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Abstract This paper presents an overview of both research advancements and field applications of offshore chemical flooding technologies. Along with offshore oilfield development strategies that require maximization of oil production in a short development cycle, chemical flooding can become a potential avenue to accelerate oil production in secondary oil recovery mode. This makes it different from onshore chemical flooding processes that mostly focus on enhanced oil recovery in matured or maturing reservoirs. The advancements of offshore chemical flooding field applications are reviewed and analyzed. By summarizing offshore application cases, it also assesses the chemical formulations applied or studied and injection/production facilities required in the offshore environments. Main technical challenges are presented for scaling up the applications on offshore platforms or floating production storage and offloading (FPSO) systems. The technologies reviewed include polymer flooding, surfactant-polymer flooding, and alkaline-surfactant-polymer flooding. By assessing the technology readiness level of these technologies, this study presents their perspectives and practical relevance for offshore chemical flooding applications. It has been long realized that chemical flooding, especially polymer flooding, can improve oil recovery in offshore oil fields. The applications in Bohai Bay (China), Dalia (Angola), and Captain (North Sea) provide the know-how workflows for offshore polymer flooding from laboratory to full field applications. It is feasible to implement offshore polymer injection either on platform or FPSO system. It is recommended to implement polymer flooding at early stage of reservoir development in order to maximize the investment of offshore facilities. By tuning the chemistry of polymer products, they can present very good compatibility with seawaters. Therefore, choosing a proper polymer is no longer a big issue in offshore polymer flooding. There are also some interesting research findings reported on the development of novel surfactant chemistries for offshore applications. The outcome from a number of small-scale trials including the single well tracer tests on surfactant, alkaline-surfactant, surfactant-polymer in offshore Malaysia, Abu Dhabi, Qatar, and South China Sea provided valuable insights for the feasibility of chemical flooding in offshore environments. However, the technology readiness levels of surfactant-based chemical flooding processes are still low partially due to their complex interactions with subsurface fluids and lack of much interest in producing residual oil from matured offshore reservoirs. Based on the lessons learned from offshore applications, it can be concluded that several major challenges still need to be overcome in terms of large well spacing, reservoir voidage, produced fluid treatment, and high operational expense to successfully scale up surfactant based chemical flooding processes for offshore applications.
- North America > United States (1.00)
- Africa > Angola (0.89)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.35)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth (0.28)
- Overview (1.00)
- Research Report > New Finding (0.48)
- Geology > Rock Type (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > Block 5 > Al-Shaheen Field > Umm Er Radhuma Formation (0.99)
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Block PM 305 > Angsi Field (0.99)
- (3 more...)
In-Depth Water Conformance Control: Design, Implementation and Surveillance of the First Thermally Active Polymers Treatment TAP in a Colombian Field
Gutierrez, Mauricio (Ecopetrol S.A.) | García, Joan Sebastian (Ecopetrol S.A.) | Castro, Ruben Hernan (Former Ecopetrol S.A.) | Zafra, Tatiana Yiceth (Ecopetrol S.A.) | Rojas, Jonattan (Ecopetrol S.A.) | Ortiz, Rocio Macarena (Ecopetrol S.A.) | Quintero, Henderson Ivan (Ecopetrol S.A.) | Garcia, Hugo Alejandro (Ecopetrol S.A.) | Niño, Luis (TIP) | Amado, Jhon (TIP) | Quintero, Diego (ChampionX) | Kiani, Mojtaba (ChampionX)
Abstract The Yariguí-Cantagallo is a mature oil field located in the western flank of the middle Magdalena valley basin in Colombia. Oil production started in 1941 and has been supported by water injection since 2008 with the aim of maintaining the pressure in the reservoir and increasing oil production. However, due to the channeling of the injected water, the water cut in some wells has been increasing, reaching values greater than 90%. Therefore, ECOPETROL S.A. implemented the first deep conformance treatment in Colombia through the design, execution, monitoring and evaluation of the technology in the YR-521 and YR-517 patterns for improving sweep efficiency of the waterflooding process. Brightwater® technology (also known as Thermally Active Polymer, TAP) has been used as an in-depth conformance improvement agent in reservoirs under waterflood suffering from the presence of thief zones or preferential flow channels. BrightWater® consists of expandable submicron particles injected downhole with a dispersive surfactant as a batch using injection water as a carrier. The selection of the injection patterns and treatment volume estimation was carried out through analysis of diagnostic plots and analytical pattern simulations. Treatment design and chemistry selection were based on reservoir characteristics, especially the temperature profile between the injector and offset producing wells in each pattern. Thus, laboratory tests with the representative fluids at various temperatures were carried out. Injection in the first pattern began on December 14, 2020, with a cumulative 6344 bbls of water containing TAP, at an injection rate of 700 bpd, gradually increasing the concentration from 3,500 ppm to 12,000 ppm. Once the injection was completed in this pattern and using the same surface facility, the second injection pattern was executed, on December 23, 2020. In the second pattern a cumulative of 9152 bbls of water containing TAP was injected at an injection rate of 700 bpd at concentration from 3500 ppm up to 8000 ppm. This paper summarizes the first TAP pilot implementation in Colombia and will describe the methodology and results of project QAQC monitoring and injection-production. Based on results to date, after one year monitoring (decrease in water cut up to 6%, in some wells, with consequent increase in oil recovery up to 18,642 STB), five additional treatments are planned in other injection patterns in this field between 2022 and 2023. It was validated that the deep conformance improvement technology allows blocking the preferential flow channels, reaching new areas with high oil saturation. Incremental oil production, potential increase in reserves, and reduction of OPEX due to lower water production were some of the observed benefits from this trial. Likewise, calculations show positive impacts in reducing the carbon footprint and water management.
