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Collaborating Authors
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-ร -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 ยฑ 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 ยฑ 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)
- 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)
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 (โผ166,000 ppm TDS) in a sour, sandstone, heavy-oil reservoir (โผ5 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-ร -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 ยฑ 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 ยฑ 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)
A Practical and Economically Feasible Surfactant EOR Strategy: Impact of Injection Water Ions on Surfactant Utilization
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Al-Qattan, Abrar (Kuwait Oil Company) | Kamal, Dawood S. (Kuwait Oil Company) | Winoto, Winoto (Ultimate EOR Services LLC) | Li, Zhitao (Ultimate EOR Services LLC) | Britton, Chris (Ultimate EOR Services LLC) | Delshad, Mojdeh (Ultimate EOR Services LLC)
Abstract A comprehensive chemical enhanced oil recovery (CEOR) laboratory evaluation program was carried out to compare surfactants for alkali-surfactant-polymer (ASP) and surfactant-polymer (SP) implementation in a giant Middle East sandstone oil reservoir. The efficacies of ASP and SP floods were investigated in laboratory corefloods and simulations with emphasis on surfactant retention to improve techno-economic feasibility. ASP and SP flooding processes were designed with low operational cost in mind and tested in laboratory corefloods. Different injection water salinities were considered for practical field application. The handling and availability of injection water with a suitable composition has significant implications in CEOR projects. SP design using produced brine with minimum water treatment is an attractive option for commercial deployment. We considered different injection water salinities, surfactant molecules, and brine treatment requirements for several ASP and SP designs. ASP and SP corefloods recovered nearly all of the remaining oil after waterflooding. The surfactant retention was lower for SP floods when brine with reduced concentration of Ca and Mg (hardness) was used. Both ASP and SP formulations were also tested for crude oil samples from different zones. A minimal adjustment in injection salinity was required for different oils with our surfactant formulations. Surfactants designed for easy manufacturing and supply availability performed well with brine compositions that require minimal treatment. Field implementation strategies were evaluated via numerical simulation. The effect of strong aquifer drive on SP performance was shown to be minimized with optimized injection/production strategies. SP was shown to be technically and economically an attractive candidate tertiary process.
- Geology > Mineral > Silicate (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- (5 more...)
Low-Salinity Polymer Flooding in a High-Temperature Low-Permeability Carbonate Reservoir in West Kuwait
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Kamal, Dawood S. (Kuwait Oil Company) | Al-Sabah, Hessa M. (Kuwait Oil Company) | AbdulSalam, Tareq (Kuwait Oil Company) | Al-Shamali, Adnan (Kuwait Oil Company) | Quttainah, Riyad (Kuwait Oil Company) | Glushko, Dan (Ultimate EOR Services LLC) | Britton, Chris (Ultimate EOR Services LLC) | Delshad, Mojdeh (Ultimate EOR Services LLC) | Liyanage, Jith (Ultimate EOR Services LLC) | Dean, Robert Matthew (Ultimate EOR Services LLC)
While polymer flooding has widely been used as a successful technology to improve mobility control and sweep efficiency in many oil reservoirs, its applicability under harsh temperature/salinity conditions and in low-permeability reservoirs has prohibitively remained a challenge. This study was aimed at investigating the feasibility of low-salinity polymer flooding in a very challenging reservoir located in Kuwait with low permeability ( 10 mD), high temperature (113 C), high salinity ( 239,000 ppm), high hardness ( 20,000 ppm), and carbonate mineralogy. The evaluation was conducted through a series of systematic laboratory studies including polymer rheology, thermal stability, and transportability using coreflood tests. Our results highlight that the common constraints may be overcome by careful selection of polymer/ cosolvent/pre-shearing and appropriate design of low-salinity polymer flooding.
- North America > United States (1.00)
- Asia > Middle East > Kuwait (1.00)
- Asia > Middle East > Oman > Dhofar Governorate > South Oman Salt Basin > Marmul Field > Al-Qalata Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- (6 more...)
