This study aims to investigate the effect of elastic properties of viscoelastic polymer solutions on the microscopic sweep efficiency in enhanced oil recovery (EOR) operations. The effect of elasticity was studied as isolated from the shear viscosity effect using polymer blends with identical shear viscosity behavior but different elastic characteristics. Oil displacement results were compared and the individual effect of elasticity on the sweep efficiency was investigated. A detailed rheological characterization of the polymer solutions was done to measure their viscoelastic properties. A series of polymer flooding experiments were performed using a radial core holder. Results of the experiments indicated that the sweep efficiency of a polymeric fluid could be effectively improved by adjusting the molecular weight distribution (MWD) of the solution at constant shear viscosity and polymer concentration. An attempt was made to find a rheological parameter of polymer solutions that correlates better with the resultant oil recovery. / Petroleum Engineering

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Fractures make both opportunities and problems for exploration and production from hydrocarbon reservoirs. It is always difficult to predict how to optimally produce a fractured reservoir due to the complexity and heterogeneity of fluid flow paths. The following behavior is seen in fractured reservoirs: early water breakthroughs, reduced tertiary recovery efficiency due to channeling of injected gas or fluids, dynamic calculations of recoverable hydrocarbons that are much less than static mass balance and dramatic production changes due to changes in reservoir pressure as fractures close down as conduits. These problems often lead to reduced ultimate recoveries or higher production costs. Polymer gels, in particular in-situ gels that can be placed deep into the reservoir, have been widely used for improved conformance control. In this dissertation, we aim to block the high-permeability zones, fractures in particular, with the microgels to increase the sweep efficiency by diverting the waterflood water to the low permeability zones that still contain unswept oil. vii Polyacrylic acid microgels can swell a thousand fold as the pH of the surrounding solution changes, with an accompanying large increase in viscosity. This pH trigger is simpler than chemical cross-linking and thus offers operational advantages. The ability of pH-sensitive polymers to block high permeability fractures is studied by performing several coreflood and batch experiments. The effect of different rock and salt minerals, polymer concentration, polymer salinity, and temperature on polymer performance is studied in this dissertation. Polymer microgels show excellent consistency in the presence of various salt minerals and in contact with different rock minerals. The placement of microgels into the fractures lowered the overall core permeability in all cases. In addition, polymer microgels were stable after being in reservoir for a month with conditions at 58°C. Consequently, using pH-triggered polymers for conformance control and reducing the permeability of high permeability areas in fractured reservoirs merit further investigations. These polymers are inexpensive and are easy to prepare. The polymer concentration, salinity and shut-in time could be set according to the desired PRF value, injectivity, propagation distance and reservoir mineralogy. / text

