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Collaborating Authors
Results
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)
Novel Application of Polyethylene Oxide Polymer for EOR from Oil-Wet Carbonates
Trine, Eric Brandon (Ultimate EOR Services, LLC) | Pope, Gary Arnold (Ultimate EOR Services, LLC) | Britton, Chris James (Ultimate EOR Services, LLC) | Dean, Robert Matthew (Ultimate EOR Services, LLC) | Driver, Jonathan William (Ultimate EOR Services, LLC)
Abstract The objective of this study was to test the performance of high-molecular weight polyethylene oxide (PEO) polymer in a low-permeability, oil-wet carbonate reservoir rock. Conventional HPAM polymers of similar molecular weight did not exhibit acceptable transport in the same rock, so PEO was explored as an alternative polymer. Viscosity, pressure drop across each section of the core, oil recovery, and polymer retention were measured. The PEO polymer showed good transport in the 23 mD reservoir carbonate core and reduced the residual saturation from 0.29 to 0.17. The reduction of residual oil saturation after polymer flooding using PEO was unexpected and potentially significant.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.88)
Abstract Chemical Enhanced Oil Recovery (EOR) methods have been implemented in a West Texas fractured carbonate. Due to the partially oil-wet nature of Yates field and slightly viscous oil (5-7 cP), surfactant injection was implemented to alter wettability and polymer was injected in the waterflood area to improve displacement efficiency, respectively. Single well huff-n-puff (HnP) surfactant treatments (late 1980's-today) and well-to-well pilots (1990's-2000's) have increased incremental oil production relative to base decline. Optimum surfactant chemicals were chosen based on laboratory results, reservoir performance, and economic viability. Polymer injection was carried out over a 6 year span (1983-1989) in which 55+ million pounds of polymer was injected; however the interpretation and analysis was complicated due to concurrent drilling, workover activities, and no prior waterflood development. Design parameters key to the surfactant implementation included: surfactant type and concentration, Critical Micelle Concentration (CMC), fluid saturations, oil composition, formation water salinity, fracture intensity, and treatment soak timing. Laboratory experiments included interfacial tension, contact angle, adsorption, fluid phase stability, Amott tests, and coreflooding. Numerical models were developed to help understand the sensitivity of each parameter on EOR performance and guide the design of treatments. Field implementation of surfactant included different surfactant types: anionic, non-ionic, and cationic. HnP treatments were followed by a soak period before returning the well to production and conducting flow back water analysis. Overall, HnP treatments using cationic surfactant resulted in the highest efficiency in terms of barrels of oil per kilogram of surfactant. Well-to-well tests were only conducted with non-ionic surfactants and showed mixed results. Design parameters for polymer injection such as fluid viscosity, concentration, adsorption and molecular weight were determined through coreflooding and fluid viscosity experiments. Two polymer types, high and low molecular weight, were studied and manufactured in-field and used in 200 or more injectors either continuously or alternating with produced water. Polymer injection was not effective in improving displacement efficiency in the water flood area of Yates reservoir and was suspended in 1989. The scale of field implementation and analysis of the impact of chemical injection on oil production in a massive, densely fractured carbonate field has provided valuable insight and learnings for future development and will be discussed. Other chemical EOR methods currently under investigation such as foam and other wettability altering technologies will also be discussed.
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.46)
- 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)
- (31 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (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)
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...)
Use of Dynamic Pore Network Modeling to Improve Our Understanding of Experimental Observations in Viscous Oil Displacement by Polymers
Salmo, Iselin Cecilie (University of Bergen) | Zamani, Nematollah (Norce) | Skauge, Tormod (Energy research Norway) | Sorbie, Ken (Energy research Norway, Heriot Watt University) | Skauge, Arne (Energy research Norway, University of Bergen, Norce)
Abstract Any aqueous solution viscosified by a polymer (or glycerol) should improve the recovery of a very viscous oil to some degree, but it has long been thought that the detailed rheology of the solution would not play a major role. However, recent heavy oil displacement experiments have shown that there are clear differences in incremental oil recovery between aqueous polymeric or Newtonian solutions viscosified to the same effective viscosity. For example, synthetic polymers (such as HPAM) recover more oil than biopolymers (such as xanthan) at the same effective viscosity. In this paper, we use dynamic pore scale network modeling to model and explain these experimental results. A previously published dynamic pore scale network model (DPNM) which can model imbibition, has been extended to include polymer displacements, where the polymer may have any desired rheological properties. Using this model, we compare viscous oil displacement by water (Newtonian) with polymer injection where the "polymer" may be Newtonian (e.g. glycerol solution), or purely shear-thinning (e.g. xanthan) or it may show combined shear thinning and thickening behaviour (e.g. HPAM). In the original experiments, the polymer concentrations were adjusted such that the in situ viscosities of each solution were comparable at the expected in situ average shear rates (see Vik et al, 2018). The rheological properties of the injected "polymer" solutions in the dynamic pore network model (DPNM), were also chosen such that they had the same effective viscosity at a given injection rate, in single phase aqueous flow in the network model. Secondary mode injections of HPAM, xanthan and glycerol (Newtonian) showed significant differences in recovery efficiency and displacement, both experimentally and numerically. All polymers increased the oil production compared to water injection. However, the more complex shear thinning/thickening polymer (HPAM) recovered most oil, while the shear-thinning xanthan produced the lowest oil recovery, and the recovery by glycerol (Newtonian) was in the middle. In accordance with experimental results, at adverse mobility ratio, the DPNM results also showed that the combined shear- thinning/thickening (HPAM) polymer improves oil recovery the most, and the shear-thinning polymer (xanthan) shows the least incremental oil recovery with the Newtonian polymer (glycerol) recovery being in the middle; i.e. excellent qualitative agreement with the experimental observations was found. The DPNM simulations for the shear-thinning/thickening polymer show that in this case there is better front stability and increased oil mobilization at the pore level, thus leaving less oil behind. Simulations for the shear-thinning polymer show that in faster flowing bonds the average viscosity is greatly reduced and this causes enhanced water fingering compared with the Newtonian polymer (glycerol) case. The DPNM also allows us to explore phenomena such as piston-like displacements, snap-off and film flow, which at the pore level may have impact on the overall efficiency of the various fluid injection schemes. The DPNM models the effect of polymer rheology which changes the balance between the viscous/capillary forces that allows fluid microscopic diversion, and hence improved incremental recovery, to emerge.
