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Collaborating Authors
Morvan, Mikel
Smartwater Synergy with Chemical EOR: Studying the Potential Synergy with Surfactants
Sofi, Abdulkareem (Saudi Aramco) | Wang, Jinxun (Saudi Aramco (Corresponding author)) | Salaün, Mathieu (Solvay) | Rousseau, David (IFP Energies Nouvelles) | Morvan, Mikel (Solvay) | Ayirala, Subhash C. (Saudi Aramco)
Summary The potential synergy between smartwater and various enhanced oil recovery (EOR) processes has recently attracted significant attention. In previous work, we demonstrated such favorable synergy for polymer floods not only from a viscosity standpoint but also in terms of wettability. Recent studies suggest that smartwater synergy might even extend to surfactant floods. In this work, we investigate the potential synergy between smartwater and surfactant flooding. Opposed to previous work, the potential synergy is investigated from ground zero. We concurrently developed two surfactant formulations for conventional high-salinity injection water and low-salinity smartwater. To design the optimal surfactant-polymer (SP) formulations, we followed a systematic all-inclusive laboratory workflow. Oil displacement studies were performed in preserved core samples using the two developed formulations with conventional injection water and smartwater. The results demonstrated the promising potential of binary surfactant mixtures of olefin sulfonate (OS) and alkyl glyceryl ether sulfonate (AGES) for both waters. The designed binary formulations were able to form Winsor Type III emulsions besides achieving ultralow interfacial tensions (IFTs). Most importantly, in terms of oil displacement, the developed SP formulations in both injection water and low-salinity smartwater were capable of recovering more than 60% of the remaining oil post waterflooding. A key novelty of this work is that it investigates the potential synergy between smartwater and surfactant-based processes from the initial step of surfactant formulation design. Through well-designed from-scratch evaluation, we demonstrate that surfactant-based processes exhibit limited synergies with smartwater. Comparable processes in terms of performance can be designed for both high-salinity and low-salinity waters. It is also quite possible that the synergistic benefits of smartwater on oil recovery cannot be effective in SP flooding processes, especially with specific surfactant formulations under optimal salinity conditions.
- Europe (1.00)
- North America > United States > Texas (0.46)
- Asia > Middle East > Kuwait (0.28)
- Geology > Geological Subdiscipline (0.46)
- Geology > Mineral (0.46)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Salymskoye Field > Zapadno Salymskoye Field (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- (4 more...)
Abstract The potential synergy between SmartWater and various EOR processes has recently attracted significant attention. In previous work, we demonstrated such favorable synergy for polymer floods not only from a viscosity standpoint but also in terms of wettability. Recent studies suggest that such synergy might extend to even surfactant floods. In this work, we investigate the potential synergy between SmartWater and surfactant flooding. Opposed to previous work, the potential synergy is investigated from ground zero. We concurrently developed two surfactant formulations for conventional high salinity injection water and low salinity SmartWater. The formulations were designed for an actual carbonate case exhibiting harsh reservoir conditions. To design the two surfactant-polymer (SP) formulations, we followed a systematic all-inclusive laboratory workflow. Oil displacement studies were performed in preserved core samples using the two developed formulations with conventional injection water and SmartWater. The results demonstrated the potential of binary surfactant mixtures of Olefin Sulfonate (OS) and Alkyl Glyceryl Ether Sulfonate (AGES) for both waters. The designed binary formulations were able to form to Winsor type III emulsions besides achieving ultralow interfacial tensions. Most importantly, in terms of oil displacement, the developed SP formulations in both injection water and low salinity SmartWater were capable of recovering more than 60% of the remaining oil in core post waterflooding (ROIC). A key novelty of this work is that it investigates the potential synergy between SmartWater and surfactant-based processes from the initial step of surfactant formulation design. Through such from-scratch evaluation, we demonstrate that surfactant-based processes exhibit limited synergies with SmartWater. Comparable processes in terms of performance can be designed with both high-salinity and low-salinity waters. It is also quite possible that the synergistic benefits of SmartWater on oil recovery cannot be effective in SP flooding processes especially under optimal salinity conditions.
