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Alkaline−surfactant−polymer (ASP) flooding is potentially the most efficient chemical EOR method. It yields extremely high incremental recovery factors in excess of 95% of the residual oil for water flooding on the laboratory scale. However, current opinion is that such extremely high recoveries can be achieved under optimum salinity conditions, i.e., for the Winsor Type III microemulsion phase characterized by ultralow interfacial tension (IFT). This represents a serious limitation since several factors, including alkali-rock interaction, the initial state of the reservoir water, and the salinity of injected water, may shift the ASP flooding design to either sub-optimum or over-optimum conditions. A recent experimental study of ASP floods, based on a single internal olefin sulfonate (IOS) in natural sandstone cores with varying salinity from sub-optimum to optimum conditions, indicated that high recovery factors can also be obtained under sub-optimum salinity conditions. In this paper, a mechanistic model was developed to explore the causes behind the observed phenomena. The numerical simulations were carried out using the UTCHEM research simulator (at The University of Texas at Austin), together with the geochemical module EQBATCH. UTCHEM combines multiphase multicomponent simulation with robust phase behavior modeling. An excellent match of the numerical simulations with the experiments was obtained for oil cut, cumulative oil recovery, pH profile, surfactant, and carbonate concentration in the effluents. The simulations gave additional insight into the propagation of alkali consumption, salinity, surfactant profiles within the core. The study showed that the initial condition of the core is important in designing an ASP flooding. Because of uncertainties in the various chemical reactions taking place in the formation, an accurate geochemical model is essential for operating an ASP flooding in a particular salinity region. The simulation results demonstrate also that, for crude oil with a very low total acid number (TAN), the ultralow IFT and low surfactant adsorption can be achieved over a wide range of salinities that are less than optimal. The results provide a basis to perform better modeling of the suboptimum salinity series of experiments and optimizing the design of ASP flooding methods for the field scale with morecomplicated geochemical conditions.

ASP flooding achieves high incremental oil recovery factors over water flooding by reducing the interfacial tension (IFT) to ultralow values and by ensuring good mobility control, provided by the polymer. Traditionally, this has been achieved by tuning the ASP flood so that it is at optimum salinity conditions, i.e. Winsor type III micro-emulsion phase. Systematic studies of the performance of ASP at different (non-optimum) salinities are scarce, while operating at lower salinities condition can offer several advantages. These include: (1) lower surfactant retention and (2) increased polymer viscosifying power, enabling a reduction in required chemical volumes, as well as (3) a lower risk of achieving over-optimum salinity conditions in the field. This paper presents a series of core-flood experiments using light crude oil with a low Total Acid Number (TAN) and two different sandstone rock types (Bentheimer and Berea). Injection salinities ranged from under-optimum to optimum conditions (i.e. giving type II- to type III micro-emulsion systems), supported by phase behaviour and spinning drop IFT measurements. The formulation used was a model, non-optimized one with one internal olefin sulfonate (IOS) surfactant component. The injected ASP solution showed no phase separation but it was not clear. Results for this IOS surfactant system, without the addition of extra components such as a co-surfactant for improved aqueous solubility, show that ASP core flood tests performed at different salinities, both at optimum salinity and up to 1.5% NaCl under-optimum, recovered similar amounts of oil remaining in the core after water flooding, regardless of a factor three difference in IFT within the range of 10−3 and 10−2 mN/m. The residual oil saturation after chemical flooding (Sorc) was similar amongst the different experiments, ranging from 16% up to 19% Pore Volume (PV) for our specific model formulation. Moreover, oil and chemical breakthrough times are in the same range for all experiments: around 0.5 PV and 1 PV, respectively. Although total oil recovery was not affected by flooding at under-optimum conditions, lower surfactant retention and a higher oil recovery before chemical breakthrough (i.e. as clean oil) were found. In the absence of a surfactant (AP flood), poor recovery of residual oil after water flooding, regardless of a factor three difference in IFT within the range of 10−3 and 10−2 mN/m. The residual oil saturation after chemical flooding (Sorc) was similar amongst the different experiments, from 16% up to 19% Pore Volume (PV) for our specific model formulation. Moreover, oil and chemical breakthrough times are in the same range for all experiments: around 0.5 PV and 1 PV, respectively. Although total oil recovery was not affected by flooding at under-optimum conditions, lower surfactant retention and a higher oil recovery before chemical breakthrough (i.e. as clean oil) were found. In the absence of a surfactant (AP flood), poor recovery of residual oil after water flood was achieved (Sorc 32% PV). These findings suggest that injection at under-optimum conditions may be, for an IOS surfactant system, an improved, alternative to injecting at optimum conditions. Further work is recommended to quantify its advantages, including with more aqueous soluble optimized surfactant systems.

In a transition period from a fossil fuel based society to a sustainable energy society it is expected that CO 2 capture and subsequent sequestration (CCS) in geological formations will play a major role in reducing greenhouse gas emissions. Possibilities of sequestration include storage in aquifers and depleted gas reservoir. The storage capacity of gas reservoirs for CO 2 depends also on the sorption in the omnipresent minerals and shales. It is important to investigate whether adsorption on shales gives an important contribution to the storage capacity. It is also important to relate the adsorption to the carbon content in the shale. Only a few measurements have been reported in the literature for high-pressure gas sorption on shales, and interest is largely focused on shales occurring outside Europe. We present results using a high pressure manometric setup on a dried black shale sample from Belgium. It consists of more than 57% of clay minerals and 6.58% organic matter. The excess sorption isotherm shows an initial increase to a maximum value of 0.19 mmol/gram and then starts to decrease until it becomes zero at 82 bar and subsequently the excess sorption becomes negative. Similar behavior was also observed for other shales and coal reported in the literature. We derive the equation for excess sorption in the manometric set-up allowing for a changing void volume. This equation is based on the finite density of the adsorbed phase. However, this is not the only mechanism causing a maximum in the sorption curve. Other reasons for void volume change are swelling of the shale and volume changes due to chemical reactions excluding sorption. Further research is necessary to investigate reasons for void volume changes in shales.