Alkaline-Surfactant-Polymer (ASP) Flooding of Crude Oil at Under-Optimum Salinity Conditions

Abstract

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.

Mechanistic Modeling of the Alkaline/Surfactant/Polymer Flooding Process under Sub-optimum Salinity Conditions for Enhanced Oil Recovery

“…Thus, the equilibrium IFT between the injected surfactant fluid and crude oil as present in a phase behavior experiment could be a representation of the phases in contact within a particular porous medium, but this may not be true for all systems . Recent studies have shown that high oil recovery is also possible under nonoptimum salinity conditions. ,, This was also the case in the series of experiments conducted in which the highest oil recovery was observed under Type II– or sub-optimum salinity conditions in the work by Battistutta et al Thus, new studies often contradict the conventional early studies. Hence, there is no clear ASP flooding strategy defining the region of salinity that is favorable for an efficient process.…”

Mechanistic Modeling of Water-Alternating-Gas Injection and Foam-Assisted Chemical Flooding for Enhanced Oil Recovery

“…All input parameters ( a 31 , a 32 , and b 3 ) need to be specified at a reference permeability ( k ref ). Since we did not measure the amount of surfactant that remained in the core during surfactant flooding in the performed FACF core-floods, we used the average surfactant adsorption in the Bentheimer sandstones measured earlier for the same type of surfactant slug: 0.25 ± 0.12 mg/g rock. Note that this value for surfactant retention lies within the ranges measured by others who performed surfactant retention measurements for a large number of cores .…”

“…The latter yields a drastic increase in capillary number. The extent to which a constant surfactant concentration, at a fixed pH, can lower the o/w IFT of a specific oil–water–surfactant system is essentially controlled by the salinity of the water phase. ,, At under-optimum salinity conditions, an oil-in-water microemulsion (ME) coexists with excess oil (type II– system). However, at over-optimum salinity, a water-in-oil microemulsion is in equilibrium with excess water (type II+ system).…”

Optimal Design of Alkaline–Surfactant–Polymer Flooding under Low Salinity Environment

“…Another challenge of the low-salinity environment is the inability to set varying salinities based on ASP components; the high value is better for preflush, the low salinity could be positive on a polymer drive by maintaining a consistent polymer viscosity, while salinity close to the optimum salinity helps mobilize residual oil through ASP slug. The salinity gradient, i.e., the modification of salinities from the preflush, ASP mixture, and polymer in sequence, has been studied in an effective way to produce more residual oil [2,[8][9][10][11][12][13]. Difficulty in maintaining designed salinities at specific locations and conditions inhibits the positive effects of the salinity gradient, e.g., the mixture of formation brine, and ASP slug can change salinities during fluid transport processes.…”

“…Gregersen et al [10] analyzed the impacts of anhydrite on ASP performance under low-salinity conditions. Battistutta et al [11] analyzed ASP flooding under optimum salinity conditions, i.e., 2.5-4.5 wt % NaCl, and showed the alteration of ASP slug would be negligible at this high salinity. Chen et al [12] performed ASP coreflooding experiments using different III-I, I-III-I, II-III-I, and III-III-III salinity profiles and concluded that negative salinity was favorable.…”