- Europe (0.93)
- North America > United States > Texas (0.28)
- Asia > Middle East > Kuwait (0.28)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.86)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.49)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Salymskoye Field > Zapadno Salymskoye Field (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- (4 more...)
Abstract Chemical EOR processes based on surfactants are highly constrained by chemicals losses due to retention in porous media. Surfactant adsorption is usually considered as the main retention mechanism. It can lead to a decrease in process efficiency and to an increase in costs. Among the factors impacting surfactant adsorption – namely reservoir rock mineralogy, brine composition and chemicals types — mineralogy is known to be prominent with an impact that is hard to predict and should be dealt with. This paper presents a comprehensive review on the importance of reservoir rock mineralogy on laboratory design and performance evaluation of surfactant-based EOR processes, using several field cases as illustrations. First, the main effects of the various factors quoted above on surfactant adsorption will be presented. Then a summary of the mitigation strategies that can be applied on field, based on either brines treatments, chemical selection or specific injections processes, will be presented. Four representative cases studies of Surfactant-Polymer process design and evaluation at the lab scale on different mineralogies and conditions will be discussed. Each of them exhibits specific hurdles and requires solutions to mitigate mineralogy impact on designed process. Oil recovery corefloods on reservoir rock were conducted with surfactant in effluent and oil production measurements. Mineralogy analysis were also conducted using XRD, SEM and NMR experiments. The first case focuses on a low clay – low temperature sandstone, an apparently simple case which nonetheless shows a very high and unexpected surfactant adsorption due to a very particular clay repartition. The second case focuses on a high clay — high temperature sandstone: this expectedly difficult case was mitigated by the use of adsorption inhibitors, leading to a good oil recovery and a low adsorption. The third case focuses on an unconsolidated – low clay sandstone containing heavy oil which shows a pronounced sensitivity to fine mobilization by surfactant-polymer process. The selected solution was an adapted brine treatment. The last case focuses on a high temperature carbonate which classically shows high adsorptions. A combined process using brine treatment and adsorption inhibitor resulted in particularly low surfactant adsorption of 60 μg/g. Mineralogy is shown to be a key factor that controls surfactant adsorption in chemical EOR processes. Using representative mineralogy in the lab feasibility studies is therefore mandatory to design relevant Surfactant-Polymer processes. This review demonstrates that efficient strategies can be developed to mitigate the impact of mineralogy on SP chemical EOR processes in a wide range of challenging conditions.
- Asia > Middle East (0.96)
- North America > United States (0.95)
- North America > Canada > Alberta (0.28)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Geological Subdiscipline > Mineralogy (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.90)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Mooney Field > Bluesky Formation (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Salymskoye Field > Zapadno Salymskoye Field (0.99)
- (4 more...)
Abstract Brine composition is one of the key parameters in the design of a surfactant based oil recovery process and is a condition imposed by the reservoir nature. This brine can contain a large variety of ions including monovalent and divalent cations (hardness), which impacts the surfactants solubility. Moreover, hardness evolution during the injection process can also impair surfactant formulations’ performances. Water treatment processes are useful ways to mitigate such risks, but they imply higher CAPEX for the process. As a consequence, the selection of the right surfactant will have a large impact on the cost and on crude oil production. This paper describes solution properties of the most common surfactants used in surfactant flooding i.e. Alkyl Benzene Sulfonates (ABS) and Internal Olefin Sulfonates (IOS) as a function of the brine hardness and will be compared with Internal Ketone Sulfonates (IKS), a new bio-based surfactant family.
