Khodaparast, Pooya (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park) | Johns, Russell T. (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park)
Surfactant floods can attain high oil recovery if optimum conditions with ultra-low interfacial tensions (IFT) are achieved in the reservoir. A new equation-of-state (EoS) phase behavior model based on the hydrophilic-lipophilic difference (HLD-NAC) has been shown to fit and predict phase behavior data continuously throughout the Winsor I, II, III, and IV regions. The state-of-the-art for viscosity estimation, however, uses empirical non-predictive models based on fits to salinity scans, even though other parameters change, such as the phase number and compositions. In this paper, we develop the first-of-its-kind microemulsion viscosity model that gives continuous viscosity estimates in composition space. This model is coupled to our existing HLD-NAC phase behavior EoS.
The results show that experimentally measured viscosities in all Winsor regions (two and three-phase) are a function of phase composition, temperature, pressure, salinity, and
This paper examines oil displacement as a function of polymer solution viscosity during laboratory studies in support of a polymer flood in the Cactus Lake reservoir in Canada. When displacing 1610-cp crude oil from field cores (at 27°C and 1 ft/d), oil recovery efficiency increased with polymer solution viscosity up to 25 cp (7.3 s-1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of the paper explores why this result occurred. That is, was it due to the core, the oil, the saturation history, the relative permeability characteristics, emulsification, or simply the nature of the test? Floods in field cores examined relative permeability for different saturation histories—including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1000 cp. In nine field cores, relative permeability to water (
Sheng, Kai (The University of Texas At Austin) | Argüelles-Vivas, Francisco J. (The University of Texas At Austin) | Baek, Kwang Hoon (The University of Texas At Austin) | Okuno, Ryosuke (The University of Texas At Austin)
Water is the dominant component in steam injection processes, such as steam-assisted gravity drainage (SAGD). The central hypothesis in this research is that in-situ oil transport can be enhanced by generating oil-in-water emulsion, where the water-continuous phase acts as an effective oil carrier. As part of the research project, this paper presents an experimental study of how oil-in-water emulsion can improve oil transport in porous media at elevated temperatures from 373 K to 443 K.
Dimethyl amine (DEA) was selected as the organic alkali to form oil-in-water emulsions with Athabasca bitumen and NaCl brine at 1000 ppm salinity and 0.5 wt% alkali concentration. This composition had been confirmed to be optimal in terms of oil solubility in the water-external emulsion phase at a wide range of temperatures. Then, flow experiments with a glass-beads pack were conducted to measure effective viscosities for emulsion samples at shear rates from 5 to 80 sec−1.
Results show that the effective emulsion viscosity is not sensitive to temperature. At an estimated shear rate of 11 sec−1, for example, the emulsion viscosity was 35 cp at 373 K and 31 cp 403 K. The efficiency of in-situ bitumen transport was evaluated by calculating bitumen molar flow rate under gravity drainage with the new experimental data. Results show that oil-in-water emulsion can enhance in-situ bitumen transport by 1.5 to 7 times at temperatures below 403 K, in comparison with the gravity drainage of oil-water two phases in conventional SAGD. This is mainly because the mobility of the bitumen-containing phase is enhanced by the reduced viscosity and increased effective permeability. A marked difference between alkaline solvents and conventional hydrocarbon solvents is that only a small amount of alkaline solvent enables to enhance in-situ transport of bitumen.