Development of an Integrated Approach to Improve Heavy Oil Recovery From a Low-Permeability Carbonate Reservoir
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Kamal, Dawood S. (Kuwait Oil Company) | Al-Tameemi, Naser (Kuwait Oil Company) | Li, Zhitao (Ultimate EOR Services LLC) | Delshad, Mojdeh (Ultimate EOR Services LLC)
Abstract Umm Gudair/Abduliyah Tayarat reservoir is a challenging EOR target because of its high oil viscosity, low permeability, and carbonate mineralogy. A previous feasibility study indicated that a hybrid EOR thermal and chemical method combined with IOR techniques could produce significant amount of oil from this reservoir. The objective of this study was to identify the most viable reservoir-specific EOR/IOR approach taking into account techno-economic considerations. With the latest well logging data, production history, and petrophysical measurements, the Tayarat reservoir simulation model was revisited. Consequently, this simulation model was updated and calibrated to reflect field and lab observations. In addition, lab tests that demonstrated good transport and oil recovery performances of a selected polymer in low permeability reservoir cores were modeled to provide parameters for field-scale scoping simulations. Sensitivity studies were conducted to evaluate the effects of injection temperature, viscous fingering, well configuration, etc. A simple economic analysis was conducted to demonstrate the economic benefits of the proposed hybrid EOR/IOR method. Calibrated by history matching the actual production data, the Tayarat reservoir model included a barrier zone that would prevent influx from a bottom aquifer. A better match was obtained by assuming that the reservoir is strongly water wet, which is consistent with the latest laboratory imbibition and contact angle measurements. Reservoir transmissibility was increased to represent possible fractures/microfractures in the carbonate reservoir. Scoping simulations based on a selected sweet spot of the Tayarat reservoir showed that primary recovery was ineffective due to the lack of a bottom aquifer, and waterflood recovered significantly more oil. A hybrid thermal/chemical EOR process was more effective when a preflush of hot water was considered to heat up a portion of the reservoir ahead of chemical injection. When viscous fingering was neglected, oil recovery could be erroneously as high as 50% more compared to the case when viscous fingering was modeled. Simulation results showed that about 19% of OOIP could be recovered using the hot waterflood followed by hot polymer flood, i.e. about 130% higher than conventional waterflood corresponding to a water cut of 95%. The chemical cost for incremental oil produced with our most promising approach was $10/bbl of incremental oil. This integrated laboratory and simulation study should provide meaningful insights into tackling challenging low permeability and/or heavy oil carbonate reservoir using novel chemical EOR techniques.
- Asia > Middle East > Kuwait (0.47)
- North America > United States > Texas (0.46)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Tayarat Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Abduliyah Field > Sargelu Formation (0.94)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Abduliyah Field > Najmah Formation (0.94)
- (7 more...)
A Feasibility Study of Hybrid Thermal and Chemical EOR Methods in a Low-Permeability Carbonate Heavy Oil Reservoir with Strong Aquifer Drive
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Fadli, Eman Hadad (Kuwait Oil Company) | Al-Shati, Fawziya Mohammad (Kuwait Oil Company) | Qubian, Ali (Kuwait Oil Company) | Li, Zhitao (Ultimate EOR Services LLC) | Trine, Eric (Ultimate EOR Services LLC) | Alizadeh, Amir H. (Ultimate EOR Services LLC) | Delshad, Mojdeh (Ultimate EOR Services LLC)
Abstract KOC's Umm Gudair/Abduliyah Tayarat reservoir has large oil reserves but is a challenging target due to low formation permeability and high oil viscosity. This study is focused on feasibility assessment of hybrid thermal and chemical methods incorporating both laboratory and simulation results. A recent updated static geological model for West Kuwait fields was used as the basis to generate a full-field dynamic reservoir model with representative reservoir geometry, heterogeneity, and complexity. Carter-Tracy aquifers were added to model lateral and bottom aquifers. Laboratory data were incorporated to model physiochemical properties. Gridblocks were globally refined to gain better resolution for heavy oil and EOR simulations. The full-field reservoir model was used to systematically study the potentials of hybrid thermal and chemical EOR methods in comparison with conventional waterflood and chemical EOR methods. Our studies show that in order to produce oil at an economic rate, long horizontal wells on the order of kilometers or horizontal wells stimulated by acidizing, multistage fracturing, or multiple laterals should be deployed. Vertical wells yield low oil production rates due to limited contact areas and severe water coning. Aquifer water intrusion from the west side of reservoir overshadows the bottom aquifer and the edge east side aquifer due to the heterogeneity of reservoir permeability. A sector model was extracted from the full-field Eclipse model and further refined to avoid grid effects in simulation of EOR processes. Simulation results show that hybrid thermal and chemical methods (hot polymer/Surfactant-Polymer/Alkaline-Surfactant-Polymer flood) can effectively increase oil recovery from high-permeability, high-saturation sweet spots of the Tayarat reservoir. With the help of horizontal wells, hot polymer flood shows the best performance after 20 years of oil production and yields more than 30% of incremental oil recovery. Hot Surfactant-Polymer flood shows slightly lower cumulative oil recovery but sustained oil production rates and less production decline in the late stage of the flood. Phase 2 coreflood experiments confirmed that hot polymer flood can effectively enhance oil recovery. In summary, this research study identified sweet spots for oil recovery and EOR applications in the challenging Tayarat reservoir and demonstrated the potential of producing significant amount of oil with appropriate IOR (e.g., extended reach horizontal wells, multistage fractures, stimulation, etc.) and EOR (e.g., hybrid thermal and chemical methods) techniques.