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Associative Polymer Compatibility with Surfactants: Advantages Vs. Standard Polymer in Bulk and under Flow Conditions
Miralles, Vincent (Solvay) | Marlière, Claire (IFP Energies Nouvelles) | Morgand, Claire (IFP Energies Nouvelles) | Rome, Virginie (IFP Energies Nouvelles) | Morvan, Mikel (Solvay) | Courtaud, Tiphaine (Solvay)
Abstract The purpose of surfactant-polymer (SP) formulation design is to concurrently achieve ultra-low interfacial tension and good mobility ratio. To this respect, associative polymers were found to be particularly interesting since their use could simultaneously solve demixing issues that can be observed in bulk when mixing surfactants with standard partially hydrolyzed poly-acrylamide (HPAM) polymers, and enhance the mobility ratio when injected in confined and under flow conditions. Varying the brine salinity and the polymer chemistry (either HPAM or associative polymer) with the same surfactant system led to the definition of four SP compatibility cases, on the basis of phase diagrams. First the focus was specifically directed to bulk and kinetic studies based on viscosity, cryo-TEM and turbidity versus time measurements. Then, monophasic injections were performed in a coreflood rig with a 3D outcrop rock with the designed formulations. The mobility reduction entailed by the injected solutions was measured by monitoring the pressure drop along the core. With the HPAM polymer, an increase in salinity leads to a clear degradation of the SP compatibility or even to a demixing behavior after a couple of days, due to depletion interactions. Interestingly, when the same surfactant system is mixed with the associative polymer, the demixing behavior vanishes due to a synergetic interaction between the surfactant and the associative polymer, hence changing the overall physical structure of the SP system and leading to a crystal clear formulation. Regarding monophasic injections in coreflood, as expected the compatible SP formulations designed at low salinity led to excellent in-depth transport properties with both polymers. While demixing at high salinity, the SP formulation involving HPAM showed good transport properties since the mobility reduction stabilizes at a value close to the relative viscosity of the solution. More interestingly, the mobility reduction for the SP formulation integrating the associative polymer also reaches a plateau but with a value almost five times higher than its relative viscosity. These results highlight that the use of an associative polymer instead of a conventional HPAM in a SP formulation can present the double advantage of vanishing depletion interactions in bulk, hence improving the formulation's solubility, and enhancing the developed mobility reduction in a coreflood experiment. It has been proven that associative polymers can bring a solution to SP compatibility issues by vanishing depletion interactions and hence improving the formulation's solubility. Depending on the surfactant formulation involved, the addition of an associative polymer can drastically enhance the developed mobility reduction while decreasing the polymer concentration compared to the use of a conventional HPAM polymer. This dosage reduction is also an element of economic advantage in favor of associative polymers.
Impact of Oil on Steam Foam Formulations at 250°C
Cuenca, Amandine (Solvay) | Lacombe, Emie (Solvay) | Chabert, Max (Solvay) | Morvan, Mikel (Solvay) | Delamaide, Eric (IFP Technologies Inc.)
Abstract The most widespread thermal EOR method relies on steam injection. Steam is employed to warm up the reservoir, increase oil mobility and in turn enhance heavy oil recovery. In steam injection processes, recovery of oil is limited by steam channeling due to reservoir heterogeneities. Early breakthrough implies large consumption of steam and incomplete reservoir drainage. A low cost viable option to minimize heat loss consists in generating steam foam in situ. Foam will reduce steam mobility, increase its apparent viscosity and reduce steam channeling. Foam should form and flow in reservoir swept regions containing residual oil saturation. For a field application, where the residual oil saturation may vary from 0 to 30% depending on the recovery method applied, any effect of the oil on foam stability becomes a crucial matter. The scope of this work is to design an appropriate foaming surfactant solution in reservoir representative conditions of 250°C. We study the impact of crude oil on its foaming properties. Previous publications demonstrate that formulation viscosity as well as foamability and foam stability are key parameters to optimize steam mobility reduction in model porous media. It is also well known that measuring foam properties at 200°C in presence of heavy crude oil is an experimental challenge. Injecting heavy oil in common equipment is often problematic, due to its high viscosity and low flowability. Our methodology is based on the use of high pressure/high temperature set-ups, such as sapphire view cell to measure foam stability, capillary rheometer to measure formulation viscosity and high temperature sandpack experiments to measure gas mobility reduction in model porous media. We also present a new high pressure/high temperature screening tool based on disposable containers to evaluate foaming properties in presence of heavy crude oil. We have shown in previous work that long chain surfactants present high foam forming ability at 200°C. We build on our knowledge to demonstrate foam existence at 250°C. This study highlights the performance of new foaming formulations at this temperature. Our development effort has been concentrated on building a novel experimental setup and also providing data to evaluate the impact of heavy crude oil on foaming performances. Based on our experimental results, we demonstrate that foam stability in presence of crude oil can be improved by surfactant synergetic associations. Overall, this work offers new insights to design efficient steam foaming formulations up to 250°C, in particular in presence of heavy crude oil. This novel approach helps in developing more efficient steam foam EOR solutions and in optimizing steam injection processes.