Alkaline-surfactant-polymer (ASP) flooding is an effective technique to improve oil recovery. It has been applied typically after a water flood. Recently, there has been a successful field test where an ASP flood was conducted after a polymer flood. Is the ASP flood after a polymer flood more effective than an ASP flood after a water flood? It is difficult to conduct this experiment in exactly the same location in a field. The goal of this study is to answer this question in a laboratory heterogeneous quarter 5-spot model. A heterogeneous quarter 5-spot sand pack of size 10″ × 10″ × 1″ was constructed. Two sands with a permeability contrast of 10:1 were packed into a 2D square steel cell. An alkali-surfactant formulation was identified that produced ultra-low interfacial tension with the reservoir oil (27 cp). In one experiment (WF-ASP), waterflood was conducted first followed by the ASP flood. In a second experiment (PF-ASP), polymer flood was conducted first followed by the ASP flood. The ASP formulation and slug size were kept the same. Secondary water flood of the heterogeneous quarter 5-spot recovered 22% OOIP. Post-waterflood ASP flood recovered 32% OOIP additional oil with a cumulative (WF-ASP) oil recovery of 54%. Secondary polymer flood of the same heterogeneous quarter 5-spot yielded 50% OOIP. Post-polymerflood ASP flood recovered 32% OOIP additional oil with a cumulative (PF-ASP) oil recovery of 82% OOIP. The water flood and the subsequent ASP flood swept a large part of the high permeability region and a small part of the low permeability region. The polymer flood swept all of the high permeability region and most of the low permeability region. The subsequent ASP flood swept the polymer-swept regions. These experiments demonstrate that the polymer flood - ASP flood combination is more effective than the water flood - ASP flood combination.
Ross, T. S. (New Mexico Institute of Mining & Technology) | Rahnema, H. (New Mexico Institute of Mining & Technology) | Nwachukwu, C. (New Mexico Institute of Mining & Technology) | Alebiosu, O. (ConocoPhillips Co) | Shabani, B. (Oklahoma State University)
Steam injection—a thermal-based enhanced oil recovery (EOR) process—is used to improve fluid mobility within a reservoir, and it is well known that it yields positive results in heavy-oil reservoirs. In theory, steam injection has the potential of being applied in light-oil reservoirs to enable vaporization of in-situ reservoir fluids, but field developments and scientific studies of this application are sparse. Conventional displacement methods like water-flooding and gas-flooding have been applied to some extent, however, oil extraction in such reservoirs relies on recovery mechanisms like capillary imbibition or gravity drainage to recover oil from the reservoir matrix. Furthermore, low-permeability reservoir rocks are associated with low gravity drainage and high residual oil saturation.
The objective of this study is to evaluate the potential of steam injection for light (47°API) oil extraction in naturally-fractured reservoirs. It is theorized that this method will serve as an effective tool for recovery of light hydrocarbons through naturally-fractured networks with the benefit of heat conduction through the rock matrix. This research investigates the application of light-oil steamflood (LOSF) in naturally- fractured reservoirs (NFR).
A simulation model comprised of a matrix block surrounded by fracture network was used to study oil recovery potential under steam injection. To simulate gravity drainage, steam was injected through a horizontal well completed in the upper section of the fracture network, while the production well was completed at the bottom of the fracture network. The simulation included two different porous media: (1) natural fractures and (2) matrix blocks. Each of these porous media was assumed to be homogeneous and characterized based on typical reservoir properties for carbonate formations. This study also analyzed the impact of different recovery mechanisms during steam injection for a light-oil sample in NFR, with reservoir sensitivity examined, based on varying amounts of vaporization, injection rate, permeability, matrix height and capillary pressure. Of these, vaporization was found to be the dominant factor in the application of LOSF in NFR, as described in detail within the results.
This paper summarizes BP's Alaskan viscous oil resource appraisal strategy to de-risk viscous oil resource progression with a goal to improve recovery factor by 10%. A key to recovery improvement is application of improved oil recovery/enhanced oil recovery (IOR/EOR) methods. However, even after detailed studies, moving to the next stage including field pilots is not always easy in the mature and remote Alaskan North Slope.
The paper also covers BP's Alaskan viscous oil technology strategy, extraction technologies selection, simulation and analytical studies, laboratory studies, and field trials for various shortlisted methods. A comprehensive study strategy conducted for progressing chemical EOR processes is discussed. The paper also addresses the challenges of obtaining new core and fluid samples for laboratory studies and logistical and economic considerations for field trials due to location and weather conditions in this part of the world.
