Field Test of CO2 Injection in a Vertical Middle Bakken Well to Evaluate the Potential for Enhanced Oil Recovery and CO2 Storage

Sorensen, James A.; Pekot, Lawrence J.; Torres, José Antonio Marina; Jin, Lu; Hawthorne, Steven B.; Smith, Steven A.; Jacobson, Lonny; Doll, Thomas

doi:10.15530/urtec-2018-2902813

Cited by 26 publications

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“…The EERC performed a research program to explore opportunities for injecting CO 2 into shale oil-bearing formations, to help increase oil productivity and store carbon dioxide. The project was completed in a reservoir located in North Dakota that has no history of production . In less than a week, nearly 100 tons of CO 2 was driven into the formation, where it was allowed to soak for ∼2 weeks more.…”

Section: Field Assessmentmentioning

confidence: 99%

“…The EERC, in collaboration with XTO Energy, performed a CO 2 injection project in 2017. The use of proppant to open and maintain complex stimulated fracture networks was not included in the well completion construction. , However, preinjection reservoir fluids were assembled to create baseline conditions. The CO 2 injection procedure was divided into two stages: the pretest stage and the final test or stage. , The pretest was a small-scale injectivity procedure, in which ∼27% of the scheduled CO 2 was injected to fill the tubing and create pressure for perforations.…”

Section: Field Assessmentmentioning

confidence: 99%

“…The use of proppant to open and maintain complex stimulated fracture networks was not included in the well completion construction. , However, preinjection reservoir fluids were assembled to create baseline conditions. The CO 2 injection procedure was divided into two stages: the pretest stage and the final test or stage. , The pretest was a small-scale injectivity procedure, in which ∼27% of the scheduled CO 2 was injected to fill the tubing and create pressure for perforations. However, because of the upper packer failure, the engineering group found that only a small percentage of the injected CO 2 entered the formation.…”

Section: Field Assessmentmentioning

confidence: 99%

“…However, the composition analysis of fluid tests before and after injection revealed that CO 2 was able to penetrate the low permeability structure and produce light hydrocarbon in the matrix, even though the well was not stimulated. By 2019, no detailed production data had been released. , …”

Section: Field Assessmentmentioning

confidence: 99%

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Huff-n-Puff Technology for Enhanced Oil Recovery in Shale/Tight Oil Reservoirs: Progress, Gaps, and Perspectives

et al. 2021

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In recent times, particularly in the 21st century, there has been an alarming increase in the demand for global energy, along with continuous depletion in conventional oil reservoirs. This necessity has incentivized interested scholars and operators worldwide to seek alternative oil resources. To secure such accelerating energy demand, considerable effort has been directed toward the development of previously unconventional oil formations that, in past decades, had remained sidelined. Although shale oil reservoirs have seen tremendous success over the past decade, the continued challenges of rapidly declining oil flow rates and oil retention in the pores continuously persist. Substantial attempts have been made to improve shale-bypassed oil recovery; however, there is little data about the accessibility on recovery mechanisms, especially in the oil field. Furthermore, approachesparticularly, Huff-n-Puff (H-n-P) experiments using conventional proceduresfail to properly represent field conditions and they generate deceptive findings, because the utilized cores are not simulated under realistic reservoir conditions, leaving the significance of critical factors unclear. Therefore, this review study comprehensively and specifically discusses the feasibility of enhanced oil recovery (EOR) methods in unconventional oil reservoirs. Beside addressing the validity of the currently applied H-n-P technology in shale/tight oil reservoirs and underlining some critical gaps regarding laboratory results, modified technology is proposed in this paper for a better field future performance. The study is divided into sections, and each section analyzes the role of one specific H-n-P portion in detail, such as preferable injected solvents, their mechanisms, and critical factors affecting H-n-P recovery. The exceptions to this are the first and second sections, which provide a brief introduction about shale and tight oil reservoirs, a history of applied technology, and the method’s current problem statement. In the Introduction section, the authors will justify why this Review fills a critical gap in the field. Within the assessment study, great focus is given to the H-n-P technique, its parameters, and effective processes. In the final sections, carefully chosen experimental results and tools are reviewed to highlight the controversy and state “the gap”.

