The physical structure of microemulsions and the degree to which ultra-low IFT is achieved is dependent on a number of parameters including the types and concentrations of surfactants, co-solvents and alkali, crude oil composition, brine composition, temperature and to a lesser extent, pressure. Modifying any one of these variables creates a microemulsion with different properties. The rheological properties of the microemulsion must be adjusted appropriately to achieve good performance under practical reservoir conditions. Two microemulsion properties of primary concern are undesirably high viscosity relative to oil viscosity and non-Newtonian behavior. The broader implications of injecting microemulsions with high viscosities or non-Newtonian behavior in the field include high surfactant retention, unsustainably high pressure gradients, reduced sweep efficiency and microemulsions that stagnate in the field due to high viscosity at low shear rates. The most common ways to reduce microemulsion viscosity are to optimize the surfactant formulation with a good co-solvent and/or by adding more branching to the surfactant hydrophobe. Adding co-solvent in appropriate concentrations makes a microemulsion much less viscous. However, co-solvents increase the cost and complexity and also tend to increase the IFT. A less conventional solution involves increasing the temperature of the injection water thereby lowering both the oil and microemulsion viscosity. This approach has been tested successfully in core floods using both surrogate and reservoir cores.

Drainage displacement at unfavorable viscosity ratios is often encountered in oil recovery, CO2 sequestration, and NAPL remediation, which significantly limits recovery of fluids from porous media. Surfactants have been extensively used as wettability modifiers to improve hydrocarbon recovery from rock matrix by imbibition. But little attention has been paid to the effect of surfactant‐assisted wettability alteration on displacement in non‐fractured porous media. In this study, we investigate surfactant‐assisted immiscible displacement in NAPL‐wet microfluidic chips. We find that the change of advancing contact angle by surfactant is velocity dependent. A stable displacement can be achieved at low velocity when wettability‐altering surfactant solution is used as injection fluid. In comparison, fingering occurs at all capillary numbers for water injection, resulting in low NAPL recovery. The generation of NAPL ganglion during waterflooding is significantly different from that during wettability‐altering surfactant flooding. The generation of NAPL ganglion during wettability‐altering surfactant flooding is related to velocity and saturation due to the wettability alteration and interfacial tension reduction. In contrast, the production of NAPL ganglion during waterflooding is only saturation dependent. NAPL ganglia generated during wettability‐altering surfactant flooding are primarily within the pore‐size range and can be easily recovered in subsequent recovery processes. To the best of our knowledge, this study reveals for the first time the pore‐scale mechanism of surfactant‐assisted wettability on the immiscible displacement, which is important for highly efficient NAPL remediation.

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.

Partitioning interwell tracer tests (PITTs) have been used to estimate remaining oil saturations during waterflooding. Compared to core tests, well logs and single well tracer tests, PITTs sample a much larger representative elemental volume (REV) and provide interwell estimates of remaining oil saturation. The test has historically been used to estimate residual oil saturation (Sorw) after waterflooding between injector-producer pairs when the oil is essentially immobile. During polymer flooding, especially with viscous oil, additional oil is displaced and traditional means of interpreting PITTs are not valid. In this paper we present the information gained from conducting a polymer PITT and the saturation estimated during the PITT. This paper presents mechanistic insights into tracer and polymer velocities during the PITT and hence allows for an estimate of remaining oil saturation left behind after polymer flooding and also presents a new log-normal fit which can be used to match multiple flow path responses as is seen in actual field tracer data and reduce the error in estimates of remaining oil saturation. The polymer PITT therefore allows characterization of polymer flood efficiency and is a useful tool in polymer flood evaluations in heterogeneous reservoirs.

In situ plasma diagnostics present the classical problem of the scientific measurement: how does one accurately measure a system without also perturbing it? The uncertainty in the degree of perturbation then reflects an inherent uncertainty in the diagnostic results. Microwave probes are no exception. This work discusses an experimental methodology for quantifying the local perturbation in hairpin resonator probe measurements. By pulsing the delivered power to a plasma, an electron density hairpin spike (HS) is readily detected at generator shutoff. The phenomenon is understood to arise from an apparent density rise as the plasma sheath collapses, thus raising the spatially averaged density measured between the hairpin tines. Other explanations for the density rise are eliminated, and the utility of the HS is presented. Under the conditions investigated, the HS provides an experimental comparison to a previous sheath correction factor developed by Sands et al.

