Browsing by Subject "Oil field flooding"
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Item Application of miscibility calculations to gas floods(2003-08) Yuan, Hua, 1974-; Johns, Russell T.Local displacement efficiency from gas injection is highly dependent on the minimum miscibility pressure (MMP) or minimum miscibility enrichment (MME). The values for these design parameters depend in turn on the displacement mechanisms, vaporizing, condensing, or a combination of the two known as a condensing/vaporizing (CV) drive. Analytical methods, which are inexpensive and quick to use, have been developed to estimate MMP’s for complex fluid characterizations. This thesis presents a simplified and robust method for MMP or MME calculation and quantification of the displacement mechanism. The calculations are also applied to develop new correlations for CO2 floods. The approach relies on finding key crossover tie lines for a dispersion-free displacement using method of characteristic theory (MOC). The new method, however, differs from published methods by significantly reducing the number of equations and unknown parameters, and by providing a fast and robust method that can avoid trivial and false solutions. We demonstrate the improvements by calculation of the MMP and MME for a variety of gas/oil systems and also give new analytical solutions for constant K-value systems that give insight into the nature of the false solutions. A method also based on MOC theory is presented to quantify the fraction of a multicomponent gas flood that is vaporizing or condensing as the pressure or gas enrichment is increased. We quantify the displacement mechanism for any number of oil or gas components by calculating the displacement path lengths along ruled surfaces bounded by these key tie lines. Several multicomponent fluid characterizations are considered. The results show that as the pressure or enrichment is increased condensation occurs at the expense of vaporization. We also show by numerical simulation that the sensitivity of the local displacement efficiency to dispersion depends on the condensing fraction of the displacement. The analytical method is also applied to the displacement of multicomponent oil by CO2. Example calculations were performed for a variety of reservoir fluids. New correlations are also generated for more accurate MMP prediction for CO2 floods. In addition, a new lumping scheme for psuedoization is proposed and applied for CO2 floods so that compositional reservoir simulation can be used in field scale where the effect of dispersion is significant.Item Development and application of capacitance-resistive models to water/CO₂ floods(2008-08) Sayarpour, Morteza; Lake, Larry W.; Sepehrnoori, Kamy, 1951-Quick evaluation of reservoir performance is a main concern in decision making. Time-consuming input data preparation and computing, along with data uncertainty tend to inhibit the use of numerical reservoir simulators. New analytical solutions are developed for capacitance-resistive models (CRMs) as fast predictive techniques, and their application in history-matching, optimization, and evaluating reservoir uncertainty for water/CO₂ floods are demonstrated. Because the CRM circumvents reservoir geologic modeling and saturation-matching issues, and only uses injection/production rate and bottomhole pressure data, it lends itself to rapid and frequent reservoir performance evaluation. This study presents analytical solutions for the continuity equation using superposition in time and space for three different reservoir-control volumes: 1) entire field volume, 2) volume drained by each producer, and 3) drainage volume between an injector/producer pair. These analytical solutions allow rapid estimation of the CRM unknown parameters: the interwell connectivity and production response time constant. The calibrated model is then combined with oil fractional-flow models for water/CO₂ floods to match the oil production history. Thereafter, the CRM is used for prediction, optimization, flood performance evaluation, and reservoir uncertainty quantification. Reservoir uncertainty quantification is directly obtained from several equiprobable history-matched solutions (EPHMS) of the CRM. We validated CRM's capabilities with numerical flow-simulation results and tested its applicability in several field case studies involving water/CO₂ floods. Development and application of fast, simple and yet powerful analytic tools, like CRMs that only rely on injection and production data, enable rapid reservoir performance evaluation with an acceptable accuracy. Field engineers can quickly obtain significant insights about flood efficiency by estimating interwell connectivities and use the CRM to manage and optimize real time reservoir performance. Frequent usage of the CRM enables evaluation of numerous sets of the EPHMS and consequently quantification of reservoir uncertainty. The EPHMS sets provide good sampling domains and reasonable guidelines for selecting