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Results
Transforming Challenges into Opportunities: First High Salinity Polymer Injection Deployment in a Sour Sandstone Heavy Oil Reservoir
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Alrukaibi, Deema (Kuwait Oil Company) | Kamal, Dawood Sulaiman (Kuwait Oil Company) | Al-Rabah, Abdullah Abdul-Karim (Kuwait Oil Company) | Hassan, Abrahim Abdelgadir (Kuwait Oil Company) | Qureshi, Faisal (Kuwait Oil Company) | Delshad, Mojdeh (Ultimate EOR Services) | Driver, Jonathan (Ultimate EOR Services) | Li, Zhitao (Ultimate EOR Services) | Badham, Scott (Chemical Tracers Inc.) | Bouma, Chris (Chemical Tracers Inc.) | Zijlstra, Ellen (Shell)
Abstract This paper describes the design and implementation of a one-spot enhanced oil recovery (EOR) pilot using high-salinity water (∼166,000 ppm TDS) in a sour, sandstone, heavy-oil reservoir (∼5 mol% hydrogen sulfide) based on an extensive laboratory study involving different polymers and operating conditions. In view of the results of this one-spot EOR pilot, a multi-well, high-salinity polymer-injection pilot is expected to start in 2020 targeting the Umm Niqqa Lower Fars (UNLF) reservoir in Kuwait. Polymer flooding is normally carried out using low- to moderate-salinity water to maintain favorable polymer solution viscosities in pursuit of maximum oil recovery. Nevertheless, low- to moderate-salinity water sources such as seawater tend to be associated with a variety of logistical, operational, and commercial challenges. For this study, laboratory experiments were conducted in conjunction with reservoir simulation to confirm the technical viability of polymer flooding using high-salinity water. Thereafter, a one-spot EOR pilot was executed in the field using a well near the location of the planned multi-well pilot to confirm the performance of the selected polymer vis-à-vis injectivity and oil desaturation. The one-spot EOR pilot described in this paper was successfully executed by performing two Single-Well Chemical Tracer (SWCT) tests. For the first stage of the pilot, 200 bbl of produced water (up to 166,000 ppm TDS) were injected into the test well in an attempt to displace mobile oil out of the investigated pore space. Following this produced water injection, an SWCT test (Test #1) was carried out and measured the remaining oil saturation to be 0.41 ± 0.03. This saturation measurement represents the fraction of oil remaining in the pore space of a cylindrical portion of the Lower Fars reservoir, measured from the wellbore out to a radius of 3.02 feet, after produced water injection. After the completion of Test #1 and subsequent recovery of the injected produced water, the same zone was treated with a 200-bbl injection of polymer solution. Following this 200-bbl polymer injection, a second SWCT test (Test #2) was performed and measured the remaining oil saturation to be 0.19 ± 0.03 out to a radius of 3.38 feet. These results indicate that polymer injection may offer considerable improvement to oil recovery over conventional waterflooding alone. Performing polymer flooding in a sour, heavy-oil reservoir using high-salinity water is a challenging and unprecedented undertaking worldwide. In addition to the improved incremental oil recovery demonstrated by this pilot, enabling the use high-salinity produced water for polymer flooding is expected to result in significant benefits for cost-efficiency and operational ease by reducing or eliminating problems commonly associated with the sourcing, treatment, and handling of less saline water in the field.
