This laboratory project has been done to evaluate pressure pulsing as an Enhanced Oil Recovery (EOR) technique. To perform the study, a consistent laboratory methodology was developed, including the construction of a Consistent Pulsing Source (CPS). Tests compared pulsed and non-pulsed waterfloods in a paraffin or crude oil saturated medium, which also contained connate water (an irreducible water saturation). Results revealed that pulsed tests had maximum flow rates 2. 5--3 times higher, greater oil recovery rates, and final sweep efficiencies that were more than 10% greater than non-pulsed tests. The CPS design has proven very successful, and has since been copied by a major oil corporation. However, there are two limitations, both caused by fluctuating water reservoir levels. Longer pulsed tests (reservoir-depletion tests) were periodically paused to refill the water reservoir, resulting in reservoir depressurization and lower flow rates. The final effect of this was impossible to quantify without correcting the problem. The second CPS limitation was the change in pulse shape with time. However, it is not expected that this had any major effect on the results. The pulse pressure and period studies were limited by early tests, which did not have the necessary time duration. Both increasing pulse pressure and decreasing pulse period were found to increase the final sweep efficiency. Slightly decreasing porosity (0. 4% lower) was found to lower sweep efficiencies. However, the 34. 9% porosity results were not done until reservoir depletion, so it is difficult to quantitatively compare results. An emulsion appeared after water breakthrough when using the CPS on light oils (mineral oil). This may have been the result of isolated oil ganglia being torn apart by the sharp pulses. Although it is difficult to apply laboratory results to the field, this study indicates that pressure pulsing as an EOR technique would be beneficial. Doubled or tripled oil recovery rates and 10% more oil recovery than waterflooding would be significant numbers in a field operation. A valuable application would be in pulsing excitation wells to both pressurize the reservoir and enhance the conformance of the displacing fluid over a long-term period. It would also be valuable for short-term chemical injections, where mixing with the largest volume possible is desirable.

Les conditions de déplacement de l'huile en géométries simples sont étudies en fonction des caractéristiques bien identifiables de fluides viscoélastiques. Dans ces expériences de déplacement immiscible, une huile de viscosité inférieure sera déplacée par un fluide newtonien de référence et par des fluides viscoélastiques que nous allons choisir, formuler et caractériser. Les expériences de déplacement dans une cellule Hele-Shaw mettent en évidence que le caractère élastique des formulations modifie les conditions de déplacement, surtout à vitesses élevées. De même nous pouvons observer une série d'expériences où la tension interfaciale du système fluide – huile a été diminuée pour monter que l'effet de l'élasticité apparaît sous ces conditions. Nous pouvons aussi observer comme les tendances se maintiennent à niveau microscopique, où la pénétration des fluides viscoélastiques dans des pores modèle est plus prononcée par rapport a un fluide newtonien. Finalement nous proposons un modèle simple qui prend en compte les propriétés élastiques des fluides en la déformation de l'interface fluide / huile que donne comme résultat une différence dans le déplacement immiscible quand on compare par rapport aux fluides newtoniens / Conditions of oil displacement in simple geometries are studied according to clearly identifiable characteristics of viscoelastic fluids. In these immiscible displacement experiments, a lower viscosity oil will be displaced using a reference Newtonian fluid and viscoelastic fluids that we will select, develop and characterize. The displacement experiments in a Hele-Shaw cell show that the elastic nature of formulations alters displacement conditions, especially at high velocities. Similarly we can observe a series of experiments in which the interfacial tension of the system fluid-oil was decreased to show that the effect of the elasticity appears under these conditions. We can also observe how the trends remain at the microscopic level, where the penetration of viscoelastic fluids in a model pore is more pronounced compared to a Newtonian fluid. Finally we propose a simple model which takes into account the elastic properties of fluids in deformation of the fluid-oil interface that results in a difference for immiscible displacement when compared to Newtonian fluids

