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.
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.
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.
Oukhemanou, Fanny (SOLVAY) | Courtaud, Tiphaine (SOLVAY) | Morvan, Mikel (SOLVAY) | Moreau, Patrick (SOLVAY) | Mougin, Pascal (IFP Energies Nouvelles) | FÃ©jean, Christophe (IFP Energies Nouvelles) | Pedel, Nicolas (IFP Energies Nouvelles) | Bazin, Brigitte (IFP Energies Nouvelles) | Tabary, Rene (IFP Energies Nouvelles)
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, stock-tank 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 illustrative 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.
Morvan, Mikel (Rhodia) | Degre, Guillaume (Rhodia) | Beaumont, Julien (Rhodia) | Colin, Annie (LOF (CNRS-Rhodia-Bx1)) | Dupuis, Guillaume (POWELTEC) | Zaitoun, Alain (POWELTEC) | Al-maamari, Rashid Salim (Sultan Qaboos University) | Al-Hashmi, Abdul-Aziz R. (Sultan Qaboos University) | Al-Sharji, Hamed Hamoud (Petroleum Development Oman)
Injections of polymer solutions have been used to improve oil recovery in heavy oil reservoirs (Zaitoun et al. 1998). Most of those polymer flood experiences refer to conditions where the polymer solution propagates through the porous media under low shear rate and exhibits mostly a Newtonian behaviour. On the other hand recent publications indicate injection of polymer solutions at concentration larger than conventional polymer flooding can result in higher recovery at field scale. Typically oil recovery of more than 20% OOIP compared to waterflooding has been reported for light oil (Wang et al; 2011). However injectivity issues have to be considered when injecting concentrated polymer solutions. This study examines whether non polymeric elastic fluids derived from surfactant solutions can represent an alternative approach to elastic polymer floods. The technology we have developed matches the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity).
Bulk flow properties as well as rheology in a confined geometry have been used to compare flow properties of surfactant and high molecular weight polymer solutions. The elastic properties of both fluids have been characterized in terms of Weissenberg numbers. The data indicate the surfactant solution as opposed to the polymer one is highly elastic at low shear rates even in the presence of brine. Those results are confirmed by comparative experiments made using a Particle Image Velocimetry (PIV) technique. Injectivity of concentrated surfactant solutions has been tested in single-phase conditions and indicated a good in depth propagation of the fluid. A series of core-flood experiments has been performed using heavy oil reservoir cores. The surfactant slug has been combined with a conventional low-concentration polymer flooding to benefit from surfactant elasticity and improve oil recovery.
Tabary, Rene (IFP Energies Nouvelles) | Douarche, Frederic (IFP Energies Nouvelles) | Bazin, Brigitte (IFP Energies Nouvelles) | Lemouzy, Pierre Maxime (Beicip-Franlab) | Moreau, Patrick (Rhodia) | Morvan, Mikel (Rhodia)
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.
Degre, Guillaume (Rhodia) | Morvan, Mikel (Rhodia) | Beaumont, Julien (LOF (CNRS-Rhodia-Bx1)) | Colin, Annie (POWELTEC) | Dupuis, Guillaume (POWELTEC) | Zaitoun, Alain (Sultan Qaboos University) | Al-Maamari, Rashid (Sultan Qaboos University) | Al-Hashmi, Abdul-Aziz R. (Petroleum Development Oman) | Al-Sharji, Hamed Hamoud
Recent publications indicate that the injection of polymer solutions at concentrations larger than those conventionally used in polymer flooding can result in higher recovery at field scale. Typically, oil recovery more than 20% OOIP compared to waterflooding using these polymer solutions has been reported (Wang et al; 2011). However, injectivity issues have to be considered when injecting such concentrated polymer solutions. This study describes an alternative approach based on surfactant-based solutions. The technology has been developed to match the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity) without any injectivity limitations even when considering very viscous surfactant solutions (i.e. up to 1000 cps) and low permeability cores.
Average first normal stress difference measurements have been used to compare the elastic properties of surfactant and high-molecular-weight polymer solutions. The degree of non-linearity in the mechanical properties for both solutions has been expressed by Weissenberg number. The surfactant solution has much higher Weissenberg number than the polymer solution at a shear rate corresponding to the fluid propagation in the reservoir, which indicates higher elasiticily of these surfactant solutions.
The potential of this surfactant-based technology is illustrated through a specific reservoir case involving heavy oil. A series of coreflood experiments has been performed in reservoir cores at reservoir conditions. The surfactant slug can be combined with a conventional low-concentration polymer flooding to further improve the process. Reduction in residual oil saturation in the range of 10 to 15% has been obtained. Complementary simulation study giving rise to economic analysis have been performed.
