Next-generation surfactants improve chemical flooding

The final report in this series details US Department of Energy (DOE)-sponsored research leading to improved understanding of chemical methods for EOR. The third phase of the research deals with next-generation surfactants for improved chemical flooding.

The objective of this project was to characterize and test current and next-generation high-performance surfactants for improved chemical flooding technology focused on reservoirs in the Pennsylvanian-aged (Penn) sands in Oklahoma. According to the Oklahoma Geological Survey, the state’s original oil in place has been estimated to be 84 Bbbl with an expected ultimate recovery of about 18 Bbbl projected due to the complexity of reservoir geometries and poor reservoir management, leaving 68 Bbbl of “trapped” oil. Producing this residual oil requires interfacial tension (IFT) values of less than 10milliNewton/m.

Achieving these ultra-low values is possible through injection of surfactant solutions, but developing surfactant formulations stable in common reservoir brines is a challenge. In the current project, surfactant formulations using the ultra-low IFTs obtainable with three-phase systems were developed for six Penn sands oil reservoirs located in Oklahoma.

Recent models relating surfactant structure were extended to optimize microemulsion formulation through the relationship between the theoretically accessible packing factor (Pf) calculation and the experimentally measurable characteristic curvature (Cc) of the surfactant in the surfactant membrane in a microemulsion. This was accomplished by extending the range of surfactants for which the Cc has been measured to surfactants typical of those used for EOR. The determination of the characteristic curvatures of 28 surfactants having a variety of chemical structures was performed. In addition, this included the study of a suite of novel petroleum sulfonates, the recently commercialized extended surfactants (alkylethoxypropoxy sulfates), and a new series of disulfonates optimized for microemulsion formation. In particular, the current Pf calculation was modified to better account for multiple and branched hydrophobes, which improved the correlation between the calculated Pf and the measured Cc.

The relationship between new surfactants, cosurfactant (e.g., alcohol) concentrations, pH, and sacrificial agents to minimize the surfactant adsorption at the brine/rock interface was studied. While current surfactant concentrations for EOR are much lower than those used earlier, the ability to reduce those concentrations further is limited by the high adsorption of the surfactant by the reservoir rock.

Improving the ability to design low-IFT formulations that simultaneously have ultra-low adsorptions on the reservoir rock can be a significant advancement in improving the commercial viability of surfactant flooding technology.

Correlations between the optimal salinity, the Cc of the surfactant, the critical microemulsion concentration (C µ C), and the achievement of ultra-low IFTs at concentrations below the C µ C also were researched. It has been shown that ultra-low IFT can be achieved without the formation of a microemulsion. If a correlation between ultra-low IFT in the absence of microemulsion formation and the microemulsion phase diagram can be determined, it will be possible to use recent design equations for microemulsion formulation to design surfactants to produce ultra-low IFTs at concentrations below those required for the formation of a middle phase (Winsor Type III) microemulsion.

Case studies

In addition to determining characteristic curvature values, stable surfactant formulations were developed for eight Penn sand reservoirs. For Reservoir M, where crude oil was found to have an equivalent alkane carbon number of 11 and in the corresponding brine a total dissolved solids content of 18 wt%, the development of effective surfactant formulations for this reservoir was approached by two different methods (case studies 1 and 2) for surfactant selection, while the evaluation involved in determining the optimal formulations relied on the same criteria and laboratory methodologies for both case studies. The optimal formulations were evaluated in sandpack column tests and in core-flood tests using Berea sandstone, reservoir crude oils, and brines at reservoir temperatures.

In case study 1 the initial surfactant mixture contained the cosolvent isopropanol, which was found to be associated with the precipitation of iron from the brine. Several tertiary surfactant mixtures were formulated, with the mixture consisting of the surfactants identified as AOT/W-7/PC-4 being selected for use in sandpack column tests. While holding the total surfactant concentration at 0.38 wt% but decreasing the polymer concentration from 2,000 ppm to 1,000 ppm, the residual oil recovery decreased from 46% to 32%, respectively. The relatively low values of residual oil recoveries in core flood studies for case study 1 may be explained in the length of the cores used for the core flood studies. The cores were 1.22 in. to minimize the pore volume, which has the positive impact of shorter overall run times for each experiment. However, the oil recovery results for core flood studies likely suffered from end effects that may have diminished residual oil recovery. Longer core lengths and, therefore, longer core flood run times are necessary to more adequately reflect the results in field studies.

