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Koparal, Gulcan Bahar (The University of Texas at Austin, Turkish Petroleum) | Sharma, Himanshu (The University of Texas at Austin, Indian Institute of Technology Kanpur) | Liyanage, Pathma J. (The University of Texas at Austin,Ultimate EOR Services) | Panthi, Krishna K. (The University of Texas at Austin) | Mohanty, Kishore (The University of Texas at Austin)
Abstract High surfactant adsorption remains a bottleneck for a field-wide implementation of surfactant floods. Although alkali addition lowers surfactant adsorption, alkali also introduces many complexities. In our systematic study, we investigated a simple and cost effective method to lower surfactant adsorption in sandstones without adding unnecessary complexities. Static and dynamic surfactant adsorption studies were conducted to understand the role of sacrificial agent sodium polyacrylate (NaPA) on adsorption of anionic surfactants n outcrop and resevoir sandstone corefloods. The dynamic retention studies were conducted with and without the presence of crude oil. Surfactant phase behavior studies were first conducted to identify surfactant blends that showed ultralow interfacial tension (IFT) with two crude oils at reservoir temperature (40°C). Base case dynamic retention data, in the absence of crude oil, was obtained for these surfactant formulations at their respective optimum salinities. NaPA was then added to these surfactant formulations and similar adsorption tests were conducted. Finally, oil recovery SP corefloods were conducted for each surfactant formulations, with and without adding NaPA, and oil recovery data including the surfactant retention was compared. Static adsorption of these surfactant formulations at their respective optimum salinities on crushed sandstone varied from 0.42-0.74 mg/g-rock. Their respective adsorptions lowered to 0.37-0.49 mg/g-rock on adding a small amount of NaPA. Surfactant retention in single-phase dynamic SP corefloods in the absence of crude oil in outcrop Berea cores was between 0.17 to 0.23 mg/g-rock. On adding a small amount of NaPA, the surfactant adsorption values lowered to 0.1 mg/g-rock. Oil recovery SP corefloods showed high oil recovery (~91% ROIP) and low surfactant retention (~0.1 mg/g-rock) on adding NaPA to the surfactant formulations.
Abstract Monitoring and surveillance (M&S) is one of the key requisites for assessing the effectiveness and success of any Improved Oil Recovery (IOR) or Enhanced Oil Recovery (EOR) project. These projects can include waterflooding, gas flooding, chemical injection, or any other types. It will help understand, track, monitor and predict the injectant plume migration, flow paths, and breakthrough times. The M&S helps in quantifying the performance of the IOR/EOR project objectives. It provides a good understanding of the remaining oil saturation (ROS) and its distribution in the reservoir during and after the flood. A comprehensive and advanced monitoring and surveillance (M&S) program has to be developed for any given IOR/EOR project. The best practices of any such M&S program should include conventional, advanced and emerging novel technologies for wellbore and inter-well measurements. These include advanced time-lapse pulsed neutron, resistivity, diffusion logs, and bore-hole gravity measurements, cross-well geophysical measurements, water and gas tracers, geochemical, compositional and soil gas analyses, and 4D seismic and surface gravity measurements. The data obtained from the M&S program provide a better understanding of the reservoir dynamics and can be used to refine the reservoir simulation model and fine tune its parameters. This presentation reviews some proven best practices and draw examples from on-going projects and related novel technologies being deployed. We will then look at the new horizon for advanced M&S technologies.
