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Results
Abstract Surfactant flooding is a promising technique that can reduce interfacial tension (IFT) between oil and water to ultra-low values, mobilizing previously trapped oil. For reservoirs at moderate to high pressures, understanding and modeling how pressure affects the phase behavior of a surfactant-brine-oil system is crucial to the design and implementation of efficient/cost-effective surfactant flooding project. Typical phase behavior experiments and models are done only at low pressures. Objective of this paper is to comprehensively model realistic range of pressure, temperature, and other parameters, using hydrophilic-lipophilic deviation (HLD) and net-average curvature (NAC) based equation-of-state (EoS). This paper shows how to model an anionic surfactant system consisting of a surfactant, co-solvent, brine (up to 10 wt%) and synthetic oil over a large range in pressure (up to 8000 psi), temperature (up to 60 °C), and compositions. The model is developed from measurements made using a high-pressure PVT cell. Parameters such as the oil-water ratio and the surfactant concentration were varied in ternary space under both atmospheric and reservoir conditions. Selected experimental results were then matched to our new EoS based on HLD-NAC. The advantage of this approach is that the tuned model can predict phase behavior in a unified way for all experiments. The pressure and temperature scans show that pressure has a significant effect on the surfactant microemulsion phase behavior, shifting it from an optimal three-phase system at low pressure to a nonoptimal two-phase system at high pressure. Further, multiple scans at different oil-water ratios show a shift in the optimum indicating that phase behavior partitioning of the various components is changing with oil saturation. In addition, we show how to determine the optimum pseudocomponent composition for such a ternary pseudocomponent system. We further show that the micellar correlation length in the three-phase region can be predicted well using linear functions with temperature, pressure, and salinity. The change in characteristic length is a critical aspect of modeling the phase behavior accurately with the HLD-NAC EoS, and ultimately to predict and scale the phase behavior for other reservoir conditions. We show that there is a well-defined optimum 3D surface in the pressure, temperature, and salinity space that can aid the design of surfactant floods for field use and reduce the risk of those projects. Further, the use of the tuned HLD-NAC EoS can define and reduce the number of experiments needed to model the optimum owing to a unified EoS prediction of the phase behavior. When input into a numerical simulator, the improved prediction of the size and shape of the two-phase lobes with changing pressure, temperature, and salinity will also improve estimations of surfactant slug size needed to maintain ultra-low IFTs.
Abstract Polymer flood improves the sweep efficiency of viscous oil recovery over water flood. The low-tension polymer (LTP) flood has the potential to improve the displacement efficiency due to low interfacial tension without sacrificing sweep efficiency. The objective of this research is to evaluate the performance of LTP floods as a function of IFT for a viscous oil in a 2D sand pack. Over 20 non-ionic surfactants/co-solvents were tested. A series of sandpack flooding experiments were conducted in a custom-designed 2D visualization cell. The results show that short-hydrophobic surfactants 2EH-xPO-yEO can reduce the IFT to as low as 0.05 dynes/cm. Flooding experiments were performed in sandpacks with and without connate water saturation. For the experiments with connate water saturation, the sandpack was water-wet/intermediate-wet. A base-case polymer flood (without any surfactant) with a viscosity ratio of 10 showed a stable displacement and 82% OOIP oil recovery at the first pore volume injected (PVI).LTP flood with an IFT of 0.1 dynes/cm also showed stable displacement front, but ahigher oil recovery at 1 PVI (90% OOIP).Further reduction in IFT to 0.05 dynes/cm resulted in an unstable displacement and a lower recovery of 65% OOIP. For the experiments without connate water saturation, sandpack was oil-wet, the base-case polymer flood at a viscosity ratio of 10 showed severe fingering and a low oil recovery at 1 PVI (58% OOIP). Adding the nonionic surfactants did not improve displacement efficiency nor oil recovery in oil-wet sandpacks.