- Europe (0.93)
- North America > United States (0.46)
- Asia > China (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.48)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract Pilot testing results and economics from a novel electrochemical desalination technology for enhanced oil recovery (EOR) produced water are presented. The pilot objectives were: (1) economically desalt produced water to improve hydrocarbon recovery and lower polymer consumption costs for chemical flood EOR; (2) inform full scale plant development with a field pilot; and (3) optimize pre-filtration, chemical consumption, and energy use to realize a greater than 20% return on investment through reduced polymer consumption. The paper will present EOR operators with a novel option to reuse produced water as low salinity injection water and recycle polymer to reduce chemical EOR flood operating costs.
- Asia > Middle East (0.93)
- North America > United States > California (0.28)
- Europe > United Kingdom > North Sea > Central North Sea (0.24)
- Water & Waste Management > Water Management (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Abstract This paper describes the interpretation of a successful inter-well field trial of a novel reservoir-triggered polymer technology, making use of pressure transient analysis and numerical simulation. The polymer has been engineered to improve sweep in oil-bearing formations whilst reducing the impact of two of the key operational and economic challenges facing polymer enhanced oil recovery (EOR). The polymer employs a chemical strategy to render it resistant to shear during injection and in the high flux region at the sand face. In addition, the injection solution has a viscosity similar to that of water until triggered in the reservoir, which sustains injectivity. We demonstrate the use of laboratory kinetics, rheology data, high-resolution surveillance of the injector, and comprehensive analysis of produced fluids to constrain the simulation of the in-situ viscosification of this polymer. Numerical models using commercial and in-house R&D codes were calibrated to tracer effluent data, pressure fall-off tests, and injection pressures, to interpret the size and mobility of the polymer bank and its response to water injection. The field trial has qualified the polymer to be considered for deployment. A comprehensive surveillance programme and downhole sampling was used to successfully demonstrate that the polymer was protected from shear degradation upon injection and propagation, and it viscosified under flow at the designed location in the reservoir. Kinetic and rheology data from laboratory testing, combined with reservoir-scale simulations and field trial surveillance, enabled the reaction and adsorption characteristics of the polymer to be estimated. Simulations of the injection pressure demonstrate that this polymer has significantly better injectivity under matrix conditions than would be obtained with a conventional polymer of an equivalent deep-reservoir viscosity.
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Bhagyam Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Bhagyam Field (0.99)
Abstract This paper summarizes BP's Alaskan viscous oil resource appraisal strategy to de-risk viscous oil resource progression with a goal to improve recovery factor by 10%. A key to recovery improvement is application of improved oil recovery/enhanced oil recovery (IOR/EOR) methods. However, even after detailed studies, moving to the next stage including field pilots is not always easy in the mature and remote Alaskan North Slope. The paper also covers BP's Alaskan viscous oil technology strategy, extraction technologies selection, simulation and analytical studies, laboratory studies, and field trials for various shortlisted methods. A comprehensive study strategy conducted for progressing chemical EOR processes is discussed. The paper also addresses the challenges of obtaining new core and fluid samples for laboratory studies and logistical and economic considerations for field trials due to location and weather conditions in this part of the world.
- North America > Canada (0.68)
- Europe > United Kingdom (0.66)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.28)
- Geology > Mineral (0.93)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- North America > United States > Alaska > Schrader Bluff Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Milne Point Field > Kuparuk Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- (8 more...)