appropriate input data for full-field numerical modeling by evaluating the range and proper combination of uncertain reservoir parameters. Significant engineering and computing time can be saved by limiting numerical simulation input data to the EPHMS sets obtained from the CRMs.Item Finite difference modeling of oil recovery by waterflooding using horizontal well injectors(Texas Tech University, 1998-12) Faruqi, Sohail ArshedWaterflooding is the most commonly used injection method for secondary recovery of oil reservoirs. The selection of a horizontal well or a vertical well as an injector is an important issue in waterflooding because these two types of wells can behave differently due to their orientation in the reservoir. Horizontal wells, due to their geometry, possess great apparent potential in injection processes because these wells have large contact with the formation as compared to the vertical wells. The performance of vertical well injectors in waterflooding an oil reservoir have been extensively investigated and reported in the literature. The detailed analysis of the performance of horizontal well injectors, on the other hand, is not found in the literature. The objective of this research was to investigate the potential of horizontal well injectors in waterflood operation with the help of a reservoir simulator. A two-phase, black oil model was developed in this research to study the potential of horizontal well injectors in waterflooding. The results showed that vertical to horizontal permeability ratio and formation thickness are the two main factors that can affect the performance of a horizontal well injector as compared to a vertical well injector. As the vertical to horizontal permeability ratio decreases, the advantage of a horizontal well injector over a vertical well injector decreases. This change in the permeability ratio does not have any significant effect on the performance of a vertical well injector. Also, the smaller the formation thickness, the better the performance of the horizontal well injectors.Item Microscopic and macroscopic visualization of displacement of oil from porous media(Texas Tech University, 2002-08) Cherian, JacobWaterflooding has gained a prominent role among the various recovery mechanisms used to recover oil, due to its simplicity and economic advantage. It is therefore imperative that people have a thorough understanding about the waterflooding concepts and possess scientific and engineering imagination to optimize oil production from oil reservoirs. Microscopic visualization at the pore level and macroscopic visualization at the reservoir level could fuel one's imagination thus strengthening the knowledge base and creativity by better understanding the displacement of oil with water. The present work discusses the waterflood concepts using an interactive computer program to visualize the movement of oil through porous media at the microscopic and macroscopic level. An approach using visualization technique has been adopted to better understand the displacement performance of a linear waterflood using Buckley-Leverett Theory. The visualization technique enhances the visual effects by delivering concise and clear images of oil displacement during a waterflood process. Input parameters such as porosity, saturation and mobility ratio can be varied to visualize the variations in both microscopic and macroscopic oil displacement processes.Item PH sensitive polymers for novel conformance control and polymer flooding applications(2008-08) Choi, Suk Kyoon, 1970-; Sharma, Mukul M.; Bryant, Steven L.; Huh, ChunPolymer flooding is a commercially proven technology to enhance oil recovery from mature reservoirs. The main mechanism for improving oil recovery is to increase the viscosity of injection water by adding polymer, thereby creating a favorable mobility ratio for improved volumetric sweep efficiency. However, polymer injection brings on several potential problems: a) a high injection pressure with associated pumping cost; b) creation of unwanted injection well fractures; and c) mechanical degradation of polymers due to high shear near wellbore. The high viscosity of polymer solutions and permeability reduction by polymer retention reduce mobility, and simultaneously increase the pressure drop required for the propagation of the polymer bank. The objective of this dissertation is to develop an improved polymer injection process that can minimize the impact of those potential problems in the polymer flooding process, and to extend this application to conformance control. This objective is accomplished by utilizing the pH sensitivity of partially hydrolyzed polyacrylamide (HPAM), which is the most commonly used EOR polymer. The idea of the “low-pH polymer process” is to inject HPAM solution at low-pH conditions into the reservoir. The polymer viscosity is low in that condition, which enables the polymer solution to pass through the near wellbore region with a relatively low pressure drop. This