- Asia > Middle East > Kuwait (0.67)
- North America > United States > Texas (0.46)
- Oceania > Australia > Western Australia > Ashmore Cartier Territory > Timor Sea (0.24)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.66)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Tayarat Formation (0.99)
- Asia > Middle East > Iraq > Basra Governorate > Arabian Basin > Widyan Basin > Mesopotamian Basin > Hartha Formation (0.94)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Abduliyah Field > Sargelu Formation (0.92)
- (8 more...)
Geochemical Modeling to Evaluate the Performance of Polymer Flooding in a Highly Sour Sandstone Heavy Oil Reservoir
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Kamal, Dawood Sulaiman (Kuwait Oil Company) | Garcia, Jose Gregorio (Kuwait Oil Company) | Delshad, Mojdeh (UEORS) | Britton, Christopher (UEORS) | Fortenberry, Robert (UEORS)
Abstract The Umm Niqa Lower Fars (Heavy Oil Field) oil reservoir has very favorable properties of high permeability, low temperature, and moderate oil viscosity for polymer flooding and work is progressing towards implementing a polymer pilot in this target reservoir. Nonetheless, Heavy Oil Field contains high salinity water, it is shallow with concerns about injectivity limitations, and high concentrations of H2S (up to 5 mol% in reservoir fluids) which may adversely impact the effectiveness of the injected polymer solutions. A comprehensive laboratory and numerical modeling was initiated to address some of these issues. One potential concern is the degradation of polymer in the co-presence of H2S and possible oxygen introduced with polymer solution injection. This study is aimed at evaluating the impact of H2S on polymer performance in the Heavy Oil Field reservoir via geochemical simulations based on laboratory data. Previously performed polymer rheology and transport experiments were history matched and model parameters were developed for subsequent simulations. Transport behavior of both HPAM type and biopolymers was modeled incorporating two new features of viscous fingering and filtration models. This was then followed by a geochemical simulation study to assess and potentially de-risk the presence of H2S near the wellbore assuming that all oxygen in the injection water (if any) is rapidly consumed by reservoir rock minerals and oil. The parameters developed for the rheology of the polymers were very robust and represented the effects of salinity and polymer shear thinning over a wide range of polymer concentrations for each polymer. These parameters were then used to conduct simulation studies on waterflooding and polymer flooding in the presence of near wellbore H2S. Sensitivity simulations to relative permeability/wettability, oil viscosity, polymer concentration were also conducted to identify the impact on injectivity of polymer solution. The use of the newly added viscous fingering and filtration models was necessary in some cases to correctly model the transport behavior of unstable displacements. Geochemical evaluation showed that injecting H2S-free water over a period of ~3 months can significantly reduce H2S concentration in the near-wellbore region (~30 ft) due to stripping from the oil phase. This is advantageous for the injected polymer because even if small oxygen concentration is co-injected with the water, there would be no H2S present to cause polymer degradation. This study presents a practical approach to de-risk the deployment of polymer flooding in a highly sour shallow sandstone heavy oil reservoir. The findings of this study will be evaluated in a one-spot EOR pilot soon.
