during acid injection, considers frictional effects in the tubulars, and predicts the depth of penetration of acid as a function of the acid volume and injection rate at all locations along the completion. A computer program is developed implementing the developed model. The program is used to simulate hypothetical examples of acid placement in a long horizontal section. A real field example of using the model to history match actual treatment data from a North Sea chalk well is demonstrated. The model will help to optimize acid stimulation in horizontal wells.

To increase the successful rate of acid stimulation, a method is required to diagnose the effectiveness of stimulation which will help us to improve stimulation design and decide whether future action, such as diversion, is needed. For this purpose, it is important to know how much acid enters each layer in a multilayer carbonate formation and if the low-permeability layer is treated well. This work develops a numerical model to determine the temperature behavior for both injection and flow-back situations. An important phenomenon in this process is the heat generated by reaction, affecting the temperature behavior significantly. The result of the thermal model showed significant temperature effects caused by reaction, providing a mechanism to quantitatively determine the acid flow profile. Based on this mechanism, a further inverse model can be developed to determine the acid distribution in each layer.

Horizontal wells are drilled to achieve improved reservoir coverage, high production rates, and to overcome water coning problems, etc. Many of these wells often produce at rates much below the expected production rates. Low productivity of horizontal wells is attributed to various factors such as drilling induced formation damage, high completion skins, and variable formation properties along the length of the wellbore as in the case of heterogeneous carbonate reservoirs. Matrix acidizing is used to overcome the formation damage by injecting the acid into the carbonate rock to improve well performance. Designing the matrix acidizing treatments for horizontal wells is a challenging task because of the complex process. The estimation of acid distribution along wellbore is required to analyze that the zones needing stimulation are receiving enough acid. It is even more important in cases where the reservoir properties are varying along the length of the wellbore. A model is developed in this study to simulate the placement of injected acid in a long horizontal well and to predict the subsequent effect of the acid in creating wormholes, overcoming damage effects, and stimulating productivity. The model tracks the interface between the acid and the completion fluid in the wellbore, models transient flow in the reservoir during acid injection, considers frictional effects in the tubulars, and predicts the depth of penetration of acid as a function of the acid volume and injection rate at all locations along the completion. A computer program is developed implementing the developed model. The program is used to simulate hypothetical examples of acid placement in a long horizontal section. A real field example of using the model to history match actual treatment data from a North Sea chalk well is demonstrated. The model will help to optimize acid stimulation in horizontal wells.

Carbonates invariably have small (micron) to large (centimeter) scale heterogeneities in flow properties that may cause the effects of injected acids to differ greatly from what is predicted by a model based on a homogenous formation. To the best of our knowledge, there are neither theoretical nor experimental studies on the effect of large scale heterogeneities (vugs) on matrix acidizing. The abundance of carbonate reservoirs (60% of the world?s oil reserves) and the lack of a detailed study on the effect of multi-scale heterogeneities in carbonate acidizing are the main motivations behind this study. In this work, we first present a methodology to characterize the carbonate cores prior to the core-flood acidizing experiments. Our approach consists of characterization of the fine-scale (millimeter) heterogeneities using computerized tomography (CT) and geostatistics, and the larger-scale (millimeter to centimeter) heterogeneities using connected component labeling algorithm and numerical simulation. In order to understand the connectivity of vugs and thus their contribution to flow, a well-known 2D visualization algorithm, connected component labeling (CCL), was implemented in 3D domain. Another tool used in this study to understand the connectivity of the vugs and its effect on fluid flow is numerical simulation. A 3D finite difference numerical model is developed based on Darcy-Brinkman formulation (DBF). Using the developed simulator a flow-based inversion approach is implemented to understand the connectivity of the vugs in the samples studied. After multi-scale characterization of the cores, acid core-flood experiments are conducted. Cores measuring four inches in diameter by twenty inches in length are used to decrease the geometry effects on the wormhole path. The post acid injection porosity distribution and wormhole paths are visualized after the experiments. The experimental results demonstrate that acid follows not only the high permeability paths but also the spatially correlated ones. While the connectivity between the vugs, total amount of vuggy pore space and size of the cores are the predominant factors, spatial correlation of the petro-physical properties has less pronounced effect on wormhole propagation in acidiziation of carbonates. The fact that acid channeled through the vugular cores, following the path of the vug system, was underlined with computerized tomography scans of the cores before and after acid injection. This observation proposes that local pressure drops created by vugs are more dominant in determining the wormhole flow path than the chemical reactions occurring at the pore level. Following this idea, we present a modeling study in order to understand flow in porous media in the presence of vugs. Use of coupled Darcy and Stokes flow principles, known as Darcy-Brinkman formulation (DBF), underpins the proposed approach. Several synthetic simulation scenarios are created to study the effect of vugs on flow and transport. The results demonstrate that total injection volume to breakthrough is affected by spatial distribution, amount and connectivity of vuggy pore space. An interesting finding is that although the presence and amount of vugs does not change the effective permeability of the formation, it could highly effect fluid diversion. We think this is a very important observation for designing of multi layer stimulation.

