In a surfactant-alternating-gas (SAG) injection, stable foams form viscous barriers and divert fluids, thereby providing conformance for enhanced oil recovery (EOR). Once foam decays, injected gas resumes preferential flow through thief zones, demonstrating the need for higher foam stability. Thus, longer foam half-lives or stability is one of the key factors determining the success of any foam-field application. The ability of surfactants to stabilize foam depends on the gas type. Many surfactants that form stable foam with nitrogen (N2) and hydrocarbon gas are not able to form a stable foam with carbon dioxide (CO2), which could be due to the presence of low pH environment in CO2 floods, relatively high solubility of CO2 in water, and CO2 permeability through liquid films. To improve the performance of CO2 floods, it is imperative to identify surfactants that can enhance the stability of CO2-foam. This work investigates an amphoteric surfactant, which is commercially available and priced similarly to other commonly used EOR foamers, for its ability to stabilize CO2-foam. Static stability and dynamic coreflood tests were conducted at high pressure and high temperature conditions, where CO2 remained in the supercritical state. The performance of the amphoteric surfactant was compared with another good foamer on the basis of foam stability and strength, both in bulk and in porous media. Dynamic adsorption tests were conducted to compare the adsorption of amphoteric and anionic surfactants on both sandstone and carbonate rock surfaces. Ways to mitigate surfactant adsorption on rock surfaces were studied. In terms of CO2-foam stability, the amphoteric surfactant performed much better than the anionic and nonionic surfactants evaluated in this study. In the presence of oil, foam stabilized by the amphoteric surfactant exhibited the longest half-life in static tests. However, the amphoteric surfactant performed similarly to other surfactants with nitrogen or hydrocarbon gas. Compared to other surfactants, foam stabilized by the amphoteric surfactant remained stable and exhibited higher apparent viscosity at high foam qualities. Foam stability at higher qualities improves the performance of SAG process as it can lengthen the gas cycle and reduce the amount of surfactant needed, a beneficial outcome when water supply is limited. We found the adsorption of amphoteric on carbonate rock to be much lower than on sandstone rock. Compared to ionic and nonionic surfactants, amphoteric surfactants are usually avoided for oilfield applications due to potential for high retention. Based on systematic evaluation, our work demonstrates the unique ability of amphoteric surfactants to enhance the stability of CO2-foams at reservoir conditions.
Alkali flooding in heavy oil reservoirs is known to stabilize emulsion in-situ and improve the recovery beyond that of conventional waterflood under certain boundary and initial conditions. The overarching goal of this study is to develop a systematic approach to optimize this process and capture underlying recovery mechanisms. Therefore, we experimentally evaluated the performance of alkali flood as a function of emulsion type and viscosity. Phase behavior and viscosity of the microemulsion are modified by introducing seven different surfactants. Microscope imaging techniques are employed to measure the droplet size distribution for type I and II emulsions. Viscosities of generated emulsions are measured with a rotational rheometer at low temperatures and with an electromagnetic viscometer at reservoir conditions. Finally, corefloods are conducted at different conditions to evaluate the performance of displacement as a function of emulsion type and viscosity. Enhanced alkali floods showed an incremental recovery of 8 – 50% beyond that of waterflood. Formation of higher viscosity emulsion has a large contribution on the sweep efficiency and therefore improved oil recovery during alkali flood; however, other mechanisms (e.g. entrainment and entrapment) also have contribute to the incremental recovery. Results of our experiments indicated that the incremental recovery is a strong function of emulsion type, emulsion viscosity, and the droplet size distribution.
Gas injection is a proven enhanced oil recovery (EOR) process, representing the leading EOR-technique in the United States. In recent years, gas EOR technologies are expanding to more challenging (deeper and tighter) reservoirs. In gas injection, there are two basic techniques – continuous gas flooding and water-alternating-gas (WAG) injection. The WAG injection promises improved sweep efficiency, with water being used for mobility control and stabilizing displacement fronts, but suffers from injectivity loss due in part to gas trapping. This injectivity loss can have a major impact on project economics. In this work, we study the modeling of relative permeability hysteresis and its impact on WAG injectivity under both immiscible and miscible conditions.Core flooding experiments are also performed and simulated to understand and quantify the WAG injectivity. Our study showed that the most significant impact of gas relative permeability hysteresis on WAG injectivity lies in the water injectivity reduction following gas flooding. Experimental results confirmed the reduced water injectivity, and this effect can be modeled and sufficiently captured by the gas relative permeability hysteresis.
Summary Physical and numerical simulations of subsurface upgrading by use of solvent deasphalting (SSU-SDA) at laboratory conditions will be presented with a heavy crude oil and propane as a solvent. In this work, 1D propane-flood experiments were performed in a live-crude-oil-saturated (8.8°API) sand at 120°F and 1,000 psi (7.58 MPa). The results showed oil recovery of 85 wt%, with increases of °API value up to 14°API for the produced crude oil. By use of laboratory-characterization data, a new asphaltene-precipitation model was developed that involves four pseudocomponents (deasphalted oil, heavy fraction, and soluble and solid asphaltenes) and three pseudochemical reactions to numerically simulate the laboratory experiments. [In this text, asphaltenes are the fraction of the crude oil that precipitates in paraffins (propane or heptane) and are soluble in aromatics or chlorine-containing solvents (CH2Cl2)]. History match showed very good agreement between the experimental and calculated oil and gas rates and cumulative oil. Also, reasonably good match between laboratory and theoretical °API value of the produced oils was found throughout the propane-flood experiments. By use of this model, a field-scale well pair in steam-assisted-gravity-drainage (SAGD) configuration was simulated for steam only and two steam/propane cases [10:1- and 1:1-vol% ratio, as measured by liquid volume of solvent per cold water equivalent (CWE) of steam] in a typical heavy-crude-oil reservoir. Results showed accelerated oil production and higher °API values of crude in the presence of propane in comparison with the steam-only case. For the 1:1 steam/propane case, the model predicted that the oil quality improved enough to make the oil transportable through a pipeline. This work finds that SSU-SDA continues to show promise as a viable oil-recovery and -upgrading process when the complex downhole physics is modeled. It is predicted that higher propane/steam ratios are needed during SSU-SDA compared with historical solvent-based enhanced-oil-recovery field pilots to capture both the oil-recovery and -upgrading benefits of this process.
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