In case study 2 the selection of potential surfactants for use in a surfactant formulation for Reservoir M was based on the relationships described by the hydrophilic-lipophilic difference (HLD) equation, which relates surfactant characteristic curvatures to oil properties and salinities. Based on this equation, four anionic primary surfactants were selected for further testing along with two anionic cosurfactants. The identities of these surfactants are considered proprietary. The ratios of 0.2/0.04 wt% and 0.2/0.06 wt% AP12-3/PC-4 were found to be optimal for 14 wt% and 17 wt% sodium chloride, respectively. The surfactant formulations containing A45-4/PC-4 and A45-4/W-7 also were found to be stable, and sandpack column tests were conducted using all three formulations with differing polymers. For the formulations tested, the residual oil recoveries ranged from 50% to 64.3%, with the greatest recoveries being accomplished using the AP12-3/PC-4 and A45-4/W-7 formulations. Due to the better results obtained in the core flood, the case study 2 results will be discussed in more detail.

Phase behavior, stability, and IFT

The surfactants were selected for this work as primary surfactants due to encouraging results obtained with some of these structures at moderate salinities in preliminary studies. One of the main objectives was to take advantage of the positive performance exhibited by these surfactants by mixing them with highly hydrophilic cosurfactants (W-7 and PC-4) to increase their solubility and optimal salinities. The use of the HLD equation takes into consideration the relative hydrophobic balance of the surfactant mixture in the solution to calculate its optimal formulation – that is, a zero value for the HLD. This optimum would correspond to an equal water and oil solubility for the surfactant system and, therefore, a near-net zero curvature for the bicontinuous microemulsion (type III or IV).

A 1:1 water:oil ratio was used for the phase behavior tests. Using the target salinity, the optimal surfactant formulation was obtained by varying the surfactant/cosurfactant ratio in a binary surfactant mixture. The occurrence of a middle-phase microemulsion was verified by visual observation. Phase behavior samples were left to reach equilibrium at reservoir temperatures for a month. IFT was measured dynamically between decane and surfactant solutions at 42?C (108°F) as reference temperature using a Grace 6500 spinning drop tensiometer. Tests performed with crude oil and brines were conducted at reservoir temperatures of 42°C for Reservoir M. Surfactant/cosurfactant formulations were evaluated in terms of solution stability (no precipitation or phase separation), low IFT, coalescence times of the microemulsion (less than a day), and absence of undesired viscous phases.

Surfactant aqueous solutions in synthetic or reservoir brines (no oil) were left to age at different temperatures or at reservoir conditions for a minimum of one month. The occurrence of precipitate or phase separation was determined visually.

Low IFT and the presence of Type III microemulsions with high oil solubilization have been widely correlated to improvements in oil mobilization at reservoir conditions. For the primary surfactants used in this case study, the IFTs and phase behaviors as functions of salinity show typical transitions from Type I-Type III-Type II microemulsions (Figure 1). Optimal salinities were obtained from the minimum values of IFT, which corresponded to the Type III microemulsion phase characterized by the presence of a distinctive middle phase. Surfactants with short carbon chains (Figure 1a) showed much lower IFT than those with longer chains (Figure 1b).

One of the main objectives of this work was to develop and test new surfactant/polymer (SP) formulations for chemical flooding at high salinities. However, optimal salinities for the primary surfactants studied are relatively low, as shown in Figure 2. Based on previous studies and formulation approaches, mixtures of surfactants with different levels of hydrophobicity, as indicated by their Cc value, were considered to create systems with low/ultra-low IFTs and Type III microemulsions at salinities up to 20 wt%. For instance, mixtures of AP12-3 with PC-4 at different ratios were compared based on IFTs and phase behaviors (Figure 2). Changing the concentration of the cosurfactant makes it possible to design a surfactant formulation that could work at different salinities. Particularly, mixtures of 0.2/0.04 wt% and 0.2/0.06 wt% (AP12-3/PC-4) produce the minimum IFTs at 14 wt% and 17 wt% sodium chloride salinity, respectively. The binary surfactant system was stable at 42?C, near the optimum ratios and at higher cosurfactant ratios.

