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Collaborating Authors
Results
Abstract Conformance control via near-wellbore mechanical and chemical treatments is well established. However, for extreme heterogeneities, effective conformance control mandates deep treatments. Such deep treatments or diversion would sustain sweep enhancement far from wells, deep into the reservoir. Deep diversion is even more mandatory for enhanced oil recovery (EOR) to assure the expensive injectants optimally contact the remaining oil. In this paper, we comprehensively present efforts to research, develop, and trial a crosslinked-gel system for deep diversion. We started by reviewing conformance control options including crosslinked systems. The review supported the immaturity of deep conformance control. Various gel-based solutions, especially preformed particle gels (PPGs) and colloidal dispersed gels (CDGs), were proposed; however, diversion effects were not clearly illustrated. For crosslinked-gels, all systems exhibited fast gelation, something suitable for near-wellbore treatments. We then studied the key crosslinked systems. We characterized their behavior using rheometry, bottle tests, and single-phase corefloods. We assessed their potential through oil-displacement corefloods in artificially fractured cores with and without in-situ imaging. In-house studies, on key gel systems demonstrated the feasibility of gels to affect diversion and enhance recovery but corroborated the extreme challenge to design systems with delayed gelation. To assure representative gelation, we developed, and utilized a continuous bi-directional injection protocol to assess gelation times in-situ. From there, we collaboratively developed, and characterized a unique delayed-gelation formulation. The collaborative study addressed this challenge where systems with delayed gelation were developed. In-situ gelation time estimation confirmed this delayed gelation capacity. Further corefloods addressed the key uncertainties including injectivity losses, limited propagation, and ineffective blockage. Simulations were performed to assess the process feasibility.The simulation studies supported the utility of deep diversion treatments. Simulation also guided the initial design of a trial. We focused on the design of a practical field trial.For further derisking, the first trial was optimized to serve as a practical proof-of-concept. Taking into account economics, success measurement, flow assurance, and depth of placement, we diverged from a trial where we observe deep diversion (and infer delayed gelation and effective blockage) then converged into a trial where we infer deep diversion (by observing delayed gelation and effective blockage). With that, we screened candidates with a clear hierarchy of screening criteria. Through this program, and for the first-time in the industry, we demonstrate the potential utility and feasibility of a crosslinked-gel system for deep diversion applications. This potential is supported by comprehensive experimentation including novel in-situ estimation of gelation times. Finally, a consistent workflow to design a practical field trial is laid out. This, in terms of design considerations and hierarchal screening, is believed to be of extreme value to the practicing reservoir engineers.
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
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 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...)
Abstract The objective of this paper is to present a critical review of best practices for conducting laboratory experiments to evaluate chemical EOR. Some legacy methods and procedures are outdated and need to be updated to address their inherent flaws. This paper presents the reasons improvements are necessary and serves to introduce or highlight better methods, while providing a good resource to review past studies. Common laboratory methods and procedures used to evaluate chemical EOR are critically reviewed and discussed for polymer flooding, surfactant-polymer flooding, alkaline-surfactant-polymer flooding, alkaline-co-solvent-polymer flooding specifically but also apply to similar processes. The laboratory methods for evaluating chemical EOR include surfactant phase behavior, coreflooding, chemical adsorption and retention measurements, polymer residual resistance factor measurements, polymer transport, polymer filtration ratio measurements, polymer stability. The best methods and procedures for these and other measurements should take into account how the laboratory measurements will be used for making field-scale performance predictions, the type of oil reservoir, the chemical EOR process and many other factors. Conducting corefloods with a low residence time is an example of a common mistake. New or improved methods are introduced or highlighted to bring best practices to the forefront. New methods that are highlighted include Residence Time Distribution Analysis to determine polymer retention and IPV, polymer transport in cores with two-phases present, and the addition of solvents/pre-shearing for improved polymer transport. The state-of-the-art laboratory methods and procedures discussed herein yield more accurate, more scalable data that are needed for reservoir simulation predictions and field-scale applications of chemical EOR. The recommended best practices will provide a better understanding needed to help select the appropriate chemicals and to determine the optimal chemical mass for field applications of chemical EOR.
- North America > United States > Texas (0.93)
- Asia > Middle East (0.67)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.67)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- (3 more...)
