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.

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.

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.

Experimental design can be vital when experiments are resource-exhaustive and time-consuming. In this work, we carry out experimental design in the Bayesian framework. To measure the amount of information that can be extracted from the data in an experiment, we use the expected information gain as the utility function, which specifically is the expected logarithmic ratio between the posterior and prior distributions. Optimizing this utility function enables us to design experiments that yield the most informative data about the model parameters. One of the major difficulties in evaluating the expected information gain is that it naturally involves nested integration over a possibly high dimensional domain. We use the Multilevel Monte Carlo (MLMC) method to accelerate the computation of the nested high dimensional integral. The advantages are twofold. First, MLMC can significantly reduce the cost of the nested integral for a given tolerance, by using an optimal sample distribution among different sample averages of the inner integrals. Second, the MLMC method imposes fewer assumptions, such as the asymptotic concentration of posterior measures, required for instance by the Laplace approximation (LA). We test the MLMC method using two numerical examples. The first example is the design of sensor deployment for a Darcy flow problem governed by a one-dimensional Poisson equation. We place the sensors in the locations where the pressure is measured, and we model the conductivity field as a piecewise constant random vector with two parameters. The second one is chemical Enhanced Oil Recovery (EOR) core flooding experiment assuming homogeneous permeability. We measure the cumulative oil recovery, from a horizontal core flooded by water, surfactant and polymer, for different injection rates. The model parameters consist of the endpoint relative permeabilities, the residual saturations and the relative permeability exponents for the three phases: water, oil and microemulsions. We also compare the performance of the MLMC to the LA and the direct Double Loop Monte Carlo (DLMC). In fact, we show that, in the case of the aforementioned examples, MLMC combined with LA turns to be the best method in terms of computational cost.

Master of Science / Department of Geology / Saugata Datta / With the ever-rising atmospheric concentrations of CO₂ there arises a need to either reduce emissions or develop technology to store or utilize the gas. Geologic carbon storage is a potential solution to this global problem. This work is a part of the U.S. Department of Energy small-scale pilot studies investigating different areas for carbon storage within North America, with Kansas being one of them. This project is investigating the feasibility for CO₂ storage within the hyper-saline Arbuckle aquifer in Kansas. The study incorporates the investigation of three wells that have been drilled to basement; one well used as a western calibration study (Cutter), and the other two as injection and monitoring wells (Wellington 1-28 and 1-32). Future injection will occur at the Wellington field within the Arbuckle aquifer at a depth of 4,900-5,050 ft. This current research transects the need to understand the lateral connectivity of the aquifers, with Cutter being the focus of this study. Three zones are of interest: the Mississippian pay zone, a potential baffle zone, and the Arbuckle injection zone. Cored rock analyses and analyzed formation water chemistry determined that at Wellington there exists a zone that separated the vertical hydrologic flow units within the Arbuckle. This potential low porosity baffle zone within the Arbuckle could help impede the vertical migration of the buoyant CO₂ gas after injection. Geochemical analysis from formation water within Cutter indicates no vertical separation of the hydrologic units and instead shows a well-mixed zone. The lateral distance between Cutter and Wellington is approximately 217 miles. A well-mixed zone would allow the CO₂ plume to migrate vertically and potentially into potable water sources. Formation brine from Cutter was co-injected with supercritical CO₂ into a cored rock from within the Arbuckle (7,098 ft.). Results show that the injected CO₂ preferentially preferred a flow pathway between the chert nodules and dolomite. Post reaction formation chemistry of the brine showed the greatest reactivity occurring with redox sensitive species. Reactivity of these species could indicate that they will only be reactive on the CO₂ plumes front, and show little to no reactivity within the plume.

