Enhanced Wettability Alteration by Surfactants with Multiple Hydrophilic Moieties
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The main production mechanism during water flooding of naturally fractured oil reservoirs is the spontaneous imbibition of water into matrix blocks and resultant displacement of oil into the fracture system. This is an efficient recovery process when the matrix is strongly water-wet. However, in mixed- to oil-wet reservoirs, secondary recovery from water flooding is often poor. Oil production can be improved by dissolving low concentrations of surfactants in the injected water. The surfactant alters the wettability of the reservoir rock, enhancing the spontaneous imbibition process. Our previous study revealed that the two main mechanisms responsible for the wettability alteration are ion-pair formation and adsorption of surfactant molecules through interactions with the adsorbed crude oil components on the rock surface. Based on the superior performance of surfactin, an anionic biosurfactant with two charged groups on the hydrophilic head, it was hypothesized that the wettability alteration process might be further improved through the use of dimeric or gemini surfactants, which have two hydrophilic head groups and two hydrophobic tails. We believe that when ion-pair formation is the dominant wettability alteration mechanism, wettability alteration in oil-wet cores can be improved by increasing the charge density on the head group(s) of the surfactant molecule since the ion-pair formation is driven by electrostatic interactions. At a concentration of 1.0 mmol L−1 a representative anionic gemini surfactant showed oil recoveries of up to 49% original oil-in-place (OOIP) from oil-wet sandstone cores, compared to 6 and 27% for sodium laureth sulfate and surfactin, respectively. These observations are consistent with our hypothesis.
KeywordsSpontaneous imbibition Wetting Anionic surfactant Charge density Dimeric surfactant Gemini surfactant
Much of the world’s oil is in reservoirs which contain high conductivity fractures surrounding low-permeability matrix blocks that are oil-wet/mixed-wet [1, 2]. Water flooding recoveries are typically low from such reservoirs. In fractured reservoirs, oil recovery depends on spontaneous imbibition of water to expel oil from the matrix into the fracture system, provided that the matrix blocks are water-wet. To enhance the spontaneous imbibition process in fractured reservoirs, low concentrations of surfactants in injected fluids are used to modify the wettability of the reservoir rock [3, 4]. The surfactant alters the wettability of the reservoir rock to a more water-wet state, enhancing the spontaneous imbibition process . A previous study by the present authors revealed that ion-pair formation and adsorption of surfactant molecules through interactions with the adsorbed crude oil components on the rock surface are the two main mechanisms responsible for the wettability alteration . It was hypothesized that the wettability alteration process might be improved through the use of dimeric (gemini) surfactants, which have two hydrophilic head groups and two hydrophobic tails. Berea cores aged in crude oil were used as porous media in imbibition studies to test this hypothesis. An anionic gemini surfactant (a xylene di C14/C16 sulfonate) was tested against sodium laureth sulfate and surfactin, a biosurfactant with two negative charges on the oligopeptide head group.
IFT was measured between equal volumes of 1.0 mmol L−1 surfactant solution and Soltrol 130 using a Fisher Model 20 ring tensiometer. IFT values versus Soltrol were: SLS, 6.4 mN m−1; surfactin, 4.0 mN m−1; and gemini, 8.0 mN m−1. The base number was obtained following the ASTM nonaqueous potentiometric titration method (D-2896) . The acid number was initially inferred using the correlation between acid number and API gravity of crude oil published by Fan and Buckley , and later confirmed by titration  according to Stan McCool (personal communication).
Berea sandstone cores were characterized (porosity, permeability, homogeneity) using 10 g L−1 NaCl brine and then initial water saturations were established by flooding the cores with Soltrol 130. The Soltrol 130 was displaced with Lansing Kansas City crude oil and cores were aged under crude oil at 90 °C for 1 month to render them oil-wet. The crude oil was displaced with multiple pore volumes of Soltrol 130 prior to imbibition testing. Aged cores had a typical Amott–Harvey index (IA–H) of −0.4.
To allow multiple tests on the same core, a cleaning protocol was used based on a method developed by Hirasaki et al.  Core cleaning was performed in a Hassler-Type core holder (Temco, Tulsa, OK) in a fume hood. The Viton® sleeves used in the core holder were sensitive to the solvents used, so the cores, along with the distribution plugs, were wrapped using fluorinated ethylene polymer (FEP) Teflon® heat-shrinkable tubing (Zeus Industrial Products Inc., Orangeburg, SC) and placed in an oven at 190 °C to allow the FEP to shrink before cooling and placing in the core holder sleeve. Solvents were delivered from glass transfer cylinders with a Teflon® piston. Water from a ConstaMetric pump (LDC Analytical, Stoke, UK) was used to drive the piston, which displaced the solvent through PEEK™ tubing into the core. For each core, approximately two pore volumes (PV) of tetrahydrofuran (THF) was injected daily until the effluent was no longer visibly discolored. THF was then displaced by injecting at least two PV chloroform (CHCl3) daily for several days. Finally, the chloroform was displaced with several PV of methanol (CH3OH) and the methanol was displaced with several PV of water. The core was then oven dried at 90 °C. A full Amott-Harvey wettability test on cores that were cleaned and aged multiple times was not performed; however spontaneous imbibition of brine was not observed in any of the cores so treated.
Imbibition tests were performed by placing cores in an Amott cell (Custom Lab Glass Service, Peculiar, MO) filled with brine with or without surfactant and monitoring oil production over time at room temperature.
Results and Discussion
A representative dimeric surfactant was shown to be appreciably more effective than either a monomeric surfactant (SLS), or surfactin, a biosurfactant with a doubly charged oligopeptide head, at displacing oil from a Berea core by spontaneous imbibition of NaCl brine at a surfactant concentration of 1.0 mmol L−1. These observations are consistent with our hypothesis that when ion-pair formation is the dominant wettability alteration mechanism, wettability alteration in oil-wet cores can be improved by increasing the charge density on the head group(s) of the surfactant molecule. This may have significant implications for oil production from naturally fractured, oil-wet reservoirs. However, more work is required to identify whether this translates to more complex brines containing e.g. divalent ions.
The authors would like to thank the US Department of Energy (DOE) for funding this work through Contract NO. DF-FC26-04NT15523. Thanks also to Mr. Gregory Bala and Ms. Sandra Fox at Idaho National Laboratory, Idaho Falls, for providing and characterizing surfactin, and to Dr. Wenyu Zhang (SINOPEC), visiting scholar at the Tertiary Oil Recovery Project, for acid number measurement. We extend our thanks to the Department of Chemical and Petroleum Engineering at the University of Kansas.
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