- South America > Colombia > Santander Department (0.68)
- South America > Colombia > Bolivar Department (0.51)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.69)
- South America > Colombia > Tolima Department > Middle Magdalena Basin > Casabe Field (0.99)
- South America > Colombia > Santander Department > Middle Magdalena Basin > Yariguí-Cantagallo Field (0.99)
- South America > Colombia > Santander Department > Middle Magdalena Basin > Casabe Field (0.99)
- (13 more...)
Comprehensive Evaluation of a Novel Recrosslinkable Hyper Branched Preformed Particle Gels for the Conformance Control of High Temperature Reservoirs
Song, Tao (Missouri University of S & T) | Ahdaya, Mohamed (Missouri University of S & T) | Zhao, Shuda (Missouri University of S & T) | Zhao, Yang (Missouri University of S & T) | Schuman, Thomas (Missouri University of S & T) | Bai, Baojun (Missouri University of S & T)
Abstract The existence of high conductivity features such as fractures, karst zones, and void space conduits can severely restrict the sweep efficiency of water or polymer flooding. Preformed particle gel (PPG), as a cost-effective technology, has been applied to control excessive water production. However, conventional PPG has limited plugging efficiency in high-temperature reservoirs with large fractures or void space conduits. After water breakthrough, gel particles can easily be washed out from the fractures due to the lack of particle-particle association and particle-rock adhesion. This paper presents a comprehensive laboratory evaluation of a novel water-swellable high-temperature resistant hyper-branched re-crosslinkable preformed particle gel (HT-BRPPG) designed for North Sea high-temperature reservoirs (130 °C), which can re-crosslink to form a rubber-like bulk gel to plug such high conductivity features. This paper systematically evaluated the swelling kinetics, long-term thermal stability and plugging performance of the HT-BRPPG. Bottle tests were employed to test the swelling kinetic and re-crosslinking behavior. High-pressure resistant glass tubes were used to test the long-term thermal stability of the HT-BRPPG at different temperatures, and the testing lasted for over one year. The plugging efficiency was evaluated by using a fractured model. Results showed that this novel HT-BRPPG could re-crosslink and form a rubber-like bulky gel with temperature ranges from 80 to 130 °C. The elastic modulus of the re-crosslinked gel can reach up to 830 Pa with a swelling ratio of 10. In addition, the HT-BRPPG with a swelling ratio of 10 has been stable for over 15 months at 130 °C so far. The core flooding test proved that the HT-BRPPG could efficiently plug the open fractures, and the breakthrough pressure is 387.9 psi/ft. Therefore, this novel BRPPG could provide a solution to improve the conformance of high-temperature reservoirs with large fractures or void space conduits.