Combustion assisted gravity drainage (CAGD) is an integrated horizontal well air injection process for recovery and upgrading of heavy oil and bitumen from tar sands. Short-distance air injection and direct mobilized oil production are the main features of this process that lead to stable sweep and high oil recovery. These characteristics identify the CAGD process as a high-potential oil recovery method either in primary production or as a follow-up process in reservoirs that have been partially depleted. The CAGD process combines the advantages of both gravity drainage and conventional in-situ combustion (ISC). A combustion chamber develops in a wide area in the reservoir around the horizontal injector and consists of flue gases, injected air, and mobilized oil. Gravity drainage is the main mechanism for mobilized oil production and extraction of flue gases from the reservoir. A 3D laboratory cell with dimensions of 0.62 m, 0.41 m, and 0.15 m was designed and constructed to study the CAGD process. The combustion cell was fitted with 48 thermocouples. A horizontal producer was placed near the base of the model and a parallel horizontal injector in the upper part at a distance of 0.13 m. Peace River heavy oil and Athabasca bitumen were used in these experiments. Experimental results showed that oil displacement occurs mainly by gravity drainage. Vigorous oxidation reactions were observed at the early stages near the heel of the injection well, where peak temperatures of about 550ºC to 690ºC were recorded. Produced oil from CAGD was upgraded by 6 and 2ºAPI for Peace River heavy oil and Athabasca bitumen respectively. Steady O2 consumption for both oil samples confirmed the stability of the process. Experimental data showed that the distance between horizontal injection and production wells is very critical. Close vertical spacing has negative effect on the process as coke deposits plug the production well and stop the process prematurely. CAGD was also laboratory tested as a follow-up process. For this reason, air was injected through dual parallel wells in a mature steam chamber. Laboratory results showed that the process can effectively create self-sustained combustion front in the previously steam-operated porous media. A maximum temperature of 617ºC was recorded, with cumulative oil recovery of 12% of original oil in place (OOIP). Post-experiment sand pack analysis indicated that in addition to sweeping the residual oil in the steam chamber, the combustion process created a hard coke shell around the boundaries. This hard shell isolated the steam chamber from the surrounding porous media and reduced the steam leakage. A thermal simulator was used for history matching the laboratory data while capturing the main production mechanisms. Numerical analysis showed very good agreement between predicted and experimental results in terms of fluid production rate, combustion temperature and produced gas composition. The validated simulation model was used to compare the performance of the CAGD process to other practiced thermal recovery methods like steam assistance gravity drainage (SAGD) and toe to heel air injection (THAI). Laboratory results showed that CAGD has the lowest cumulative energy-to-oil ratio while its oil production rate is comparable to SAGD.

With the production from mature oil fields declining, the increasing demand of oil urges towards more effective recovery of the available resources. Currently, the CO2 Floods are the second most applied EOR processes in the world behind steam injection. With more than 30 years of experience gained from CO2 flooding, successful projects have showed incremental oil recovery ranging from 7 to 15 % of the oil initially in place. Despite all of the anticipated success of CO2 floods, its viscosity nature is in heterogeneous and naturally fractured reservoirs is challenging; CO2 will flow preferentially through the easiest paths resulting in early breakthrough and extraction ineffectiveness leaving zones of oil intact. This research aims at investigating gel treatments and viscosified water-alternating-gas CO2 mobility control techniques. A set of experiments have been conducted to verify the effectiveness and practicality of the proposed mobility control approaches. Our research employed an imaging technique integrating an X-Ray CT scanner with a CT friendly aluminum coreflood cell. With the integrated systems, we were able to obtain real time images when processed provide qualitative and qualitative evaluations to the coreflood. The research studies included preliminary studies of CO2 and water injection performance in fractured and unfractured cores. These experiments provided a base performance to which the performances of the mobility control attempts were compared. We have applied the same methodology in evaluation of the experimental results to both conformance control gel treatments and viscosified water-alternating-gas CO2 mobility control. The gel conformance control studies showed encouraging results in minimizing the effect of heterogeneities directing the injected CO2 to extract more oil from the low permeability zones; the gel strength was evaluated in terms of breakdown and leakoff utilizing the production data aided with CT imaging analysis. The viscosified water coupled with CO2 investigations showed great promising results proving the superiority over neat CO2 injection. This research serves as a preliminary understanding to the applicability of tested mobility control approaches providing a base to future studies in this category of research.

