The Influence of Organics on Supercritical CO2 Migration in Organic-Rich Shales

Kurz, Bethany A.; Sorensen, James A.; Hawthorne, Steven B.; Smith, Steven A.; Sanei, Hamed; Ardakani, Omid H.; Walls, Joel; Jin, Lu; Butler, Shane K.; Beddoe, Christopher J.; Mibeck, Blaise A.F.

doi:10.15530/urtec-2018-2902743

Cited by 11 publications

(11 citation statements)

References 0 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…The presence of organic matter is expected to facilitate the gas recovery with CO 2 injection and also the sequestration of CO 2 . This effect has also been demonstrated from laboratory experiments of both static and dynamic CO 2 contact with a Bakken shale sample, where a very high recovery factor is obtained. This was explained by the high microporosity associated with organic matter and high affinity of CO 2 with organic matter.…”

Section: Resultssupporting

confidence: 55%

Competitive Sorption of CO₂ with Gas Mixtures in Nanoporous Shale for Enhanced Gas Recovery from Density Functional Theory

Liu

Chapman

2019

Langmuir

View full text Add to dashboard Cite

CO 2 competitive sorption with shale gas under various conditions from simple to complex pore characteristics is studied using a molecular density functional theory (DFT) that reduces to perturbed chain-statistical associating fluid theory in the bulk fluid region. The DFT model is first verified by grand canonical Monte Carlo simulation in graphite slit pores for pure and binary component systems at different temperatures, pressures, pore sizes, and bulk gas compositions for methane/ethane with CO 2 . Then, the model is utilized in multicomponent systems that include CH 4 , C 2 H 6 , and C3+ components of different compositions. It is shown that the selectivity of CO 2 decreases with increases in temperature, pressure, nanopore size, and average molecular weight of shale gas. Extending the model to more realistic situations, we consider the impact of water present in the pore and consider the effect of permeation of fluid molecules into the kerogen that forms the pore walls. The water−graphite interaction is calibrated with contact angle from molecular simulation data from the literature. The kerogen pore model prediction of gas absolute sorption is compared with experimental and molecular simulation values in the literature. It is shown that the presence of water reduces the CO 2 adsorption but improves the CO 2 selectivity. The dissolution of gases into the kerogen matrix also leads to the increase in CO 2 selectivity. The effect of kerogen type and maturity on the gas sorption amount and CO 2 selectivity is also studied. The associated mechanisms are discussed to provide fundamental understanding for gas recovery by CO 2 .

show abstract

Section: Resultssupporting

confidence: 55%

Competitive Sorption of CO₂ with Gas Mixtures in Nanoporous Shale for Enhanced Gas Recovery from Density Functional Theory

Liu

Chapman

2019

Langmuir

View full text Add to dashboard Cite

show abstract

“…The associated goals of reducing greenhouse gas emissions and increasing oil recoveries have led to growing interest in injecting CO 2 and/or produced rich gas hydrocarbons for both gas storage and enhanced oil recovery (EOR). ,,− This interest has resulted in several recent pilot-scale injections of CO 2 and rich gas hydrocarbons into the Bakken, ,,, but experimental data needed to support successful field projects that compare these gases’ abilities to mobilize crude oil under relevant reservoir conditions are limited. Recently, CO 2 and various hydrocarbon gas minimum miscibility pressures (MMPs) were measured with crude oils produced from the Three Forks (TFs) and Middle Bakken (MB) intervals of the Bakken Petroleum System.…”

Section: Introductionmentioning

confidence: 99%

Comparison of CO₂ and Produced Gas Hydrocarbons to Recover Crude Oil from Williston Basin Shale and Mudrock Cores at 10.3, 17.2, and 34.5 MPa and 110 °C