- North America > Canada > Alberta (0.46)
- North America > United States > Texas (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (0.66)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Mooney Field > Bluesky Formation (0.99)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
Polymer Stabilized Foam Rheology and Stability for Unconventional EOR Application
Griffith, Christopher (Chevron) | Jin, Julia (Chevron) | Linnemeyer, Harry (Chevron) | Pinnawala, Gayani (Chevron) | Aminzadeh, Behdad (Chevron) | Lau, Samuel (Chevron) | Kim, Do Hoon (Chevron) | Alexis, Dennis (Chevron) | Malik, Taimur (Chevron) | Dwarakanath, Varadarajan (Chevron)
Abstract It has been shownthat injecting surfactants into unconventional hydraulically fractured wells can improve oil recovery. It is hypothesized that oil recovery can be further improved by more efficiently distributing surfactants into the reservoir using foam. The challenge is that in high temperature applications (e.g., 240 F) many of these formulations may not make stable foams as they have only moderate foaming properties (short half-life). Therefore, we are evaluating polymers that can be used to improve foam stability in high temperature wells which has the potential to improve oil recovery beyond surfactant only injection.Surfactant stabilized nitrogen foams were evaluated using a foam rheometer at pressures and temperatures representative of a field pilot well. The evaluation process consisted of measuring baseline properties (foam viscosity and stability) of a surfactant stabilized foam without any added stabilizer. Next, conventional enhanced oil recovery polymers (HPAMs, modified-HPAMs, and nonionic polymers) were added at different concentrations to determine their impacts on foam stability. Our results demonstrate that inclusion of a relatively low concentration (0.05 wt% – 0.2 wt%) of polymer has a pronounced impact on foam stability. It was determined that reservoir temperature plays a key role in selecting astabilizing polymer. For example, at higher temperatures (>240 F), sulfonated HPAM polymers at just 0.2 wt% more than doubled the stability of the foam. The polymer that was selected from this lab work was tested in a foam field trial in an unconventional well. It is thought that improved foam stability could potentially help improve the distribution of surfactants in fracture network and further improve oil recovery.
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
A New Logistically Simple Solution for Implementing ASP/ACP in Difficult Environments – Evaluation of Concept with High TAN Viscous Crude Oil
Southwick, Jeffrey George (JSouth Energy LLC) | Upamali, Karasinghe Nadeeka (Ultimate EOR Services, LLC) | Fazelalavi, Mina (Ultimate EOR Services, LLC) | Weerasooriya, Upali Peter (Ultimate EOR Services, LLC) | Britton, Chris James (Ultimate EOR Services, LLC) | Dean, Robert Matthew (Ultimate EOR Services, LLC)
Abstract Research on alkali assisted chemical EOR technology with high TAN crude oils have led to developments with liquid organic alkalis and co-solvents (Southwick J., et al., 2020) (Fortenberry, et al., 2015) (Schumi, et al., 2019) (Upamali, et al., 2018). Both concepts afford potential significant cost reduction in field operations but to date it has not been demonstrated that these two concepts can work together. Monoethanolamine (MEA) alkali and a wide variety of liquid co-solvents are evaluated with high TAN (total acid number) crude oil. Formulations are found that give ultra-low interfacial tension (IFT) at a specified injection salinity. Fine tuning the formulation to different injection salinities can be done by choosing alternate co-solvents (or a co-solvent blend). A formulation comprising 1% MEA and a novel high molecular weight (3,152 g/gmol) co-solvent, 0.5% Glycerin alkoxylate with 30 moles propylene-oxide and 35 moles ethylene-oxide (Glycerin-30PO-35EO), gave ultra-low IFT in 21,000 TDS injection brine and gave 100% oil recovery in Bentheimer sandstone with 3500 ppm FP 3630 as mobility control agent. All oil was produced clean, no separation of emulsion was needed to measure oil recovery. Alkali consumption tests were also performedwith a high permeability reservoir sandstone. Results confirmed earlier data published with Boise outcrop sandstone (Southwick J., et al., 2020) showing low alkali consumption with MEA. On a mass basis, only 12% of the amount of MEA is consumed relative to sodium carbonate. This reduces the logistical challenges of shipping chemicals to remote locations. MEA is also a low viscosity liquid which further simplifies field handling.
- Asia (1.00)
- North America > United States > Idaho > Ada County > Boise (0.25)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Salymskoye Field > Zapadno Salymskoye Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- (2 more...)
