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The ultimate recovery from shale formations is relatively low compared to the total in-place reserves. The important role that these reservoirs have in the future of the oil and gas industry generates a significant need for cost-effective and environmentally-friendly enhanced oil recovery techniques. This study evaluates the application of enzyme EOR in shale reservoirs. Laboratory results of tests conducted on multiple cores taken from Woodford shale outcrops demonstrate an average of 20% improvement in the recovery factors.
Enzymes change the wettability of formation rocks and fluid systems by changing the interfacial tension which results in releasing hydrocarbons from the rock. In this study, enzyme solutions with concentrations of 10 and 5 wt.% are used on 6 different cores. Recovery factors of the spontaneous imbibition tests at this concentration were 11 and 22%, respectively, after a soak time of 200 hours. This compares to 2 and 12% recovery factors, respectively, in the control tests. The experiment is performed under static condition, addressing the change in the recovery of crude oil from each sample using spontaneous imbibition tests.
A suitable concentration of enzyme is identified to be 5 wt.%. Some of the shale samples used in this study were clay-rich and some were carbonate-rich. There was no significant difference in the EOR performance between the two categories of rocks.
Oil recovery in shale formations could be improved up to around 10% using cyclic gas injection. However, this study proves that adding biological enzymes has the potential to improve this recovery factor up to 25%. Moreover, the effect of enzymes is everlasting in the formation because the enzyme dissolved in formation water continues to invade pores and fractures in lower concentrations.
All oil recovery factors from shale and tight formations, in which the permeability is less than 0.1 mD and pore sizes with less than 100 nm in diameter are abundant, are reported to be less than 10% (Sheng, 2017; Salahshoor et al., 2018). The average oil recovery factor of Woodford shale is reported as 8.4% by Energy Information Administration (Advanced Resources International, 2013). Therefore, EOR techniques are massively explored to help with improving the recovery from these formations. However, the complex fluid flow and phase behavior of these formations make them more challenging in many aspects including finding the best EOR practices (Salahshoor and Fahes, 2018; Salahshoor and Fahs, 2018). Common EOR practices in shale and tight formations, including gas injection, water injection, and surfactant injection, are studied in numerous industry and academic research publications.
Understanding the behavior of water-in-crude-oil emulsions is necessary to determine its effect on oil and gas production. The presence of emulsions in any part of the production system could cause many problems such as large pressure drop in pipelines due to its high viscosity. Electrical submersible pumps (ESPs) and gas lift are commonly used separately in lifting crude oil from wells. However, the use of downhole equipment and instruments such as ESPs that cause mixing can result in the formation of an emulsion with a high viscosity. The pressure required to lift emulsions is greater than the pressure required to lift non-emulsified liquids. Lifting an emulsion decreases the pressure drawdown capabilities, lowers production rate, increases the load on the equipment, shortens its life expectancy and can result in permanent equipment damage. Methods and apparatus which reduce the load on the pump, therefore, are desirable. The present paper is directed to understand the behavior of water-in-oil emulsions in artificial lift systems, mainly through gas lift.
Two stable water-in-oil synthetic emulsions were created in the laboratory and their rheology and stability characteristics were measured. One contained crude oil and the other, mineral oil. The second stage included measuring the effect of gas lift exposure on the emulsion behavior and characteristics. The results of the present work indicate that water-in-oil emulsions can be destabilized, and their viscosities lowered under gas exposure. The effect of gas injection on the emulsion was linked to the initial conditions of the emulsion as well as the gas type, injection rate and exposure time.
The present study is directed to methods and systems for combining both ESPs and gas lift for the purpose of improving and simplifying the lift of water-in-oil emulsions from oil wells. The novel methods and apparatus are based on the discovery that by adding gas above the ESPs in the wellbore, the viscosity of an oil-in-water emulsion is actually reduced, thus making it easier to lift oil from the well and extending the life of the ESP. Therefore, in addition to the normal benefits of gas in aiding the lift of liquids, if the gas lift valve is installed at a calculated distance above the pump location, the emulsion viscosity can be reduced. This reduces the load on the ESP.
Low-salinity water injection for EOR applications and for shale and tight sand fracturing has become a widely accepted approach. Experimental and modeling work is slowly unraveling the complexity of this system, with no unified theory to explain the fundamentals behind it. Our work adds a new spin to the topic, where the non-monotonic impact of salinity on contact angle reported in literature is linked to its non-monotonic impact on the properties of the water-oil interface.
We used a crude oil sample that originated from a field in Texas to create surfactant-stabilized brine-in-oil emulsions. We synthesized different brine systems starting from deionized water using two different salts, NaCl and CaCl2 at 8.55, 85.5 and 855 mMol/L. We quantified the stability of the emulsion using both gravimetric and centrifuge methods. We measured the variation in the viscosity of the emulsion for different brine fractions from 10 to 50 wt%.
The results show a different effect of salt on stability for different values of water-cut. This effect can range from a stability being directly proportional to salt concentration in one case, to being inversely proportional to salt concentration in the other case, including a scenario where a non-monotonic impact is recorded.
The work provides a comprehensive and detailed set of experiments on various measurements relating to the brine-oil interactions away from the influence of rock minerals. It shows similar trends to what is reported in the literature on experiments and simulations where carbonate and sandstone rock minerals are included. This brings to question some of the theories that are used to explain this behavior given that the complexity is evident even without the rock presence.