Core flooding is a commonly used experimental procedure in the petroleum industry. It involves pressurizing a reservoir rock and flowing fluid through it in the laboratory. The cylindrical rock, called a core, can be cut from the reservoir during a separate core drilling operation or a formation outcrop. A core flooding apparatus suitable for matrix acidizing was designed and assembled. Matrix acidizing is a stimulation technique in which hydrochloric acid (HCl) is injected down the wellbore below formation fracture pressure to dissolve carbonate (CaCO3) rock creating high permeability streaks called wormholes. The main components of the apparatus include a continuous flow syringe pump, three core holders, a hydraulic hand pump, two accumulators, a back pressure regulator, and two pressure transducers connected through a series of tubing and valves. Due to the corrosive nature of the acid, the apparatus features Hastelloy which is a corrosion resistant metal alloy. Another substantial feature of the apparatus is the ability to apply 3000psi back pressure. This is the pressure necessary to keep CO2, a product of the CaCO3 and HCl reaction, in solution at elevated temperatures. To perform experiments at temperature, the core holder is wrapped with heating tape and surrounded by insulation. Tubing is wrapped around a heating band with insulation to heat the fluid before it enters the core. A LabVIEW graphical programming code was written to control heaters as well as record temperature and pressure drop across the core. Other considerations for the design include minimizing footprint, operational ease by the user, vertical placement of the accumulators and core holders to minimize gravity effects, and air release valves. Core floods can be performed at varying injection rates, temperatures and pressures up to 5000psi and 250 degF. The apparatus can handle small core plugs, 1’’ diameter X 1’’ length, up to 4’’ X 20’’ cores. The equipment description includes the purpose, relevant features, and connections to the system for each component. Finally documented is the procedure to run a core flooding test to determine permeability and inject acid complete with an analysis of pressure response data.

The main purpose of acid/water jetting treatments currently applied in the field is to clean up the filter cake formed during the drilling process and perhaps further stimulate the wellbore by creating wormholes if acid jetting is used in carbonate formation. This purpose can be achieved for the reason that the filter cake on the borehole can be mechanically broken by the high speed jetting action, and additionally, if acid is used, some materials in the filter cake can be dissolved, which can facilitate the mechanical breaking action. The knowledge of jetting effectiveness under various conditions is crucial for the purpose of optimizing the treatment design. In order to investigate quantitatively the effectiveness of acid/water jetting for filter cake cleanup and wellbore productivity enhancement, laboratory experiments were carried out under conditions similar to those in the field. Filter cake was deposited on the face of a 4 inch diameter core and then water or 15% HCl were used for jetting treatment. The original permeability, the permeability right after the drill-in fluid damage, and the permeability after the jetting treatment were measured and compared. The effect of overbalance pressure during the jetting treatment was investigated. CT scan was carried out for those cores that may have wormholes after the acid jetting treatment. An analysis of the mechanism for filter cake removal and wormhole creating during acid jetting treatment was proposed. It is discovered that acid jetting can effectively remove the filter cake by penetrating and lifting it from beneath, and efficient wormhole creation can only happen when the overbalance pressure during the acid jetting treatment is above a certain value. Based on this study, several suggestions for field applications were made.

In matrix acidizing, the goal is to dissolve minerals in the rock to increase well productivity. This is accomplished by injecting an application-specific solution of acid into the formation at a pressure between the pore pressure and fracture pressure. A hydrochloric acid solution is used in carbonate reservoirs, which actually dissolves the calcite rock matrix in the form of conductive channels called wormholes. These wormholes propagate from the wellbore out into the reservoir, bypassing the damaged zone. In matrix acidizing of carbonates, there are four parameters that affect performance: the concentration of calcite present, injection rate of the acid, reaction type, and heterogeneity. Of these parameters, this paper will focus on how rock heterogeneity affects performance. To do this, a coreflood and acidizing apparatus was used to acidize heterogeneous limestone core samples. Rock characterizations and volumetric measurements were considered with the results from these experiments, which made it possible to correlate and quantify the results with rock and volume parameters. It was found that the core samples with more and larger heterogeneities generally required less acid (measured in pore volumes) to achieve breakthrough, that is, a wormhole created axially from one end of the core to the other. This value for pore volumes to breakthrough was one to two orders of magnitude less than more homogeneous samples. The general procedure and best practices for acidizing the core samples is also detailed in this thesis. This procedure was followed for preparation, coreflooding, and acidizing for all core samples.

