Rognmo, Arthur U. (University of Bergen) | Al-Khayyat, Noor (University of Bergen) | Heldal, Sandra (University of Bergen) | Vikingstad, Ida (University of Bergen) | Eide, Øyvind (University of Bergen) | Fredriksen, Sunniva B. (University of Bergen) | Alcorn, Zachary P. (University of Bergen) | Graue, Arne (University of Bergen) | Bryant, Steven L. (University of Calgary) | Kovscek, Anthony R. (Stanford University) | Fernø, Martin A. (University of Bergen)
The use of nanoparticles for CO2-foam mobility is an upcoming technology for carbon capture, utilization, and storage (CCUS) in mature fields. Silane-modified hydrophilic silica nanoparticles enhance the thermodynamic stability of CO2 foam at elevated temperatures and salinities and in the presence of oil. The aqueous nanofluid mixes with CO2 in the porous media to generate CO2 foam for enhanced oil recovery (EOR) by improving sweep efficiency, resulting in reduced carbon footprint from oil production by the geological storage of anthropogenic CO2. Our objective was to investigate the stability of commercially available silica nanoparticles for a range of temperatures and brine salinities to determine if nanoparticles can be used in CO2-foam injections for EOR and underground CO2 storage in high-temperature reservoirs with high brine salinities. The experimental results demonstrated that surface-modified nanoparticles are stable and able to generate CO2 foam at elevated temperatures (60 to 120°C) and extreme brine salinities (20 wt% NaCl). We find that (1) nanofluids remain stable at extreme salinities (up to 25 wt% total dissolved solids) with the presence of both monovalent (NaCl) and divalent (CaCl2) ions; (2) both pressure gradient and incremental oil recovery during tertiary CO2-foam injections were 2 to 4 times higher with nanoparticles compared with no-foaming agent; and (3) CO2 stored during CCUS with nanoparticle-stabilized CO2 foam increased by more than 300% compared with coinjections without nanoparticles.
Moreno Ortiz, Jaime Eduardo (Schlumberger) | Gossuin, Jean (Schlumberger) | Liu, Yunlong (Schlumberger) | Klemin, Denis (Schlumberger) | Gurpinar, Omer (Schlumberger) | Gheneim Herrera, Thaer (Schlumberger)
Challenges on EOR process upscaling have been discussed extensively in the industry and effects of diffusion, dispersion, heterogeneity, force balance and frontal velocity -among others, recognized and qualified, along with the importance of understanding the numerical model finite difference equations and modeling strategy. Augmenting the upscaling complexity is the often-limited understanding/data on the EOR displacement at different scales (from micro to full field), including the EOR agent/rock/fluid interactions that is often available at the early stages of the EOR process de-risking.
A common denominator for the EOR process characterization and upscaling (along with the discretization of the displacement) is the non-uniqueness nature of the problem. As the complexity of numerical representation of the EOR process increases (thus increasing data characterization requirements), so does the number of plausible solutions and challenges when dealing with an otherwise incomplete dataset. Digital rock has evolved as a strong alternative to complement laboratory corefloods, allowing for EOR agent optimization on a high-resolution digital representation of the pore structure, detailed digital fluid model of both reservoir fluids and EOR agents and physical rock-EOR agent-reservoir fluid interaction, thus providing several calibration points to ensure the finite-difference model calibration and upscaling preserve the process behavior.
This paper discusses the use of digital rock solutions on the EOR deployment, particularly on translating the results to numerical finite difference models, addressing the inherent laboratory measurement uncertainty and proposing a fit-for-purpose multi-scale upscaling strategy that addresses both effects of heterogeneity and EOR agent characterization during the upscale process.
This paper addresses the challenges of chemical flooding upscaling, particularly polymer by using a real-life polymer injection case where digital rock, corefloods and more importantly pilot results are available to test and validate our observations. Using a polymer coreflood and digital rock results as input, numerical finite difference simulation models were built and calibrated to effectively reproduce the displacement physics observed on both digital rock and corefloods, digital flood results were used to bridge the laboratory-to-numerical model step by providing effective upscaled polymer properties as well as intrinsic rock properties such as relative permeability and capillary pressures, which are then taken through a series of multi-scale finite difference models to identify, validate and quantify upscaling requirements, addressing polymer deformation through pore throats and effective simulation viscosity. Digital rock is used to rank and resolve ambiguity on the finite difference model calibration by providing an otherwise rare opportunity to visualize the displacement in the 3D space. The analysis shed a new light on fluid-fluid and fluid-rock interaction at pore scale and enabled us to improve on the finite difference model generation and polymer properties.