- Asia (0.68)
- North America > United States (0.28)
- North America > Canada (0.28)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Heavy oil extraction is mostly based on thermal EOR processes. Warming up the reservoir reduces oil viscosity, makes it more mobile and in turn enhances heavy oil recovery. The most prominent thermal heavy oil EOR method relies on steam injection. This recovery process consumes high quantities of fresh water and energy to produce the steam, and heat loss due to reservoir heterogeneities and thief zones must be minimized. For that purpose, steam foams can be used to decrease steam mobility and improve its utilization by a better distribution in the reservoir. Selection of appropriate products for steam harsh temperature conditions poses several challenges regarding chemicals stability and foam durability. We have shown in previous papers that synergistic association of thermally stable surfactants can highly improve high temperature foaming performances. Here, we extend these results to specific surfactant formulations designed to provide enhanced bulk viscosity. These formulations are intended to compensate for the strong decrease of water viscosity with temperature. This is expected to enhance steam foams lifetime and in turn provide a better steam mobility control in application conditions. Bulk foam half-life is highly dependent on experimental conditions, in particular on the initial state of the foam in terms of quality and bubble size. This is even truer for steam foams that are also highly sensitive to possible temperature gradients. An optimized experimental setup has been developed to evaluate high temperature foam half-life obtained with standard and enhanced viscosity formulations. We couple these measurements with rheology and mobility reduction evaluation in sandpack experiments. Based on these various parameters, we try to extract correlations between bulk steam foam half-life, bulk viscosity and mobility reduction in porous media. This paper describes the characteristics of newly developed enhanced viscosity surfactant formulations, and also provides data regarding impact of viscosity on high temperature foam stability and mobility reduction.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Steam injection is currently the most widespread method for heavy oil recovery. However, a serious limitation of this method is its energy cost due to heat losses in the reservoir. Steam foams can be used to increase the apparent viscosity of steam. Such an improvement of steam mobility control optimizes the heat distribution in the reservoir and reduces the impact of reservoir heterogeneities in order to raise oil recovery. Optimized formulations are required to generate stable steam foams in reservoir conditions. This paper presents an original workflow to design efficient combinations of surfactants for steam foam stabilization. The first step is the selection of surfactants demonstrating a good chemical stability at steam temperature, together with a good solubility. The second step consists in evaluating foam stability of these formulations at high pressure and temperature. We study the thermal stability of surfactants using anaerobic screening tests at high temperature. The chemical structure of surfactants is evaluated through quantitative NMR analysis before and after thermal treatment in various conditions (temperatures from 150 to 250°C and durations from 24h to a week). Generated data permit a better understanding of surfactants degradation mechanisms. A customized high pressure/high temperature sapphire view cell is used to investigate the impact of high temperature on the solubility of formulations and to generate foams in reservoir conditions of pressure and temperature. A custom image processing routine is used to measure foam volume as a function of time, in order to evaluate foam stability and rank formulations. We demonstrate the thermal stability of specific surfactants up to 240°C in anaerobic conditions. A strong influence of temperature on foam stability is observed. Our experiments serve as a baseline to design new formulations giving much longer foam stability at 185°C than benchmarks based on alpha olefin sulfonate (AOS) and alkyl aryl sulfonate (AAS). This paper thus aims at providing new insights on steam foam applications with the development of a dedicated surfactant selection workflow and the characterization of new steam foam formulations with improved performances.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.48)
Alkaline Surfactant-Polymer Formulation Evaluation in Live Oil Conditions: The Impact of Temperature, Pressure and Gas on Oil Recovery Performance