Re-Injection of Produced Polymer in EOR Projects to Improve Economics and Reduce Carbon Footprint
Ghosh, Pinaki (SNF Holding Company) | Wilton, Ryan R (SNF Holding Company) | Bowers, Annalise (SNF Holding Company) | O’Brien, Thomas (SNF Holding Company) | Cao, Yu (SNF Holding Company) | Wilson, Clayton (SNF Holding Company) | Metidji, Mahmoud Ould (SNF SA) | Dupuis, Guillaume (SNF SA) | Ravikiran, Ravi (SNF Holding Company)
Abstract Chemical Enhanced Oil Recovery (cEOR) flooding is one of the more attractive methods to improve oil recovery. However, during times of instability in the oil market, cost of specialized chemicals and necessary facilities for alkali-surfactant-polymer (ASP) or surfactant-polymer (SP) make this technology very expensive and challenging to implement in the field. In majority of cases, polymer flooding alone has proven to be the most cost-effective solution that has resulted in attractive and predictable return on investment. In recent times, challenging economic environment has operators looking for added economic and sustainable savings. The possibility of re-injection of produced polymer to offset injection concentration requirements can lead to reduced cost and longer sustainability of oil recovery; thus, offering a subsequent reduction in produced water treatment and a reduced full-cycle carbon footprint. This innovative approach is subject to conditions experienced in the surface facilities, as well as in the reservoir. As part of this study, different polymer chemistries were investigated for their mobility control in porous media and comparative effect on oil recovery trends in presence of produced fluid containing residual polymer. The initial fluid-fluid testing and lab characterization results were validated against a mature field EOR project for reduction in polymer requirement to achieve target viscosity. Monophasic flow behavior experiments were performed in Bentheimer and Berea outcrop cores, while oil recovery experiments were performed in Bentheimer outcrops with different polymer solutions – freshly made and combinations with residual produced polymer. In addition, comparative injectivity experiments with field and lab prepared solutions were performed in Bentheimer outcrop cores. Based on field observations and lab measurements, a 10-15% reduction in fresh polymer loading could be achieved through the re-utilization of water containing residual polymer in these specific field conditions. Similar screen factor measurements were obtained with increasing concentration of residual polymer solution. This agreed with the monophasic injectivity experiments in both outcrop cores that resulted in similar resistance factors for fresh polymer and blends with produced water containing residual polymer solution. Oil recovery experiments also resulted in similar oil displacement behavior (approximately 30-40% OOIP after 0.5 PV waterflood) for fresh and blends with sheared polymer solutions, validating no loss in recovery potential, with the added benefit of 10-15% polymer loading reduction.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada (0.93)
- Europe (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Geology > Rock Type (0.46)
- Water & Waste Management > Water Management > Lifecycle > Treatment (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 > Lloydminster Field (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > P09C License > Horizon Field > Vlieland Sandstone Formation (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
Characterization of Carboxylate Surfactant Retention in High Temperature, Hard Brine Sandstone Reservoirs
Pinnawala, Gayani (Chevron Energy Technology Company) | Davidson, Andrew (Chevron) | Taylor, Isbell (Chevron Energy Technology Company) | Yang, Hyuntae (Chevron Energy Technology Company) | Slaughter, Will (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Abstract Large hydrophobe Carboxylate surfactants (MW above 1000) are a relatively new class of surfactants developed for surfactant flooding during chemical enhanced oil recovery (EOR) processes. The presence of carboxylate groups and alkoxylate groups in the molecules provides stability and salinity tolerance at high temperature and in high salinity environments. Many high temperature reservoirs have injection and reservoir brine containing high concentrations of divalent ions making them prime targets for using carboxylate surfactants. Much of the earlier literature showed successful carboxylate applications at high pH during alkali-enhanced flooding, as the high pH stabilizes the carboxylate groups. Such processes are not feasible in the presence of hardness at high temperatures. We present an approach where we use an alkali buffer wherein the pH is adjusted from highly basic to near neutral. Under such conditions we demonstrated low retention and high performance in terms of phase behavior and coreflood oil recovery.