process can save a considerable amount of pump horse power required during injection, and also enables the use of large-molecular-weight polymers without danger of mechanical degradation while injecting below the fracture gradient. Away from the near wellbore region, the polymer solution becomes thickened with an increase in pH, which occurs naturally by a spontaneous reaction between the acid solution and rock minerals. The viscosity increase lowers the brine mobility and increases oil displacement efficiency, as intended. Another potential application of the low-pH polymer injection process is conformance control in a highly heterogeneous reservoir. As a secondary recovery method, water flooding can sweep most oil from the high-permeability zones, but not from the low-permeability zones. The polymer solution under low-pH conditions can be placed deep into such high-permeability sands preferentially, because of its low viscosity. It is then viscosified by a pH increase, caused by geochemical reactions with the rock minerals in the reservoir. With the thickened polymer solution in the high permeability sands, the subsequently injected water is diverted to the low permeability zone, so that the bypassed oil trapped in that zone can be efficiently recovered. To evaluate the low-pH polymer process, extensive laboratory experiments were systematically conducted. As the first step, the rheological properties of HPAM solutions, such as steady-shear viscosity and viscoelastic behavior, were measured as functions of pH. The effects of various process variables, such as polymer concentrations, salinity, polymer molecular weight, and degree of hydrolysis on rheological properties, were investigated for a wide range of pH. A comprehensive rheological model for HPAM solutions was also developed in order to provide polymer viscosity in terms of the above process variables. As the second step, weak acid (citric acid) and strong acid (hydrochloric acid) were evaluated as pH control agents. Citric acid was shown to clearly perform better than hydrochloric acid. A series of acid coreflood experiments for different process variables (injection pH, core length, flow rate, and the presence of shut-ins) were carried out. The effluent pH and five cations (total Ca, Mg, Fe, Al, and K) were measured for qualitative evaluation of the geochemical reactions between the injected acid and the rock minerals; these measurements also provide data for future history matching simulations to accurately characterize these geochemical reactions. Finally, polymer coreflood experiments were carried out with different process variables: injection pH, polymer concentration, polymer molecular weight, salinity, degree of hydrolysis, and flow rate. The transport characteristics of HPAM solutions in Berea sandstone cores were evaluated in terms of permeability reduction and mobility reduction. Adsorption and inaccessible/excluded pore volume were also measured in order to accurately characterize the transport of HPAM solutions under low-pH conditions. The results show that the proposed “low-pH polymer process” can substantially increase injectivity (lower injection pressures) and allow deeper transport of polymer solutions in the reservoir due to the low solution viscosity. The peak pH’s observed in several shut-ins guarantee that spontaneous geochemical reactions can return the polymer solution to its original high viscosity. However, low-pH conditions increase adsorption (polymer-loss) and require additional chemical cost (for citric acid). The optimum injection formulation (polymer concentration, injection pH) will depend on the specific reservoir mineralogy, permeability, salinity and injection conditions.Item Soak alternating gas: a new approach to carbon dioxide flooding(Texas Tech University, 2002-08) Murray, Malcolm DavidCarbon dioxide (CO2) flooding as a method of enhanced oil recovery (EOR) has been used successfully for many years to increase the recovery of the original oil in place (OOIP) of a reservoir. The two most common methods of using CO2 to accomplish this are the continuous CO2 flood and the cyclic CO2 flood, or CO2 hufTn'puff. In the continuous CO2 flood, CO2 is injected continuously into a wellbore while fluids are recovered continuously at the adjacent wellbores. A frequently used variation of this process is the water alternating-gas (WAG) flood where CO2 and water are injected alternately to combine the solvent properties of CO2 with the mobility properties of water and further optimize the recovery. However, one limitation to the WAG process is that of water shielding where the relatively high water saturation in the pore spaces prevents much of the potential contact between the crude oil and the CO2 from occurring and causes a significant portion of the oil to be bypassed. In the cyclic CO2 flood, CO2 is injected into the reservoir, shut in for a soak period, then produced from the same wellbore until the economic limits of production are reached and the