The goal of this work is to evaluate the applicability of a novel set of surfactants to enhance recovery from a viscous oil, high temperature, high permeability, clastic reservoir. A large number of novel short-hydrophobe based surfactants/cosolvents were designed and synthesized. As these surfactants do not require expensive aliphatic alcohols for their synthesis, they are likely to be less costly than conventional anionic surfactants. Here only phenol hydrophobe based non-ionic surfactants with varying number of propylene oxide (PO) and ethylene oxide (EO) groups are discussed. These surfactant molecules were investigated for their aqueous stability limits, interfacial tensions (IFT) with a viscous crude oil and oil recovery from sandpack or sandstone cores. Surfactant phase behavior experiments with viscous crude oil showed low IFT (not ultralow) for single surfactant systems. Only one surfactant (Phenol-7PO-15EO) formulation was chosen for coreflood in sandpack and sandstone cores. Water flood recovered about 50% original oil in place (OOIP) and reduced the oil saturation to about 48% in the high permeability sandpacks. The tertiary surfactant polymer flood with Phenol-7PO-15EO increased the cumulative recovery to 99% for sandpacks. The oil recovery was insensitive to injection brine salinity in the range studied. As the permeability decreased, the tertiary oil recovery decreased if the permeability is lower than 7 Darcy. Surfactant-polymer (SP) formulations with this surfactant can be recommended for high permeability sandstone reservoirs with viscous oils, but not for sub-Darcy sandstones.
Abdelfatah, Elsayed (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Wahid-Pedro, Farihah (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Melnic, Alexander (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Vandenberg, Celine (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Luscombe, Aidan (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Berton, Paula (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada) | Bryant, Steven (Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive NW, Calgary, Alberta T2N 1N4, Canada)
Waterflooding of heavy oil reservoirs is commonly used to enhance their productivity. However, preferential pathways are quickly developed in the reservoir due to the significant difference in viscosity between water and heavy oil, and hence, the oil is trapped. Here, we propose a platform for designing ultra-low IFT solutions for reducing the capillary pressure and mobilizing the heavy oil.
In this study, mixtures of organic acids and bases were formulated. Three different formulations were tested: (i) Ionic liquid (IL) formulation where bulk acid (4-dodecylbenzene sulfonic acid) and base (Tetra-
The IL and ABs formulation are acidic solutions with pH around 3. The ASBs formulation is highly basic with a pH around 12. Non of the formulations salted out below 14 wt% of NaCl. While conventional surfactant, SDBS, precipitated at salt concnetration less than 2 wt% of NaCl. The formulation solutions (1 wt%) have different optimum salinities: 2.5 wt% NaCl for ASBs, 3 wt% NaCl for IL and AB. Although IL and AB have the same composition and molar ratio of the components, their performances are completely different, indicating different intermolecular interactions in both formulations. Corefloods were conducted using sandpack saturated with Luseland heavy oil (~15000 cP) and at fixed Darcy velocity of 12 ft/day. A slug of 1 PV of each formulation was injected after waterflooding for 5 PV and followed by 5 PV post-waterflooding. In the hydrophilic sandpacks, IL and AB formulation produced an oil bank, consisting mainly of W/O emulsion, with oil recovery that is 1.7 times what was recovered by 11 PV of waterflooding solely. Majority of the oil was recovered in the 2 PV of waterflood following the IL slug. ASBs formulations produced O/W emulsions with prolonged recovery over 5 PV waterflooding after the ASB slug. The recovery factor for ASBs was 1.6 times that recovered for 11 PV of waterflooding only. In the hydrophobic sandpacks, The ASB formulation slightly increased the recovery factor compared to only waterflooding. While for IL and AB formulation, the recovery factor decreased.
This work presented a novel platform for tuning the recovery factor and the timescale of recovery of heavy oil with a variable emulsion type from O/W to W/O depending on the intermolecular interactions in the system. The results demonstrate that the designed low IFT solutions can effectively reduce the capillary force and are attractive for field application.