- Geology > Mineral (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.89)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
Field Trial for Wettability Alteration Using Surfactants: Formulation Development In Laboratory to the Implementation and Production Monitoring in an Offshore Reservoir
Rohilla, Neeraj (Dow Chemical International Pvt. Ltd.) | Katiyar, Amit (The Dow Chemical Company) | Rozowski, Pete M. (The Dow Chemical Company) | Gentilucci, Adrianno (The Dow Chemical Company) | Patil, Pramod D. (Rock Oil Consulting Group) | Pal, Mayur (North Oil Company) | Saxena, Prabhat (North Oil Company)
Abstract Wettability Alteration (WA) as an Enhanced Oil Recovery (EOR) technique is screened for an oil wet carbonate offshore reservoir in this study. Surfactants can be used to change the rock wettability from oil-wet to water-wet conditions and can lead to unlocking significant incremental oil from oil-wet tight pores. A thorough lab program was designed to develop a wettability altering surfactant formulation and was validated with corefloods and spontaneous imbibition tests at reservoir conditions. Surfactant injection trials at smaller scale were conducted first which were successful. Currently, an ongoing long term surfactant injection pilot is operating to evaluate incremental oil gains. An optimal surfactant formulation is developed on the basis of favorable phase behavior at reservoir conditions, the ability to alter wettability to a more water-wet state and cause minimal chemical losses on reservoir minerals in the form of adsorption. Surfactant formulations designed in this work are unique and provide high temperature stability (above 70 °C and in some cases up to 120 °C) and high salinity tolerance (> 12 % TDS and up to 22% TDS in some low temperature cases). The field implementation was done in a systemetic step wise manner to mitigate the risk in implementing such a technology field wide. The first step was to de-risk the long term injection and see if there is any injectivity impairment due to surfactant injection. The current injection trial showed improvement in injectivity that is indicative of changes in wettability. More importantly, there has been no evidence of any injectivity impairment, which paves the way for long term surfactant injection in the field.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.48)
Experimental Investigation of the Effect of Polymer Viscoelasticity on Residual Saturation of Low Viscosity Oils
Jin, Julia (The University of Texas at Austin) | Qi, Pengpeng (The University of Texas at Austin) | Mohanty, Kishore (The University of Texas at Austin) | Balhoff, Matthew (The University of Texas at Austin)
Abstract We performed coreflood experiments to determine the effect of polymer viscoelasticity on the residual saturation of low viscosity oils by varying the rock type, wettability, polymer rheology, and flow conditions. Several authors have shown that polymers, if viscoelastic, can recover a significant amount of capillary-trapped oil, beyond inelastic floods, in water-wet sandstones. We demonstrate that the polymer viscoelastic effect works for several different rock types, both water-wet and oil-wet media, and with low viscosity oils which broadens the applicability found in previous works. In polymer field studies, the rheology can be tailored to maximize the effect based on our findings. Eleven corefloods were performed in Bentheimer, Boise, and Berea cores. Two of the cores were made oil-wet using dichlorodiphenylsilane (DCDPS) and chlorotrimethylsilane (CTMS). The cores were initially saturated with brine and then displaced by low viscosity (4-10 cp) crude oil until steady state was reached. Brine was then injected to displace the oil until steady state and residual oil saturation was reached. In most experiments, HPAM polymer was then injected at ∼1 ft/day; the polymer rheology was tailored via the salinity, concentration, molecular weight, and degree of hydrolysis. Once steady state was reached, a second polymer solution (with the same viscosity but higher salinity) was injected until a final oil saturation was reached. A reduction in oil saturation was observed in all corefloods in which the polymer was viscoelastic. On average, the oil saturation was reduced by 5.6% in the first polymer flood and 4.0% in the second, high salinity polymer flood. Higher recoveries were found for some experiments in which the first polymer was more elastic (higher dimensionless Deborah number). Final oil saturations as low as 5% were achieved using only polymer (and no surfactant). Results were not dependent on the rock type (e.g. Bentheimer versus Boise) but the effect was more pronounced in water-wet cores than those changed to oil-wet.