This laboratory project has been done to evaluate pressure pulsing as an Enhanced Oil Recovery (EOR) technique. To perform the study, a consistent laboratory methodology was developed, including the construction of a Consistent Pulsing Source (CPS). Tests compared pulsed and non-pulsed waterfloods in a paraffin or crude oil saturated medium, which also contained connate water (an irreducible water saturation). Results revealed that pulsed tests had maximum flow rates 2. 5--3 times higher, greater oil recovery rates, and final sweep efficiencies that were more than 10% greater than non-pulsed tests. The CPS design has proven very successful, and has since been copied by a major oil corporation. However, there are two limitations, both caused by fluctuating water reservoir levels. Longer pulsed tests (reservoir-depletion tests) were periodically paused to refill the water reservoir, resulting in reservoir depressurization and lower flow rates. The final effect of this was impossible to quantify without correcting the problem. The second CPS limitation was the change in pulse shape with time. However, it is not expected that this had any major effect on the results. The pulse pressure and period studies were limited by early tests, which did not have the necessary time duration. Both increasing pulse pressure and decreasing pulse period were found to increase the final sweep efficiency. Slightly decreasing porosity (0. 4% lower) was found to lower sweep efficiencies. However, the 34. 9% porosity results were not done until reservoir depletion, so it is difficult to quantitatively compare results. An emulsion appeared after water breakthrough when using the CPS on light oils (mineral oil). This may have been the result of isolated oil ganglia being torn apart by the sharp pulses. Although it is difficult to apply laboratory results to the field, this study indicates that pressure pulsing as an EOR technique would be beneficial. Doubled or tripled oil recovery rates and 10% more oil recovery than waterflooding would be significant numbers in a field operation. A valuable application would be in pulsing excitation wells to both pressurize the reservoir and enhance the conformance of the displacing fluid over a long-term period. It would also be valuable for short-term chemical injections, where mixing with the largest volume possible is desirable.

There are many heavy oil reservoirs with thin pay zones (less than 10 m) in the world and in Turkey. Conventional steam injection techniques are not costeffective for such reservoirs, due to excessive heat loss through the overburden. Heat losses can be minimized through controlled heating of the pay zone. One such way is to introduce heat to the reservoir in a controlled manner is microwave heating. Laboratory studies on microwave heating of a scaled model of a heavy oil reservoir with a thin pay zone are presented with an economical feasibility of the method. In this thesis, three different conceptual oil reservoirs from south east Turkey are evaluated: Bati Raman (9.5 API) and &Ccedil / amurlu (12 API) heavy crude oils and paraffinic Garzan (26 API)crude oil. Using a graphite core holder packed with crushed limestone with crude oil and water microwave effects of operational parameters like heating time and waiting period as well as rock and fluid properties like permeability, porosity, wettability, salinity, and initial water saturation are studied. The main recovery mechanisms for the experiments are viscosity reduction and gravity drainage. An analytical model is developed by coupling heat equation with the electromagnetic dissipated power per unit of volume based in Maxwell&#039 / s equation successfully models the experiments for temperatures less than the pyrolysis temperature is presented. Also the experiments are scaled to the model by geometric similarity concept. In economic evaluation, the cost of oil is calculated based on domestic electricity prices.