Ghosh, Pinaki (The University of Texas at Austin) | Zepeda, Angel (The University of Texas at Austin) | Bernal, Gildardo (The University of Texas at Austin) | Mohanty, Kishore (The University of Texas at Austin)
Waterflood in low permeability carbonate reservoirs (<50 mD) leaves behind a substantial amount of oil due to capillary trapping and poor sweep. Addition of polymer to the injected water increases the viscosity of the aqueous phase and decreases the mobility ratio, thus, improving the sweep efficiency and oil production from the tight formations. Performance of current synthetic EOR polymers is limited by salinity, temperature and injectivity issues in low permeability formations. Mechanical shear degradation can be applied to high molecular weight synthetic polymers to improve the injectivitiy; but makes the process less economical due to significant viscosity loss and consequent increase in polymer dosage. Recently, a different class of polymer has been developed called "hydrophobically modified associative polymers (AP)". The primary goal of this work is to investigate the performance of associative polymers in low permeability carbonate reservoirs. We compare the performance of associative polymers with that of conventional HPAM polymers in low permeability formations. A low molecular weight associative polymer was investigated as part of this study. A detailed study of polymer rheology and the effect of salinity at the reservoir temperature (60 °C) was performed. Additional experiments were performed in bulk and porous media to investigate the synergy of associative polymers with hydrophilic surfactant blends at different brine salinities. Single phase polymer flow experiments were performed in outcrop Edwards Yellow and Indiana limestone cores of low permeability to determine the optimum polymer concentration to achieve the desired in-situ resistance factor (or apparent viscosity). Similar experiments were performed with HPAM polymer for a comparative study. Results showed successful transport of this associative polymer in low permeability formations after a small degree of shear degradation. The resistance factors for the associative polymer were higher than those for HPAM. Shear degraded polymers showed significant improvement in polymer transport in lower permeability cores with reduction in RRF.
We present a CT coreflood study of foam flow with two representative oils: hexadecane C16 (benign to foam) and a mixture of 80 wt% C16 and 20 wt% oleic acid (OA) (very harmful to foam). The purpose is to understand the transient dynamics of foam, both generated in-situ and pre-generated, as a function of oil saturation and type. Foam dynamics with oil (generation and propagation) are quantified through sectional pressure-drop measurements. Dual-energy CT imaging monitors phase saturation distributions during the corefloods. With C16, injection with and without pre-generation of foam exhibits similar transient behavior: strong foam moves quickly from upstream to downstream and creates an oil bank. In contrast, with 20 wt% OA, pre-generation of foam gives very different results from co-injection, suggesting that harmful oils affect foam generation and propagation differently. Without pre-generation, initial strong-foam generation is very difficult even at residual oil saturation about 0.1; the generation finally starts from the outlet (a likely result of the capillary-end effect). This strong-foam state propagates backwards against flow and very slowly. The cause of backward propagation is unclear yet. However, pre-generated foam shows two stages of propagation, both from the inlet to outlet. First, weak foam displaces most of the oil, followed by a propagation of stronger foam at lower oil saturation. Implicit-texture foam models for enhanced oil recovery cannot distinguish the different results between the two types of foam injection with very harmful oils. This is because these models do not distinguish between pre-generation and co-injection of gas and surfactant solution.
