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Collaborating Authors
Asia
Abstract The goal of this work is to develop alkaline-surfactant-polymer (ASP) formulations for a shallow, clayey sandstone reservoir. Commercially available surfactants were used in the phase behavior study. The gas-oil-ratio (GOR) was low; the phase behavior and coreflood study was conducted with the dead oil. The surfactant formulation systems were tested in tertiary ASP core floods in reservoir rocks. Many surfactant formulations were identified which gave ultralow IFT, but the formulation with only one surfactant (at 0.5 wt% concentration) in presence of one co-solvent was selected for corefloods. The cumulative oil recovery was in the range of 94-96% original oil in place (OOIP) in the corefloods. The surfactant retention was low (0.15 mg/gm of rock) in spite of the high clay content. The study showed that 0.5 PV of ASP slug and 2700 ppm of the polymer were required to make the flood effective. The use of alkali and preflush of the soft brine helped minimize surfactant retention.
- Asia > Middle East (1.00)
- Asia > China > Heilongjiang Province (0.28)
- North America > United States > Missouri (0.28)
- Geology > Mineral (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (6 more...)
Abstract The objective of this paper is to present a critical review of best practices for conducting laboratory experiments to evaluate chemical EOR. Some legacy methods and procedures are outdated and need to be updated to address their inherent flaws. This paper presents the reasons improvements are necessary and serves to introduce or highlight better methods, while providing a good resource to review past studies. Common laboratory methods and procedures used to evaluate chemical EOR are critically reviewed and discussed for polymer flooding, surfactant-polymer flooding, alkaline-surfactant-polymer flooding, alkaline-co-solvent-polymer flooding specifically but also apply to similar processes. The laboratory methods for evaluating chemical EOR include surfactant phase behavior, coreflooding, chemical adsorption and retention measurements, polymer residual resistance factor measurements, polymer transport, polymer filtration ratio measurements, polymer stability. The best methods and procedures for these and other measurements should take into account how the laboratory measurements will be used for making field-scale performance predictions, the type of oil reservoir, the chemical EOR process and many other factors. Conducting corefloods with a low residence time is an example of a common mistake. New or improved methods are introduced or highlighted to bring best practices to the forefront. New methods that are highlighted include Residence Time Distribution Analysis to determine polymer retention and IPV, polymer transport in cores with two-phases present, and the addition of solvents/pre-shearing for improved polymer transport. The state-of-the-art laboratory methods and procedures discussed herein yield more accurate, more scalable data that are needed for reservoir simulation predictions and field-scale applications of chemical EOR. The recommended best practices will provide a better understanding needed to help select the appropriate chemicals and to determine the optimal chemical mass for field applications of chemical EOR.
- North America > United States > Texas (0.93)
- Asia > Middle East (0.67)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.67)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- (3 more...)
Bhagyam ASP Pilot: Successful Formulation Development to Pilot Design and Planning
Jain, Shakti (Cairn Oil & Gas, Vedanta Limited) | Prasad, Dhruva (Cairn Oil & Gas, Vedanta Limited) | Pandey, Amitabh (Cairn Oil & Gas, Vedanta Limited) | Koduru, Nitish (Cairn Oil & Gas, Vedanta Limited) | Raj, Rahul (Cairn Oil & Gas, Vedanta Limited)
Abstract The paper discusses the alkaline surfactant polymer (ASP) flood pilot design including formulation development, pilot area selection, well and pattern type, slug size and sequence, slug viscosity etc for the Bhagyam field. It also discusses the various lab, well and reservoir surveillance techniques planned for the baseline, ASP flood monitoring, residual oil saturation and incremental recovery estimates from the pilot. The Bhagyam is an onshore field in the Rajasthan state of western India and is part of Mangala-Bhagya m- Aishwariya (MBA) development in the Barmer basin. The main producing unit is Fatehgarh multi -storied fluvial sand stone. Reservoir quality is excellent with permeability in the range of 1 to 10 Darcy and porosity in the range of 25-30%. The crude oil is moderately viscous (15 to 500 cP) and highly active with TAN (total acid number) value of ~2 mgKOH/gm. All the reservoir and fluid properties together with low salinity (5000 ppm) and moderate temperature (54 degC) makes it an ideal candidate for polymer and ASP EOR methods. The field has been developed with downdip water injection and post successful evaluation of long term polymer injectivity test, it is currently under full-field polymer flood implementation. The details of polymer flood injectivity and full-field expansion plans are discussed by Sharma et. al. 2016 and Shankar et. al. 2018. EOR assessment has been part of the field development planning process from start. Multiple phase behaviour studies and corefloods have been conducted to screen the surfactant and generate necessary parameters for the simulation studies. The formulation consists of combination of sulfate and sulfonate based surfactants. The focus of the pilot area selection has been to utilize the existing well s to maximum possible extent, reduce the geological uncertainty and minimize the interference from ongoing activity in the field. A normal 4 spot pilot with ~150m spacing has been selected together with two observation well for time lapse saturation monitoring and one coring well towards end of pilot for saturation determination. Dynamic models have been used to design slug size, sequence, viscosity and estimate incremental oil potential. Multiple tracer surveys together with distributed pressure measurements and interference tests are planned to establish connectivity and calibrate model. Initial estimates of pilot incremental oil recovery is in the range of 15-25% of stock tank oil intial in-place (STOIIP) over the polymer flood. Overall pilot design aims at collecting all the necessary data for reducing uncertainty for full-field expansion in a short time frame.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Bhagyam Field (0.99)
- (4 more...)