cycle must be repeated. During the injection phase of a CO2 hufTn'puff, CO2 is distributed over as great an area as possible throughout the reservoir. Next, during the soak period CO2 is allowed to disperse through the water to contact as much oil as possible and make full use of the CO2 recovery mechanisms, which allows production to be optimized in the production phase of the process. In this work, a new concept in CO2 flooding is introduced as "soakalternating-gas," or SAG, which incorporates the soak period of a CO2 huffn'puff into the continuous CO2 flood to provide additional mobility control and a viable alternative to a WAG process in cases where water injectivity is too low to allow WAG to be feasible. Since SAG does not depend on water injectivity the prospect of greater recovery in such cases could be quite significant. In addition, the mobility control provided by SAG may offer advantages over those of WAG, even where water injectivity is adequate. Thus, the integration of continuous CO2 flooding techniques with those of the CO2 hufTn'puff appears to offer greater recovery potential than those of either method used separately. The concepts behind SAG appear to be supported by previous literature on the research, testing, and implementation of the continuous CO2, the CO2 hufTn'puff, and the WAG processes. In order to ascertain its potential, it is recommended that the SAG process be investigated with respect to miscibility conditions as well as the parameters of the injection stage, soak period and production stage, then verified experimentally using slim tube experiments, coreflood experiments and pilot tests prior to full-scale field implementation.Item Unsteady growth and relaxation of viscous fingers(2003) Moore, Mitchell George; Swinney, H. L., 1939-Item Waterflood feasibility of the Brushy Canyon Formation: Red Tank field, Lea County, New Mexico(Texas Tech University, 1996-08) Green, Kevin MichaelThe U. S. Department of Energy estimates that 5 billion barrels of oil will remain in existing slope basin clastic reservoirs of the Permian Basin unless new and innovative recovery methods are implemented. This clearly highlights the need for operators to take a more comprehensive look into secondary recovery methods such as waterflooding. In this study, the author used a variety of tools to characterize this reservoir and to predict its response to water injection. Sequence stratigraphy was used to construct the geologic framework of the field. Scanning electron microscopy, X-ray diffraction, and thin section analysises were used to determine the bulk and clay mineralogy of the reservoir. Core analysis helped to determine Archie log parameters and net pay cutoffs needed in determining reserves from volumetrics. Analytical waterflood models recommended in SPE Monograph 3 were used to predict the reservoirs response to water injection. Sequence stratigraphy indicated that the basal Brushy Canyon contains cyclic deposits. Five highstand and five lowstand deposits were identified in three wells along a 1-1/2 mile cross-section. These deposits were interpreted to have been transported by a variety of mechanisms during an overall drop in relative sea level within an intermediate-order cycle. The drop in sea level was most likely caused by glaciation with cyclic waxing and waning induced by Milankovic climate cycles. Bulk mineralogy of this reservoir indicate it to be a subarkosic sandstone with quartz, K-feldspar, and carbonate cements comprising the major minerals. Clay mineralogy indicate that the average laboratory volume of clay is 11.6%, of which 55% is illite and 45% is iron-rich chlorite. The iron-rich chlorite renders this reservoir acid sensitive. There were no significant amounts of swelling clays detected. Using a porosity-permeability transform a minimum core porosity cutoff for a minimum economic permeability of 1.0 md was 11%. Formation resisitivity factor measurements indicate a cementation exponent of 1.41 and an a coefficient of 1.28. A saturation exponent of 1.80 was obtained using a modified Maute method (1992). Relative permeability measurements indicate this reservoir to be uniformly water-wet. From the relative permeability curves it was noted that permeability to oil was insignificant at saturations above 50%. This value was used as the saturation cutoff in the net pay criteria. Using the Archie equation with the above parameters and cutoffs, along with a volume of clay cutoff less than 15%, the total reserves in the area studied were 9.07 MMstb. Waterflood calculation indicate a mobility ratio of 0.33 and permeability variance of 0.3. Fractional flow calculations predict piston like displacement Predicted injection rates are low and should continually reduce throughout the life of the waterflood due to a low average permeability and low water mobility. Using the Dykstra-Parsons and modified Craig-Geffen-Morse methods the predicted waterflood reserves were 276.7 and 123.7 Mstb of oil per 40 acre five-spot pattern.