Nguyen, Nhat (The University of Texas at Austin) | Ren, Guangwei (TOTAL E&P R&T, USA) | Mateen, Khalid (TOTAL E&P R&T, USA) | Ma, Kun (TOTAL E&P R&T, USA) | Luo, Haishan (TOTAL E&P R&T, USA) | Neillo, Valerie (TOTAL SA) | Nguyen, Quoc (The University of Texas at Austin)
Low-Tension Gas (LTG) has emerged as a novel enhanced oil recovery injection strategy, employing foam in place of polymer to displace the oil bank created with the help of ultra-low-IFT (ULIFT). In our prior work, the process was successfully employed, both in sandstones and carbonates, to achieve attractive oil recoveries with relatively low surfactant retention. However, earlier experiments were carried out at high flow rates in relatively high permeability cores. To improve the robustness of this novel injection scheme, it is necessary to examine it under wider practical environments. Therefore, in this work, experiments are conducted in carbonate and sandstone cores, at lower injection rates and rock permeabilities, to determine whether the foam could provide the necessary mobility control with this novel EOR technique. Initially, a lower flow rate (1 ft/D) experiment is conducted in relatively high permeability (388 md) sandstone core to compare it with the earlier results under a higher injection rate (4 ft/D). Subsequently, even further reduced injection rate (0.5 ft/D) is employed in a sandstone core with one order of magnitude lower permeability (36 md). Two other corefloods with Estaillades limestone (166 md) and Richmont (7 md) are carried out to extend the comparison to carbonate rocks. Surfactant retentions are determined. It is found that four-times-lower injection rate (1ft/D) just slightly delayed oil production, and achieved comparably high oil recovery (87%), indicating a good mobility control. Proportionally reduced pressure drop during slug injection implies similar total fluid mobility. Accordingly, salinity propagation examined from effluents shows slight delays. Even with ten-times-lower permeability sandstone (36 md) at a lower total injection rate (0.5 ft/D), comparable oil recovery (84%) and salinity propagation are found, despite of much lower foam strength. With an intermediate-permeability Estaillades limestone (166 md), compared to high permeability sandstone, oil production is delayed, but comparable eventual oil recovery (88%) is obtained. The delay could be due to higher surfactant retention (0.301 mg/g). The delayed effluent salinity propagation is noticeable, which may be caused by increased total fluid mobility. Finally, extremely low permeability Richmont (7 md) indeed adversely impacts the oil recovery (~58%) and the salinity propagation. This could be attributed to higher surfactant retention and/or decreased foam stability due to oil-wet rock surface. The works here test the robustness of the LTG process in more practical reservoir conditions and have widened its applicability. Demonstration of its feasibility in low-permeability reservoirs, where use of polymer is not currently feasible, will greatly promote the testing and deployment of this technology in the future.
Lee, Jungin (University of Alberta) | Huang, Jingjing (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Chengdu University of Technology and University of Alberta) | Babadagli, Tayfun (University of Alberta)
The performance of non-thermal, cold, heavy oil production methods, such as waterflooding or gas injection (foamy oil) applications, is predominantly limited. As an alternative, efficient chemical flooding has been recommended and tested around the world (mainly in Canada and China). Cost aside, the main issue with this application is the compatibility of the chemicals used in terms of rock type, salinity, temperature, and emulsion generation and stability. Low-cost materials with strong emulsion stability capability have been tested previously in our research group. As an ongoing part of our past studies on the extensive chemical flooding applications in enhanced heavy oil recovery, we visualize directional motion, patterns, and deformation of fingers observed in Hele-Shaw cells with different oil types (heavy oil of 13,850 cP at 21°C from western Canada, heavy mineral oil of 649.9 cP at 20°C.
Macroscopic and microscopic visualizations allow us to gain insights into important and fundamental physical flow mechanisms such as the Saffman-Taylor instabilities due to the viscosity ratio, and the Marangoni effect due to the surface tension gradient, wetting, dewetting, and superspreading behaviors. Hele-Shaw visualization studies in the past have mainly focused on weakening or eliminating the fingering instabilities. In this study, we attempt to categorize the observed finger types which appear during the displacement, identify the finger types responsible for heavy oil-in-water emulsification, and relate the visualization results to final enhanced heavy oil recovery. We observe both miscible and immiscible flow behavior and in the case of immiscible flow, and we investigate the impact of the capillary number on finger growth and ramification patterns by manipulating the flow rates.
There are a plethora of factors that may impact the visualization of heavy-oil emulsification including the fixed chemical properties, chemical compatibility, heterogeneous (or non-heterogeneous) chemical reaction, capillary number effect, mobility ratio, IFT gradient, chemical concentration, liquid-substrate wettability, pH of liquids, precipitation, and brine conditions. To investigate such impact, we investigated a large series of in-situ heavy oil-in-water emulsifications at various conditions using emulsifiers such as anionic surfactants, cationic surfactants, and NaOH. And for the stabilization of the emulsions formed with the emulsifiers, we tested nanofluids (silica, cellulose nanocrystal, zirconia, alumina) and polymer (Xanthan Gum and an anionic polyacrylamide-based polymer). The results displayed that there exist finger types which are responsible for stable Winsor type 4 heavy oil-in-water emulsification. By the method of controlling the infrastructure of emulsion droplets and correlating observed multiple finger interactions to the material designs, we enable the selection of both novel and cost-effective designs for heavy oil recovery as well as displacement mechanisms.