Novel Surfactants without Hydrocarbon Chains for Chemical EOR
Sharma, Himanshu (The University of Texas at Austin) | Panthi, Krishna (The University of Texas at Austin) | Ghosh, Pinaki (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Mohanty, Kishore (The University of Texas at Austin)
Abstract Enhanced oil recovery (EOR) techniques involving surfactants such as surfactant floods, foam floods, and wettability alteration have been studied to recover remaining oil after primary and secondary floods. In these processes, a surfactant solution is injected to promote one (or more) of the following: lowering of capillary forces, improvement in sweep efficiency, and wettability alteration. Although significant advances have been made in designing surfactant molecules to achieve the above mentioned objectives efficiently, surfactant price is often the key limiting factor for a field-scale operation. Most surfactant molecules have a hydrocarbon chain (for example alkyl chain) or an aromatic ring as the main hydrophobe. The hydrocarbon chain (or ring) imparts hydrophobicity (and surface activity) to the surfactant molecule. However, these hydrophobes also result in additional cost. In this study, we discuss low-cost surfactants developed without hydrocarbon chains (or rings) for chemical EOR processes in general. The focus of this paper, however, is on their application in surfactant floods. These novel surfactants were developed by using methanol as the starting material, followed by the addition of propylene oxide (PO) and ethylene oxide (EO) groups, and an anionic head group. The surface tension and critical micelle concentration (CMC) values of these surfactants were measured. A screening study was performed to identify promising candidates; which showed ultralow interfacial tension (IFT) with various crude oils as well as aqueous stability at reservoir conditions. A comparison between novel surfactants with traditional surfactants was made based on the screening study. Oil recovery corefloods were performed in Berea and Boise sandstone cores to test the ultralow IFT formulations. These surfactants were found to have very low CMC values, and lowered the surface tension to about 32 dynes/cm. Their aqueous stability at a given temperature was found to be dependent on the number of PO and EO groups. Phase behavior experiments showed low IFT formulations with different crude oils by using these surfactants by themselves as well as in combination with internal olefin sulfonates (IOS). Moderate oil recoveries were obtained in coreflood experiments using these surfactants.
- North America > United States > Texas (0.28)
- North America > United States > Idaho > Ada County > Boise (0.25)
- Geology > Mineral (0.34)
- Geology > Geological Subdiscipline (0.30)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Mangala Field > Barmer Hill Formation (0.99)
Dynamic Field Rheology, Filterability and Injectivity Characterization Using a Portable Measurement Unit
Espinosa, David (Chevron) | Walker, Dustin (Chevron) | Alexis, Dennis (Chevron) | Dwarakanath, Varadarajan (Chevron) | Jackson, Adam (Chevron) | Kim, Do Hoon (Chevron) | Linnemeyer, Harold (Chevron) | Malik, Taimur (Chevron) | McKilligan, Derek (Chevron) | New, Peter (Chevron) | Poulsen, Anette (Chevron) | Winslow, Greg (Chevron)
Abstract Field deployment of Chemical EOR floods requires monitoring of wellhead injection fluids to ensure field performance is commensurate with laboratory design. Real-time surveillance allows for optimizing chemical use, detecting potential issues, and ensures correct chemical handling. In an offshore setting traditional surveillance methods can present unique challenges due to space constraints, field conditions, and location. We present a novel approach to field surveillance using a portable measurement unit (PMU) that can dynamically characterize polymer rheology, filterability and long-term core-injectivity. We developed a PMU and placed it inside a suitcase sized box (42x26x20″) with appropriate devices to measure polymer rheology, filterability and long-term core injectivity. Polymer rheology was measured using a series of capillary tubes with pressure measurements. Filterability was measured through a 1.2 um filter at 15 psi with coarse filtration to remove large oil droplets and suspended solids. This was compared against filterability without filtration to observe water quality impact. Finally, long-term injectivity was measured using an epoxy-coated Bentheimer core with a pressure tap to quantify whether there was any face and/or core-plugging. By constructing this apparatus, wellhead injection fluids under anaerobic conditions can be monitored and analyzed to improve fluid quality assurance and contribute to a project's success even in challenging and remote locations. The use of the PMU is critical for dynamic fluid surveillance. The injection solutions consistently met or exceeded target viscosity of 20 cP. Furthermore, the coarse-filtered solutions also met a filtration ratio (FR) requirements of less than 1.5 at 15 psi through 1.2 micron filters. The unfiltered solutions achieved a FR of 1.75, which was considered acceptable. Finally, no plugging was observed with coarse-filtered solutions after 25 PV across the whole core and > 75 PV across the core face. Further testing was completed with wellhead injectate samples at variable operating conditions to establish a baseline for chemical flooding operations and provided insight for future facilities design. The information these experiments produced helped identify and diagnose facility and operational issues that would have caused negative consequences with the chemical injection had the configuration been used without the PMU surveillance. By testing the wellhead fluid, we determined that there was improper dosing of the chemical. This was determined by comparing the field fluid properties to expected results from the lab. The data also influenced facilities design and in turn improved the chemical and project efficiency. By testing the injectate at different operating conditions we could determine the operating envelope for the current injection facilities and base future work on the results. All of this was done in real time on an offshore platform, as opposed to sending samples onshore to test which yields unrepresentative results from the time delay and fluid quality changes during transport.