However, for salinities over 10 wt%, some precipitation was observed when the cosurfactant content was less than 10% of the total surfactant concentration. For all salinities studied, the optimum formulation was characterized by ultra-low IFT, Type III microemulsion phase behavior, no gel formation or undesired phase, and coalescence times below 48 hours. The results suggest that the binary surfactant systems could be adapted for use in different salinity conditions by simply varying the surfactant ratio.

SWTT of Reservoir M

The field test for Reservoir M comprised six distinct and separate events in a specific sequence at the well site. The first event was a brine flood of the target formation for four pore volumes (PVs) to mimic a waterflood process and ensure a low residual oil saturation (Sor) similar to the Sor observed for crude oil reservoirs nearing the end stages of waterflood processing. The second event was a single-well tracer test (SWTT) to confirm oil saturation in a volumetric zone extending from 1.5 m to 4.6 m (5 ft to 15 ft) from the wellbore over a 6.1-m (20-ft) perforated zone to determine the Sor of the target volume. The target volume was defined as a pore volume.

The third event was a two-day shut-in period to allow hydrolysis of the partitioning tracer to produce the secondary nonpartitioning tracer. The fourth event was the injection of the optimized laboratory-designed surfactant and polymer chemical flood formulation to mobilize the residual crude oil out of the target zone. The chemical flood was composed of a slug of approximately 0.5 PV of surfactant/polymer solution followed by a slug of approximately 0.1 PV of a polymer solution.

The fifth event was a brine push of approximately 3 PV to push the mobilized crude oil out of the target zone. The sixth and final event was an SWTT to measure the resulting Sor of the target volume to allow determination of the effectiveness of the chemical flood. The injection and production rate for this field study ranges from 150 b/d to 170 b/d.

Results

Shown in figures 3 and 4 are the normalized nonpartitioning and partitioning tracer data for the SWTT and the chromatographic transformation of the normalized ethanol concentration to determine the Sor of the target zone prior to the chemical flood. Shown in figures 5 and 6 are the normalized nonpartitioning and partitioning data for the SWTT and the chromatographic transformation of the normalized ethanol concentration to determine the Sor of the target zone after the chemical flood of the target zone.

In Figure 3 there is a marked difference in the production volume where the maximum concentrations of ethyl formate and ethanol are observed. The ethanol maximum concentration is observed at 10 bbl of production, and the ethyl formate maximum concentration is observed at 50 bbl of production. This delay in observing the ethyl formate maximum normalized concentration relative to the ethanol maximum normalized concentration is a direct result of partitioning of the ethyl formate into the crude

oil phase. Figure 4 shows the chromatographic transformation resulting in a retardation factor for tracer ( B ) value of 1.2 or an Sor value of 25% prior to the chemical flood.

In Figure 5 there is no significant difference in the production volume where the maximum normalized concentration of ethyl formate and maximum normalized concentration of ethanol are observed. Both the ethanol normalized maximum concentration and ethyl formate normalized maximum concentration are observed at 10 bbl of production. There is no ethyl formate maximum normalized concentration delay relative to the ethanol maximum normalized concentration as is observed in the first SWTT before the chemical flood. The overlay of the maximum ethanol normalized concentration and maximum ethyl formate normalized concentration is a direct result of a lack of ethyl formate partitioning into the crude oil phase since the residual crude oil phase has been significantly decreased by mobilization. Figure 6 shows the chromatographic transformation resulting in a B value of 0.1 and an Sor value of 2.7% post chemical flood.

Analysis of presurfactant/polymer and post-surfactant/polymer SWTT data shows that the chemical formulation that is investigated in the laboratory reduces the Sor from 25% to 7% in the field study. In other words, for this field study, at least 70% of the residual oil is successfully mobilized out of the target zone. The field study result confirms the effectiveness of the surfactant formulation observed in high-salinity brine laboratory studies.

Acknowledgments

The work described in the article was supported by awards from the DOE/National Energy Technology Laboratory (NETL). The author acknowledges permission given by the DOE to write the paper. The paper is based on reports presented by the principal investigators: Randy Seright, New Mexico Tech; Stan McCool, University of Kansas; Jeff Harwell, University of Oklahoma; and Beverly Seyler, Illinois Geological Survey. These and numerous other researchers contributed to the information in the paper.

References available on request.