- Asia > Middle East > Kuwait (0.35)
- North America > United States > Texas (0.28)
- North America > United States > Oklahoma (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.71)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- 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)
Scleroglucan Polymer Injectivity Test Results in the Adena Oilfield
Muhammed, Farag (Cargill, Inc) | Dean, Elio (Surtek, Inc.) | Pitts, Malcolm (Surtek, Inc.) | Wyatt, Kon (Surtek, Inc.) | Kozlowicz, Briana (Cargill, Inc) | Khambete, Malhar (Cargill, Inc) | Jensen, Tryg (Cargill, Inc) | Sumner, Eric (Cargill, Inc) | Ray, Charles (Cargill, Inc)
Abstract Reservoirs with harsh environments are now being routinely evaluated for applications of chemical EOR. High temperatures and high salinity water are proving to be hurdles chemical manufacturers must overcome. Scleroglucan is a biopolymer with robust viscosifying power, excellent stability under high temperature, high salinity, and resistance to shear. An injectivity test was conducted in the high temperature (180 °F) Adena oilfield to evaluate the injectivity of scleroglucan polymer. Field injectivity test results are compared to those from the laboratory. Polymer parameters evaluated include polymer viscosity, polymer shear, resistance factor, and residual resistance factor. The unique feature of this injectivity test is the bottom-hole pressure data that allowed for direct field measurement of resistance factor and the evaluation of multiple fall off tests. Pressure transient analysis (PTA) allowed for (1) skin to be measured before and after polymer injection to evaluate sand face plugging, and (2) permeability measurements that were used for direct field measurement of residual resistance factor. Conclusions from the injectivity test in the Adena field are: Scleroglucan was successfully injected into a harsh reservoir environment. PTA data provided a field based direct measurement of resistance factor (RF) and residual resistance factor (RRF). PTA fall off test indicated no sand face plugging, in that a constant skin was observed at the well before and after the polymer injectivity test. RRF was measured at the sand face via FBHP and several feet into the reservoir via PTA. Sandface RRF was 1.3, indicating a 25% reduction in permeability, while PTA based permeability (larger radius of investigation) was reduced by 50%, the equivalent of a RRF of 2. Skin for the two fall off tests, before and after polymer injection, show the polymer did not plug nor exacerbate the pre-existing formation damage. The first field injection of EOR–grade scleroglucan was successful. The use of BHP data and fall off testing allowed for field-based values of resistance factor and residual resistance factor to be measured. Typically, these parameters are laboratory derived values and uncertainty exists when scaling up the process. The use of pressure transient analysis in polymer injectivity tests offers an economical option for field evaluation of polymer based EOR technologies.
- North America > United States > Colorado > Adena Field (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Colorado Field (0.97)
- 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 > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (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...)
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)
A Successful Polymer Flood Pilot at Palogrande-Cebu, A Low Permeability Reservoir in the Upper Magdalena Valley, Colombia
Leon, J. M. (Ecopetrol SA) | Castillo, A. F. (Ecopetrol SA) | Perez, R.. (Ecopetrol SA) | Jimenez, J. A. (Ecopetrol SA) | Izadi, M.. (Ecopetrol SA) | Mendez, A.. (Ecopetrol SA) | Castillo, O. P. (Ecopetrol SA) | Londoño, F. W. (Ecopetrol SA) | Zapata, J. F. (Ecopetrol SA) | Chaparro, C. H. (Ecopetrol SA)
Abstract Palogrande-Cebu is a mature clastic field located in the south of Colombia and part of the production train of the Monserrate Formation that has several fields and presents an OOIP about 1000 MMBBLs. In these fields Ecopetrol have been tested different chemical EOR/IOR technologies like polymer flooding, CDG and conformance treatments with encouraging results. Palogrande field has been in production since 1971, and under peripheral water injection since 1984, with a recovery factor of 28%. The reservoir has a permeability between 6 and 150 mD, and a crude with an in-situ viscosity of 9.4 cP at reservoir conditions. As part of a portfolio screening within Ecopetrol, chemical EOR was considered the most viable option for the field. This lead to a polymer flood pilot in Palogrande-Cebu in two patterns from May 2015 to June 2017. The present paper presents the results of the pilot, which includes the assessment of two different sources of water to prepare the polymeric solution, fresh water and produced water. Likewise, three different polymers were used to assess the impact on injectivity of the molecular weight considering the low permeability of the reservoir. Moreover, the paper presents the data from a comprehensive surveillance and monitoring program, which includes a polymer backflow test to assess the polymer viscosity in the reservoir. As of June 2017 the accumulated polymer injection was 2.07 million barrels distributed between both injectors, and a projected incremental recovery factor of 8% in the most mature pattern, and 2% in the less mature pattern, with water cut reductions up to 14% in some wells. Based on the success of the pilot, the feasibility of expanding the polymer flood is currently being considered to further develop the field.