The efficiency of one fluid displacing another in permeable media depends greatly on the pore-scale dynamics at the main wetting front. Experiments have shown that the frontal dynamics can result in two different flow regimes: a stable and an unstable front. In stable displacements, any perturbation of the front will diminish with time and the effect of variation in permeability will be lessened. In contrast, in unstable displacements any perturbation of the front will grow with time and any variation in permeability will be magnified. In this dissertation, the stability of two different displacement processes are contemplated; a) vertical infiltration of dense liquid into dry sand from above and b) horizontal displacement of nanoparticle suspension with high pressure liquid CO₂. Significant insights are obtained by measuring the in-situ flow patterns in real time with a light transmission method and CT scanning. Vertical infiltration of dense fluid into dry sands from above is often observed to be unstable and produce gravity driven fingers. The formation of gravity fingers can have large consequences on the sweep efficiency of a displacement. Infiltration experiments showed that gravity driven fingers have a unique saturation profile known as saturation overshoot with a higher saturation at the finger tips than the saturation at the finger tail. Despite the vast number of theoretical and experimental investigations, conditions under which the front is unstable, remain unclear. To determine what controls the saturation overshoot and how it relates to the dynamics at the initial wetting front, saturation overshoot was measured as a function of flux for seven different liquids. These liquids gave a range of molecular weights, viscosities, and vapor pressures. It is found that for each fluid there is a flux (called overshoot flux) below which saturation overshoot ceases and the front is diffuse. The magnitude of the overshoot flux depends inversely on the invading fluid's viscosity and shows little or no dependence on the invading fluid's surface tension, vapor pressure, or miscibility with water. Since the saturation overshoot is not described by the continuum multi-phase flow models, the experimental results are used to develop a semi-continuum model that bridges the continuum-scale and pore-scale physics. The proposed model predicts the observed dependence of overshoot on media permeability and invading fluid properties. At the planned depth for CO₂ injection, either as an enhanced oil recovery technique or for CO₂ storage, CO₂ is typically less dense and less viscous than the in-situ fluid. Therefore, CO₂ injection is unstable and produces viscous fingers. This can greatly reduce the efficiency of a CO₂ flood or CO₂ storage capacity of an aquifer. To remedy this behavior, surface treated nanoparticles were used to reduce the mobility of injected CO₂. Displacement experiments were performed at low pressure with a CO₂ analogue (n-octane) fluid and at high pressure with liquid CO₂. Saturation distributions and pressure drops were measured in real time with the CT scanner when high pressure liquid CO₂ or n-octane was used to displace brine in different cores with and without suspended nanoparticles. In the presence of nanoparticles, the displacement front is more spatially uniform with a later breakthrough compared to the same experiment with no suspended nanoparticles. These observations suggest that nanoparticle stabilized foam, which forms during the displacement, acts to suppress the instability. It is argued that the generation of droplets occurs at the leading front of all drainage displacements. In the presence of nanoparticles, these droplets are preserved when nanoparticle adhere at the fluid-fluid interface. The new mechanism for foam generation described here, provides an interesting alternative for mobility control in CO₂ floods. Moreover, the same mechanism can potentially a) increase the CO₂ storage capacity of an aquifer, b) enhance the CO₂ capillary trapping, and c) provide an engineered barrier to CO₂ leakage from a storage sites, thereby alleviating the risk of contaminating the overlying fresh groundwater resources for CO₂ storage projects. / text

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.

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.

Waterflooding is currently the most commonly used method to improve oil recovery after primary depletion. The reservoir heterogeneity such as permeability distribution could negatively affect the performance of waterflooding. The presence of high permeability streaks could lead to an early water breakthrough at the producers and thus reduce the sweep efficiency in the field. One approach to counteract the impact of heterogeneity and to improve waterflood sweep efficiency is through optimal rate allocation to the injectors and producers. Through optimal rate control, we can manage the propagation of the flood front, delay water breakthrough at the producers and also increase the sweep and hence, the recovery efficiency. The arrival time optimization method uses a streamline-based method to calculate water arrival time sensitivities with respect to production and injection rates. It can also optimize sweep efficiency on multiple realizations to account for geological uncertainty. To extend the scope of this optimization method for more general conditions, this work utilized a finite difference simulator and streamline tracing software to conduct the optimization. Apart from sweep efficiency, another most widely used optimization method is to maximize the net present value (NPV) within a given time period. Previous efforts on optimization of waterflooding used optimal control theorem to allocate injection/production rates for fixed well configurations. The streamline-based approach gives the optimization result in a much more computationally efficient manner. In the present study, we compare the arrival time optimization and NPV optimization results to show their strengths and limitations. The NPV optimization uses a perturbation method to calculate the gradients. The comparison is conducted on a 4- spot synthetic case. Then we introduce the accelerated arrival time optimization which has an acceleration term in the objective function to speed up the oil production in the field. The proposed new approach has the advantage of considering both the sweep efficiency and net present value in the field.