Today, optimizing well stimulation techniques to obtain maximum return of investment is still a challenge. Hydraulic fracturing is a typical application to improve ultimate recovery from oil and gas reservoirs. Proppant fracturing has become one of the most widely considered alternatives for application in carbonate reservoirs. Especially in areas that have high closure stress, the non-smoothly etched surface created by acid fracturing may not remain open upon closing, resulting in decrease in fracture conductivity and unsuccessful stimulation treatment. In early years, because of the increase in the success of proppant fracturing, proppant partial monolayer has been put forward as a method that helps generate the maximum fracture conductivity from proppant fracturing treatment. However, this method was not widely successful because of proppant crushing and proppant embedment problems that result in losing conductivity. The ability to transport propping agents in available fracturing fluid was also poor and resulted in difficulties and failures to obtain proppant partial monolayer placement. For carbonate formations, acid fracturing is another effective stimulation method. Simpler operation and lower cost made the technique attractive in the field with plenty of successful experiences. The heterogeneity feature of carbonate formation brings a challenge to create sufficient conductivity. In cases of high closure formation, fracture conductivity is hard to sustain. This factor limited the applications of acid fracturing sometimes. In this study, laboratory tests were carried out using low concentrations of ultralightweight proppant to obtain partial monolayer proppant. Because of low specific gravity property of this proppant, it was claimed to help improve proppant transport inside the fracture. In this experimental study, the partial monolayer technique was examined with particular emphasis upon the impact of acid in possibly improving fracture conductivity of carbonate rocks. The technique is referred as "closed fracture acidizing". After obtaining a partial monolayer distribution on the fracture face, gelled acid was injected through the fracture face. Fracture conductivity before and after acid injection were evaluated. Experimental results showed clearly that acid injection does not enhance fracture conductivity of partial monolayer proppant fracturing. The more the volume of acid injection, the more rapidly fracture conductivity declines.