The goal of this work was to evaluate matrix acidizing treatments of vertical and horizontal wells in carbonate reservoirs. Twenty field cases for acidizing treatments were analyzed by evaluating the skin factor evolution from on-site rate/pressure data during the treatment. A skin monitoring method based on the concept of inverse injectivity (Hill and Zhu, 1996) was used to calculate the skin factor evolution. Viscous diversion techniques were analyzed by using the viscous diversion skin model that accounts for viscosity contrast between the reservoir fluid and the injected fluid. The estimated skin evolution during the treatment was validated using the post-treatment well performance. From the post-treatment analysis, it was observed that emulsified acid was not an efficient viscous diverter because only 27% of the wells treated with emulsified acid showed evidence of viscous diversion. Therefore, other viscous diversion techniques are needed to ensure uniform acid coverage. In addition, treatments that involved diversion techniques such as foam, associative-polymers, and viscoelastic surfactants were also evaluated. Thus, the post-treatment evaluation was used to improve and optimize the acid treatment designs. This study was beneficial to diagnose if excess acid volumes were used, or effective diversion was achieved during the acid treatment.

Design of matrix acidizing treatments of carbonate formation is still a challenge although extensive research has been done on it. It is necessary to estimate acid distribution along the wellbore. This estimation is very important especially for the case where the reservoir properties vary along the wellbore. This work provides development and application of an apparent skin factor model which accounts for both damage and mobility difference between acid and gas. Combining this model with a conventional acid placement model, we develop an acid placement model for vertically extensive, multilayer gas reservoirs. A computer program is developed implementing the acid placement model. The program is used to simulate hypothetical examples of acid placement for vertically extensive, multilayer gas reservoirs. This model will improve matrix acidizing for gas reservoirs and enable realtime monitoring of acid stimulation more accurately.

Matrix acidizing is a well stimulation procedure where acid is injected down the wellbore or coil tubing and into the reservoir near the wellbore region. Wellbore damage is a common issue in the oil field. The primary goal of matrix acidizing in carbonate reservoirs is to bypass wellbore damage by creating highly conductive channels that go several feet into the formation, known as wormholes. The goal of laboratory experiments is to find an optimum injection rate to create dominant wormholes and provide this information to the field. To conduct various experiments, core flooding setups are created. The setup consists of a core holder, accumulator, overburden pump, injection pump, accumulator, pressure sensors, and a back pressure regulator. Results from matrix acidizing core flooding in laboratory conditions provide an understand for wormhole growth, acid diversion, injection rates, and adds a variety of liquid chemicals for testing at reservoir pressures and temperatures. The first objective was to design, assemble, and test a matrix acidizing parallel core flooding apparatus. The apparatus was rated for 5,000 psi and 250 ºF. Combinations of the various mechanical components were chosen appropriately to meet the requirements. Electrical wiring and data acquisition hardware was assembled. LabVIEW software code was written for controlling temperature and recording data. The second objective was to create a documented method for conducting experiments.

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.

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.

Matrix acidizing is a well stimulation technique used to remove formation damage in the near wellbore region. But it comes with an associated set of challenges such as corrosion of the tubulars and iron precipitation in the formation. To counter these challenges, different chemicals, or additives, are added to the acid solution such as corrosion inhibitors and iron control agents. These additives may change the relative permeability of the spent acid, and formation wettability, and may either hinder or improve spent acid clean-up. Such effects of additives on the spent acid clean-up have not been documented. The aim of this research effort was to document the aforementioned change in the spent acid concentration (by using one additive at a time) before and after gas flowback. This was achieved by acidizing cores and creating wormholes halfway through them, then CT scanning them to observe the spent acid region. Later on, gas was flown through the core opposite to the direction of acid injection for 2 hours, and another CT scan was taken. The difference between the two CT scans was documented. Using a different additive each time, a series of such CT scans was obtained to develop an idea about whether the said additive was beneficial or detrimental to spent acid clean-up. It was found that the corrosion inhibitor FA-CI performed the best in terms of spent acid recovery after gas flowback for both Indiana Limestone and Texas Cream Chalk cores. Moreover, the corrosion inhibitor MI-CI was the worst for Indiana Limestone and the non-emulsifying agent M-NEA the worst for Texas Cream Chalk for spent acid recovery after gas flowback.

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.