Foam-assisted low interfacial tension and foam-improved sweep efficiency are attractive enhanced oil recovery (EOR) methods with numerous studies and researches have been conducted in the past few decades. For example, CO₂-Enhanced Oil Recovery (CO₂-EOR) is very efficient in terms of oil displacement. However, due to the low viscosity of super critical CO₂, the process usually suffers from poor sweep efficiency. One method of increasing sweep efficiency in CO₂-EOR has been identified through the use of surfactants to create "foams" or more correctly CO₂-in-water (C/W) macroemulsions. Polymer flooding techniques such as Alkali -- Polymer (AP), Surfactant -- Polymer (SP), and Alkali -- Surfactant -- Polymer (ASP) have been the only proven chemical EOR method in sandstone reservoirs with many successful pilot tests and field projects. However, the use of polymer is limited in carbonates due to unfavorable conditions related to natural characteristics of this type of lithology. In this case, foam-assisted EOR, specifically Alkali -- Surfactant -- Gas (ASG) process, can be an alternative for polymer flooding. It is a fact that large amount of the world's oil reserves resides in carbonate reservoirs. Therefore, an increase in oil recovery from carbonates would help meet the world's increasing energy demand. This study consists of two parts: (1) the development of new surfactant for creating CO₂ -- in -- water macroemulsions for improving sweep efficiency in CO₂ -- EOR processes; (2) systematic study of ASG method as a novel EOR technique and an alternative for polymer flooding in carbonate reservoirs. Both studies are related to the use of foam as a mobility control agent. In the first part, the design and synthesis of twin tailed surfactants for use at the CO₂/water interface is discussed. The hydrohobes for these surfactants are synthesized from epichlorohydrin and an excess alcohol. Subsequent ethoxylation of the resulting symmetrical dialkyl glycerin yields the water soluble dual tailed surfactants. The general characteristics of these surfactants in water are described. A comparison is carried out between twin-tailed dioctylglycerine surfactants and linear secondary alcohol surfactant based on results from a core flood. The results show that even above the cloud point of the surfactants, the twin tailed surfactants create a significant mobility reduction, likely due to favorable partitioning into the CO₂ phase. The data covers surfactant structures designed specifically for the CO₂-water interface and can be used by producers and service companies in designing new CO₂-floods, especially in areas that might not have been considered due to problems with reservoir heterogeneity. Second part contains a systematic study of ASG process on carbonate rocks through a series of experiments. The purpose is to demonstrate the performance as well as the potential of ASG as a new EOR technique. In this study, basic concepts in chemical EOR are presented, while the design of chemical formulation, phase behavior, and the role of foam are discussed in details. Experimental results showed relatively good recovery, low surfactant retention. However, pressure drop during chemical injections were high, which indicates the formation of both strong foam and viscous microemulsion at the displacement front when surfactant starts solubilizing oil. Overall, ASG showed good performance on carbonate rocks. Optimization can be made on surfactant formula to form less viscous microemulsion and therefore improve efficiency of the process. / text

Une des méthodes de récupération assistée du pétrole les plus utiliséesest l'injection de polymères. L'efficacité de cette méthode est attribuée principalement à laréduction de la mobilité de la phase aqueuse et à la viscoélasticité des polymères. Cetteefficacité dépend de plusieurs paramètres comme la perméabilité, la température, la salinité,l'hétérogénéité, la mouillabilité, le nombre capillaire, etc. De nombreuses connaissances ontété accumulées s’agissant du rôle des polymères dans la récupération du pétrole. Néanmoins,il subsiste encore des questions importantes:• Quel est le meilleur moment pour l’injection de polymère?• Quel rôle joue la mouillabilité dans la récupération ultime de pétrole?• Comment les effets viscoélastiques influencent-ils la récupération?• Quel est le rôle l’adsorption du polymère dans le processus de récupération?Cette thèse, expérimentale, a pour but de fournir des données concernant ledéplacement diphasique (en conditions de mouillabilité intermédiaire et de mouillabilité francheà l’eau) et d’investiguer l’impact réel de la rhéologie sur l’efficacité de déplacement de l’huile.Des injections de polymères sont réalisées à différents stades de précocité (c’est àdire, à différents moments après l’injection d’eau). Les résultats montrent un impact significatifde la précocité du balayage de polymère sur les taux de récupération finale et apparait commeun facteur déterminant à prendre en compte. D’autre part, on observe une récupération plusfaible pour une mouillabilité franche à l’eau que pour une mouillabilité intermédiaire etl’adsorption et la viscoélasticité de la solution de polymère ne sont pas déterminants dans letaux de récupération (dans nos conditions) alors que nos résultats indiquent un changementde mouillabilité durant l’injection de polymère.Des expériences complémentaires de dispersion diphasique ont ensuite mis enévidence un lien direct entre la dispersivité et le taux de récupération final. / Polymer flooding is one of the most developed chemical enhanced oil recoverymethod that has been used successfully since decades. In this chemical EOR method, thepolymer is adding to a waterflood to decrease its mobility. The resulting increase in viscosityas well as a decrease in aqueous phase permeability improve macroscopic oil sweepefficiency. At the pore scale, viscoelasticity is known to be also a key parameter that controlsthe microscopic sweep efficiency. However this sweep efficiency depends on several factorslike the permeability, temperature, salinity, wettability, capillary number, heterogeneity, etc.Therefore several studies are still necessary to have a better understanding of the behaviourof the polymer inside porous media and to optimize the process.• What is the best moment to inject polymer?• What is the role of wettability in final recovery?• How do viscoelastic effects influence recovery?• What is the role of adsorption of the polymer in the recovery process?In our interest to optimize and to understand polymer flooding process we have analysed thedependence of the sweep efficiency with the moment of the polymer injection duringwaterflooding and wettability (Water wet and intermediate wet). The polymer solution isinjected in the core at different maturity times (0PV, Breakthrough, 1PV, 2PV, 3PV, 4PV and6PV).The main results can be summarized in three points .The results show oil recoveryfinal for water wet corefloods is lower than intermediate wet corefloods. On the other hand, theproduction of oil with the injection of polymer is higher than the injection of water due to afavorable mobility ratio. Finally, the final recovery rates are lower when the polymer injectionis late. These results suggest that the history of sweeping can lead to different distributions ofphases (oil/brine) at the end of the waterflood. The sweep efficiency is related to the ability ofthe polymer to disperse throughout the accessible portal space. We have analysed this aspectfrom the point of view of the diphasic dispersion by showing that the dispersivity of the phasesis different at each time of the water injection. The complementary diphasic dispersionexperiments showed a direct link between dispersivity and the final oil recovery.