Oukhemanou, Fanny (Solvay, The EOR Alliance) | Courtaud, Tiphaine (Solvay, The EOR Alliance) | Morvan, Mikel (Solvay, The EOR Alliance) | Moreau, Patrick (Solvay, The EOR Alliance) | Mougin, Pascal (IFPEN, The EOR Alliance) | Féjean, Christophe (IFPEN, The EOR Alliance) | Pedel, Nicolas (IFPEN, The EOR Alliance) | Bazin, Brigitte (IFPEN, The EOR Alliance) | Tabary, René (IFPEN, The EOR Alliance)
Abstract An Alkaline-Surfactant-Polymer / Surfactant-Polymer (ASP/SP) design study generally includes intensive work. Hundreds formulations have to be tested to screen phase behavior and typically a dozen of corefloods are performed to select the best formulation and further optimize the injection strategy/slugs design to match economic criteria. To be extrapolated to the field, it is critical to perform these tests in conditions as close as possible to real reservoir conditions: reservoir temperature, injection brine, reservoir pressure and reservoir oil. Specifically, dissolved gas and high-pressure tend to significantly impact crude oil properties, and subsequently formulation behavior and performance, even when limited amount of gas is present. Ideally, this parameter should be considered from the beginning of the formulation design. However, considering the high number of tests to perform, as well as the relatively high cost and technical challenges associated with live oil experiments, it is unrealistic to routinely perform all the required experiments in high-pressure environment. We will present here the methodology developed to design surfactant based process by mimicking the impact of reservoir gas and pressure on the reservoir stock-tank oil. First a thermodynamic model based on an equation of state is fitted to reservoir PVT data (Gas/Oil Ratio or GOR, stocktank oil and associated gas composition analysis, bubble pressure and volumetric factor Bo) to predict consistent thermodynamic behavior and properties of the live oil. This step allows us to validate the reservoir conditions. A recombination of stock-tank oil with gas should be then performed to obtain the fluid in the reservoir conditions. Then we will illustrate through case studies how to combine a high-throughput robotic platform and a high-pressure/high-temperature cell to determine a representative crude oil matching live oil main properties, namely viscosity and Equivalent Alkane Carbon Number (EACN). This representative crude oil is obtained from the reservoir stock-tank oil which has been adjusted, using solvents or alkanes, to present the same characteristics as the reservoir live oil. This oil will therefore be used for an exhaustive formulation design and process optimization. Finally, we will compare oil recovery performances with the representative crude oil and with the reservoir live oil.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.91)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract Bramberge reservoir is a low temperature (40°C), high permeability (~1 Darcy) sandstone reservoir located in Germany. Waterflooded during several decades, oil production has been declining for the past few years. These conditions make this reservoir a good candidate for surfactant-polymer flooding. Despite favourable attributes, the use of production brine, which exhibits very high hardness, as a re-injection fluid makes this project challenging and unique. In this paper, we illustrate how this specific hurdle can be managed using a new strategy specifically developed for hard brines. We show that surfactant/polymer formulations can be optimized in Bramberge re-injection brine despite its hardness with adequate properties for SP flooding (ultra-low interfacial tension and good solubility). The high level of divalent ions, and especially calcium ions, makes alkalis irrelevant for this project. We demonstrate using coreflood experiments that conventional injection strategies, successfully applied in soft brines (salinity gradient, etc…), and brine management options fail in these specific conditions because of the high chemicals adsorption. This high adsorption is showed to be strongly related to divalent ions. We finally propose a successful alternative based on a careful selection of adsorption inhibitors. Using these additives, high oil recovery (94 %OOIP) was obtained together with low anionic surfactant and polymer adsorption. The overall technical performance is in line with conventional alkali-surfactant-polymer strategy in soft brine making this project very attractive and promising. The process is currently in an optimization phase for pilot and field scale simulations allowing technical and economical optimization.
- Europe > Germany (0.34)
- North America > United States (0.28)
- Asia (0.28)
- Geology > Geological Subdiscipline > Geomechanics (0.55)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)