- Geology > Geological Subdiscipline (0.46)
- Geology > Rock Type (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.50)
- South America > Colombia > Tolima Department > Magdalena Upper Valley Basin (0.99)
- South America > Colombia > Santander Department > Middle Magdalena Basin > Yariguí-Cantagallo Field (0.99)
- South America > Colombia > Bolivar Department > Middle Magdalena Basin > Yariguí-Cantagallo Field (0.99)
- South America > Argentina > Tierra del Fuego > Magallanes Basin > South-central > Zapata Formation (0.93)
Low Salinity Flooding Trial at West Salym Field
Erke, S. I. (Salym Petroleum Development) | Volokitin, Y. E. (Salym Petroleum Development) | Edelman, I. Y. (Salym Petroleum Development) | Karpan, V. M. (Salym Petroleum Development) | Nasralla, R. A. (Shell Global Solutions International) | Bondar, M. Y. (Salym Petroleum Development) | Mikhaylenko, E. E. (Salym Petroleum Development) | Evseeva, M.. (Salym Petroleum Development)
Abstract Low-salinity waterflooding (LSF) has been recognized as an IOR/EOR technique for both green and brown fields in which the salinity of the injected water is lowered for particular reservoir properties to improve oil recovery. While providing lower or similar UTC's low salinity projects have the advantage of lower capital and operational costs as compared to some more expensive EOR alternatives. This work describes LSF experiments, field-scale simulation results, and conceptual design of surface facilities for West Salym oil field. The field is located in West Siberia and is on stream since 2004. Conventional waterflooding was started in 2005 and current water cut is currently above 80% in the developed area of the field. To counter oil production decline a tertiary Alkaline-Surfactant-Polymer (ASP) flooding technique selected for mature waterflooded field parts and piloting of this technique is ongoing. Operationally simpler and more cost-effective LSF method is considered for implementation in the unflushed (green) areas of the field since it has been recognized that application of LSF in secondary mode results in better incremental oil recovery than LSF in tertiary mode. The results of a comprehensive conceptual study performed to justify the LSF trial are presented in this paper. To generate production forecast for LSF in the isolated area at the outset of reservoir development the results of laboratory core tests executed at different salinities presented earlier (Suijkerbuijk et al., 2014) have been used. Dynamic reservoir modelling using low-salinity relative permeability curves showed that injection of low-salinity water leads to incremental oil production up to 2.5% of STOIIP. These results establish the fundamentals for a LSF field trial. A concept of surface facilities design for LSF trial area at West Salym oil field is also presented in the paper. Differently to other LSF projects it is proposed to prepare low-salinity water with required properties by mixing fresh water from aquifer and high salinity water from produced water reinjection (PWRI) system. In such a case LSF facilities concept does not require expensive water treatment techniques which significantly reduces the project capital and operational costs.
- Europe > Russia > Volga Federal District > Tatarstan > Volga Urals Basin > Pervomaiskoye Field (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Salymskoye Field > Zapadno Salymskoye Field (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Salym Field > Verkhne Salymskoye Field > Vadelypskoye Field > Zapadno Salymskoyeskoye Field (0.99)
- (5 more...)
