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Collaborating Authors
Results
Nanoparticle Stabilized Strong Foam for EOR in High Salinity Fractured Carbonate Reservoirs
Xuezhen, Wang (The University of Texas at Austin) | Kishore, Mohanty K (The University of Texas at Austin)
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)
Design of Surrogate Oils for Surfactant-Brine-Oil Phase Behavior
Park, Jaebum (The University of Texas at Austin) | Mohanty, Kishore (The University of Texas at Austin)
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)
Fundamental Improvements in Modeling Surfactant Behavior in Reservoir Simulators
Chang, Leonard Yujya (The University of Texas at Austin) | Li, Zhitao (Ultimate EOR Services) | Luo, Haishan (The University of Texas at Austin) | Pope, Gary Arnold (The University of Texas at Austin)
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)
Surfactant Enhanced Oil Recovery from Tight Carbonates: Core-Scale Experiments to Reservoir-Scale Modeling
Shi, Yue (The University of Texas at Austin) | Mohanty, Kishore (The University of Texas at Austin)
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)
Chemical Flood with a Single Surfactant
Panthi, Krishna (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin)
Abstract The goal of this work is to develop alkaline-surfactant-polymer (ASP) formulations for a shallow, clayey sandstone reservoir. Commercially available surfactants were used in the phase behavior study. The gas-oil-ratio (GOR) was low; the phase behavior and coreflood study was conducted with the dead oil. The surfactant formulation systems were tested in tertiary ASP core floods in reservoir rocks. Many surfactant formulations were identified which gave ultralow IFT, but the formulation with only one surfactant (at 0.5 wt% concentration) in presence of one co-solvent was selected for corefloods. The cumulative oil recovery was in the range of 94-96% original oil in place (OOIP) in the corefloods. The surfactant retention was low (0.15 mg/gm of rock) in spite of the high clay content. The study showed that 0.5 PV of ASP slug and 2700 ppm of the polymer were required to make the flood effective. The use of alkali and preflush of the soft brine helped minimize surfactant retention.
- Asia > Middle East (1.00)
- Asia > China > Heilongjiang Province (0.28)
- North America > United States > Missouri (0.28)
- Geology > Mineral (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (6 more...)
The Effect of Phase Distribution on Imbibition Mechanisms for Enhanced Oil Recovery in Tight Reservoirs
Wang, Mingyuan (The University of Texas at Austin) | Argüelles-Vivas, Francisco J. (The University of Texas at Austin) | Abeykoon, Gayan A. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin)
Abstract The main objective of this research was to investigate the impact of initial water on the oil recovery from tight matrices through surfactant-enhanced water imbibition. Two flooding/soaking experiments using fractured tight cores with/without initial water were performed. The experimental results were analyzed by the material balance for components: oil, brine, and surfactant. The analysis resulted in a quantitative evaluation of the imbibed fraction of the injected components (brine and surfactant). Results show that the surfactant enhanced the brine imbibition into the matrix through wettability alteration. The initial efficiency of the surfactant imbibition increased when brine was initially present in the matrix. The imbibition of brine was more efficient with no initial water in the matrix. A possible reason is that the presence of initial water in the matrix was able to increase the initial efficiency of the surfactant imbibition; however, the increased amount of surfactant in the matrix lowered the interfacial tension between the aqueous and oleic phases; therefore, the efficiency of brine imbibition was reduced. Another possible reason is that capillary force was lower in the presence of initial water in the matrix, resulting in weaker imbibition of brine. Although the two cases showed different characteristics of the mass transfer through fracture/matrix interface, they resulted in similar values of final water saturation in the matrix. Hence, the surfactant injection was more efficient for a given amount of oil recovery when there was no initial water in the matrix.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.32)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
Wettability Altering Surfactants for High Temperature Tight Carbonate Reservoirs
Alammari, Faisal G. (The University of Texas at Austin) | Miller, Chammi S. (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin)
Abstract Most tight carbonate reservoirs have low oil recovery factors after the primary and secondary recovery stages. High-temperature carbonate reservoirs tend to be oil-wet/mixed-wet due to positively charged minerals and negatively charged oil molecules, hence reducing oil relative permeability. This study aims to enhance oil recovery from tight carbonates by virtue of wettability alteration using surfactants. Twenty different surfactants of different classes and different functional groups are systematically evaluated by first testing their aqueous stability at reservoir conditions. The aqueous stable surfactants were tested for contact angles on the mineral surface. Seven surfactant candidates were selected for spontaneous imbibition experiments, where oil recovery was monitored as a function of time. Wettability-altering surfactants increase the oil recovery by spontaneous imbibition. Up to 190% increase in oil recovery from outcrop core plugs was observed compared to the control sample with sea water.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Successful Field Implementation of CO2-Foam Injection for Conformance Enhancement in the EVGSAU Field in the Permian Basin