Polymer rheological behavior in an Enhanced Oil Recovery (EOR) project is one of the critical factors to determine whether the polymer injection would be effective to increase the oil production in a field. Due to complications on the measurement of this parameter and its variation within the reservoir, the challenge of understanding viscosity behavior relies on lab and field tests that become key factors to solve this issue.
This study was conducted during an injectivity test for an EOR project in Los Perales field (Santa Cruz, Argentina) in three wells with different operational and subsurface conditions, and tests were performed twice a day for 30 days each in order to obtain sufficient time span of data.
From lab rheology tests performed at reservoir conditions, where the main objective was to analyze viscosity changes through time, two different tendencies were observed: one that affects in early times and another that becomes preeminent at late times. With these results, a describing equation was developed to predict viscosity evolution over time. The equation consists of three terms including thermal variation, chemical degradation and the final viscosity towards which the polymer tends.
Although the equation properly describes both lab and field polymer solution, there is a considerable difference, especially when the effects mentioned become preponderant. This difference is attributed to both the water used for the mixture and the possible impurities that may be incorporated during the maturation or transfer of the polymer. Since most of the data used was obtained from field tests, this emphasizes the appliance of the equation on the field.
Impurities turn out to be crucial, specially oxygen (O2) and hydrogen sulfide (H2S) combined. Their presence highly impacts the asymptotic viscosity, so a correlation between H2S content and final viscosity was also developed.
Finally, an analysis of the temperature influence on the viscosity was conducted. A correlation between the final viscosity and temperature was found and used to incorporate temperature variations in the predictions and therefore to relate measurements performed at different conditions.
The primary advantage of this study is that the equation and correlations enable the prediction of the polymer solution viscosity at any time. This allows the estimation of actual polymer viscosity in the reservoir from a routine measurement at any temperature and impurities content. The versatility of this equation is what makes it novel and useful in an industry going towards EOR projects.
Luo, Haishan (TOTAL E&P R&T, USA) | Mateen, Khalid (TOTAL E&P R&T, USA) | Ma, Kun (TOTAL E&P R&T, USA) | Ren, Guangwei (TOTAL E&P R&T, USA) | Neillo, Valerie (TOTAL SA) | Blondeau, Christophe (TOTAL SA) | Dong, Pengfei (Rice University) | Puerto, Maura (Rice University) | Biswal, Sibani (Rice University) | Hirasaki, George (Rice University)
Recovering oil from oil-wet matrix in fractured carbonate rocks is highly challenging. Recent experiments have indicated that ultra-low-interfacial-tension (ULIFT) foam flood could significantly boost the oil recovery from such rocks. However, there is limited information available about the foam and the microemulsion transport in the fractured system to extract the oil from low permeability matrix. Adaptation of this technology in the field would not be possible without a good understanding of the process.
The aim of this work is to model and history match the ULIFT foam flood in fractured carbonate cores for further gaining insight into the complex four-phase flow. The model was set up based on a group of experiments using cores split lengthwise to simulate axially confined fractures. Pre-generated foam was tested in this system due to the lack of in-situ generation of foam in the straight fracture at the core scale. Various foam coalescence mechanisms, with/without oil, were modeled, and a dynamic-texture population-balance foam model was developed for this purpose.
Our model incorporates the effects of oil and permeability as well as the coexistence of foam and microemulsion on the foam apparent viscosity. The model is able to reasonably well history match both the oil recoveries and the total pressure drops of the ULIFT foam floods in fractured carbonate cores. More impressively, the modeling results agree very well with the pressure gradient of each section of the core, indicating that the spatial variation and distribution of the foam texture are largely captured. The simulation results also show that the pre-generated foam greatly resists the fluid flow in the fracture close to the injector side and enhances the diversion of injected fluids into the matrix layers, leading to improved oil displacement. The resulting oil crossflow from the matrix to the fracture destabilizes the foam at the foam front thereby slowing the transportation of foam in the fracture. Additional case studies suggest that significantly more oil can be recovered if the foam destabilization by oil could be reduced/mitigated.
Test results disclosed in this paper demonstrate for the first time the successful modeling and history-match of ULIFT foam floods in fractured rocks. Valuable insight into this complex process has been gained through this innovative research. This is of great value with respect to the further optimization of the corefloods, the design of the surfactant formulation, and the feasibility of applying this new technology to the field scale.