Pinnawala Arachchilage, Gayani W. P. (Chevron Energy Technology Company) | Spilker, Kerry K. (Chevron Energy Technology Company) | Tao, Emily Burdett (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Linnemeyer, Harold (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Conducting surfactant phase behavior experiments above 100°C is challenging and requires specialized methods to minimize health and safety risks. Shifts in optimal salinity can be correlated to temperature. However, data above 100°C is sparse and the correlations have not been extensively validated above 110°C. In addition, aqueous stability changes with temperature and is often not characterized. We systematically present shifts in optimal salinity and aqueous stability with temperature and use results from both experiments to optimize co-solvent concentrations at high temperatures
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)
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.
Arachchilage, Gayani W. P. Pinnawala (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Davidson, Andrew (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Chemical costs dominate surfactant enhanced oil recovery (EOR) processes. A measure of chemical usage is the pore volume of chemical injected multiplied by the concentration of the chemical in the formulation (PV*C). Recent developments have reduced PV*C to about 30 units for conventional surfactant processes and to about 10 units for ASP processes. Our goal was to demonstrate high oil recovery using conventional surfactant processes at PV*C of 10 units. Under these conditions surfactant polymer flooding becomes just as viable an alternative for oil recovery as the more complex ASP processes.
In this paper, we conducted several phase behavior experiments with the goal of minimizing microemulsion viscosity and maximizing oil solubilization ratios. In addition, we focused on maintaining aqueous stability of both the surfactant slug and dilutions with polymer chase fluids. Both surfactant and co-solvent compositions were optimized to achieve low microemulsion viscosity. The microemulsion viscosity was also measured using three-phase relative permeability experiments. Once an appropriately low microemulsion viscosity was achieved, a series of corefloods at different PV*C units of surfactant were conducted in Bentheimer sandstone. Our baseline formulation included 2 wt% surfactant and 2.8 wt% co-solvent and recovered more than 95% oil in a surrogate Bentheimer coreflood using 30 units of surfactant. The existing surfactant formulation was optimized to match the new crude oil sample and it also recovered more than 95% oil in a Bentheimer coreflood using 30 units of surfactant.
By incorporating large hydrophobe surfactants, we achieved good phase behavior with 1.25% surfactant and 2% co-solvent. The optimized formulation recovered 98% oil with 20 units and 91% with 10 units of surfactant, which translated into a retention of <0.1 mg/g of surfactant. These results indicate that high-performance surfactant formulations have the potential to significantly reduce chemical cost and compete with conventional SP processes in terms of PV*C. Consequently, we illustrate the ability of recovering more than 90% oil with only 10 units of surfactant in conventional surfactant-polymer flooding with high performance surfactants. Such an approach can potentially compete with ASP processes and allow for rapid deployment due to reduced complexity.
Unomah, Michael (Chevron Energy Technology Company) | Thach, Sophany (Chevron Energy Technology Company) | Shong, Robert (Chevron Energy Technology Company) | App, Jeff (Chevron Energy Technology Company) | Zhang, Tiantian (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Permeability reduction provided by conventional polymer gels is affected by harsh reservoir conditions. Harsh conditions are defined by high temperature (> 75°C), high salinity, high divalent ions and the presence of H2S. Polymer gels undergo syneresis when exposed to high salinity and hardness reservoir brines. We evaluated conventional polyacrylamide-based polymer (HPAM)-gels and other modified HPAM-gels with molecular weights between 2-20MM Daltons for gelation time and long-term gel stability under harsh conditions. In addition to polymer degradation, the cross-linkers are also sensitive to harsh reservoir conditions. Specifically, H2S can consume cross-linkers and inhibit gelation. The cross-linkers tested were Chromium (III) Acetate and Chevron Unogel formulation consisting of a combination of hexamethylenetetramine (HMTA) and hydroquinone (HQ). High performing gels were tested for sensitivity to high salinity brines and H2S in a limited number of experiments. The gels were observed for gel strength, and syneresis with time. The goal of our work was to identify a combination of polymer and cross-linker that would provide effective conformance under harsh conditions.
