Surfactant Formulation Study for Bakken Shale Imbibition

Wang, Dongmei; Butler, Raymond; Liu, Hong; Ahmed, Salowah

doi:10.2118/145510-ms

Cited by 42 publications

(11 citation statements)

References 14 publications

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“…The observed recovery factors from the Bakken shale cores exceeded 45% using different surfactant formulations compared with only 6% recovery factor when used 2% KCl brine. In a similar study, Wang et al (2011) also studied different surfactant formulations to investigate the potential of chemical imbibition in Bakken shale at different temperatures and brine salinities. They mentioned that surfactant did not imbibe effectively in Bakken cores using distilled water or low saline water and the highest oil recovery achieved was 19% using 0.1 wt% of 58N, cationic surfactant, 0.1 wt% alkali (NaBO 2 .…”

Section: Effect Of High Ph Solutions (Alkaline) On Mineral Dissolutiomentioning

confidence: 99%

Imbibition Characteristics of the Barnett Shale Formation

Morsy¹,

Sheng²

2014

SPE Unconventional Resources Conference

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In order to understand the effect of injected stimulation fluids on nano-darcy permeability, naturally fractured shale reservoirs, an integrated study of spontaneous imbibition has been performed. In this study, oil recovery during spontaneous imbibition in naturally fractured shale samples was improved using different water formulations. Different water solutions were formulated by adding different amounts of HCl and NaOH to either distilled water or 2 wt% KCl-base brine solution. Eight water formulations, distilled water, 2% KCl brine, low pH HCl solutions (0.74-1.2), and high pH alkaline solutions (11.7-12.4) were examined to recover oil from shale rocks. Outcrop samples from the Barnett shale formation were used in this study. The samples were 2.54 to 3.81 cm in diameter and 0.762 to 5.08 cm in length. Firstly, we studied the average porosity of the used samples using CT Scanning. The average porosity was around 7%. Secondly, we studied the rock stability and spontaneous imbibtion of the different Barnett samples in distilled water, 2 wt% KCl, low pH solutions (0.74-1.2), and high pH alkaline solutions (11.7-12.4). During the spontaneous imbibition, the maximum oil recovery was 24% using distilled water and low pH solution of pH0.74 (3 wt% HCl in 2 wt% KCl base brine solution). Clay swelling can contribute to the Barnett oil recovery improvement by creating along bedding cracks. Oil recoveries from the Barnett shale can be improved by 56% when used 2 wt% NaOH solution and 88% when used 3 wt% HCl when added to 2 wt% KCl simulation base fluid. High pH solutions did not improve oil recoveries from the Barnett samples when added to distilled water due to pore plugging resulted from the combination of clay swelling with mineral dissolution. Low pH solutions showed along bedding cracks similar to distilled water effect on the Barnett shale samples that helped recovery accelerations, while higher pH solutions showed sever samples damage with higher alkaline concentrations (2 wt% NaOH).

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Section: Effect Of High Ph Solutions (Alkaline) On Mineral Dissolutiomentioning

confidence: 99%

Imbibition Characteristics of the Barnett Shale Formation

Morsy¹,

Sheng²

2014

SPE Unconventional Resources Conference

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“…2 They suggested some nonionic, ionic, and cationic surfactants that are effective in enhancing oil recovery at high temperatures 2 . Their study revealed that surfactant concentration, brine salinity, and divalent ion concentration are the major factors affecting oil recovery from shale.…”

Section: Introductionmentioning

confidence: 99%

Dynamic Interfacial Tensions and Contact Angles of Surfactant-in-Brine/Oil/Shale Systems: Implications to Enhanced Oil Recovery in Shale Oil Reservoirs

et al. 2014

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Unconventional shale oil resources have emerged as a significant source of fossil fuels in recent years. The oil contained in shales is held in natural microfractures, micropores, and inside nanopores of the organic matter. The strong capillary forces in these pores can bind the oil to the surface with strengths that are inversely proportional to the pore radius. In order to recover more oil from these pores, it is beneficial to reduce the capillary pressure by manipulating the interfacial tension and contact angle of oil/brine/shale systems using surfactant solutions. The main consideration in surfactant flooding is to optimize brine salinity and surfactant concentration while minimizing their adsorption on rock surfaces. Although the effect of some surfactants on recovery in shale oil reservoirs has been studied in the past, the mechanism is still unclear. Moreover, the limited data available in the literature is not representative of the actual reservoir conditions. The objective of this study is to elucidate the oil displacement mechanisms in shale oil by surfactant flooding. The phase behavior of several anionic surfactants was studied in the presence of crude oil at reservoir temperature (i.e. 80 °C). The results of these tests were used to screen the best surfactants. Dynamic interfacial tensions (IFT) and contact angles (CA) of selected surfactant-in-brine/oil/shale systems were measured by the rising/captive bubble technique using a state-of-the-art IFT/CA apparatus. The apparatus was thoroughly validated with various systems using the axisymmetric drop shape analysis technique. Using the same methodology, the effects of surfactant concentration (0.01 to 0.1 wt%) and brine salinity (0.1 to 5 M NaCl) on IFT and CA at ambient and reservoir conditions (i.e. 80 °C and 3000 psig) were studied. Surfactant adsorption on shale samples was also measured in brines at ambient conditions. Our data reveal that the most effective surfactant was able to reduce the oil-brine IFT from its original value (23 mN/m) down to 0.3 mN/m at reservoir condition. A reduction in the IFT value and an increase in the dynamic contact angle of oil drop on polished shale surface were observed with the addition of surfactant and salt to the system. A trend between these parameters, pressure, and temperature was also reported.

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“…The most suited surfactant formulations were discovered by laboratory studies, concerning imbibition improvement from oil shale in Bakken (US). Furthermore, the wettability of Bakken was determined through Amott tests [10,11]. Imbibition experiments on mineral plates were carried out including eight anionic surfactants and three nonionic surfactants, and they confirmed that oil recovery increases as wettability alteration increases [12].…”

Section: Cos Cmentioning

confidence: 86%

EOR of Spontaneous Imbibition by Surfactant Solution for Tight Oil Reservoirs

Shen¹,

Liu²,

Liang³

et al. 2018

IJPE

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Spontaneous imbibition has been well investigated due to its impacts on oil recovery in conventional and fractured reservoirs. Differentiated in relation to the conventional reservoir, the tight reservoir is characterized by its ultra-low porosity and permeability. The scope of current research is to study the mechanism of imbibition under conditions of tight cores and surfactant solution. A series of experiments was conducted to determine the effects of tight core imbibition including three kinds of common surfactant solutions. The main factors of low IFT (interfacial tension) and wettability alteration are examined. The experimental results indicate that the original wettability affects the imbibition oil recovery, since low IFT and wettability alteration constitute beneficial parameters for imbibition as it concerns adhesive work reduction. The parameter of NBm-1 was not applied for optimal IFT or CA (contact angle) calculation concerning porous media with reduced capillary scale. Future research concerning the imbibition mechanism should take the property of surfactant into account.

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Surfactant Formulation Study for Bakken Shale Imbibition

Cited by 42 publications

References 14 publications

Imbibition Characteristics of the Barnett Shale Formation

Imbibition Characteristics of the Barnett Shale Formation

Dynamic Interfacial Tensions and Contact Angles of Surfactant-in-Brine/Oil/Shale Systems: Implications to Enhanced Oil Recovery in Shale Oil Reservoirs

EOR of Spontaneous Imbibition by Surfactant Solution for Tight Oil Reservoirs

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