Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs

Mokhtari, R.; Anabaraonye, Benaiah U.; Afrough, Armin; Mohammadkhani, Samira; Feilberg, Karen L.

doi:10.1016/j.petrol.2021.109282

Cited by 32 publications

(26 citation statements)

References 65 publications

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“…While the recovery factors for these two different rock materials are different, in both cases, DSW (1/10) and FW are better candidates for enhanced oil production when compared to SW. This observation is in line with a recent study on reservoir chalk from Tor formation [54]. For core plugs from Ekofisk formation, both FW and DSW (1/10) showed more than 9% additional oil recovery compared to SW.…”

Section: Brine Effectsupporting

confidence: 92%

“…In both experiments, we observe significant increases, relative to the injected brine concentrations, in the effluent calcium concentrations; this is indicative of calcium carbonate dissolution [56]. We also observed a decrease in magnesium concentrations; these results are consistent with a recent core-flooding study on standard core plugs from Tor formation [54]. As shown in Table 6, these increases are higher with the injection of DSW (1/10).…”

Section: Tertiary Water Floodingsupporting

confidence: 90%

“…The present study was carried out on a series of short core plugs and it is important to note the similar results obtained from longer core plugs reported in Mokhtari et al (2021) for Tor formation [54]. In addition, the effects of pressure and temperature on these lowsalinity effects would be worth exploring in future work, as the present study is focused on the conditions for the chalk reservoirs in the Ekofisk and tor formations in the Danish North Sea.…”

Section: Discussionmentioning

confidence: 62%

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Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study

et al. 2021

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We present a systematic study of crude oil–brine–rock interactions in tight chalk cores at reservoir conditions. Flooding experiments are performed on outcrops (Stevns Klint) as well as on reservoir core plugs from Dan field, the Ekofisk and Tor formations. These studies are carried out in core plugs with reduced pore volumes, i.e., short core samples and aged with a dynamic ageing method. The method was evaluated by three different oil compositions. A series of synthetic multicomponent brines and designed fluid injection scenarios are investigated; injection flow rates are optimized to ensure that a capillary-dominant regime is maintained. Changes in brine compositions and fluid distribution in the core plugs are characterized using ion chromatography and X-ray computed tomography, respectively. First, we show that polar components in the oil phase play a major role in wettability alteration during ageing; this controls the oil production behavior. We also show that, compared to seawater, both formation water and ten-times-diluted seawater are better candidates for enhanced oil recovery in the Dan field. Finally, we show that the modified flow zone indicator, a measure of rock quality, is likely the main variable responsible for the higher oil recoveries observed in Tor core samples.

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Section: Brine Effectsupporting

confidence: 92%

Section: Tertiary Water Floodingsupporting

confidence: 90%

Section: Discussionmentioning

confidence: 62%

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Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study

et al. 2021

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“…The injection of ion-engineered water, or low salinity water as it is popularly referred to, has gained acceptance in the industry. Several works of literature [ 21 , 22 , 23 , 24 , 25 , 26 , 27 , 28 ] exist on oil recovery improvement due to ion-tuned water injection, with several mechanisms identified to be responsible for the observed recovery. This section examines the effect of ion-tuned water on the surface charge development of the particles under study.…”

Section: Resultsmentioning

confidence: 99%

Effect of Native Reservoir State and Oilfield Operations on Clay Mineral Surface Chemistry

et al. 2022

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An understanding of clay mineral surface chemistry is becoming critical as deeper levels of control of reservoir rock wettability via fluid–solid interactions are sought. Reservoir rock is composed of many minerals that contact the crude oil and control the wetting state of the rock. Clay minerals are one of the minerals present in reservoir rock, with a high surface area and cation exchange capacity. This is a first-of-its-kind study that presents zeta potential measurements and insights into the surface charge development process of clay minerals (chlorite, illite, kaolinite, and montmorillonite) in a native reservoir environment. Presented in this study as well is the effect of fluid salinity, composition, and oilfield operations on clay mineral surface charge development. Experimental results show that the surface charge of clay minerals is controlled by electrostatic and electrophilic interactions as well as the electrical double layer. Results from this study showed that clay minerals are negatively charged in formation brines as well as in deionized water, except in the case of chlorite, which is positively charged in formation water. In addition, a negative surface charge results from oilfield operations, except for operations at a high alkaline pH range of 10–13. Furthermore, a reduction in the concentrations of Na, Mg, Ca, and bicarbonate ions does not reverse the surface charge of the clay minerals; however, an increase in sulfate ion concentration does. Established in this study as well, is a good correlation between the zeta potential value of the clay minerals and contact angle, as an increase in fluid salinity results in a reduction of the negative charge magnitude and an increase in contact angle from 63 to 102 degree in the case of chlorite. Lastly, findings from this study provide vital information that would enhance the understanding of the role of clay minerals in the improvement of oil recovery.

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“…In an analysis of the impact of LSW flooding on chalk core samples, Mokhtari et al 81 concluded that 10-fold diluted SW exhibits greater recovery than FW and SW. Furthermore, the scientists deduced from the ion effluent study that mineral dissolution cannot be the sole mechanism responsible for the observed recovery and that the effect of SO 4 2– is not responsible for observed recovery in all situations.…”

Section: Smart and Low Salinity Watermentioning

confidence: 99%

Effect of Sulfate-Based Scales on Calcite Mineral Surface Chemistry: Insights from Zeta-Potential Experiments and Their Implications on Wettability

et al. 2022

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Scale formation and deposition in the subsurface and surface facilities have been recognized as a major cause of flow assurance issues in the oil and gas industry. Sulfate-based scales such as sulfates of calcium (anhydrite and gypsum) and barium (barite) are some of the commonly encountered scales during hydrocarbon production operations. Oilfield scales are a well-known flow assurance problem, which occurs mainly due to the mixing of incompatible brines. Researchers have largely focused on the rocks’ petrophysical property modifications (permeability and porosity damage) caused by scale precipitation and deposition. Little or no attention has been paid to their influence on the surface charge and wettability of calcite minerals. Thus, this study investigates the effect of anhydrite and barite scales’ presence on the calcite mineral surface charge and their propensity to alter the wetting state of calcite minerals. This was achieved vis-à-vis zeta-potential (ζ-potential) measurement. Furthermore, two modes of the scale control (slug and continuous injections) using ethylenediaminetetraacetic acid (EDTA) were examined to determine the optimal control strategy as well as the optimal inhibitor dosage. Results showed that the presence of anhydrite and barite scales in a calcite reservoir affects the colloidal stability of the system, thus posing a threat of precipitation, which would result in permeability and porosity damage. Also, the calcite mineral surface charge is affected by the presence of calcium and barium sulfate scales; however, the magnitude of change in the surface charge via ζ-potential measurement is insignificant to cause wettability alteration by the mineral scales. Slug and continuous injections of EDTA were implemented, with the optimal scale control strategy being the continuous injection of EDTA solutions. The optimal dosage of EDTA for anhydrite scale control is 5 and 1 wt % for the formation water and seawater environments, respectively. In the case of barite, in both environments, an EDTA dosage of 1 wt % suffices. Findings from this study not only further the understanding of the scale effects on calcite mineral systems but also provide critical insights into the potential of scale formation and their mechanisms of interactions for better injection planning and the development of a scale control strategy.

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Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs

Cited by 32 publications

References 65 publications

Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study

Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study

Effect of Native Reservoir State and Oilfield Operations on Clay Mineral Surface Chemistry

Effect of Sulfate-Based Scales on Calcite Mineral Surface Chemistry: Insights from Zeta-Potential Experiments and Their Implications on Wettability

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