Improved Oil Recovery from Carbonate Reservoirs by Chemical Stimulation

Xie, Xiangyang; Weiss, W.W.; Tong, Z.; Morrow, Norman R.

doi:10.2118/89424-ms

Cited by 52 publications

(31 citation statements)

References 11 publications

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“…In order to alter wettability by using surfactants, three different types of surfactants including anionic surfactants (Standnes, andAustad, 2000a, Ronaldo, et al, 2006;Golabi, et al, 2008), non-ionic surfactants (Chen, et al 2000;Golabi, et al, 2009), and ammonium type of cationic surfactants are used (Tabatabal, et al, 1993;Xie, et al, 2004, Golabi, et al, 2009.…”

Section: Introductionmentioning

confidence: 99%

Experimental Study of Wettability Alteration of Limestone Rock from Oil-Wet to Water-Wet using Various Surfactants

et al. 2012

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The water flooding in the carbonate fracture reservoir is low efficiency because of higher permeability in fractures than in matrix, and water will not imbibe spontaneously into the matrix due to a negative capillary pressure. Spontaneous imbibition of water into carbonate fracture reservoir is a very important issue in secondary oil recovery method. However, almost more than 80% of the entire known carbonate reservoir can be categorized as oil wet. It is therefore important to find methods to alter the wettability from oil-wet to water-wet conditions that are effective in order to improve the recovery from carbonate fracture reservoir. So far, two methods have been developed wettability alterations: 1) addition of certain chemical surface active agent to the injection water, and 2) thermally wettability alteration by steam injection. In this study, an oil sample with 20 API was used to investigate the effect of the understudied surfactants on wettability alteration in the oil-water-limestone system. Understudied surfactants were SDBS (sodium dodecylbenzene sulfonate), C 12 TAB (dodecyl trimethyl ammonium bromide), C 16 TAB (hexadecyl trimethyl ammonium bromide) and Triton X-100 that were utilized at 0.5, 1.5 and 2.5 wt% concentrations. The experiments were performed several times (0, 1, 6, 12, 24, 48, 72, 96 h) after injection of oil drop under limestone rock sample at reservoir temperature of 80 o C. The obtained results showed that the increasing each of the surfactant could cause wettability alteration of the rock from oil-wet towards water-wet situation by passing of time. This alteration was very sharp at the beginning, but it was increases slightly at the time. It was observed that Triton X-100 was more efficient than C 16 TAB, C 12 TAB and SDBS to alter the wettability of the rock.

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Section: Introductionmentioning

confidence: 99%

Experimental Study of Wettability Alteration of Limestone Rock from Oil-Wet to Water-Wet using Various Surfactants

et al. 2012

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“…A wide range of surfactants have been evaluated over the past 30 years for enhanced oil recovery by performing static imbibition experiments. These studies have included tests with cationic surfactants (Austad and Milter, 1997;Standnes and Austad, 2000;Xie et al, 2005;Sharma and Mohanty, 2013), nonionic surfactants (Standnes et al, 2002;Xie et al, 2005;Gupta et al, 2010;Sharma and Mohanty, 2013), and anionic surfactants (Seethepalli et al, 2004;Nurkamelia and Arihara, 2004;Adibhatla and Mohanty, 2008;Gupta and Mohanty, 2010;Sharma and Mohanty, 2013;Chen and Mohanty, 2013;Wang and Mohanty, 2014;Lu et al, 2014). Austad et al (1998) used the cationic surfactant Dodecyl Trimethyl Ammonium Bromide (DTAB) and chalk cores with a diameter of 3.7 cm.…”

Section: Introductionmentioning

confidence: 99%

“…The C12TAB gave about 40-45% oil recovery compared to only 10% for the ethoxylated alcohol. Xie et al (2005) tested both a cationic surfactant and a nonionic surfactant in dolomite cores with diameters of 2.54 cm and 3.8 cm. Seethepalli et al (2004) identified several anionic surfactants that change the wettability of carbonate surfaces from oil wet to intermediate-or water-wet as well as or better than the cationic surfactant DTAB.…”