Even in times of renewable energy revolution fossil fuels will play a major role in energy supply, transportation, and chemical industry. Therefore, increasing demand for crude oil will still have to be met in the next decades by developing new oil re-serves. To cope with this challenge, companies and researchers are constantly seeking for new methods to increase the recovery factor of oil fields. For that reason, many enhanced oil recovery (EOR) methods have been developed and applied in the field. EOR methods alter the physico-chemical conditions inside the reservoir. One possibility to achieve this is to inject an aqueous solution containing special chemicals into the oil-bearing zone. Polymers, for example, increase the viscosity of the injected water and hence improve the displacement of the oil to the production well. The injection of surfactant solutions results in reduced capillary forces, which retain the oil in the pores of the reservoir. Some surfactants form viscoelastic solutions under certain conditions. The possibil-ity to apply those solutions for enhanced oil recovery has been investigated by some authors in the last years in low salinity brines. Reservoir brines, however, often contain high salt concentrations, which have detrimental effects on the properties of many chemical solutions applied for EOR operations. The Triphenoxymethane derivatives, which were the subject of study in this thesis, form viscoelastic solutions even in highly saline brines. The aim of this thesis was to investigate the efficiency and the mode-of-action of this new class of chemical EOR molecules with respect to oil mobilization in porous media.

Even in times of renewable energy revolution fossil fuels will play a major role in energy supply, transportation, and chemical industry. Therefore, increasing demand for crude oil will still have to be met in the next decades by developing new oil re-serves. To cope with this challenge, companies and researchers are constantly seeking for new methods to increase the recovery factor of oil fields. For that reason, many enhanced oil recovery (EOR) methods have been developed and applied in the field. EOR methods alter the physico-chemical conditions inside the reservoir. One possibility to achieve this is to inject an aqueous solution containing special chemicals into the oil-bearing zone. Polymers, for example, increase the viscosity of the injected water and hence improve the displacement of the oil to the production well. The injection of surfactant solutions results in reduced capillary forces, which retain the oil in the pores of the reservoir. Some surfactants form viscoelastic solutions under certain conditions. The possibil-ity to apply those solutions for enhanced oil recovery has been investigated by some authors in the last years in low salinity brines. Reservoir brines, however, often contain high salt concentrations, which have detrimental effects on the properties of many chemical solutions applied for EOR operations. The Triphenoxymethane derivatives, which were the subject of study in this thesis, form viscoelastic solutions even in highly saline brines. The aim of this thesis was to investigate the efficiency and the mode-of-action of this new class of chemical EOR molecules with respect to oil mobilization in porous media.

Chemical EOR processes such as polymer flooding and surfactant polymer flooding must be designed and implemented in an economically attractive manner to be perceived as viable oil recovery options. The primary expenses associated with these processes are chemical costs which are predominantly controlled by the crude oil properties of a reservoir. Crude oil viscosity dictates polymer concentration requirements for mobility control and can also negatively affect the rheological properties of a microemulsion when surfactant polymer flooding. High microemulsion viscosity can be reduced with the introduction of an alcohol co-solvent into the surfactant formulation, but this increases the cost of the formulation. Experimental research done as part of this study combined the process of hot water injection with ASP flooding as a solution to reduce both crude oil viscosity and microemulsion viscosity. The results of this investigation revealed that when action was taken to reduce microemulsion viscosity, residual oil recoveries were greater than 90%. Hot water flooding lowered required polymer concentrations by reducing oil viscosity and lowered microemulsion viscosity without co-solvent. Laboratory testing of viscous microemulsions in core floods proved to compromise surfactant performance and oil recovery by causing high surfactant retention, high pressure gradients that would be unsustainable in the field, high required polymer concentrations to maintain favorable mobility during chemical flooding, reduced sweep efficiency and stagnation of microemulsions due to high viscosity from flowing at low shear rates. Rough scale-up chemical cost estimations were performed using core flood performance data. Without reducing microemulsion viscosity, field chemical costs were as high as 26.15 dollars per incremental barrel of oil. The introduction of co-solvent reduced chemical costs to as low as 22.01 dollars per incremental barrel of oil. This reduction in cost is the combined result of increasing residual oil recovery and the added cost of an alcohol co-solvent. Heating the reservoir by hot water flooding resulted in combined chemical and heating costs of 13.94 dollars per incremental barrel of oil. The significant drop in cost when using hot water is due to increased residual oil recovery, reduction in polymer concentrations from reduced oil viscosity and reduction of microemulsion viscosity at a fraction of the cost of co-solvent. / text