Recent studies have shown that enhanced oil recovery will be the focal point for approximately 50% of the global oil production in the upcoming two-three decades. According to the several ballpark studies conducted on EOR techniques, results show that for reservoirs with oil viscosities ranging from 10 to 150 m Pa.s., polymer flooding seems to be an ideal development strategy. However, when the oil viscosities exceed 150 m Pa.s., polymer injectivity and pumping efficiencies can turn out to be major inhibiting factors, thereby limiting the range of oil viscosities for which polymer flooding can be utilized. The core reason for this is that the values of viscosity for the injected water containing polymer, calculated for the beneficial mobility ratio, can lead to the inhibiting factor stated above.
Previously conducted lab studies have shown that supramolecular systems are very resistant in high temperature - high salinity systems. To be able to achieve the easier injection, the injected supramolecular viscosity will be kept at lower values and then increased to the levels right before or upon contacting the oil in the reservoir.
The core difference between conventional polymer systems and supramolecular polymer systems is that the latter disassemble and re-assemble as opposed to degradation when exposed to extreme shear stress and temperatures. It can therefore be said that supramolecular polymer systems are self-healing in nature. The phenomenon has been observed in cases where polymers with high molecular weight are forced through narrow flow channels. Though molecular division takes place, supramolecular systems have shown a tendency of reassembly later on. Therefore, adaptability of these systems to bounded or restricted environments can be established.
This study will add the modeling and simulation components of supramolecular systems which can be effectively utilized in high temperature-high salinity conditions through adjustments to viscosities and interfacial properties of these assemblies. This will help compare the displacement efficiency of supramolecular systems which efficiently perform in a wide range of reservoirs such as thin zones, and reservoirs within permafrost conditions. This can significantly benefit the oil and gas companies worldwide in preparing a technically feasible, but also, a cost effective EOR development strategy, whenever polymer injection is of consideration.
When EOR by polymer flooding is applied in the offshore environment, polymer can be expected to face long reservoir retention times of up to several years. The stability and viscosity retention of the polymer needs to be evaluated throughout this time. Copolymers of acrylamide (AM) and acrylamide tertiary butyl sulfonic acid (ATBS) are a potential polymer choice for relatively high temperature and salinity reservoirs. In this study, it was evaluated how the long term stability of AM-ATBS copolymers can be predicted by accelerated aging tests at elevated temperature.
The main cause of viscosity loss in AM-ATBS copolymer solutions is the hydrolysis reaction turning AM and ATBS groups into acrylic acid (AA). This hydrolysis was studied in strictly anaerobic conditions at 70-120°C. Besides temperature, the impact of ATBS content in the copolymer (15-55 mol%), pH, salinity and divalent ion concentration were studied. In addition, some tests were done with copolymers of ATBS and AA to elucidate the effect of neighboring monomer on ATBS hydrolysis. The reaction progress was followed by 13C NMR and viscosity measurements.
Over a range of conditions, it was observed that AM-ATBS copolymers aged at different temperatures but at otherwise equal conditions, had similar AA/AM/ATBS ratios at equivalent degrees of hydrolysis. Additionally, the shapes of viscosity retention vs. time curves were corresponding in the studied temperature interval after being normalized into the same time scale. It is proposed that AM hydrolysis is the rate determining step, resulting in a similar hydrolysis pathway over a range of temperatures. AM hydrolysis reaction rates were fitted into an Arrhenius function to estimate acceleration at elevated temperatures.
The data generated in this study helps to predict how the results from accelerated tests (e.g. at 100-120°C) correlate to stabilities at lower temperature (e.g. actual reservoir temperature at 70-80°C). Specifically, a practical overview of expected time of stability (viscosity retention >80%) has been generated for AM-ATBS copolymers in seawater.
