Favorable interactions between injection gas and crude oil are crucial for successful carbon dioxide (CO2) recovery processes. The miscibility behavior and thereby the flooding scheme changes with the pressure applied. Although first contact miscibility (FCM) flooding schemes result in most efficient recovery processes, in many cases multiple contact miscibility (MCM) provides economically viable recovery rates already at lower injection pressure. Thus, the determination of the miscibility pressure is a key step in the lab evaluation for CO2 EOR. Miscibility enhancing additives are able to improve the interactions between CO2 and crude oil leading to reduced miscibility pressure. This paper illustrates an easily applicable procedure to identify the pressure required for full miscibility. Using a pressure resistant sapphire cell the phase behavior of mixtures of different crude oils and CO2 with and without additives was investigated at common reservoir conditions. The effect of the additives on the physical phase behavior of CO2/crude oil mixtures and the benefit that can be achieved by their application will be discussed. The miscibility gaps are determined by measuring the phase behavior of CO2/additive/crude oil mixtures as a function of pressure and temperature. The pressure required for full miscibility (physical minimum miscibility pressure (MMPP)), coming along with an FCM scheme, can easily be detected as the pressure above which the miscibility gap closes and a homogeneous mixture is obtained. Another important point, which was determined in this study, was the critical point of the miscibility gap. Its corresponding pressure is the maximum value of the minimum miscibility pressure (MMP) from a thermodynamical viewpoint, above which MCM schemes take place. Hence, knowledge of the critical point of the mixture is an easy to use method to estimate the maximum value of the MMP for a specific reservoir. Adding proper additives to the CO2 improves the miscibility of injection gas and crude oil. By this the miscibility gap shrinks and both the MMP and the MMPP will be reduced significantly compared to the pure CO2/crude oil system. The method presented is a proper, quick, and low-cost alternative to the time-consuming and expensive slim tube experiments commonly used in the oil industry to measure the MMP. Since at pressures above the MMP an MCM procedure is ensured by physics it is the lowest injection pressure that needs to be applied to ensure miscible CO2 EOR. Reducing the MMP and the MMPP using proper additives can lead to a more economical CO2 flood or can even make reservoirs accessible for this technology, which are naturally not.
In gas flooding EOR applications the injection pressure plays a significant role. It has to be higher than the minimum miscibility pressure (MMP) for a fully miscible flood to obtain the highest oil recovery, since the swelling, and consequently the efficiency of a flood, strongly depends on the miscibility of the residual oil and the recovery fluid. Poor miscibility leads to poor recovery. On the other hand the injection pressure must not be higher than the reservoir fracture pressure to avoid the creation of high thief zones in the formation. The addition of proper additives to the injection gas can reduce the MMP significantly. Using a pressure resistant sapphire cell firstly the solubility of different additives in the gas at common reservoir conditions was determined. The compatibility of the additives with CO2 is needed to be ascertained first in order to identify compounds that enable an easy co-injection of the additive within the flow of the CO2. Then the miscibility behavior of the gas and a model oil was studied and the change of the miscibility pressure in the presence of chosen additives was investigated. Phase behavior studies at typical reservoir pressures and temperatures show the miscibility behavior of the fluids and the effect of the different additives on the mutual miscibility. It was proven that the minimum miscibility pressure can be lowered significantly by the choice of an appropriate additive. Through determination of phase diagrams it is shown how the miscibility gap between crude oil and CO2 can be decreased, thereby going from immiscible or multi-contact miscible to fully miscible conditions. Adjusting the MMP broadens the pressure range of high sweep efficiency that is limited by the formation fracture pressure as the upper and the MMP as the lower limit. Thus, conditions can be created at which the reservoir pressure leads to fully miscible floods. Using an appropriate additive can lead to an improvement of the miscibility behavior at given reservoir conditions and make it more favorable for a CO2 EOR process. A former near-miscible or even immiscible application can become a miscible flood. By this the sweep efficiency is maximized and the recovery rate is highest. The parameters that define an economic reasonable gas flooding application now comprise a larger number of reservoirs due to the improved miscibility of crude oil and injection gas.
The surfactant selection for chemical floods usually starts with an extensive lab study identifying the formulation that provides the best recovery performance. However, it is oftentimes overlooked that in a laboratory setting the requirements on product availability and applicability are less sensitive than for a field scale injection. Thus, there are various other aspects that contribute to the overall economics of chemical selection which also need to be taken into account. Aside from the molecular properties, the manufacturing aspects have to be examined carefully to allow proper planning and ensure the supply of large volumes for full field implementation on time. Furthermore, opportunities to simplify and optimize the logistics (i.e. packaging, regulatory compliances …) help to reduce the cost of a chemical injection project. This is also strongly connected with the handling properties of the selected materials when it comes to the blending of the final injection cocktail (e.g. activity, viscosity, storage conditions, etc…). This paper describes the crucial factors that impact the economics of a selected surfactant for a chemical EOR project, taking into account the production, transportation, delivery form, application performance, handling, amongst others. Another point that will be discussed, is the option to create in-country value and reduce logistic challenges by performing a final production step regionally close to the project site. In the end, we conclude that involving the suppliers at a very early stage of the screening process helps to eliminate unsuitable molecules. It also allows for proper planning and leads to the most appropriate procedure. By taking into account the whole economics picture, a win-win situation can be created and the project is beneficially optimized. Forward thinking the treatment of both injected and produced fluids can be part of this optimization process.
Steam override and channeling due to high steam mobility during steam injection for heavy oil recovery can result in high operating costs and low oil recovery. The high steam mobility issue can be overcome with a sufficient increase in the apparent steam viscosity by surfactant stabilized foams. The objective of this research is to identify surfactants that are thermally stable and can generate stable foam at typical conditions of steam injection for thermal steam EOR processes. Proprietary surfactant structures were found to be stable at up to 250 °C for at least 2 weeks. It was also found that these surfactants at 0.5 wt% concentration were able to generate stable foam in the sandpack with steam at 75% quality (i.e. volume fraction of steam in the injected mixture of steam and surfactant solution) and up to 250 °C. Foam increased the apparent steam viscosity by three orders of magnitude without bitumen and by two orders of magnitude in the presence of bitumen. The results demonstrate that this type of surfactant significantly reduces steam mobility, which is needed to overcome steam gravity override and channeling issues. The study of structure-property relationship shows that the foaming efficiency and effectiveness depend on the temperature and the hydrophobicity of the surfactants. Past research reported in literature focused mostly on sulfonate surfactants as foaming agents for steam EOR processes at operating temperatures up to 200 °C and in the absence of oil. This work has extended the scope of steam foam research as it identified surfactants that are thermally stable and could stabilize foam at up to 250 °C even in the presence of oil. In addition, the structures of the identified surfactants in this study could be optimized with respect to surfactant hydrophobicity to tailor the transport and thermodynamic properties as well as the foam property of the surfactants to target specific reservoir temperature and salinity condition.
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