- North America > United States > Texas (0.46)
- Asia > Middle East > Kuwait (0.29)
- North America > United States > Oklahoma (0.28)
- North America > United States > Colorado (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.61)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Effects of CEOR Chemicals on Asphaltene Precipitation
Curren, Morgan (Clariant Oil Services) | Kaiser, Anton (Clariant Oil Services) | Adkins, Stephanie (Ultimate EOR Services LLC) | Qubian, Ali (Kuwait Oil Company) | Al-Enezi, Huda (Kuwait Oil Company) | Sana, Heba (Kuwait Oil Company) | Al-Murayri, Mohammed (Kuwait Oil Company) | Delshad, Mojdeh (Ultimate EOR Services LLC)
Abstract Enhanced oil recovery methods are appealing to increase oil recovery from reservoirs due to market pressures in times of lower oil price. Chemical enhanced oil recovery (cEOR) methods such as ASP involve the use of alkali, surfactant, and polymer, to create an ultralow interfacial tension (IFT) between microemulsion and oil phases. These chemicals have the potential to interact with asphaltenes in crude oil and may cause either a decrease or an increase in asphaltene deposition. This paper presents an investigation into the effects of ASP chemicals on asphaltene precipitation. Crude oil, from a cEOR-nominated Kuwaiti reservoir, was analyzed with an ASP formulation that was determined through microemulsion phase behavior experiments. Crude oil, chemical components, and incompatible solvent were added together, and light transmission was measured over a 15-minute period to determine asphaltene precipitation over time. A blank graph of the crude in incompatible solvent showed a light transmission increase of 36.2% over the test duration indicating asphaltene precipitation. If asphaltenes remain suspended in oil, light transmission remains low and stable from the beginning to the end of the test. Addition of asphaltene inhibitor (AI) to the crude oil prevented asphaltene flocculation which was evidenced by a maximum light transmission of 3.0%, an efficiency of 91.7% dispersability relative to the blank sample. With addition of the ASP formulation, light transmission increased which indicates interaction between (1) chemical species of the ASP formulation with asphaltenes or (2) the alkali in the chemical package altering the pH and causing more asphaltene precipitation from suspension in the crude. Maximum light transmission of oil dosed with the chemical additives is 41.3% which is a decrease in asphaltene inhibition efficiency of 14.1% relative to the blank. With the addition of AI to the crude containing the chemical additives, the maximum light transmission is 6.5% indicating an efficiency of 82% asphaltene dispersability. Results indicate a clear relationship between addition of ASP chemicals and asphaltene precipitation. Conditions will differ for other crude oils and cEOR formulations, but asphaltene scaling issues should be considered for cEOR projects.
- Asia (0.70)
- North America > United States > Texas (0.28)
- North America > United States > Oklahoma (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.73)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Mission Canyon Formation (0.98)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Madison Formation (0.98)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Forbisher Formation (0.98)
- North America > Canada > Saskatchewan > Williston Basin > Weyburn Field > Charles Formation:Middale Formation (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Low Salinity Waterflood and Low Salinity Polymer Injection in the Wara Reservoir of the Greater Burgan Field
Al-Qattan, Abrar (Kuwait Oil Company) | Sanaseeri, Abbas (Kuwait Oil Company) | Al-Saleh, Zainab (Kuwait Oil Company) | Singh, B.B.. B. (Kuwait Oil Company) | Al-Kaaoud, Hassan (Kuwait Oil Company) | Delshad, Mojdeh (Ultimate EOR Services, LLC) | Hernandez, Richard (Ultimate EOR Services, LLC) | Winoto, Winoto (Ultimate EOR Services, LLC) | Badham, Scott (Chemical Tracers, Inc.) | Bouma, Chris (Chemical Tracers, Inc.) | Brown, John (Chemical Tracers, Inc.) | Kumer, Kory (Chemical Tracers, Inc.)
