Fluorinated benzoic acids (FBA) have been widely used in the oil industry as conservative tracers. However, some of these tracers have been shown to rapidly degrade when tested at temperatures above 121°C within three weeks. Naphthalene sulfonates (NSAs) have been shown to be excellent tracers in geothermal applications. However, a broader study was required to determine tracer conservation in reservoir fluids and formations typically encountered in the oil field.
In this study we compare the oil field industry standard FBA tracers to NSA tracers under dynamic test conditions in the presence of reservoir oil, sandstone, carbonates and clays. We also compare the two sets of tracers under static conditions in the presence of four crude oils and different clay mineralogy to establish tracer conservation. Seven different sodium salts of naphthalene sulfonic acids were tested to determine if the tracers were adsorbed onto natural porous media (reservoir rock) at reservoir conditions. A broad range of conditions were selected to target typical reservoirs encountered. In addition, reservoir rock and a pseudo formation containing 10 Wt.% clay in silica sand were used in sand packs saturated with surrogate brine to ensure the tracer recovery under dynamic conditions.
High pressure liquid chromatography (HPLC-FLD) separation was used for simultaneous detection of seven NSAs while FBAs were analyzed using HPLC-UV. GC analysis of isopropyl alcohol (IPA) was used as a standard against which the others were measured.
Dynamic tracer tests demonstrated that the sodium salts of naphthalene sulfonates behaved similarly to the control, IPA, with none of the tracers adsorbing on to the rock surface or partitioning into the oil phase. The naphthalene sulfonates can be successfully used as conservative tracers most specifically for high temperature applications. NSA tracers are an attractive replacement for conservative FBA tracers in the oil field due to their superior thermal stability, solubility in oil field brine, lower detection limits and cost.
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.