- Europe > Norway > North Sea (0.34)
- Europe > United Kingdom > North Sea (0.25)
- Europe > North Sea (0.25)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock (0.88)
- Geology > Geological Subdiscipline (0.88)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Europe > United Kingdom > North Sea > Central North Sea > Utsira High > PL 006 > Ekofisk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
Hydrothermal Stability and Transport Properties of Optically Detectable Advanced Barcoded Tracers with Carbonate Rocks in the Presence of Oil
Ow, Hooisweng (Aramco Americas: Aramco Research Center - Boston) | Chang, Sehoon (Aramco Americas: Aramco Research Center - Boston) | Thomas, Gawain (Aramco Americas: Aramco Research Center - Boston) | Chen, Hsieh (Aramco Americas: Aramco Research Center - Boston) | Saleh, Salah H. (Saudi Aramco: EXPEC Advanced Research Center) | Otaibi, Mohammad B. (Saudi Aramco: EXPEC Advanced Research Center) | Ayirala, Subhash (Saudi Aramco: EXPEC Advanced Research Center)
Abstract The use of tracer technology to illuminate reservoir characteristics such as well connectivity, volumetric sweep efficiency, and geological heterogeneity for the purpose of improving history-matching fidelity and enriching production optimization algorithm has gained momentum over the last decade. Herein, we report the stringent laboratory qualification of a novel class of fluorescent molecules, optically detectable down to ultra-trace levels (
- North America > United States > Oklahoma (0.29)
- Asia > Middle East > UAE (0.29)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline (0.94)
- North America > United States > Wyoming > Rim Field (0.99)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Lower Austria > Vienna Basin (0.99)
- 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 > Formation Evaluation & Management > Tracer test analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (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...)
Polymer Injectivity Enhancement Using Chemical Stimulation: A Multi-Dimensional Study
Chandrasekhar, Sriram (Chevron Technical Center, a division of Chevron USA Inc.) | Alexis, Dennis Arun (Chevron Technical Center, a division of Chevron USA Inc.) | Jin, Julia (Chevron Technical Center, a division of Chevron USA Inc.) | Malik, Taimur (Chevron Technical Center, a division of Chevron USA Inc.) | Dwarakanath, Varadarajan (Chevron Technical Center, a division of Chevron USA Inc.)
Abstract Chevron injected emulsion polymer in the Captain field, offshore UK in the last decade at various scales (Poulsen et al., 2018). Pilot horizontal wells had exhibited faster than designed injectivity decline and Jackson et al. (2019) documented the causes to include oleic phase damage from a) injection of produced water containing crude oil after imperfect separation, and b) entrainment of injected emulsion polymer’s carrier oil. The wells were remediated with a surfactant stimulation package (Alexis et al., 2021; Dwarakanath et al., 2016). The remediation boosted the water relative permeability near wellbore which enhanced injectivity and allowed higher processing rates for subsequent continuous polymer injection. In this work, we conducted a set of core floods in slabs of surrogate rock of varying dimension and patterns to demonstrate the beneficial effect of near wellbore stimulation in the general case. 0.04 PV of the remediation package was injected and we show consistent injectivity enhancement across the experiments. We demonstrate the dominant effect of well skin treatment on the pressure drop profile compared to flow resistance from a) residual oil saturation and b) viscous fingering. The result is an important reminder for injectivity maintenance for high polymer flood processing rates for the life of the project. Clean injection fluids were demonstrated to maintain injectivity. We show applicability of stimulation for injectors into viscous oil reservoirs with adverse viscosity ratio. The robust nature of the remediation package developed by Alexis et al. (2021) is also shown, working to efficacy on viscous oil, as well as in situ phase separated polymer. We estimated skin and stimulation depth for a line drive case with low chemical dosage finding that 0.04 pore volumes of surfactant injection at 0.33 oil saturation units gave injectivity improvement of 31%. Surfactant stimulation is thus broadly applicable to wells with oleic phase skin.
Improved Oil Recovery Techniques and Their Role in Energy Efficiency and Reducing CO2 Footprint of Oil Production
Farajzadeh, R. (Shell Global Solutions International, Delft University of Technology) | Glasbergen, G. (Shell Global Solutions International) | Karpan, V. (Shell Development Oman) | Mjeni, R. (Petroleum Development Oman) | Boersma, D. (Shell Global Solutions International) | Eftekhari, A. A. (Technical University of Denmark) | Casquera García, A. (Delft University of Technology) | Bruining, J. (Delft University of Technology)
Abstract The energy intensity (and potentially CO2 intensity) of the production of hydrocarbons increases with the lifetime of the oil fields. This is related to the large volumes of gas and water that need to be handled for producing the oil. There are two potential methods to reduce CO2 emissions from the aging fields: (1) use a low-carbon energy source and/or (2) reduce the volumes of the non-hydrocarbon produced/injected fluids. The first solution requires detailed analysis considering the availability of the infrastructure and carbon tax/credit economics and is largely influenced by the cost of the CO2 capture technologies and renewable power. The second solution utilizes improved/enhanced oil recovery methods (I/EOR) aimed at injecting materials to increase the fraction of oil in the producers. In this paper, we use the production data from a field in the Middle East and show the high-level economics associated with switching the field operating energy demand to solar energy. We begin the analysis by first investigating the energy requirement of different stages in the life cycle of oil production and quantifying the CO2 emission and energy loss that can be avoided in each stage. We also utilize the concept of exergy to identify process steps that require lower energy quality and thus are the main targets for optimization. The analysis indicates that preventing CO2 emission is economically more attractive than utilizing mitigation methods, i.e., to capture the emitted CO2 and store it at later stages. Moreover, we show quantitatively how I/EOR techniques can be designed to reduce the CO2 intensity (kgCO2/bbl oil) of oil production. The energy efficiency of any oil production system depends on the injectant utilization factor, i.e., the volume of produced oil per mass or volume of the injectant.
