Abstract:Carbon dioxide injection in shale reservoirs can be beneficial for enhanced oil recovery and CO2 storage scenarios. CO2 mass transfer can be influenced strongly by the in-situ liberation of light oil components from live oil forming a distinct gas phase. This mechanism has been overlooked in the past for studying CO2 and oil interactions in tight formations. In this work, a series of analytical solutions and numerical simulations were developed to identify the effect on EOR by CO2 due to the liberation of a li… Show more
“…During the pressure depletion (puff) stage, as the pressure in the fracture reduces to the puff pressure, the resulting pressure gradient induces the convective flow. Also, increasing gas expansion as pressure continues to drop could carry more crude oil from the matrix to the fracture (Mahzari et al 2019(Mahzari et al , 2020. When the huff 'n' puff process is operated at high interfacial tension (e.g., below the MCP), the lower huff pressure provides less driving forces for the mass transfer between the oil and the injection gas (Tang et al 2020;Sie et al 2018Sie et al , 2019Anand et al 2019).…”
Summary
Low primary and secondary recoveries of original oil in place from modern unconventional reservoirs beg for utilization of tertiary recovery techniques. Enhanced oil recovery (EOR) via cyclic gas injection (“huff ‘n’ puff”) has indeed enhanced the oil recovery in many fields, and many of those projects have also been documented in industry technical papers/case studies. However, the need remains to document new techniques in new reservoirs. This paper documents a small-scale EOR pilot project in the eastern Eagle Ford and shows promising well results.
In preparation for the pilot, full characterization of the oil and injection gas was done along with laboratory testing to identify the miscibility properties of the two fluids. Once the injection well facility design was completed, a series of progressively larger gas volumes were injected followed by correspondingly longer production times. Fluids in the returning liquid and gas streams were monitored for compositional changes, and the learnings from each cycle led to adjustments and facility changes to improve the next cycle.
After completing five injection/withdrawal cycles in the pilot, a few key observations can be made. The implementation of cyclic gas injection can be both a technical and a commercial success early in its life if reasonable cost controls are implemented and the scope is kept manageable. The process has proved to be both repeatable and predictable, allowing for future economic modeling to be used to help determine timing of subsequent injection cycles. A key component of the success of this pilot has been the availability of small compressors capable of the high pressures required for these projects and learning how to implement cost saving facility designs that still meet high safety standards.
“…During the pressure depletion (puff) stage, as the pressure in the fracture reduces to the puff pressure, the resulting pressure gradient induces the convective flow. Also, increasing gas expansion as pressure continues to drop could carry more crude oil from the matrix to the fracture (Mahzari et al 2019(Mahzari et al , 2020. When the huff 'n' puff process is operated at high interfacial tension (e.g., below the MCP), the lower huff pressure provides less driving forces for the mass transfer between the oil and the injection gas (Tang et al 2020;Sie et al 2018Sie et al , 2019Anand et al 2019).…”
Summary
Low primary and secondary recoveries of original oil in place from modern unconventional reservoirs beg for utilization of tertiary recovery techniques. Enhanced oil recovery (EOR) via cyclic gas injection (“huff ‘n’ puff”) has indeed enhanced the oil recovery in many fields, and many of those projects have also been documented in industry technical papers/case studies. However, the need remains to document new techniques in new reservoirs. This paper documents a small-scale EOR pilot project in the eastern Eagle Ford and shows promising well results.
In preparation for the pilot, full characterization of the oil and injection gas was done along with laboratory testing to identify the miscibility properties of the two fluids. Once the injection well facility design was completed, a series of progressively larger gas volumes were injected followed by correspondingly longer production times. Fluids in the returning liquid and gas streams were monitored for compositional changes, and the learnings from each cycle led to adjustments and facility changes to improve the next cycle.
After completing five injection/withdrawal cycles in the pilot, a few key observations can be made. The implementation of cyclic gas injection can be both a technical and a commercial success early in its life if reasonable cost controls are implemented and the scope is kept manageable. The process has proved to be both repeatable and predictable, allowing for future economic modeling to be used to help determine timing of subsequent injection cycles. A key component of the success of this pilot has been the availability of small compressors capable of the high pressures required for these projects and learning how to implement cost saving facility designs that still meet high safety standards.
“…This difference in composition can also indicate that, the low-pressure gas release by heating can target a gas with different characteristics, which can introduce notable errors in gas in place estimation. On the other hand, this notable remaining CO 2 within the shale sample after depressurization due to excess adsorption of CO 2 can indicate the considerable capacity of the shale rocks to house CO 2 during various applications of CO 2 injection such as EOR huff-n-puff and CO 2 storage 24 , 26 , 27 . Figure 6 Composition of charged and evolved gases used and collected, respectively.…”
Shale gas exploitation has been the game-changer in energy development of the past decade. However, the existing methods of estimating gas in place in deep formations suffer from large uncertainties. Here, we demonstrate, by using novel high-pressure experimental techniques, that the gas in place within deep shale gas reservoirs can be up to five times higher than that estimated by implementing industry standard approaches. We show that the error between our laboratory approach and the standard desorption test is higher for gases with heavier compositions, which are of strongest commercial interests. The proposed instrumentation is reliable for deep formations and, provides quick assessment of the potential for the gas in place, which could be useful for assessing hydrocarbon reservoirs, and the potential for geological carbon sequestration of a given formation.
“…Among the proposed technologies for increasing oil recovery, one can highlight the creation of reservoir pressure maintenance systems, which involve the injection of water or gas, as well as hydraulic fracturing and the use of horizontal wells. In practice, some methods are experimental in nature, and so far, no universal method has been found to develop reservoirs of this type (Mahzari, Jones & Oelkers 2020;Sheng, Li, Yu et al 2017;Waburoko, Xie, & Ling 2021). In order to evaluate the effectiveness of these technologies and compare them with each other, both individually and in combination, several development options were considered:…”
A variety of methods are examined in this study in order to improve oil recovery from low-permeability heterogeneous reservoirs in oil-saturated shale deposits. Calculations based on the fluid flow model revealed that water and gas injection was effective, and that horizontal and directional wells, including those employing hydraulic fracturing are evaluated in this study. Moreover, hydraulic fracturing in directional wells with vertical completions was found to be one of the most effective methods for water injection in this study. However, when hydraulic fracture length is hard to achieve, the gas injection has been found to be a more efficient way to enhance oil recovery than water injection. Furthermore, horizontal drilling technology was most effective in the central part of the reservoir.
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