Chemical enhanced oil recovery (CEOR) has gained a rapid momentum in the recent past due to depleting reserves of “easy-oil” and soaring oil prices. Hence, CEOR is now being considered for several candidates with varied oils and reservoir conditions, which demands the need for large hydrophobe surfactants. A new class of thermally and chemically stable large hydrophobe surfactant, Guerbet alkoxy carboxylates (GAC) has been tested. Unlike Guerbet alkoxy sulfates, GAC are stable at all pH and can be extremely useful in cases where alkali usage is prohibitive. They also exhibit synergistic behavior with internal olefin sulfonates (IOS) and alkyl benzene sulfonates (ABS), with the mixture showing enhanced calcium tolerance than the individual surfactants. Furthermore, in an attempt to diversify the raw material base, a new class of hydrophobe, viz. tristyrylphenol (TSP) based on petrochemical feed stock has also been developed and evaluated. Given the fact that there are hundreds of surfactants that can be tested for a particular candidate, the difficulty often lies in choosing the right surfactant to begin with. In an attempt to simplify that, a new correlation to predict the optimum surfactant structure has been developed. It relates the optimum surfactant structure to the formulation variables like oil properties, salinity, and temperature, including the parameters like PO and EO for new-generation surfactants. The correlation can serve as a guideline in choosing the optimum surfactant and will help in improving our understanding of the relationship among variables affecting the optimum surfactant structure. Surfactant retention is an important factor affecting the economics of chemical flooding and has to be studied carefully. Using an extensive data obtained from core flood studies a new correlation for predicting surfactant retention including the variables like pH, TAN, salinity, mobility ratio, temperature, co-solvent, and surfactant molecular weight has been developed. All these are new and highly significant advance in the optimization of chemical EOR processes that will greatly reduce the time and cost of the effort required to develop a good formulation as well as to improve its performance. / text

A partnership between oilfield operators and the federal government in the coupled CO₂ enhanced oil recovery (EOR) and storage projects brings long-term benefits for both. We quantify the win-win condition for this partnership in terms of an optimum storage tax credit. We describe the field-scale design optimization of coupled CO₂-EOR and storage operations from the viewpoint of oilfield operators. We introduce a CO₂ market model and investigate two special CO₂ market problems, namely a fixed storage requirement and an integrated asset optimization. The first problem follows an environmental objective by giving priority to the storage element of CO₂-EOR and storage; the second prioritizes the oil recovery and relies on the principles of a free market where CO₂ is a commodity and the commitment to storage is made based on the economic benefits. We investigate the CO₂ market sustainability conditions and quantitatively derive them for the fixed storage requirement and integrated asset optimization problems. Ultimately, we quantify the impact of storage tax credit on the operator benefits, the federal government benefits, and the optimum economic storage capacity of an oilfield. CO₂ EOR-storage projects are long-term and capital-intensive and therefore vulnerable to the risks of the CO₂ market. Two important uncertain economic parameters are investigated, the oil price and the storage tax credit. The government plays an important role in reducing the CO₂ market risks because it has the leverage to regulate the storage tax credit. The stochastic optimization results show that a transparent storage tax credit reinforces the sustainability of the CO₂ market and helps both the government and the oilfield operators boost their long-term benefits. / text