Morvan, Mikel (Rhodia) | Degre, Guillaume (Rhodia) | Beaumont, Julien (Rhodia) | Dupuis, Guillaume (POWELTEC) | Zaitoun, Alain (POWELTEC) | Al-maamari, Rashid Salim (Sultan Qaboos University) | Al-Hashmi, Abdul-Aziz R. (Sultan Qaboos University) | Al-Sharji, Hamed Hamoud (Petroleum Development Oman)
Recent publications indicate injection of polymer solutions at concentration larger than conventional polymer flooding can result in higher recovery at field scale. Typically more than 20% OOIP compare to waterflooding have been reported (Wang et al; 2011). However injectivity issues have to be considered when injecting such concentrated polymer solutions. This work describes an alternative approach based on surfactant-based fluids. The technology we have developed matches the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity) without any injectivity limitation even when considering very viscous surfactant solutions (ie up to 1000 cps) and low permeability cores.
Average first normal stress difference measurements have been used to compare the elastic properties of surfactant and high molecular weight polymer solutions. The degree of non linearity in the mechanical properties for both fluids has been expressed by Weissenberg number. The surfactant solution has much larger Weissenberg number than the polymer solution at a shear rate corresponding to the fluid propagation in the reservoir.
The potential of this surfactant-based technology is illustrated through a specific reservoir case involving heavy oil. A series of core-flood experiments has been performed in reservoir cores. The surfactant slug can be combined with a conventional low-concentration polymer flooding to further improve the process. Reduction in residual oil saturation in the range of ?Sw = 10-15% has been obtained. Complementary simulation study giving rise to economic analysis have been performed.
Injection of dense supercritical CO2 (sc-CO2) represents today more than half of the EOR projects carried out in USA. While sc-CO2 flooding is very effective in mobilizing trapped oil at the microscopic (pore-scale) level, this technology is usually limited by unfavorable mobility ratio and gravity segregation issues. In that context, use of dense CO2 foams (emulsions) may be one of the most robust methods for improving sc-CO2 flooding efficiency and maximizing oil recovery at
reservoir scale. However, surfactant screening for dense CO2 foams has until now been extremely time consuming and limited to a few products due to strong technical constraints (high pressure equipments). Here, we report an original set of high throughput screening for optimizing dense CO2 foams formulations. The formulation yielding the best results is further characterized in corefloods experiments.
We use a proprietary high pressure jet-drop transition technique to screen interfacial properties of molecules at the dense CO2 / brine interface. The surfactants showing significant interfacial activities between aqueous solution and sc-CO2 are selected for the next steps. We use an autoclave to generate highly sheared foam with low cell sizes and study generated foam stability in a high pressure variable volume view cell. Structure/properties relationships are extracted from our numerous screening experiments and complement existing design rules for dense CO2 foam formulations.
A surfactant formulation yielding superior sc-CO2 foam stability is tested for mobility reduction in low-permeability carbonate cores. Using a CO2/aqueous solution co-injection scheme, we observe various flow regimes for different fractional flows. We confront these first results to the existing theories of foam flooding in porous media.
After primary and secondary production of oil from a petroleum reservoir, more than half of the oil is often left in place. In order to improve the process displacement efficiency - so that one can recover some of this remaining capillary-trapped or water-by-passed oil -, it is necessary to screen enhanced oil recovery (EOR) techniques and to apply processes such as surfactant flooding, either Surfactant (S), Surfactant Polymer (SP) or Alkaline Surfactant Polymer (ASP), when recommended.
This paper describes an advanced methodology to select EOR surfactant based processes with special emphasis on the design of a formulation by considering real brine compositions. Salinity is the major parameter for the design of an efficient surfactant process. Salinity is defined by running reservoir numerical simulations with SARIPCH, a black oil simulator for chemical tertiary recovery. Inputs are formation water salinity and composition of waterflood brine. Strong heterogeneity of flow properties and resisual oil zones as well as reservoir geometry, for example crossflow, are considered. Results help to define the effective salinity and the salinity window for the surfactant formulation design.
Formulation design is performed through a validated High Throughput Screening (HTS) methodology using a robotic platform combined with microfluidic tools. Data on brine compatibility, oil solubilization ratio and water-oil interfacial tension (IFT) are systematically provided. Adsorption measurements are conducted in order to take into account the potential efficiency and the economics of the process. Core flood experiments are performed to validate performances of selected
chemical formulation(s). Conclusions are drawn on the key effect of salinity and on the necessity of adopting a methodology giving a first appraisal of the salinity that will be seen by the surfactant slug during its transport.