Field deployment of Chemical EOR floods requires monitoring of wellhead injection fluids to ensure field performance is commensurate with laboratory design. Real-time surveillance allows for optimizing chemical use, detecting potential issues, and ensures correct chemical handling. In an offshore setting traditional surveillance methods can present unique challenges due to space constraints, field conditions, and location. We present a novel approach to field surveillance using a portable measurement unit (PMU) that can dynamically characterize polymer rheology, filterability and long-term core-injectivity. We developed a PMU and placed it inside a suitcase sized box (42x26x20″) with appropriate devices to measure polymer rheology, filterability and long-term core injectivity. Polymer rheology was measured using a series of capillary tubes with pressure measurements. Filterability was measured through a 1.2 um filter at 15 psi with coarse filtration to remove large oil droplets and suspended solids. This was compared against filterability without filtration to observe water quality impact. Finally, long-term injectivity was measured using an epoxy-coated Bentheimer core with a pressure tap to quantify whether there was any face and/or core-plugging. By constructing this apparatus, wellhead injection fluids under anaerobic conditions can be monitored and analyzed to improve fluid quality assurance and contribute to a project's success even in challenging and remote locations. The use of the PMU is critical for dynamic fluid surveillance. The injection solutions consistently met or exceeded target viscosity of 20 cP. Furthermore, the coarse-filtered solutions also met a filtration ratio (FR) requirements of less than 1.5 at 15 psi through 1.2 micron filters. The unfiltered solutions achieved a FR of 1.75, which was considered acceptable. Finally, no plugging was observed with coarse-filtered solutions after 25 PV across the whole core and > 75 PV across the core face. Further testing was completed with wellhead injectate samples at variable operating conditions to establish a baseline for chemical flooding operations and provided insight for future facilities design. The information these experiments produced helped identify and diagnose facility and operational issues that would have caused negative consequences with the chemical injection had the configuration been used without the PMU surveillance. By testing the wellhead fluid, we determined that there was improper dosing of the chemical. This was determined by comparing the field fluid properties to expected results from the lab. The data also influenced facilities design and in turn improved the chemical and project efficiency. By testing the injectate at different operating conditions we could determine the operating envelope for the current injection facilities and base future work on the results. All of this was done in real time on an offshore platform, as opposed to sending samples onshore to test which yields unrepresentative results from the time delay and fluid quality changes during transport.

Waterflooding viscous oil suffers from poor displacement efficiency, requiring excessive volumes throughput for a given recovery. Heterogeneity reduces recovery further by reducing volumetric sweep efficiency. These can be mitigated by modifying injection viscosity with polymer. An improved mobility ratio reduces the throughput to achieve a given recovery, increases volumetric sweep efficiency, and reduces water production and associated handling costs. These three factors make polymer flooding an attractive alternative to waterflooding. From a volumetric sweep perspective, there is no practical limit to the benefit of increased injection viscosity. However, increased fluid viscosity decreases injectivity, through damage (residual resistance factor) or increased resistance to flow with injection of a more viscous fluid. Injectivity issues can be overcome by decreasing well spacing, but at a capital cost. This introduces a de facto limit on polymer concentration; by reducing the concentration we can increase injectivity and increase well spacing, but at the expense of reduced macroscopic displacement efficiency and increased throughput. There are two decision variables (polymer concentration and well spacing) that have three consequences (injectivity, processing rate, and total volume throughput). We have designed a workflow that maximizes NPV for given reservoir and flood properties by optimizing well spacing and polymer concentration. For given polymer concentration and spacing we analytically solve for injection rate vs. time and use that in fractional flow calculations to determine oil production vs. time. The workflow is automated, so a wide range of decision variables can be easily explored via Experimental Design. Surface response methods are then used to determine well spacing and polymer concentration that maximize net present value. The methods developed for the optimization are presented, and the workflow steps are outlined. The method was applied to a field study; for the reservoir properties and under tertiary polymer flooding, the optimized set of conditions was 1900 ppm polymer and an injector-producer spacing of 700 ft. Injecting polymer prior to any water injection reduces the spacing to 380 feet and increases the polymer concentration to 2250 ppm, in large part because the low oil bank mobility dominates injectivity decline. This suggests an important design consideration of pre-conditioning the reservoir prior to instigating a polymer flood.