Surfactant related recovery processes are of increasing interest and importance because of high oil prices and the urge to meet energy demand. High oil prices and the accompanying revival of EOR operations have provided academia and industry with great opportunities to test alkaline surfactant polymer (ASP) methods on a field scale and to develop novel surfactant systems that can improve the performance of such EOR processes. This dissertation intends to discuss both opportunities through two unique projects, the development of novel surfactants for EOR applications and the design for an alkaline/surfactant/polymer (ASP) field pilot. In Section I of this dissertation, a novel series of anionic Gemini surfactants are carefully synthesized and systematically investigated. The remarkable abilities of Gemini surfactants to influence oil-water interfaces and aqueous solution properties are fully demonstrated. These surfactants are shown to have great potential for application in EOR processes. A wide range of Gemini structures (C₁₄ to C₂₄ chain length, -C2- and -C4- spacers, sulfate and carboxylate head groups) was synthesized and shown to have high aqueous solubility, with Krafft points below 20°C. The critical micelle concentrations (CMC) for these new molecules are measured to be orders of magnitude lower than their conventional counterparts. The significantly more negative Gibbs free energy for Gemini surfactant drives the micellization process and results in ultralow CMC. An adsorption study of Gemini surfactants at air-water and solid-water interfaces shows their superior surface activity from tighter molecular packing, and attractive characteristics of low adsorption loss at the solid surface. All anionic Gemini surfactants synthesized have an extraordinary tolerance to salinity and/or hardness. No phase separation or precipitation occurs in the aqueous stability tests, even in the presence of extremely high concentrations of mono- and/or di-valent ions. Moreover, ultra-low IFT values are reached under these conditions for Type I microemulsion systems, at very low surfactant concentrations. The stronger molecular interaction between the Gemini and conventional surfactants offers synergy that promotes aqueous stability and interfacial activity. Gemini molecules with short spacers are capable of giving rise to high viscosities at fairly low concentrations. The rheological behavior can be explained by changes in the micellar structure. A molecular thermodynamic model is developed to study anionic Gemini surfactants aggregation behavior in solution. The model takes into account of the head group-counter-ion binding effect and utilizes two simplified solutions to the Poisson-Boltzmann equation. It properly predicts the CMC of the surfactants synthesized and can be easily expanded to investigate other factors of interest in the micellization process. Section II of this dissertation studies chemical formulation design and implementation for an oilfield where an alkaline/surfactant/polymer (ASP) pilot is being carried out. A four-step systematic design approach, composed of a) process and material selection; b) formulation optimization; c) coreflood validation; 4) lab-scale simulation, was successfully implemented and could be easily transferred to other EOR projects. The optimal chemical formulation recovered over 90% residual oil from Berea coreflood. Lab-scale simulation model accurately history matches the coreflood experiment and sets the foundation for pilot-scale numerical study. Different operating strategies are investigated using a pilot-scale model, as well as the sensitivities of project economics to various design parameters. A field execution plan is proposed based on the results of the simulation study. A surface facility conceptual design is put together based on the practical needs and conditions in the field. Key lessons learned throughout the project are summarized and are invaluable for planning and designing future pilot floods. / text

There is a vast deposit of viscous and heavy oil, especially in Canada and Venezuela. Typically thermal methods are used to recover heavy oil. However, thermal methods are inefficient when the depth of the reservoir is high and pay thickness is low. Non-thermal methods need to be developed for viscous and heavy oils. Alkaline-surfactant-polymer (ASP) floods can be used for improving the displacement efficiency, but its effect on sweep efficiency in viscous oil recovery has not been studied. The objective of this research was to investigate 2D ASP floods in a quarter five-spot pattern. Through careful phase behavior screening, the surfactant formulation was developed that produced ultra-low interfacial tension with reservoir viscous oil (100 cp). After verifying that the design of surfactant formulation was robust and can recover more than 90% of oil in a 1D ASP sandpack flood, it was tested in a 2D geometry. Both stable and unstable tertiary ASP floods were performed in a 2D quarter five-spot sandpack using the surfactant formulation developed in 1D ASP sandpack flood. In a stable ASP quarter five-spot sandpack flood, the oil recovery was excellent (~97% of ROIP). Oil recovery in the stable 2D ASP flood behaved similar to oil recovery in the 1D stable ASP flood. However, pressure drop obtained was high which would be unsustainable in field applications. Interestingly, unstable 2D flood performed well even with an adverse mobility ratio between oil/water bank and ASP slug with a recovery of 80% ROIP. Decreasing the viscosity of ASP slug 6 times decreased the maximum pressure drop 5 times; thus, the maximum pressure drop was almost proportional to the ASP slug viscosity in a 2D pattern. This research showed that unstable ASP flood in a 2D geometry can recover significant amount of oil with a practical pressure gradient. / text