Sulfonated polyacrylamide (ATBS) polymers were found to provide better resistance to high salinity/hardness brines than partially hydrolyzed polyacrylamides in high temperature conditions. The addition of hydrophobic groups to the sulfonated-acrylamide backbone does not increase the hardness tolerance of the polymer. Higher concentration, low molecular weight sulfonated polymers are recommended for use at high temperature and salinity. Polymer gels made with 2MM Dalton polymer show less syneresis with time compared to higher molecular weight polymer at the same polymer concentration. HMTA/HQ ATBS polymer gels are preferable to chromium (III) ATBS polymer gel for high temperature and salinity conditions. Chromium (III) ATBS polymer gels show more susceptibility to syneresis compared to organic crosslinked gels at same polymer concentration. HMTA/HQ crosslinker is ineffective in the presence of hydrogen sulfide. Gelants consisting of HMTA/HQ do not mature into rigid gels after 14 days of exposure to sour gas. Preformed HMTA/HQ gels lose strength upon exposure to sour crude. This is mostly due to HMTA ability as a sour gas/crude sweetener. Chromium (III) gels form weak gels in the presence of sour gas. Chromium competes with sulfide ions to produce insoluble chromium sulfide leading to consumption of crosslinker and poor gelation. Malonate and tartrate are effective gel retardants for chromium (III) polymer gels. Malonate is better at extending onset of gelation for longer periods of time. Tartrate is more effective for shorter gelation time at lower concentrations.
Davidson, Andrew (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Unomah, Michael (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company) | Dwarakanath, Varadarajan
Low microemulsion viscosity is critical for the success of chemical EOR. Typical microemulsion viscosities are measured using a rheometer and are considered to be static measurements. Given that microemulsions have a propensity to show non-Newtonian behavior, static viscosity measurements are not scalable to dynamic viscosities observed in cores and hence difficult to scale-up to field designs using simulations. We present a technique to measure dynamic microemulsion viscosity using a modified two-phase steady state relative permeability setup. Such dynamic viscosities provide a more practical feel for microemulsion viscosity under reservoir conditions in the pores and allow for selection of low microemulsion viscosity formulations. A two-phase steady state relative permeability setup was used with continuous co-injection of oil and surfactant. A glass filled sand pack was used as a surrogate core and the injection fluids were allowed to equilibrate into the appropriate phases as determined by the phase behavior. For the rapidly equilibrating and low viscosity Winsor Type III formulations three phases are clearly observed in the sand packs. Using the phase cuts in the sand pack/effluent and the known oil and water viscosities, we can estimate the microemulsion viscosity. Both low and high viscosity formulations were tested in corefloods and oil recovery measured to illustrate the importance of low viscosity microemulsions for oil recovery. As expected, the low viscosity microemulsions correlated with higher oil recovery. In addition, the equilibration times to reach Winsor Type III microemulsions were also linked to better oil recovery. For the well behaved formulations that equilibrated in less than 2 days the static microemulsion viscosity correlated well with the dynamic viscosity. The modified steady state relative permeability setup can accurately estimate microemulsion viscosity and allow for better screening of surfactant formulations identified for field flooding. The dynamic microemulsion viscosities can also provide inputs for numerical simulation and better predict microemulsion behavior in the subsurface during field surfactant floods.
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)
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.
Alexis, Dennis (Chevron Energy Technology Company) | Varadarajan, Dwarakanath (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Winslow, Greg (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company)
Performance of current synthetic EOR polymers is primarily constrained by salinity, temperature and shear which restrict their application to low to moderate salinity, low to moderate temperature and relatively high permeability reservoirs. The primary goal of the current work is to qualify recently developed associative polymers (AP) for EOR applications as well as to study their behavior in porous media. We also compare their performance with conventional non-associative polymers. In this work, we present the evaluation of several associative polymers. Two broad types of associative polymers were tested, one with a partially hydrolyzed poly acrylamide (HPAM) backbone and the other with a sulfonated HPAM backbone. The concentrations of the tested polymer vary between 75 ppm and 1000 ppm. We demonstrate the applicability of these innovative AP's through the carefully controlled lab experiments: (1) Corefloods in sandpacks to compare the sweep behaviors with conventional HPAM's. (2) Single phase flooding experiments are carried out in consolidated outcrop rocks to identify optimal polymer concentrations to achieve the desired in-situ resistance. (3) One dimensional displacement experiments with 8 cP and 90 cP oil are carried out in both unconsolidated and consolidated rocks at different temperatures to validate improved oil recovery. Results generally indicate that associative polymers require lower polymer concentration to generate high resistance factors in porous media and have stable long term injectivity behavior in high permeability rocks (>1D). Associative polymers with HPAM backbone have better filterability and injectivity in comparison to those with HPAM sulfonated backbone in low permeability(<300mD) rocks. Improved oil recovery in high permeability rocks compare well with conventional HPAM and sulfonated HPAM polymers. Based on the laboratory results, we are able to establish the selection baseline for associative polymers in different permeability rocks, salinities and temperatures. Such information can be used to select and screen the appropriate associative polymers, resulting in extending their applicability envelope in EOR.