Abstract Application of chemical enhanced oil recovery (C-EOR) processes to low-permeability sandstone reservoirs (in the 10-100 mD range) can be very challenging as strong retention and difficult in-depth propagation of polymer and surfactant can occur. Transport properties of C-EOR chemicals are particularly related to porous media mineralogy (clay content). The present experimental study aimed at identifying base mechanisms and providing general recommendations to design economically viable C-EOR injection strategies in low permeability clayey reservoirs. Polymer and surfactant injection corefloods were conducted using granular packs (quartz and clay mixtures) with similar petrophysical characteristics (permeability 70-130 mD) but having various mineralogical compositions (pure quartz sand, sand with 8 wt-% kaolinite and sand with 8 wt-% smectite). The granular packs were carefully characterized in terms of structure (SEM) and specific surface area (BET). The main observables from the coreflood tests were the resistance and residual resistance factors generated during the chemical injections, the irreversible polymer retention and the surfactant retention in various injection scenarios (polymer alone, surfactant alone, polymer and surfactant). A first, the impact of the clay contents on the retention of polymer and surfactant considered independently was examined. Coreflood results have shown that retention per unit mass of rock strongly increased in presence of both kaolinite and smectite, but not in the same way for both chemicals. For polymer, retention was about twice higher with kaolinite than with smectite, despite the fact that the measured specific surface area of the kaolinite was about 5 times less than that of the smectite. Conversely, for surfactant, retention was much higher with smectite than with kaolinite. Secondly, the impact of the presence of surfactant on the polymer in-depth propagation and retention was investigated in pure quartz and kaolinite-bearing porous media. In both mineralogies, the resistance factor quickly stabilized when polymer was injected alone whereas injection of larger solution volumes was required to reach stabilization when surfactant was present. In pure quartz, polymer retention was shown, surprisingly, to be one order of magnitude higher in presence of surfactant whereas with kaolinite, surfactant did not impact polymer retention. The results can be interpreted by considering adsorption-governed retention. The mechanistic pictures being that (a) large polymer macromolecules are not able to penetrate the porosity of smectite aggregates, whereas surfactant molecules can, and (b) that surfactant and polymer mixed adsorbed layers can be formed on surfaces with limited affinity for polymer. Overall, this study shows that C-EOR can be applied in low permeability reservoirs but that successful injection strategies will strongly depend on mineralogy.
Abstract Chemical flooding has been widely used to enhance oil recovery after conventional waterflooding. However, it is always a challenge to model chemical flooding accurately since many of the model parameters of the chemical flooding cannot be measured accurately in the lab and even some parameters cannot be obtained from the lab. Recently, the ensemble-based assisted history matching techniques have been proven to be efficient and effective in simultaneously estimating multiple model parameters. Therefore, this study validates the effectiveness of the ensemble-based method in estimating model parameters for chemical flooding simulation, and the half-iteration EnKF (HIEnKF) method has been employed to conduct the assisted history matching. In this work, five surfactantpolymer (SP) coreflooding experiments have been first conducted, and the corresponding core scale simulation models have been built to simulate the coreflooding experiments. Then the HIEnKF method has been applied to calibrate the core scale simulation models by assimilating the observed data including cumulative oil production and pressure drop from the corresponding coreflooding experiments. The HIEnKF method has been successively applied to simultaneously estimate multiple model parameters, including porosity and permeability fields, relative permeabilities, polymer viscosity curve, polymer adsorption curve, surfactant interfacial tension (IFT) curve and miscibility function curve, for the SP flooding simulation model. There exists a good agreement between the updated simulation results and observation data, indicating that the updated model parameters are appropriate to characterize the properties of the corresponding porous media and the fluid flow properties in it. At the same time, the effectiveness of the ensemble-based assisted history matching method in chemical enhanced oil recovery (EOR) simulation has been validated. Based on the validated simulation model, numerical simulation tests have been conducted to investigate the influence of injection schemes and operating parameters of SP flooding on the ultimate oil recovery performance. It has been found that the polymer concentration, surfactant concentration and slug size of SP flooding have a significant impact on oil recovery, and these parameters need to be optimized to achieve the maximum economic benefit.