- North America > United States > Idaho > Ada County > Boise (0.45)
- North America > United States > Texas (0.29)
Instow a Full Field, Multi-Patterned Alkaline-Surfactant-Polymer Flood – Analyses and Comparison of Phases 1 and 2
Pitts, Malcolm J. (Surtek, Inc.) | Dean, Elio (Surtek, Inc.) | Wyatt, Kon (Surtek, Inc.) | Skeans, Elii (Surtek, Inc.) | Deo, Dalbir (Crescent Point Energy) | Galipeault, Angela (Crescent Point Energy) | Mohagen, Dallas (Crescent Point Energy) | Humphry, Colby (Crescent Point Energy)
Abstract An Alkaline-Surfactant-Polymer (ASP) project in the Instow field, Upper Shaunavon formation in Saskatchewan Canada was planned in three phases. The first two multi -well pattern phases are nearing completion. Beginning in 2007, an ASP solution was injected into Phase 1. Phase 1 polymer drive injection began in 2011 after injection of 35% pore volume (PV) ASP solution. Coincident with the polymer drive injection into Phase 1, Phase 2 ASP solution injection began. Phase 2 polymer drive began in 2016 after injection of 47% PV ASP solution. Polymer drive continues in both phases with Phase 1 and Phase 2 injected volume being 55% PV and 35% PV, respectively. Phase 1 and Phase 2 oil cut response to ASP injection showed an increase of approximately four times from 3.5% to 12 to 16% and an increase in oil rate from approximately 3,200 m/m (20,000 bbl/m) to 8,300 m/m (52,000 bbl/m) in Phase 1 and from 2,200 m/m (14,000 bbl/m) to 7,800 m/m (49,000 bbl/m) in Phase 2. Phase 1 pattern analysis indicates the pore volumes of ASP solution injected varied from 13% to 54% PV of ASP with oil recovery percentage increasing with increasing injected volume. Oil recoveries in the different patterns ranged from 3% OOIP up to 21% OOIP with lower oil recoveries correlating with lower volume of ASP injected. The response from some of the patterns correlates with coreflood results. Wells in common to the two phases show increase oil cut and oil rate responses to chemical injection from both Phases 1 and 2. Oil recovery as of August 2019 is 60% OOIP for Phase 1 and 57% OOIP for Phase 2. Phase 1 economic analysis indicated chemical and operation cost would be approximately C$26/bbl resulting in the decision to move forward with Phase 2.
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (0.93)
- Geology > Rock Type > Sedimentary Rock (0.46)
- North America > Canada > Saskatchewan > Williston Basin > Shaunavon Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Instow Field > Shaunavon Formation (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (8 more...)
Bhagyam ASP Pilot: Successful Formulation Development to Pilot Design and Planning
Jain, Shakti (Cairn Oil & Gas, Vedanta Limited) | Prasad, Dhruva (Cairn Oil & Gas, Vedanta Limited) | Pandey, Amitabh (Cairn Oil & Gas, Vedanta Limited) | Koduru, Nitish (Cairn Oil & Gas, Vedanta Limited) | Raj, Rahul (Cairn Oil & Gas, Vedanta Limited)
Abstract The paper discusses the alkaline surfactant polymer (ASP) flood pilot design including formulation development, pilot area selection, well and pattern type, slug size and sequence, slug viscosity etc for the Bhagyam field. It also discusses the various lab, well and reservoir surveillance techniques planned for the baseline, ASP flood monitoring, residual oil saturation and incremental recovery estimates from the pilot. The Bhagyam is an onshore field in the Rajasthan state of western India and is part of Mangala-Bhagya m- Aishwariya (MBA) development in the Barmer basin. The main producing unit is Fatehgarh multi -storied fluvial sand stone. Reservoir quality is excellent with permeability in the range of 1 to 10 Darcy and porosity in the range of 25-30%. The crude oil is moderately viscous (15 to 500 cP) and highly active with TAN (total acid number) value of ~2 mgKOH/gm. All the reservoir and fluid properties together with low salinity (5000 ppm) and moderate temperature (54 degC) makes it an ideal candidate for polymer and ASP EOR methods. The field has been developed with downdip water injection and post successful evaluation of long term polymer injectivity test, it is currently under full-field polymer flood implementation. The details of polymer flood injectivity and full-field expansion plans are discussed by Sharma et. al. 2016 and Shankar et. al. 2018. EOR assessment has been part of the field development planning process from start. Multiple phase behaviour studies and corefloods have been conducted to screen the surfactant and generate necessary parameters for the simulation studies. The formulation consists of combination of sulfate and sulfonate based surfactants. The focus of the pilot area selection has been to utilize the existing well s to maximum possible extent, reduce the geological uncertainty and minimize the interference from ongoing activity in the field. A normal 4 spot pilot with ~150m spacing has been selected together with two observation well for time lapse saturation monitoring and one coring well towards end of pilot for saturation determination. Dynamic models have been used to design slug size, sequence, viscosity and estimate incremental oil potential. Multiple tracer surveys together with distributed pressure measurements and interference tests are planned to establish connectivity and calibrate model. Initial estimates of pilot incremental oil recovery is in the range of 15-25% of stock tank oil intial in-place (STOIIP) over the polymer flood. Overall pilot design aims at collecting all the necessary data for reducing uncertainty for full-field expansion in a short time frame.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- 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 > Rajasthan Block > Bhagyam Field (0.99)
- (4 more...)