Abstract Saturation distributions exhibiting unphysical "checkerboard" patterns, time-step size sensitivity, and slow convergence in certain instances are observed in a fully implicit surfactant simulator that is based on an industry-wide accepted formulation. In this paper, we discuss methods to address each of the above conditions and hereby achieve a robust algorithm with favorable convergence characteristics. The proposed remedies are result of in-depth studies of the physics of micro-emulsion appearance and disappearance as well as detailed analysis of the numerical convergence difficulty. Our method considers wide ranges of solution variables in a typical surfactant flood simulator and critical key parameters identified by flash algorithm [Han, et al. 2017] and general non-linear solver. The details of the improved formulation are provided and should enable readers to replicate all these results. Identifying grid cells in a reservoir model where and when the micro-emulsion phase appears is a key capability in the modeling of surfactant phase behavior. The Critical Micelle Concentration (CMC) is the commonly accepted triggering criterion for forming the micro-emulsion phase. We have observed unphysical "checkerboard" saturation patterns for several cases where water mobility is greater than oil mobility when using the conventionally accepted CMC calculation method. We have analyzed the reasons for this unphysical solution and propose a new CMC definition to ensure physically consistent simulation results. Typical CMC values for surfactant flood are in the range of 10 to 10. This requires surfactant concentration to be solved more accurately relative to other component concentrations as it directly affects micro-emulsion phase disappearance. The simulation results may vary with time-step sizes not only from the time-truncation errors but, more importantly, from the accuracy of the solved surfactant concentration for each time-step. Special treatments are introduced to reduce the time-step size sensitivity in our simulator. For cases with cation exchange, slow convergence is observed as the corresponding governing equations form an ill-conditioned matrix for cells with small surfactant concentration. An extra term is introduced into the formulation to speed up the convergence rate without changing the model behavior.
Abstract Foam flooding can minimize bypassing in gas floods in fractured reservoirs. Finding a good foam formulation to apply in high salinity reservoirs is challenging, especially with divalent cations, e.g., API brine (8% NaCl with 2% CaCl2). When formulating with nanoparticles, the colloidal dispersion stability is difficult due to the dramatic reduction of the Debye length at high salinity. The aim of this work was to develop a strong foam in API brine, using nonionic surfactant (SF) and ethyl cellulose nanoparticles (ECNP), for gas flooding in fractured carbonate reservoirs. ECNP particles were synthesized and dispersed in API brine using a nonionic surfactant (SF). SF and SF/ECNP foams were created and their stability was studied at atmospheric pressure and 950 psi. Foam mobility was measured in a sand pack at the high pressure. Foam flood experiments were conducted in oil saturated fractured carbonate cores. The nonionic surfactant was proven to be a good dispersion agent for ECNP in API brine. Moreover, the SF-ECNP stabilized foam in API brine, even in the presence of oil. The foam was found to be shear-thinning during flow through sand packs. Core floods showed that SF/ECNP foam recovered 81.6% of the oil from the matrix, 13.8% more oil than the surfactant only foam, indicating the synergy between ECNP and surfactant. ECNP accumulates in the foam lamella and induces larger pressure gradients in the fracture to divert more gas into the matrix for oil displacement.
- Geology > Petroleum Play Type > Unconventional Play > Fractured Carbonate Reservoir Play (0.61)
- Geology > Rock Type > Sedimentary Rock (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.98)
Development of Bio-Based Surfactant Foams for Hydrocarbon Gas Disposal Applications
Jin, Julia (Chevron Technical Center, a Division of Chevron USA Inc.) | Zuo, Lin (Chevron Technical Center, a Division of Chevron USA Inc.) | Pinnawala, Gayani (Chevron Technical Center, a Division of Chevron USA Inc.) | Linnemeyer, Harold (Chevron Technical Center, a Division of Chevron USA Inc.) | Griffith, Christopher (Chevron Technical Center, a Division of Chevron USA Inc.) | Zhou, Jimin (Chevron Technical Center, a Division of Chevron USA Inc.) | Malik, Taimur (Chevron Technical Center, a Division of Chevron USA Inc.)
Abstract There has been increasing interest in different greenhouse gas (GHG) management strategies including the reduction of methane emissions and carbon sequestration. It has been proposed that reinjection of excess produced natural gas can mitigate GHG emissions without compromising oil production. Foam has been used as a method to reduce gas mobility, delay gas breakthrough, and improve sweep efficiency. However, industrial production of petroleum-based chemicals or surfactants to generate foam can be dependent on fossil-based resources that can be scarce or expensive. The main objective of this work was to reduce chemical cost and oil-based chemical dependency by developing an alternative biosurfactant formulation to generate high quality foam. Biosurfactant blends were ranked in comparison to single component anionic and nonionic surfactants and other commercially available surfactant blends. Bulk stability "shake tests" were done to look at initial foamability and stability of the different candidates and then corefloods in sandpacks and surrogate rocks were completed to look at if formulations would generate foam in porous media with methane gas and in the presence of crude oil. Experiments showed success in replicating chemical performance by replacing traditional oil-based surfactants with bio-based lignin derived surfactants even at reservoir conditions. High-quality biosurfactant foams reduced chemical costs, provided an alternative method to dispose of large amounts of hydrocarbon gas, and improved oil recovery through foam displacement.