Screening for EOR and Estimating Potential Incremental Oil Recovery on the Norwegian Continental Shelf
Smalley, P. C. (Imperial College London) | Muggeridge, A. H. (Imperial College London) | Dalland, M.. (Norwegian Petroleum Directorate) | Helvig, O. S. (Norwegian Petroleum Directorate) | Høgnesen, E. J. (Norwegian Petroleum Directorate) | Hetland, M.. (Norwegian Petroleum Directorate) | Østhus, A.. (Norwegian Petroleum Directorate)
Abstract This paper presents an improved approach for rapid screening of candidate fields for EOR and estimation of the associated incremental oil recovery, and the results of applying it systematically to oil fields on the Norwegian Continental Shelf (NCS), an area that already has a high average recovery factor (47%). Identifying, piloting and implementing new improved recovery methods within a reasonable time is important if substantial remaining oil volumes on the NCS are not to be left behind. The approach uses up-to-date screening criteria, and has more sophisticated routines for calculating screening scores and incremental oil recovery compared to previous published methods. The EOR processes screened for are: hydrocarbon miscible and immiscible WAG, CO2 miscible and immiscible WAG, alkaline, polymer, surfactant, surfactant/polymer, low salinity, low salinity/polymer, thermally activated polymers and conventional near well gel treatments. Overall screening scores are derived from sliding-scale scores for individual screening criteria, weighted for importance, and with the ability to define non-zero scores when non-critical criteria are outside their desired range, so avoiding the problem of processes being ruled out completely even though rock or fluid properties are only marginally outside the threshold of applicability. Incremental recoveries are estimated taking into account the existing recovery processes in the field and are capped by theoretical maximum recovery factors derived from theoretical/laboratory values for displacement and sweep. The methodology calculates the expected increment (and uncertainty range) for each EOR process and the increments for the top three compatible process combinations. The methodology was implemented in a spreadsheet-based tool that allowed multiple fields to be screened and the results compared and evaluated. The new tool was used to estimate the potential EOR opportunity for 53 reservoirs from 27 oil fields on the NCS. The results indicate a mid case EOR technical potential of 592 million standard cubic metres (MSm) with a low- to high case range of 320-860 MSm. The most promising processes are low salinity with polymer, surfactant with polymer, and miscible hydrocarbon and CO2 gas injection. Some field clusters were identified that could provide economies of scale for such processes. The EOR screening study has enabled the Norwegian Petroleum Directorate to advocate EOR-technology studies, including pilots, in specific regions or fields. Such pilots will play an important role in verifying process feasibility and narrowing the uncertainty range for incremental recovery potential.
- Asia > Middle East (0.88)
- Europe > Norway (0.67)
- Europe > United Kingdom > North Sea (0.46)
- North America > United States > Alaska > North Slope Borough (0.46)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Alwyn Area > Block 3/9b > Alwyn Area > Alwyn South Field > Dunbar Field (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Alwyn Area > Block 3/8a > Alwyn Area > Alwyn South Field > Dunbar Field (0.99)
- (13 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract While synthetic polymer floods are being deployed in mild temperature and low salinity fields, many oilfields (harsh conditions) remain inaccessible due to performance limitations, and concentration requirements, which adversely affect project economics. Historically, biopolymers have been considered in such reservoirs, with mixed results. Xanthan was used in the 1980's, while more recently schizophyllan polymer was tested in a pilot study. This study presents scleroglucan polymers as a class of viscosifiers that demonstrate excellent performance in harsh temperature and salinity reservoirs. Scleroglucan polymers do not suffer from catastrophic drop in viscosity in the presence of high concentration of divalent ions. This makes produced water re-injection projects without water treatment a reality. This work demonstrates that cost-effective, high purity EOR grade Scleroglucan polymers, show excellent performance in lab trials as related to excellent rheological properties, injectivity, bio and thermal stability and with minimal shear degradation. Injectivity tests demonstrated good propagation through cores without blockage or injectivity issues. Resistance factors and residual resistance factors are in the desirable range. Core floods carried out in sandstone and carbonate outcrop cores demonstrated that adsorption values and oil recoveries are consistently in the expected range for polymer recoveries. Shear degradation studies showed that recycling scleroglucan through a centrifugal pump causes less than 5% drop in viscosity after 100 passes while synthetic polymer showed substantial loss after a single pass and a 50% drop after 10 passes through the same pump. Capillary shear testing (API RP 63 method) of scleroglucan shows little change in viscosity upon multiple passes through shear regimes greater than 150,000 s. Scleroglucan polymer solution showed less than 25% drop in viscosity after exposure to 115 °C for six months. No change in viscosity was observed at 95 °C after one year. Scleroglucan has no compatibility issues through 6 months (at 37, 85, and 95 °C) with glutaraldehyde and tributyl tetradecyl phosphonium chloride (TTPC) biocides. Long term biostability studies at various temperatures and salinities are ongoing - current data will be presented. Scleroglucan has excellent stability in the presence of hydrogen sulfide (H2S) and ferrous species (Fe) under fully aerobic conditions! This work provides insight on the potential of using EOR grade scleroglucan for CEOR in harsh condition reservoirs. Currently, the program is moving towards pilot implementation of a scleroglucan formulation to demonstrate large scale hydration, long term injectivity and oil recovery.
- Asia (0.68)
- North America > United States > Texas (0.47)
- North America > United States > California (0.46)
- Geology > Geological Subdiscipline (0.46)
- Geology > Rock Type > Sedimentary Rock (0.34)