Higher stability of the bulk and dynamic foam with polymer addition to the aqueous phase has been demonstrated experimentally. Recent experiments indicated that the efficacy of polymer enhanced foam (PEF) is dependent on polymer type and surfactant-polymer interaction. However, numerical modeling of PEF flow in porous media has been relatively less well understood due to the additional complexity. In this work, we propose modifications to the population-balance foam model for PEF modeling, and their successful use in matching the experimental results.
The population-balance model proposed by Chen and co-workers has been used as development platform. Upon reviewing various aspects in the physics of foam generation, coalescence and mobility reduction in porous media with the addition of polymer, a modified population-balance model was proposed with new parameters pertaining to the polymer effect on the net foam generation and the limiting capillary pressure. The new model was implemented and used to history match foam coreflood experiments with and without polymer.
In addition to the foam apparent viscosity increase due to higher viscosity of the aqueous phase, polymer also impacts foamability and foam stability of bulk foam as indicated in the literature. Our modified population-balance model introduce the viscosity terms in foam generation and coalescence coefficients to account for postulated positive impact on reducing liquid drainage and foam coalescence and negative impact on the characteristic time needed for bubble snap-off in porous media. Additionally, a modification in the limiting capillary pressure was proposed in the new model to include the polymer effect based on our analysis of the disjoining pressure. Two new model parameters are proposed and implemented accordingly. The new foam model succeeded in history-matching the anionic-surfactant-based and nonionic-surfactant-based PEF corefloods with different types of polymers through tuning the two new model parameters. The simulations also captured the transient increasing of the pressure drops induced by polymer transport and adsorption. The proposed model can be used to provide meaningful values of the model parameters that were able to explain the physical mechanisms behind the PEF floods and to guide future experimental design to further constraint the choices of model parameters.
This work provided new methodology to model PEF flow in porous media using the mechanistic population-balance approach for the first time. With proper calibrations of the parameters proposed in the model, the new model can therefore be used to simulate PEF EOR processes to describe the combined effect of foam and polymer on the mobility control of the injectants.
Dang, Cuong (Computer Modelling Group Ltd.) | Nghiem, Long (Computer Modelling Group Ltd.) | Nguyen, Ngoc (University of Calgary) | Yang, Chaodong (Computer Modelling Group Ltd.) | Mirzabozorg, Arash (Computer Modelling Group Ltd.) | Li, Heng (Computer Modelling Group Ltd.) | Chen, Zhangxin (University of Calgary)
Many attempts have been made to understand, design, and optimize a chemical flooding process; however, the current low oil price environment makes its implementation very challenging from an economics point of view. Recently, CoSolvent Assisted Chemical Flooding (CACF) has been considered as a promising approach to reduce the cost of surfactant-based recovery methods, especially in heavy oil reservoirs. More importantly, recent studies indicated that CACF can be efficiently applied at relatively low temperature, i.e., without the need of steam injection. This helps reduce for the cost of steam generation and injection, and the associated greenhouse gas effects. This paper presents a new development in modeling CACF using an Equation-of-State (EOS) compositional reservoir simulator.
We used a new approach to model the behavior of the oil-water-microemulsion system based on solubility data without modeling type III microemulsion explicitly. The results showed an excellent agreement with numerous chemical coreflooding data and are in agreement with a chemical floodingresearch simulator. The new development presented includes the effects of cosolvent on rheological properties and phase behavior of microemulsion in the CACF process, particularly microemulsion viscosity and interfacial tension.
The proposed model showed good agreement with four published CACF coreflood experiments in which surfactant was not used in alkali and polymer chemical slugs. This model efficiently captures the complex chemical reactionsoccurring in the CACF process, i.e., generation of in-situ soap based on reactions between alkali and a rich acid component in heavy crude oil. The model provides consistent results with laboratory coreflood data at different operating temperatures, which is very important for heavy oil reservoirs. The ultimate recovery factor by CACF coreflooding is about 97%, similar to ASP (Alkali, Surfactant and Polymer) coreflooding, but without the need of surfactant injection.