- Asia > Middle East (0.49)
- North America > United States (0.46)
- Europe > United Kingdom (0.46)
Screening of Topside Challenges Related to Polymer Presence in the Back Produced Fluids – Casabe Case Study
Mouret, Aurélie (IFP Energies Nouvelles) | Blazquez-Egea, Christian (IFP Energies Nouvelles) | Hénaut, Isabelle (IFP Energies Nouvelles) | Jermann, Cyril (IFP Energies Nouvelles) | Salaün, Mathieu (Solvay) | Quintero, Henderson (Ecopetrol) | Gutierrez, Mauricio (Ecopetrol) | Acosta, Tito (Ecopetrol) | Jimenez, Robinson (Ecopetrol) | Vargas, Nadine (Ecopetrol)
Abstract Polymer enhanced oil recovery (EOR) pilots were implemented in various mature oilfield reservoirs in Colombia with encouraging results. That chemical EOR technology is often considered as a promising process to faster recover oil. To increase the chance of success of such an industrial project it is important not to neglect the potential impact of residual polymer in back produced effluents. The objective of this work is to highlight the impact of back-produced EOR polymer at the laboratory scale on various topside equipment before deploying the polymer injection at wider scale in a heavy oil field (18° API). A topside facility review was first performed to collect operational conditions and parameters, to identify applied treatment technologies and to define relevant sampling locations for the laboratory study. The impact of the residual acrylamide/ATBS ter-polymer selected for the future polymer implementation was then explored in a set of experiments as part of a dedicated laboratory workflow representing the whole surface treatment chain. The scope of the study has covered primary separation, static gravity water clarifying, deep-bed filtration and heater fouling. Large residual polymer concentration and water cut ranges were investigated to anticipate some produced fluid composition change over time. In the case studied, the selected polymer does not stabilize tight water-in-oil emulsions, but it has a negative impact on the water quality. Some compatibility issues are observed with incumbent demulsifiers, which seems to be sensitive to both polymer concentration and water cut. The fouling risk of heat exchanger is very low in the testing conditions. In the water de-oiling side, filtration and gravity settling performance are reduced but the right chemical and equipment combination enables to obtain a better water quality and to meet injection specifications targets. Novel/Additive Information: This work illustrates that management of produced fluid containing EOR polymer has to be considered as early as possible in the project implementation. It also points out that laboratory experiments are useful to better appraise and mitigate the potential operational issues. All the results obtained in such a study are valuable guideline and input data for treatment facilities upgrade studies. In polymer flooding roadmap implementation, it is key to bond operational conditions and laboratory parameters in order to be as close as possible to the field conditions as each case is unique.