Abstract The Greater Burgan Field, first discovered in 1938, is the second largest oilfield in the world. Production from the Greater Burgan began in 1946 from the Wara reservoir via primary recovery. Recently, field-wide waterflood as a secondary recovery mechanism has been implemented. The current insight on the potential of hybrid low salinity water and polymer flooding in the Greater Burgan is presented. The goal of the Greater Burgan Study team in this enhanced oil recovery (EOR) evaluation program was to compare the benefits of using low salinity waterflood (LSW) and low salinity polymer (LSP) injection as tertiary oil recovery methods in the Wara sandstone reservoir of the Greater Burgan field. The efficacy of low salinity and low salinity polymer injection has been investigated in the laboratory and by conducting a series of single-well chemical tracer (SWCT) tests in one Wara producer. In the field trial carried out on Well A, three separate determinations of residual oil saturation (Sor) were made. The first SWCT test measured waterflood Sor after injecting a slug of high salinity water (HSW) that is compositionally comparable to the produced water utilized field-wide for waterflooding operations. The second and third SWCT tests measured the remaining oil saturation after LSW and LSP, respectively. Laboratory corefloods were also performed to evaluate LSW and LSP recoveries and their impacts on injectivity. The injection water salinity, injection design, oil viscosity, and polymer viscosity used in the laboratory experiments were identical to those used in the field SWCT tests. These SWCT test trial results establish a baseline waterflood Sor (i.e., after high salinity water injection) and show that further reductions in Sor may be achieved with low salinity waterflooding and low salinity polymer injection. The laboratory results showed no plugging or injectivity issues during LSW or LSP corefloods. Overall, LSW and LSP were shown to be technically workable tertiary processes in the Greater Burgan.
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- (18 more...)
Design and Demonstration of New Single-Well Tracer Test for Viscous Chemical Enhanced-Oil-Recovery Fluids
Fortenberry, Robert (Ultimate EOR Services) | Suniga, Pearson (Ultimate EOR Services) | Delshad, Mojdeh (Ultimate EOR Services) | Singh, Bharat (Kuwait Oil Company) | AlKaaoud, Hassan A. (Kuwait Oil Company) | Carlisle, Charlie T. (Chemical Tracers Incorporated) | Pope, Gary A. (University of Texas at Austin)
Summary Single-well-partitioning-tracer tests (SWTTs) are used to measure the saturation of oil or water near a wellbore. If used before and after injection of enhanced-oil-recovery (EOR) fluids, they can evaluate EOR flood performance in a so-called one-spot pilot. Four alkaline/surfactant/polymer (ASP) one-spot pilots were recently completed in Kuwait's Sabriyah-Mauddud (SAMA) reservoir, a thick, heterogeneous carbonate operated by Kuwait Oil Company (KOC). UTCHEM (Delshad et al. 2013), the University of Texas chemical-flooding reservoir simulator, was used to interpret results of two of these one-spot pilots performed in an unconfined zone within the thick SAMA formation. These simulations were used to design a new method for injecting partitioning tracers for one-spot pilots. The recommended practice is to inject the tracers into a relatively uniform confined zone, but, as seen in this work, that is not always possible, so an alternative design was needed to improve the accuracy of the test. The simulations showed that there was a flow-conformance problem when the partitioning tracers were injected into a perforated zone without confinement after the viscous ASP and polymer-drive solutions. The water-conveyed-tracer solutions were being partially diverted outside of the ASP-swept zone where they contacted unswept oil. Because of this problem, the initial interpretation of the performance of the chemicals was pessimistic, overestimating the chemical residual oil saturation (ROS) by up to 12 saturation units. Additional simulations indicated that the oil saturation in the ASP-swept zone could be properly estimated by avoiding the post-ASP waterflood and injecting the post-ASP tracers in a viscous polymer solution rather than in water. An ASP one-spot pilot using the new SWTT design resulted in an estimated ROS of only 0.06 after injection of chemicals (Carlisle et al. 2014). These saturation values were obtained by history matching tracer-production data by use of both traditional continuously-stirred-tank (CSTR) models and compositional, reactive-transport reservoir models. The ability of the simulator to model every phase of the one-spot pilot operation was crucial to the insight of modified SWTT design. The waterflood, first SWTT, ASP flood, and the final SWTT were simulated using a heterogeneous permeability field representative of the Mauddud formation. Laboratory data, field-ASP quality-control information, and injection strategy were all accounted for in these simulations. We describe the models, how they were used, and how the results were used to modify the SWTT design. We further discuss the implications for other SWTTs. The advantage of mechanistic simulation of multiple aspects of a one-spot pilot is an important theme of this study. Because the pore space investigated by the SWTTs can be affected by the previously injected EOR fluids (and vice versa), these interactions should be accounted for. This simulation approach can be used to identify and mitigate design problems during each phase of a challenging one-spot pilot.
- Asia > Middle East > Kuwait (0.90)
- North America > United States > Texas (0.68)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Upper Marrat Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Sargelu Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > Sabiriyah Mauddud (SAMA) Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Sabriyah Field > Marrat Formation > SAMA Formation (0.99)