et al. 2021

Self Cite

View full text Add to dashboard Cite

Carbon dioxide and hydrocarbon gases including methane, ethane, propane, and produced gas (69.5/21/9.5 mol ratio of methane/ethane/propane) were used to recover oil from rock samples collected in the Middle Bakken (MB) target drilling zone and from a Lower Bakken Shale (LBS) source rock. Experiments were designed to mimic the fracture-dominated flow expected to occur during gas injection into hydraulically fractured unconventional reservoirs such as the Bakken Petroleum System. Higher pressures recovered oil (and heavier hydrocarbons) more efficiently than lower pressures from both rock samples for each of the test gases but recoveries varied dramatically with the gas used. In general, oil recovery efficiencies from both MB and LBS rocks were the highest with propane, followed by ethane, CO2, and produced gas, and finally methane. Propane and ethane were the most efficient in recovering oil hydrocarbons from the rock samples at all three pressures, although ethane required higher pressures. Recoveries with CO2 and produced gas were low at 10.3 MPa but increased substantially at higher pressures with the recoveries achieved at 34.5 MPa approximating those achieved at lower pressures using propane and ethane. Finally, methane was only capable of significant oil recoveries from MB samples at the highest (34.5 MPa) test pressure but was not effective in mobilizing hydrocarbons from the tighter LBS samples at any of the pressures tested. Molar densities and the related injected gas solvent strengths at the three test pressures had a strong influence on oil recovery rates. For example, when molar densities of all five gases at the three test pressures were correlated with total hydrocarbon recoveries, linear correlation coefficients (r 2) were significant (0.69 for 1 h oil recoveries from the MB mudrock samples and 0.68 for the 24 h oil recoveries from the LBS shale samples). When oil recoveries at the three test pressures were compared to the molar densities of each individual gas, linear correlation coefficients (r 2) ranged from 0.89 to 0.99 for the recoveries from the MB samples, and 0.95 to >0.99 for the LBS samples for all of the gases except propane (which gave high recoveries at every test pressure, consistent with the fact that propane’s molar density shows little change at the three test pressures). The results of these laboratory studies indicate that ethane, propane, or very rich produced gas should be capable of recovering oil from unconventional reservoirs at significantly lower pressures than leaner produced gas or CO2, although both produced gas and CO2 could be effective at higher pressures.

show abstract

“…The success of miscible and immiscible CO 2 floods in conventional reservoirs, as well as the desire to store CO 2 , has led several authors to suggest its use for enhanced oil recovery (EOR) in tight oil plays including the Bakken Petroleum System based on experimental work − and simulations. − However, it is likely that the CO 2 flow patterns through the reservoir rock as occurs in conventional (i.e., permeable) reservoirs are not representative of the fracture-dominated flow that controls how injected EOR fluids move through tight hydraulically fractured systems like the Bakken Petroleum System. ,,, Thus, CO 2 injected into the Bakken Petroleum System is not likely to flow primarily through the rock matrix, as it does in a conventional reservoir flood but rather will flow primarily through the fractures as driven by the pressure gradient and around the rock matrix via the induced (or natural) fractures. Once the pressure gradient is reduced in the fractures, the bulk rock matrix holding the unproduced oil experiences a “bath” of CO 2 , where the CO 2 permeates by diffusion into the rock matrix and oil hydrocarbons diffuse out of the rock matrix into the bulk CO 2 in the fractures.…”

Section: Introductionmentioning

confidence: 99%

“…Although there have been several reports of achieving some degree of oil recovery from rock samples from unconventional tight oil plays with CO 2 , results from different investigators are hard to evaluate since there has not yet been a consistent experimental approach among different laboratories that would allow results from different studies to be compared and evaluated. − In addition, the number of rock samples used in these studies have typically been very limited and not sufficient to generalize behavior in unconventional tight oil plays or even in a single play. Therefore, the purpose of the present study is to validate an experimental method for exposing rock core samples to CO 2 that mimics expected processes in fractured unconventional tight rocks and to apply the method to a large number of core samples collected from all relevant lithofacies from across the Bakken Petroleum System to yield a better understanding of play-wide oil recovery variations under CO 2 exposures.…”