Matrix acidizing is used in carbonate formations to create wormholes that connect the formation to the wellbore. Hydrochloric acid, organic acids, or mixtures of these acids are typically used in matrix acidizing treatments of carbonate reservoirs. However, the use of these acids in deep wells has some major drawbacks including high and uncontrolled reaction rate and corrosion to well tubulars, especially those made of chrome-based tubulars (Cr-13 and duplex steel), and these problems become severe at high temperatures. Hydrochloric acid (HCl) and its based fluids have a major drawback in stimulating shallow (low fracture gradient) formations as they may cause face dissolution (formation surface washout) if injected at low rates. The objective of stimulation of sandstone reservoirs is to remove the damage caused to the production zone during drilling or completion operations. Many problems may occur during sandstone acidizing with Hydrochloric/Hydrofluoric acids (HCl/HF) mud acid. Among those problems: decomposition of clays in HCl acids, precipitation of fluosilicates, the presence of carbonate can cause the precipitation of calcium fluorides, silica-gel filming, colloidal silica-gel precipitation, and mixing between various stages of the treatment. To overcome problems associated with strong acids, chelating agents were introduced and used in the field. However, major concerns with most of these chemicals are their limited dissolving power and negative environmental impact. Glutamic acid diacetic acid (GLDA) a newly developed environmentally friendly chelate was examined as stand-alone stimulation fluid in deep oil and gas wells. In this study we used GLDA to stimulate carbonate cores (calcite and dolomite). GLDA was also used to stimulate and remove the damage from different sandstone cores containing different compositions of clay minerals. Carbonate cores (calcite and dolomite) of 6 and 20 in. length and 1.5 in. diameter were used in the coreflood experiments. Coreflood experiments were run at temperatures ranging from 180 to 300oF. Ethylene diamine tetra acetic acid (EDTA), hydroxyl ethylethylene diaminetriacetic acid (HEDTA), and GLDA were used to stimulate and remove the damage from different sandstone cores at high temperatures. X-ray Computed Topography (CT) scans were used to determine the effectiveness of these fluids in stimulation calcite and dolomite cores and removing the damage from sandstone cores. The sandstone cores used in this study contain from 1 to 18 wt percent illite (swellable and migratable clay mineral). GLDA was found to be highly effective in creating wormholes over a wide range of pH (1.7-13) in calcite cores. Increasing temperature enhanced the reaction rate, more calcite was dissolved, and larger wormholes were formed for different pH with smaller volumes of GLDA solutions. GLDA has a prolonged activity and leads to a decreased surface spending resulting in face dissolution and therefore acts deeper in the formation. In addition, GLDA was very effective in creating wormholes in the dolomite core as it is a good chelate for magnesium. Coreflood experiments showed that at high pH values (pH =11) GLDA, HEDTA, and EDTA were almost the same in increasing the permeability of both Berea and Bandera sandstone cores. GLDA, HEDTA, and EDTA were compatible with Bandera sandstone cores which contains 10 wt percent Illite. The weight loss from the core was highest in case of HEDTA and lowest in case of GLDA at pH 11. At low pH values (pH =4) 0.6M GLDA performed better than 0.6M HEDTA in the coreflood experiments. The permeability ratio (final/initial) for Bandera sandstone cores was 2 in the case of GLDA and 1.2 in the case of HEDTA at pH of 4 and 300oF. At high pH HEDTA was the best chelating agent to stimulate different sandstone cores, and at low pH GLDA was the best one. For Berea sandstone cores EDTA at high pH of 11 was the best in increasing the permeability of the core at 300oF. The low pH GLDA based fluid has been especially designed for high temperature oil well stimulation in carbonate and sandstone rock. Extensive studies have proved that GLDA effectively created wormholes in carbonate cores, is gentle to most types of casing including Cr-based tubular, has a high thermal stability and gives no unwanted interactions with carbonate or sandstone formations. These unique properties ensure that it can be safely used under extreme conditions for which the current technologies do not give optimal results. Furthermore, this stimulation fluid contributes to a sustainable future as it based on readily biodegradable GLDA that is made from natural and renewable raw material.

Diversion in carbonates is more difficult than in sandstones because of the ability of acid to significantly increase the permeability in carbonates as it reacts in the pore spaces and flow channels of matrix. In-situ gelled acids that are based on polymers have been used in the field for several years and were the subject of many lab studies. An extensive literature survey reveals that there are conflicting opinions about using these acids. On one hand, these acids were used in the field with mixed results. Recent lab work indicated that these acids can cause damage under certain conditions. There is no agreement on when this system can be successfully applied in the field. Therefore, this study was conducted to better understand this acid system and determine factors that impact its performance. Lab test of polymer-based in-situ gelled acids reveal that polymer and other additives separate out of the acid when these acids are prepared in high salinity water. In coreflood tests, in-situ gelled acid formed a gel inside 20” long core samples, and the acid changed its direction several times. Unexpectantly, the core's permeability was reduced at low shear rate. Wormhole length increased as the shear rate was increased; while the diameter of the wormhole increased as the acid cumulative injected volume was increased. CT scan indicated the presence of gel residue inside and around the wormhole. Gel residue increased at low shear rates. Material balance on the cross-linker indicated that a significant amount of the crosslinker was retained in the core. Based on the results obtained from this study the in-situ gelled acids should be used only at low HCl concentrations (5 wt percent HCl). Acid should be prepared in low salinity water and the acid injection rate should be determined based on the expected shear rate in the formation. A core flood experiment is recommended to confirm optimum injected rate. Well flow back is needed to minimize the residual gel inside the formation. The data obtained in this study can be used as a guideline for injection rate selection.