Abstract Controlling excessive water production in mature oil fields has always been one major objective of the oil and gas industry. This objective calls for planning of more effective water-control treatments with optimized designs to obtain more attractive outcomes. Unfortunately, planning such treatments still represents a dilemma for conformance experts due to the lack of systematic design tools in the industry. This paper proposes and makes available a new design approach for bulk gel treatments by grouping designs of 62 worldwide field projects (1985-2018) according to gel volume-concentration ratio (VCR). After compiling them from SPE papers, the average gel volumes and polymer concentrations in the field projects were used to evaluate the gel VCR. Distributions of field projects were examined according to the gel VCR and the formation type using stacked histograms. A comprehensive investigation was performed to indicate the grouping criterion and design types of gel treatments. Based on mean-per-group strategy, the average VCR was estimated for each channeling and formation type to build a three-parameter design approach. Two approximations for the average polymer concentration and two correlations for minimum and maximum designs and were identified and included in the approach. The study shows that the gel VCR is a superior design criterion for in-situ bulk gel treatments. Field applications tend to aggregate in three project groups of clear separating VCR cut-offs (<1, 1-3, >3 bbl/ppm). The channeling type is the dividing or distributing criterion of the gel projects among the three project groups. We identified that VCRs<1 bbl/ppm are used to treat conformance problems that exhibit pipe-like channeling usually presented in unconsolidated and fractured formations with very long injection time (design type I). For fracture-channeling problems frequently presented in naturally or hydraulically-fractured formations, VCRs of 1-3 bbl/ppm are used (design type II). Large gel treatments with VCR>3 bbl/ppm are performed to address matrix-channeling often shown in matrix-rock formations and fracture networks (design type III). Results show that the VCR approach reasonably predicts the gel volume and the polymer concentration in training (R of 0.93 and 0.67) and validation (AAPE <22%) samples. Besides its novelty, the new approach is systematic, practical, and accurate, and will facilitate the optimization of the gel treatments to improve their performances and success rate.
Abstract This study designs a novel complex fluid (foam/emulsion) using as main components gas, low-toxicity solvents (green solvents) which may promote oil mobilization, and synergistic foam stabilizers (i.e. nanoparticles and surfactants) to improve sweep efficiency. This nanoparticle-enabled green solvent foam (NGS-foam) avoids major greenhouse gas emissions from the thermal recovery process and improves the performance of conventional green solvent-based methods (non-thermal) by increasing the sweep efficiency, utilizing less solvent while producing more oil. Surfactants and nanoparticles were screened in static tests to generate foam in the presence of a water-soluble/oil-soluble solvent and heavy crude oil from a Canadian oil field (1600 cp). The liquid phase of NGS-foam contains surfactant, nanoparticle, and green solvent (GS) all dispersed in the water phase. Nitrogen was used as the gas phase. Fluid flow experiments in porous media with heterogeneous permeability structure mimicking natural environments were performed to demonstrate the dynamic stability of the NGS-foam for heavy oil recovery. The propagation of the pre-generated foam was monitored at 10 cm intervals over the length of porous media (40 cm). Apparent viscosity, pressure gradient, inline measurement of effluent density, and oil recovery were recorded/calculated to evaluate the NGS-foam performance. The outcomes of static experiments revealed that surfactant alone cannot stabilize the green solvent foam and the presence of carefully chosen nanoparticles is crucial to have stable foam in the presence of heavy oil. The results of NGS-foam flow in heterogeneous porous media demonstrated a step-change improvement in oil production such that more than 60% of residual heavy oil was recovered after initial waterflood. This value of residual oil recovery was significantly higher than other scenarios tested in this study (i.e. GS- water and gas co-injection, conventional foam without GS, GS-foam stabilized with surfactant only and GS-waterflood). The increased production occurred because NGS-foam remained stable in the flowing condition, improves the sweep efficiency and increases the contact area of the solvent with oil. The latter factor is significant: comparing to GS-waterflood, NGS-foam produces a unit volume of oil faster with less solvent and up to 80% less water. Consequently, the cost of solvent per barrel of incremental oil will be lower than for previously described solvent applications. In addition, due to its water solubility, the solvent can be readily recovered from the reservoir by post flush of water and thus re-used. The NGS-foam has several potential applications: recovery from post-CHOPS reservoirs (controlling mobility in wormholes and improving the sweep efficiency while reducing oil viscosity), fracturing fluid (high apparent viscosity to carry proppant and solvent to promote hydrocarbon recovery from matrix while minimizing water invasion), and thermal oil recovery (hot NGS-foam for efficient oil viscosity reduction and sweep efficiency improvement).