Section: Introductionmentioning

confidence: 99%

Scaling of Low IFT Imbibition in Oil-Wet Carbonates

Churchwell

et al. 2016

All Days

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Primary and secondary oil recovery from naturally fractured carbonate reservoirs with an oil-wet matrix is very low. Enhanced oil recovery from these reservoirs using surfactants to alter the wettability and reduce the interfacial tension have been extensively studied for many years, but there are still many questions about the process mechanisms, surfactant selection and testing, experimental design and most importantly how to scale up the lab results to the field. We have conducted a series of imbibition experiments using cores with different vertical and horizontal dimensions to better understand how to scale up the process. There was a particular need to perform experiments with larger horizontal dimensions since almost all previous experiments have been done in cores with a small diameter, typically 3.8 cm. We adapted and modified the experimental method used for traditional static imbibition experiments by flushing out fluids surrounding the cores periodically to better estimate the oil recovery, including the significant amount of oil produced as an emulsion. We used microemulsion phase behavior tests to develop high performance surfactant formulations for the oils used in this study. These surfactants gave ultra-low IFT at optimum salinity and good aqueous stability. Although we used ultra-low IFT formulations for most of the experiments, we also performed tests at higher IFT for comparison. Even for the higher IFT experiments, the capillary pressure is very small compared to gravity and viscous pressure gradients. We also developed a simple analytical model to predict the oil recovery as a function of vertical and horizontal fracture spacing, rock properties and fluid properties. The model and experimental data are in good agreement considering the many simplifications made to derive the model. The scaling implied by the model is significantly different than traditional scaling groups in the literature.

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“…Recent years have witnessed an increasing interest in surfactant mediated wettability alteration and enhanced spontaneous imbibition in oil-wet carbonates. There are a wide range of choices in the selections of surfactants: nonionic surfactants (Vijapurapu and Rao, 2004;Standnes et al, 2002;Xie et al, 2005), cationic surfactants (Austad et al, 1998;Standnes et al, 2002) and anionic surfactants (Seethepalli et al, 2004, Sharma andMohanty, 2011;Chen and Mohanty, 2013).…”

Section: Introductionmentioning

confidence: 99%

Surfactant-Enhanced Oil Recovery from Fractured Oil-wet Carbonates: Effects of Low IFT and Wettability Alteration

Chen

Mohanty

2015

Day 1 Mon, April 13, 2015

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The performance of surfactant-enhanced oil recovery (EOR) in fractured carbonates relies on spontaneous imbibition or low IFT-aided gravity drainage. This work investigated the synergism between wettability effects and IFT reduction mediated by a variety of surfactants through experiments and numerical simulation studies. Experiments have shown that oil can be recovered from oil-wet Silurian dolomite fracture blocks either by capillarity driven imbibition, gravity-driven imbibition or low tension-aided gravity drainage. The mixture of wettability alteration (WA) surfacant with IFT reduction surfactant exhibits the synergistic effect on the imbibition oil recovery from oil-wet carbonate rocks. It was found that divalent ion scavengers help the wettability altertion capability of some sulfonate surfactants in hard brine, which leads to the high oil recovery up to 70% OOIP (IFTϩWA), compared with oil recovery of 30-50% OOIP by sulfonate surfactant only (only IFT reduction). We proposed a mechanism that the presence of a sufficient amount of divalent ion scavengers in the anionic surfactant formulation reduces the free divalent cations in hard brine, which then promotes the release of surfactant monomers from the micelles and enhances wettability alteration by surfactant adsorption. The UTCHEM simulation results confirmed the existence of synergism between IFT reduction and WA in spontaneous imbibition processes. According to the capillary desaturation curve (CDC), that residual oil saturation after gravity drainage is approximately 10% to 20% higher than gravity-driven spontaneous imbibition when two processes have the similar trapping numbers, confirming that the wettability alteration contributes to the ultimate oil recovery.

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Improved Oil Recovery from Carbonate Reservoirs by Chemical Stimulation

Cited by 52 publications

References 11 publications

Experimental Study of Wettability Alteration of Limestone Rock from Oil-Wet to Water-Wet using Various Surfactants

Experimental Study of Wettability Alteration of Limestone Rock from Oil-Wet to Water-Wet using Various Surfactants

Scaling of Low IFT Imbibition in Oil-Wet Carbonates

Surfactant-Enhanced Oil Recovery from Fractured Oil-wet Carbonates: Effects of Low IFT and Wettability Alteration

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