Oil production from EOR and waterflood processes supplies a considerable amount of the world's oil production. Therefore, the screening and selection of the best EOR process becomes important. Numerous steps are involved in evaluating EOR methods for field applications. Binary screening guides in which reservoirs are selected on the basis of reservoir average rock and fluid properties are consulted for initial determination of applicability. However, quick quantitative comparisons and performance predictions of EOR processes are more complicated and important than binary screening that are the objectives of EOR forecasting. Forecasting (predicting) the performance of EOR processes plays an important role in the study, design and selection of the best method for a particular reservoir or a collection of reservoirs. In EOR forecasting, we look for finding ways to get quick quantitative results of the performance of different EOR processes using analytical model/s before detailed numerical simulations of the reservoirs under study. Although numerical simulation of the reservoirs is widely used, there are significant obstacles that restrict its applicability. Lack of necessary reservoir data and time consuming computations and analyses can be barriers even for history matching and/or predicting EOR/waterflood performance of one reservoir. There are different forecasting (predictive) models for evaluation of different secondary/tertiary recovery methods. However, lack of a general purpose EOR/waterflood forecasting model is unsatisfactory because any differences in results can be caused by differences in the model rather than differences in the processes. As the main objective of this study, we address this deficiency by presenting a novel and robust analytical-base general EOR and waterflood forecasting model/tool (UTF) that does not rely on conventional numerical simulation. The UTF conceptual model is based on the fundamental law of material balance, segregated flow and fractional flux theories and is applied for both history matching and forecasting the EOR/waterflood processes. The forecasting model generates the key results of isothermal EOR and waterflooding processes including variations of average oil saturation, recovery efficiency, volumetric sweep efficiency, oil cut and oil rate with real or dimensionless time. The forecasting model was validated against field data and numerical simulation results for isothermal EOR and waterflooding processes. The forecasting model reproduced well (R2> 0.8) all of the field data and reproduced the simulated data even better. To develop the UTF for forecasting when there is no injection/production history data, we used experimental design and numerical simulation and successfully generated the in-situ correlations (response surfaces) of the forecasting model variables. The forecasting model variables were proven to be well correlated to reservoir/recovery process variables and can be reliably used for forecasting. As an extension to the abilities of the forecasting model, these correlations were used for prediction of volumetric sweep efficiency and missing/dynamic pore volume of EOR and waterflooding processes. / text