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/7 > Snorre Field > Lunde Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > PL 375 > Block 34/4 > Snorre Field > Statfjord Group (0.99)
- (9 more...)
Abstract Many conventional surfactant-brine-oil phase behavior tests are conducted under ambient pressure conditions without the solution gas. It is known that the solution gas lowers the optimum salinity. Researchers often mix toluene (or cyclohexane) with the dead oil and form a surrogate oil to mimic the live oil. The objective of our work is to study the effect of gas and toluene on phase behavior, and to provide the proper amount of toluene to be mixed to mimic the live oil. Effects of toluene in surrogate oil and solution gas in live oil are examined by hydrophilic-lipophilic difference and net average curvature (HLD-NAC) structural model simulation and the equivalent alkane carbon number (EACN). Experimental values from literature and our experiments are also examined to compare those with the simulation results. For the simulation, both the mole fraction and mass fraction were used to calculate mixture EACN and examine the effect of additional components. HLD-NAC simulation results showed that the mass fraction-based simulation is more accurate (~7% error) than mole fraction-based simulation (~19% error) with a toluene EACN of 1. For larger molecules like toluene in surrogate oil, EACN using mole fraction also works with a toluene EACN of 5.2. The EACN of the surrogate oil should match the EACN of the live oil to determine the proper amount of toluene in the surrogate oil.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Most chemical EOR formulations are surfactant mixtures, but these mixtures are usually modeled as a single pseudo-component in reservoir simulators. However, the composition of an injected surfactant mixture changes as it flows through a reservoir. For example, as the mixture is diluted, the CMC changes, which changes both the adsorption of each surfactant component and the microemulsion phase behavior. Modeling the physical chemistry of surfactant mixtures in a reservoir simulator was found to be more significant than anticipated and is needed to make accurate reservoir-scale predictions of both chemical floods and the use of surfactants to stimulate shale wells.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Geology > Mineral (0.46)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract Most carbonate reservoirs are oil-wet/mixed-wet and heterogenous at multiple scales. Majority of the injected water flows through the high permeability regions/fractures and bypass the oil in the matrix due the high negative capillary pressure (Pc). To enhance oil recovery from such reservoirs, the sign of the Pc should be changed by wettability alteration (WA) or the Pc should be reduced by lowering interfacial tension (IFT). In this study, surfactants which can either alter wettability or develop ultra-low IFT were identified through laboratory measurements for the target carbonate reservoir. The performance of these two types of surfactants was systematically evaluated at the core scale and scaled-up to the reservoir scale. A reservoir-scale model was developed to simulate injection-soak-production (ISP) tests and evaluate performance of the selected surfactants at the field scale. Experiments showed that quaternary ammonium cationic surfactants have excellent WA ability, while a series of propoxy sulfate anionic surfactants showed intermediate WA and ultra-low IFT. Spontaneous imbibition tests showed that WA surfactants have fast initial oil production, while ultra-low IFT surfactants has low initial oil rate but higher final oil recovery, which was validated by mechanistic simulation. Low IFT results in low Pc and slow imbibition, but also triggers gravity-driven drainage. For ultra-low IFT system, gravity drainage is more dominant than WA, and Pc-alteration is less important than relative permeability (Kr) alteration. As reservoir thickness increases, Kr-alteration is more important than Pc-alteration. Gravity drainage is expected to be scaled up by length of matrix (L), while Pc-driven imbibition is scaled by L. Field-scale simulation showed that low-IFT surfactant has better injectivity than WA surfactant during injection phase. In soaking phase, spontaneous imbibition by WA surfactant is much more significant than that by low-IFT surfactant. In production phase, post-waterflood achieved higher oil recovery from low-IFT surfactant treated matrix due to its low residual oil saturation and high oil relative permeability.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- North America > United States > Wyoming > Bighorn Basin > Phosphoria Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Word Group > San Andreas Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Grayburg Formation > San Andreas Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)