Abstract Alaska North Slope (ANS) contains vast viscous oil resources that have not been developed effectively due to the lack of efficient Enhanced Oil Recovery (EOR) techniques. This study investigates the EOR performance of three new hybrid EOR techniques: HSW-LSW-LSP flooding, solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding. Additionally, pressure-volume-temperature (PVT) tests have been conducted to investigate the oil swelling and viscosity reduction effects of the proposed solvent. It has been found that the oil recovery of HSW flooding was 43.42%, while the tested HSW-LSW-LSP flooding, solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding could improve the oil recovery to 74.17%, 79.73%, and 85.87%, respectively. All three proposed hybrid EOR techniques can significantly enhance the viscous oil recovery since they were all designed to both improve the microscopic and macroscopic sweep efficiencies. In particular, the PVT test results confirmed that the proposed solvent in this study could effectively swell the viscous oil over 30% and significantly reduce the viscous oil viscosity by about 97%. However, the initially designed solvent-alternating-LSP flooding displacement experiment had to be terminated after the first slug of polymer injection due to the extremely high differential pressure, which was over the measurement range of the pressure gauge. Thus, the actually tested displacement process in this study was solvent-LSP flooding. The extremely high differential pressure was found to result from the polymer deposit and blockage at the outlet. Although the proposed solvent-alternating-LSP flooding may produce the highest oil recovery, it cannot be applied in the field until the issue of polymer precipitation is understood and solved. The study has practical guidance to the selection of proper EOR techniques to enhance viscous oil recovery on ANS.
Abstract Successful field trials of surfactant-based Production Enhancement (PROE) technology in different shale plays including Permian Basin, Bakken and Eagle Ford indicate that specially tailored surfactant formulations can improve the unconventional well productivity during flowback and production. One major challenge for the operator is to further optimize the surfactant dosage to maximize the economic return. Analysis of the residual surfactant concentration in the produced water (PW) might provide a new path to optimize the surfactant application in the field. Such quantitative measurements can help understand how much surfactant is consumed in the downhole and how much surfactant is in the flowback, and possibly correlate back to the well performance. Additionally, surfactant partitioning and adsorption behaviors can be studied through residual analysis, which will further provide guidance to develop next generation of surfactant formulations. In this study, a liquid chromatography-mass spectrometry (LC-MS) method was developed to accurately measure the residual surfactant concentration in the produced water. The liquid chromatograph (LC) separates the surfactant from sample matrix and avoids the possible interference, and then the mass spectrometer (MS) detects the separated surfactant, signal correlating to the residual concentration. This analytical method provides unrivalled selectivity and specificity compared to other methods reported in the literature. In addition, a Methyl Orange method was developed and can potentially be used in the field for quicker measurements. Produced water samples collected from a Huff-and-Puff treatment in the Permian Basin were evaluated using both methods. Our results indicate that both methods can successfully capture the trend of residual concentration vs. production time. The deviation between LC-MS and Methyl Orange measurements was due to the presence of ADBAC (alkyldimethylbenzylammonium chloride) in the produced water, which is a cationic amine surfactant typically used as biocide in the well stimulation. It produces positive interference and thus leads to a higher residual detection in the Methyl Orange test. Notably, the residual concentration of surfactant in produced water decreased with time after the well was placed back to production, which is consistent with the concept that more surfactant will adsorb to the rock surface or partition into the oil phase over production time. In summary, we believe the LC-MS and Methyl Orange methods can potentially be used to detect residual concentration for any type of surfactant-based applications in unconventional reservoirs including Huff-and-Puff, completion, frac protect, surfactant flooding and re-frac. The field application of surfactant-based chemistry followed by this type of residual analysis can help understand the underlying mechanisms of the surfactant and provide further guidance for production optimization of shales.