Katiyar, Amit (The Dow Chemical Company) | Hassanzadeh, Armin (The Dow Chemical Company) | Patil, Pramod (Rock-Oil Consulting Group) | Hand, Michael (ConocoPhillips) | Perozo, Alejandro (ConocoPhillips) | Pecore, Doug (ConocoPhillips) | Kalaei, Hosein (ConocoPhillips) | Nguyen, Quoc (The University of Texas at Austin)
Abstract This paper presents the performance of a CO2 foam injection pilot implemented in the East Vacuum Grayburg San Andres Unit (EVGSAU) by ConocoPhillips in cooperation with The Dow Chemical Company. The pilot project focuses on a single CO2 injection pattern, consisting of one injector and eight producers, selected due to signs of early gas breakthrough and poor overall sweep efficiency. To solve these conformance issues and increase overall pattern production performance, a new foaming surfactant with low adsorption and high gas partitioning characteristics was developed and experimentally tested at simulated reservoir conditions. A "water alternating surfactant-in-gas" injection strategy was created utilizing a history matched reservoir simulation model and an empirical foam model. This reservoir model was also utilized to better understand the dependency of surfactant concentration on foam generation and fluid diversion. Injection profile logs (IPLs) were also run, in both water and CO2 phases, prior to pilot implementation to establish baseline injection performance. This paper will detail several performance indicators that illustrate sustained improvement in pattern injection and production after more than 15 cycles of alternating water, CO2+surfactant, and CO2-only injection. During each cycle, gas injectivity trends were calculated and compared to the baseline to monitor foam strength and performance. Four additional IPLs were run, which indicated continuous improvement in vertical sweep efficiency and ultimately resulted in uniform injection distribution between the upper and lower sections of the producing zone. Finally, the most significant result of the trial was the uplift in pattern oil production. It has averaged ~20% above the baseline production forecast throughout the entire pilot period and peaked within the first six months at ~60% above the baseline. The success of this pilot illustrates the benefits of using a low adsorbing and CO2 soluble foaming surfactant to address reservoir conformance issues for CO2 floods. Further optimization of the pilot based on the simulation forecast is planned to improve long-term pilot economics.
- North America > United States > New Mexico (1.00)
- North America > United States > Texas (0.82)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (42 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
ASP Flood After a Polymer Flood vs. ASP Flood After a Water Flood
Aitkulov, Almas (The University of Texas at Austin) | Dao, Eric (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin)
Abstract 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.
- 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)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
Structure-Property Model for Microemulsion Phase Behavior
Chang, Leonard (The University of Texas at Austin) | Jang, Sung Hyun (The University of Texas at Austin) | Tagavifar, Mohsen (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Abstract The objective of this research was to develop a model to predict the optimum phase behavior of chemical formulations for a given oil based on the molecular structure of the surfactants and co-solvents. The model is sufficiently accurate to provide a useful guide to an experimental testing program for the development of chemical EOR formulations. There are thousands of combinations of surfactants and co-solvents that could be tested for each oil, so even approximate predictions are very useful in terms of reducing the time and effort required for testing and for prioritizing the chemical combinations to test that are most likely to yield ultra-low IFT at reservoir conditions. The effects of changing molecular structures (e.g. swapping head groups, swapping hydrophobes, increasing the length of hydrophobes, increasing the number of PO and EO groups, adjusting the ratios of surfactants) are shown. The variables with the greatest impact on the optimum salinity and solubilization ratio were identified, and methods are proposed to shift the optimum salinity and the optimum solubilization ratios in any desired direction. The structure-property model was developed and tested using a large dataset consisting of 684 microemulsion phase behavior experiments using 24 oils. The chemical formulations used 85 surfactants and 18 co-solvents in various combinations. Both optimum salinity and optimum solubilization ratio (and thus IFT) are modeled whereas other models have focused almost exclusively on the optimum salinity. Predicting the optimum solubilization ratio is actually of more value because of its relationship to IFT. The models include the effects of co-solvent partitioning, soap formation and the molecular structure of both the surfactants and co-solvents.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)