Well stimulation techniques are applied on a regular basis to enhance productivity and maximize recovery in oil and gas wells. Among these techniques, matrix acidizing is probably the most widely performed job because of its relative low cost, compared to hydraulic fracturing, and suitability to both generate extra production capacity and to restore original productivity in damaged wells. The acidizing process leads to increased economic reserves, improving the ultimate recovery in both sandstone and carbonate reservoirs. Matrix acidizing consists of injecting an acid solution into the formation, at a pressure below the fracture pressure to dissolve some of the minerals present in the rock with the primary objective of removing damage near the wellbore, hence restoring the natural permeability and greatly improving well productivity. Reservoir heterogeneity plays a significant role in the success of acidizing treatments because of its influence on damage removal mechanisms, and is strongly related to dissolution pattern of the matrix. The standard acid treatments are HCl mixtures to dissolve carbonate minerals and HCl- HF formulations to attack those plugging minerals, mainly silicates (clays and feldspars). A matrix acidizing apparatus for conducting linear core flooding was built and the operational procedure for safe, easy, and comprehensive use of the equipment was detailed. It was capable of reproducing different conditions regarding flow rate, pressure, and temperature. Extensive preliminary experiments were carried out on core samples of both Berea sandstone and Cream Chalk carbonate to evaluate the effect of rock heterogeneities and treatment conditions on acidizing mechanisms. The results obtained from the experiments showed that the temperature activates the reaction rate of HF-HCl acid mixtures in sandstone acidizing. The use of higher concentrations of HF, particularly at high temperatures, may cause deconsolidation of the matrix adversely affecting the final stimulation results. It was also seen that the higher the flow rate the better the permeability response, until certain optimal flow rates are reached which appears to be 30 ml/min for Berea sandstone. Highly permeable and macroscopic channels were created when acidizing limestone cores with HCl 15%. In carbonate rocks, there is an optimum acid injection rate at which the dominant wormhole system is formed.

This work proposes to survey new chemical knowledge, developed since 1984, on fluid additives used in matrix stimulation treatments of carbonate and sandstone petroleum reservoirs and describes one method of organizing this new knowledge in a software program using the Visual Basic for Applications programming language. While matrix stimulation treatments have been used in the petroleum industry for over 100 years, the last major review of the technical literature addressing this process occurred in 1984. Currently though, the petroleum industry better understands formation damage; uses different and more chemical additives in matrix stimulation treatments; and understands how some additives interact with one another affecting well performance. As a result, a new and thorough review of the literature regarding chemical additive choices for matrix stimulation treatments will help practicing engineers achieve better results worldwide. Moreover, organizing this chemical knowledge in a software program using VBA allows an engineer to access the information through Microsoft's widely available spreadsheet program, Microsoft Excel.

Iron precipitation during matrix acidizing treatments is a well-known problem. During matrix acidizing, successful iron control can be critical to the success of the treatment. Extensive literature review highlighted that no systematic study was conducted to determine where this iron precipitates, the factors that affect this precipitation, and the magnitude of the resulting damage. Iron (III) precipitation occurs when acids are spent and the pH rises above 1, which can cause severe formation damage. Chelating agents are used during these treatments to minimize iron precipitation. Disadvantages of currently used chelating agents include limited solubility in strong acids, low thermal stability, and/or poor biodegradability. In this study, different factors affecting iron precipitation in Indiana limestone rocks were examined. Two chelating agents, GLDA and HEDTA, were tested at different conditions to assess their iron control ability. Results show that a significant amount of iron precipitated, producing a minimal or no gain in the final permeability, this indicated severe formation damage. The damage increased with the increase of the amount of iron in solution. When chelating agents were used, the amount of iron recovered depended on both chelate-to-iron mole ratio and the initial permeability of the cores. Calcium is chelated along with iron, which limits the effectiveness of chelating agents to control iron (III) precipitation. Acid solutions should be designed considering this important finding for more successful treatments.