Section: Introductionmentioning

confidence: 99%

Hydrocarbon Recovery from Williston Basin Shale and Mudrock Cores with Supercritical CO₂: Part 1. Method Validation and Recoveries from Cores Collected across the Basin

et al. 2019

Self Cite

View full text Add to dashboard Cite

Rock core samples (51) from multiple lithofacies and depths were collected from 10 wells located throughout the Bakken Petroleum System. Each 11.2 mm diameter core was exposed to CO 2 for 24 h at reservoir conditions of 34.5 MPa (5000 psi) and 110 °C in a pressurized apparatus designed to mimic the fracture-dominated flow expected to occur during a CO 2 injection into hydraulically fractured tight unconventional formations. The oil recovered from the rock samples was collected hourly by slowly depressurizing the CO 2 into a collection solvent, while maintaining both CO 2 pressure and temperature constant in the extraction chamber. Recoveries of light and heavy oils were validated by comparing rock samples before and after CO 2 exposure using the extended slow heating Rock-Eval analysis. Extractions of replicate core samples from Middle Bakken (MB) tight nonshale, Upper Bakken shale (UBS), and Lower Bakken shale (LBS) gave reproducible results, demonstrating that the 11.2 mm diameter cores represent the original 10.2 cm (4 in.) core, and that the extraction and associated analysis procedures are reproducible. Recoveries of oil from the Three Forks (TF) and all MB cores ranged from 65 to >99% after 7 h of exposure and exceeded 94% for all cores at 24 h, despite median pore throat radii of only about 13 nm (MB) to 26 nm (TF). Surprisingly, significant oil was obtained from UBS and LBS cores despite the median pore throat radii of only ca. 3.5 nm, sizes that approach molecular dimensions. Although all TF and MB reservoir rocks showed high oil recoveries, the oil obtained in 24 h from UBS and LBS source rocks varied greatly for different well locations and ranged from as low as 11% to as high as 80%. Data analysis of mineralogical components, including clays, carbonates, evaporates, feldspars, and pyrite, showed that these factors were not useful to predict oil recoveries. Both total organic carbon (4−15 wt % for shales and 0.1−0.4 wt % for TF and MB) and the pore throat radii appear to control oil recovery, though they were not predictive for individual UBS and LBS cores. Results from the 51 rock core samples demonstrate that CO 2 is capable of penetrating oil-bearing pores and displacing crude oil from the UBS and LBS source rocks as well as the MB and TF reservoir rocks.

show abstract

The Influence of Organics on Supercritical CO2 Migration in Organic-Rich Shales

Cited by 11 publications

References 0 publications

Competitive Sorption of CO₂ with Gas Mixtures in Nanoporous Shale for Enhanced Gas Recovery from Density Functional Theory

Competitive Sorption of CO₂ with Gas Mixtures in Nanoporous Shale for Enhanced Gas Recovery from Density Functional Theory

Comparison of CO₂ and Produced Gas Hydrocarbons to Recover Crude Oil from Williston Basin Shale and Mudrock Cores at 10.3, 17.2, and 34.5 MPa and 110 °C

Hydrocarbon Recovery from Williston Basin Shale and Mudrock Cores with Supercritical CO₂: Part 1. Method Validation and Recoveries from Cores Collected across the Basin

Contact Info

Product

Resources

About

The Influence of Organics on Supercritical CO2 Migration in Organic-Rich Shales

Cited by 11 publications

References 0 publications

Competitive Sorption of CO2 with Gas Mixtures in Nanoporous Shale for Enhanced Gas Recovery from Density Functional Theory

Competitive Sorption of CO2 with Gas Mixtures in Nanoporous Shale for Enhanced Gas Recovery from Density Functional Theory

Comparison of CO2 and Produced Gas Hydrocarbons to Recover Crude Oil from Williston Basin Shale and Mudrock Cores at 10.3, 17.2, and 34.5 MPa and 110 °C

Hydrocarbon Recovery from Williston Basin Shale and Mudrock Cores with Supercritical CO2: Part 1. Method Validation and Recoveries from Cores Collected across the Basin

Contact Info

Product

Resources

About

Competitive Sorption of CO₂ with Gas Mixtures in Nanoporous Shale for Enhanced Gas Recovery from Density Functional Theory

Competitive Sorption of CO₂ with Gas Mixtures in Nanoporous Shale for Enhanced Gas Recovery from Density Functional Theory

Comparison of CO₂ and Produced Gas Hydrocarbons to Recover Crude Oil from Williston Basin Shale and Mudrock Cores at 10.3, 17.2, and 34.5 MPa and 110 °C

Hydrocarbon Recovery from Williston Basin Shale and Mudrock Cores with Supercritical CO₂: Part 1. Method Validation and Recoveries from Cores Collected across the Basin