Rohilla, Neeraj (TIORCO, a Nalco Champion Company) | Ravikiran, Ravi (Stepan Company) | Carlisle, Charlie T. (Chemical Tracers Inc.) | Jones, Nick (University of Wyoming) | Davis, Marron B. (Sunshine Valley Petroleum Corporation) | Finch, Kenneth B. H. (TIORCO, a Nalco Champion Company)
Sandstone reservoirs containing significant amount of clays (30-40 wt%) with moderate permeability (20-50 mD) provide a unique challenge to surfactant based enhanced oil recovery (EOR) processes. A critical risk factor for these types of reservoirs is adsorption of surfactants due to greater surface area attributed to clays. Clays also have high cation exchange capacity (CEC) and can release significant amounts of di-valents that lead to increased retention of the surfactant. These factors could adversely affect the economics of a flood.
We present a case study where a robust formulation was designed and tested in lab/field for a reservoir located in Wyoming, USA and contains up to 35-40 wt% clays (predominately Kaolinite and Illite). The residual oil saturation is high (Sor=0.4) while the permeability of the formation is between 20-50 mD. The reservoir has been waterflooded historically with low salinity water which has led to formation permeability damage. Due to high levels of clays, adsorption of the surfactant on the rock surface was determined to be between 3-4 mg/g rock by static adsorption tests.
This publication demonstrates how the following challenges have been successfully addressed in the lab as well as in the field in the form of single well chemical tracer test (SWCTT).
Designed a robust alkaline-surfactant-polymer (ASP) formulation that showed ultra-low interfacial tension (IFT) values and aqueous solubility remains soluble in the aqueous solution over a broad range of salinity. Mitigated surfactant adsorption issues to make the cEOR solution economic. A sacrificial agent was identified that acted synergistically with alkali and also did not alter the optimum salinity of the formulation. Performed restored state core analysis using the available damaged core material. The main challenge being restoration of the coreplugs to current reservoir conditions for coreflood experiment without causing additional formation damage due to injection of low salinity formation brine. Designed a flood that utilized a pre-flush to provide a favorable salinity gradient and to inject sacrificial agent ahead of the surfactant front. Performed polymer screening to select right molecular weight of polymer so that the right balance of mobility control and injectivity in the reservoir can be obtained.
Designed a robust alkaline-surfactant-polymer (ASP) formulation that showed ultra-low interfacial tension (IFT) values and aqueous solubility remains soluble in the aqueous solution over a broad range of salinity.
Mitigated surfactant adsorption issues to make the cEOR solution economic. A sacrificial agent was identified that acted synergistically with alkali and also did not alter the optimum salinity of the formulation.
Performed restored state core analysis using the available damaged core material. The main challenge being restoration of the coreplugs to current reservoir conditions for coreflood experiment without causing additional formation damage due to injection of low salinity formation brine.
Designed a flood that utilized a pre-flush to provide a favorable salinity gradient and to inject sacrificial agent ahead of the surfactant front.
Performed polymer screening to select right molecular weight of polymer so that the right balance of mobility control and injectivity in the reservoir can be obtained.
Low-salinity waterflooding has been portrayed as an effective enhanced-oil recovery technology. Despite compelling laboratory and field evidence of its potential, the underlying mechanisms still remain controversial. In this study, the enhanced-oil recovery mechanisms are investigated considering a distinct interfacial effect, i.e. water-crude oil interfacial viscoelasticity, through analysis of capillary hysteresis. An experimental setup with an oil-wet and a water-wet media on each end face of the core sample was utilized to capture capillary and rock electrical properties hysteresis. Moreover, new improvements over the traditional quasi-static porous plate method were implemented to accelerate measurements. Two experiments were conducted on Minnelusa formation rock samples and TC crude oil, at low temperature (30 °C) and without any significant aging as to minimize wettability alteration. Two core plugs were flooded with high-salinity and low-salinity brines, separately. It is found that the dynamic-static method with a ceramic disk, i.e. a combination of continuous injection in drainage and stepwise quasi-static method in imbibition on short 1" long core samples, allows one to capture the correct envelopes of the capillary pressure curves and save ~ 30% of the total time; a thin membrane is anticipated to save ~90% with respect to traditional quasi-static porous plate method. The capillary hysteresis experiments at low temperature prove that low-salinity brine is able to suppress capillary hysteresis. This is attributed to the formation of a more visco-elastic brine-crude oil interface upon exposure to low-salinity brine, leading to a more continuous oil phase. In addition, we show that wettability plays an essential role on electrical resistivity and the more oil-wet, the more hysteresis occurs, namely that resistivity values in imbibition are higher than those in drainage. The findings in this paper demonstrate that low-salinity waterflooding can still increase oil recovery even in the absence of wettability alteration.
Recovery from oil reservoirs could be improved by lowering the injection water salinity or by modifying the water injection chemistry. This has been proposed as a way to increase rock water-wetness. However, we have observed that the presence of sulfate anions in the aqueous phase can change the crude oil-water interfacial rheology drastically, and as a result, the oil recovery factor could be increased solely by alteration of fluid-fluid interactions. The purpose of this research is to show the effect of sulfate anion concentration in seawater injection on oil production through coreflooding results at low temperature.
Interfacial rheological experiments were run with several crude oils and modified seawater to see the effect of different ions on visco-elasticity of the crude oil-brine interface using an AR-G2 rheometer with a dual-wall ring fixture. Based on previous experimental results, carefully selected coreflooding experiments were run to evaluate differential pressure and oil recovery for each selected brine. Coreflooding experiments used Indiana Limestone at 25°C without aging to minimize changes in rock wettability.
The interfacial rheological results show that the visco-elasticity of the crude oil-brine interface is higher for a low-salinity brine compared to a higher-salinity one when individual salts are used, e.g. NaCl or Na2SO4. The difference is more pronounced if ultralow salinities are compared. For the cases with salinity values similar to that of seawater, the effect of sulfate concentration in water on interfacial visco-elasticity is more noticeable. Coreflooding results show that brines with a higher visco-elasticity, corresponding to a higher sulfate concentration in the water injected, yield higher oil recovery factor that those with lower visco-elasticity, including the experiments with salinity lower than 50% of that of seawater. Brine-rock reactions were geochemically simulated to prevent injection conditions that could cause formation damage. Additionally, pH, electrical conductivity and total dissolved solid (TDS) were analyzed in the effluents. Results show that for the model rock used, brine composition does not change significantly from contact with rock surfaces. Since wettability alteration was minimized by use of low-temperature and short ageing time, recovery correlates better with changes in interfacial rheology. For results showing an apparent lack of correspondence with the interfacial rheological response, arguments based on ganglia dynamics might shed light on the observed recovery outcome.
Our findings reveal that the injection of water with sulfate can modify the fluid-fluid interactions and consequently the final oil recovery, so in some cases, low-salinity brine injection is not necessarily conducive to an increment in oil production. Findings also indicate that more characterization of the brine-crude oil interface should be carefully conducted as part of the screening of adjusted brine chemistry waterflooding.