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Section: Field Assessmentmentioning

confidence: 99%

Section: Field Assessmentmentioning

confidence: 99%

Section: Field Assessmentmentioning

confidence: 99%

Section: Field Assessmentmentioning

confidence: 99%

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Huff-n-Puff Technology for Enhanced Oil Recovery in Shale/Tight Oil Reservoirs: Progress, Gaps, and Perspectives

et al. 2021

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“…The desire to reduce greenhouse gas emissions and increase oil production has led to rapidly increasing interest in reinjecting CO 2 and/or rich gas for enhanced oil recovery (EOR). ,,− Currently, a major pilot program is being conducted to capture CO 2 from lignite-fired power plants in western North Dakota to inject for carbon storage (and potentially for future EOR projects) in the nearby Bakken and other formations within the basin . These increasing interests have led to several recent pilot-scale injections of natural gas and CO 2 into the Bakken. ,,− …”

Section: Introductionmentioning

confidence: 99%

Comparison of CO₂ and Produced Gas Hydrocarbons to Dissolve and Mobilize Bakken Crude Oil at 10.3, 20.7, and 34.5 MPa and 110 °C

Hawthorne

Miller

2020

Energy Fuels

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The ability of an injected gas to dissolve crude oil hydrocarbons may be a major factor controlling the success of enhanced oil recovery (EOR) projects in unconventional reservoirs. Multiple laboratory gas injection tests were conducted using Bakken crude oil in which the gas-dominated upper phase in equilibrium with the bulk crude oil was collected and analyzed to determine dissolved crude oil concentrations and their molecular weight distributions. Dissolved concentrations varied greatly among the test gases, as well as at different pressures for all of the fluids except propane. The ranges of total dissolved hydrocarbons at 10.3, 20.7, and 34.5 MPa were methane (8–67 mg/mL), ethane (40–228 mg/mL), propane (230–278 mg/mL), and CO2 (13–254 mg/mL). The oil solubility in a representative produced gas (69.5/21/9.5 methane/ethane/propane) ranged from 9 to 145 mg/mL. The gases and pressures that mobilized the lowest total hydrocarbon concentrations were also the least effective at mobilizing heavier hydrocarbons. For example, the C20–C36 fraction of the crude oil that was mobilized with each gas exposure at 10.3–34.5 MPa was methane (<1–6%), ethane (12–95%), propane (58–99%), produced gas (<1–33%), and CO2 (<1–40%), indicating concentration of the heavier hydrocarbons in the residual crude oil after exposure to gases (and pressures) that are less effective. Residual crude oil viscosities after gas exposure showed significant increases (with the notable exception of propane at all three pressures), also consistent with each test gas’s ability to dissolve heavier hydrocarbons. Consideration of each gas’s density changes with pressure correlated well with their abilities to dissolve crude oil, and increases in pressure always increased oil solubilities regardless of each gas’s minimum miscibility pressure (MMP) value with the crude oil used for these mobilization experiments. Multiple exposures of a crude oil sample to fresh test gas showed declining dissolved hydrocarbon concentrations demonstrating that crude oil solubilities were not controlled by saturation solubility, but were controlled by equilibrium partitioning of hydrocarbons between the gas-dominated and oil-dominated phases.

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A review of the current progress of CO2 injection EOR and carbon storage in shale oil reservoirs

Jia

Tsau

Barati

2019

Fuel

512

248

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Field Test of CO2 Injection in a Vertical Middle Bakken Well to Evaluate the Potential for Enhanced Oil Recovery and CO2 Storage

Cited by 26 publications

References 0 publications

Huff-n-Puff Technology for Enhanced Oil Recovery in Shale/Tight Oil Reservoirs: Progress, Gaps, and Perspectives

Huff-n-Puff Technology for Enhanced Oil Recovery in Shale/Tight Oil Reservoirs: Progress, Gaps, and Perspectives

Comparison of CO₂ and Produced Gas Hydrocarbons to Dissolve and Mobilize Bakken Crude Oil at 10.3, 20.7, and 34.5 MPa and 110 °C

A review of the current progress of CO2 injection EOR and carbon storage in shale oil reservoirs

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Field Test of CO2 Injection in a Vertical Middle Bakken Well to Evaluate the Potential for Enhanced Oil Recovery and CO2 Storage

Cited by 26 publications

References 0 publications

Huff-n-Puff Technology for Enhanced Oil Recovery in Shale/Tight Oil Reservoirs: Progress, Gaps, and Perspectives

Huff-n-Puff Technology for Enhanced Oil Recovery in Shale/Tight Oil Reservoirs: Progress, Gaps, and Perspectives

Comparison of CO2 and Produced Gas Hydrocarbons to Dissolve and Mobilize Bakken Crude Oil at 10.3, 20.7, and 34.5 MPa and 110 °C

A review of the current progress of CO2 injection EOR and carbon storage in shale oil reservoirs

Contact Info

Product

Resources

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Comparison of CO₂ and Produced Gas Hydrocarbons to Dissolve and Mobilize Bakken Crude Oil at 10.3, 20.7, and 34.5 MPa and 110 °C