- South America > Colombia (0.67)
- North America > United States (0.46)
- Asia > India (0.46)
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.48)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- 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 > Colombia > Antioquia Department > Middle Magdalena Basin > Casabe Field (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Abstract Low salinity relative permeability curves are required to estimate the benefit of low salinity waterflooding at the field-level. Low salinity benefit is measured from corefloods (i.e., at the plug scale) and the same benefit is often assumed in full field models to generate low salinity curves from high salinity curves (often pseudo curves). The validity of this assumption is investigated. We present how uncertainty distribution of low salinity benefit can be propagated through an ensemble of full field models in which each simulation case could have a set of distinctive high salinity pseudos. A 0.5-ft vertical resolution sector and its 10-ft upscaled counterpart are used. Low salinity benefit from corefloods is used to generate low salinity relative permeabilities for the high-resolution sector. Rock curves (relative permeability curves from corefloods) are used in the high-resolution sector to create "truth" profiles. Pseudo high and low salinity curves are generated for the upscaled sector by history matching high salinity and incremental low salinity truth case profiles. Low salinity benefit from the upscaled model is compared against that of high-resolution sector ("truth" model). It is crucial to include capillary pressure in high resolution models. In the case studied, analogue and published data are used to produce low salinity capillary pressure curves. Our results show that generating low salinity curves for high salinity pseudos using low salinity benefit from corefloods slightly underestimates the true low salinity benefit at field-scale (i.e., low salinity benefit estimated from high-resolution models). This conclusion is consistent for two extreme relative-permeability scenarios tested (i.e., a high total mobility-unfavorable fractional flow and low total mobility-favorable fractional flow). We demonstrate how a set of high salinity relative-permeability data obtained from corefloods, which encompasses a range for fractional flow and total mobility, can be included in ensemble modeling appropriately, and how low salinity benefit could be estimated for such an ensemble. It is adequate to generate low salinity curves for bounding high salinity sets of curves. The bounding low salinity curves can then be used to estimate low salinity curve for any interpolated high salinity curve. This significantly simplifies the process of generating a probability distribution function (pdf) of low salinity benefit for an ensemble of models, where each model has a different high salinity relative permeability. We explain the pseudoization process and how to generate a counterpart low salinity curve for a high salinity relative permeability that honors an estimated low salinity benefit from corefloods. We present how a pdf of low salinity benefit can be built for an ensemble of models with distinctive high salinity curves that each honors the low salinity benefit. The workflow simplifies the process of describing the uncertainty in the benefit of low salinity waterflooding.
- Asia > Middle East > Kuwait (0.28)
- North America > United States (0.28)
- Europe > United Kingdom (0.28)
- 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 > Block 211/7a > Magnus Field > Kimmeridge Formation > Magnus Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/7a > Magnus Field > Kimmeridge Formation > Lower Kimmeridge Clay Formation (0.99)
- (15 more...)
Polymer Containing Produced Fluid Treatment for Re-Injection: Lab Development to Field Deployment
Pinnawala, Gayani Wasana (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Subrahmanyan, Sumitra (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Alexis, Dennis Arun (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Palayangoda, Sujeewa Senarath (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Linnemeyer, Harold (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Matovic, Gojko (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Kim, Do Hoon (Chevron Oronite a Division of Chevron U.S.A. Inc.) | Theriot, Timothy (Chevron Oronite a Division of Chevron U.S.A. Inc.) | Malik, Taimur (Chevron Technical Center, a Division of Chevron U.S.A. Inc) | Dwarakanath, Varadarajan (Chevron Technical Center, a Division of Chevron U.S.A. Inc)
Abstract Chemical Enhanced Oil Recovery operations involve injecting polymer and surfactants for enhanced recovery. Some of the polymer and surfactant are produced in the form of emulsions. The emulsions need to be treated to recover the oil and reuse water for mixing new polymer for injection. New treatment methods are required to effectively break these emulsions. While chemical treatment and other methods are effective in breaking emulsions formed by electric submersible pumps (ESP's), these methods are not successful in breaking emulsions formed by injected chemicals for CEOR. Reuse of produced water is important in off-shore as well as some on-shore fields. Produced water re-injection requires mixing of fresh polymer with fluid containing produced polymer and traces of oil, which can cause potential incompatibility. Ideally, removal of all produced polymer using a viscosity reducer followed by injection of fresh polymer will improve facility reliability and uptime. Sodium hypochlorite (NaOCl or bleach) was evaluated as a viscosity reducer (VR). Bleach can reduce the viscosity of any HPAM by breaking down the polymer. Polymer destruction fortuitously causes a breakdown of emulsions which releases oil from water and results in improved water quality. After destruction of HPAM, excess bleach was neutralized by chemical means using a neutralizer. After neutralization, the resulting water is free of excess bleach and can be reused for mixing fresh polymer for injection without the risk of degradation of newly mixed polymer. Activating the VR (acidic VR) by pH adjustment can enhance the performance of VR dramatically. Improved oil separation as well as polymer removal can be realized using this technique.
- North America > United States (0.68)
- Asia > Middle East > UAE (0.28)
- Asia > Middle East > Oman (0.28)
- Asia > China > Heilongjiang Province (0.28)
- Materials (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.94)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Europe > France > Chateaurenard Field (0.99)
- Asia > Middle East > Oman > Dhofar Governorate > South Oman Salt Basin > Marmul Field > Al-Qalata Formation (0.99)
- (2 more...)