Nanoparticle Stabilized CO2 Foam: Effect of Different Ions
San, Jingshan (New Mexico Institute of Mining and Technology) | Wang, Sai (New Mexico Institute of Mining and Technology) | Yu, Jianjia (New Mexico Institute of Mining and Technology) | Lee, Robert (New Mexico Institute of Mining and Technology) | Liu, Ning (New Mexico Institute of Mining and Technology)
Abstract This paper reports the study of the effect of different ions (monovalent, bivalent, and multiple ions) on nanosilica-stabilized CO2 foam generation. CO2 foam was generated by co-injecting CO2/5,000 ppm nanosilica dispersion (dispersed in different concentrations of brine) into a sandstone core under 1,500 psi and room temperature. A sapphire observation cell was used to determine the foam texture and foam stability. Pressure drop across the core was measured to estimate the foam mobility. The results indicated that more CO2 foam was generated as the NaCl concentration increased from 1.0% to 10%. Also the foam texture became denser and foam stability improved with the NaCl concentration increase. The CO2 foam mobility decreased from 13.1 md/cp to 2.6 md/cp when the NaCl concentration increased from 1% to 10%. For the bivalent ions, the generated CO2 foam mobility decreased from 19.7 md/cp to 4.8 md/cp when CaCl2 concentration increased from 0.1% to 1.0%. Synthetic produced water with total dissolved solids of 17,835 ppm was prepared to investigate the effect of multiple ions on foam generation. The results showed that dense, stable CO2 foam was generated as the synthetic produced water and nanosilica dispersion/CO2 flowed through a porous medium. The lifetime of the foam was observed to be more than two days as the foam stood at room temperature. Mobility of the foam was calculated as 5.2 md/cp.
- 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)
- (21 more...)
Abstract Fracturing fluids are commonly formulated with fresh water to ensure reliable rheology. However, fresh water is becoming more costly, and in some areas, it is difficult to obtain. Therefore, using produced water in hydraulic fracturing has received increased attention in the last few years. A major challenge, however, is its high total dissolved solids (TDS) content, which could cause formation damage and negatively affect fracturing fluid rheology. The objective of this study is to investigate the feasibility of using produced water to formulate crosslinked-gel-based fracturing fluid. This paper focuses on the compatibility of water with the fracturing fluid system and the effect of salts on the fluid rheology. Produced water samples were analyzed to determine different ion concentrations. Solutions of synthetic water with different amounts of salts were prepared. The fracturing fluid system consisted of natural guar polymer, borate-based crosslinker, biocide, surfactant, clay controller, scale inhibitor, and pH buffer. Compatibility tests of the fluid system were conducted at different cation concentrations. Apparent viscosity of the fracturing fluid was measured using a high-pressure high-temperature rotational rheometer. All rheology tests were conducted at a temperature of 180°F and were conducted according to API 13m procedure with a three-hour test duration. Fluid breaking test was also performed to ensure high fracture and proppant pack conductivity. Produced water analysis showed a TDS content of 125,000 ppm, including Na, Ca, K, and Mg ion concentrations of 36,000, 10,500, 1,700, and 700 ppm, respectively. Results indicated the potential of produced water to cause formation damage. Therefore, produced water was diluted with fresh water and directly used to formulate the fracturing fluid. Divalent cations were found to be the main source of precipitation, and the reduced amounts of each ion were determined to prevent precipitation. The separate and combined effects of Na, K, Ca, and Mg ions on the viscosity of the fracturing fluid were also studied. Fluid viscosity was found to be significantly affected by the concentrations of divalent cations regardless of the concentrations of monovalent cations. Monovalent cations reduced the viscosity of fracturing fluid only in the absence of divalent cations, and showed no effect in the presence of Ca and Mg ions. Water with reduced concentrations of monovalent and divalent cations showed the most suitable environment for polymer hydration and crosslinking. This paper contributes to the understanding of the main factors that enable the use of produced water for hydraulic fracturing operations. Maximizing the use of produced water could reduce its disposal costs, mitigate environmental impacts, and solve fresh water acquisition challenges.
- Europe (1.00)
- North America > United States > Texas (0.47)
- North America > United States > Oklahoma (0.29)
- North America > United States > Louisiana (0.29)
- 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)