- North America > United States > Texas (0.47)
- North America > United States > Oklahoma (0.30)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- (3 more...)
Abstract Polymer flooding is a widely used commercial process with a low cost per barrel of produced oil, For this application, hydrolyzed polyacrylamide (HPAM) polymers are the most widely used type of polymer. In an era of low cost oil, it is becoming even more essential to optimize the polymer flooding design under realistic reservoir conditions. The objective of this research was to better understand and predict the behavior of HPAM polymers and their effect on residual oil saturation, in order to improve the capability of optimizing field design and performance. The corefloods were performed under typical field conditions of low pressure gradients and low capillary numbers. The polymer floods of the viscous oils recovered much more oil than the water floods, with up to 24% lower oil saturation after the polymer flood than the water flood. The experimental data are in good agreement with the fractional flow analysis using the assumptions that the true residual oil saturations and end point relative permeabilities are the same for both water and polymer. This suggests that for more viscous oils, the oil saturation at the end of water flood (i.e. at greater than 99% water cut) is better described as ‘emaining’ oil saturation rather than the true ‘esidual’ oil saturation. This was true for all of the corefloods regardless of the core permeability and without the need for assuming a permeability reduction factor in the fractional flow analysis.
- Asia (0.68)
- North America > United States > Louisiana (0.28)
- 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)
Permeability Reduction Due to use of Liquid Polymers and Development of Remediation Options
Dwarakanath, Varadarajan (Chevron) | Dean, Robert M. (Chevron) | Slaughter, Will (Chevron) | Alexis, Dennis (Chevron) | Espinosa, David (Chevron) | Kim, Do Hoon (Chevron) | Lee, Vincent (Chevron) | Malik, Taimur (Chevron) | Winslow, Greg (Chevron) | Jackson, Adam C. (Chevron) | Thach, Sophany (Chevron)
Abstract Polymer flooding by liquid polymers is an attractive technology for rapid deployment in remote locations. Liquid polymers are typically oil external emulsions with included surfactant inversion packages to allow for rapid polymer hydration. During polymer injection, a small amount of oil is typically co-injected with the polymer. The accumulation of the emulsion oil near the wellbore during continuous polymer injection will reduce near wellbore permeability. The objective of this paper is to evaluate the long-term effect of liquid polymer use on polymer injectivity. We also present a method to remediate the near well damage induced by the emulsion oil using a remediation surfactant that selectively solubilizes and removes the near wellbore oil accumulation. We evaluated several liquid polymers using a combination of rheology measurement, filtration ratio testing and long-term injection coreflood experiments. The change in polymer injectivity was quantified in surrogate core after multiple pore volumes of liquid polymer injection. Promising polymers were further evaluated in both clean and oil-saturated cores. In addition, phase behavior experiments and corefloods were conducted to develop a surfactant solution to remediate the damage induced by oil accumulation. Permeability reduction due to long term liquid polymer injection was quantified in cores with varying permeabilities. The critical permeability where no damage was observed was identified for promising liquid polymers. A surfactant formulation tailored for one of the liquid polymers improved injectivity three- to five-fold and confirms our hypothesis of permeability reduction due to emulsion oil accumulation. Such information can be used to better select appropriate polymers for EOR in areas where powder polymer use may not be feasible.
- Asia > Middle East (0.94)
- North America > United States > Texas (0.47)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- Asia > Middle East > Oman > Dhofar Governorate > South Oman Salt Basin > Marmul Field > Al-Qalata Formation (0.99)