Hydraulic Fracture Orientation for Miscible Gas Injection EOR in Unconventional Oil Reservoirs

Xu, Tao; Hoffman, Todd

doi:10.1190/urtec2013-189

Cited by 25 publications

(13 citation statements)

References 7 publications

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“…Xu et al (2014) evaluated the reservoir performance of Elm Coulee field in Eastern Montana under CO 2 flooding with different hydraulic fracture orientations. 100 They concluded that transverse fractures would have a higher oil recovery factor, but these transverse fractures would have a lower utilization value than the longitudinal fractures due to the breakthrough problems. in which the EOR gases could be injected into a hydraulic fracture orienated along a horizontal well, and the production process could occur from an adjacent fracture, which has an intersection with the same well.…”

Section: ■ Backgroundmentioning

confidence: 99%

Factors Affecting CO₂-EOR in Shale-Oil Reservoirs: Numerical Simulation Study and Pilot Tests

2017

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Shale oil reservoirs such as Bakken, Niobrara, and Eagle Ford have become the main target for oil and gas investors as conventional formations started to be depleted and diminished in number. These unconventional plays have a huge oil potential; however, the predicted primary oil recovery is still low as an average of 7.5%. Injecting carbon dioxide (CO 2 ) to enhance oil recovery in these poor-quality formations is still a debatable issue among investigators. In this study, three steps of research have been integrated to investigate the parameters that control the success of CO 2 huff-n-puff process in the field scale of shale oil reservoirs. First, a numerical simulation study was conducted to upscale the reported experimental studies outcomes to the field conditions. The second step was to validate these numerical models with the field data from some of CO 2 -EOR pilots, which were performed in Bakken formation, in North Dakota and Montana regions. Finally, statistical methods for Design of Experiments (DOE) have been used to rank the most important parameters affecting CO 2 -EOR performance in these unconventional reservoirs. The Design of Experiments approved that the intensity of natural fractures (the number of natural fractures per length unit in each direction, I-direction, J-direction, and K-direction) and the conductivity of oil pathways (the average conductivity for the entire oil molecules path, from its storage (matrix) to the wellbore) are the two main factors controlling CO 2 -EOR success in shale oil reservoirs. However, the fracture intensity has a positive effect on CO 2 -EOR, while the later has a negative effect. Furthermore, this study found that the porosity and the permeability of natural fractures in shale reservoirs are clearly changeable with the production time, which, in turn, led to a clear gap between CO 2 performances in the lab conditions versus what happened in the field pilots. This work reported that the molecular diffusion mechanism is the key mechanism for CO 2 to enhance oil recovery in shale oil reservoirs. However, the conditions of the candidate field and the production well criteria can enhance or downgrade this mechanism in the field scale. Accordingly, the operating parameters for managing CO 2 -EOR huff-n-puff process should be tuned according to the candidate reservoir and well conditions. Moreover, general guidelines have been provided from this work to perform successful CO 2 projects in these complex plays. Finally, this Article provides a thorough idea about how CO 2 performance is different between the field scale of shale oil reservoirs and the lab-scale conditions.

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Section: ■ Backgroundmentioning

confidence: 99%

Factors Affecting CO₂-EOR in Shale-Oil Reservoirs: Numerical Simulation Study and Pilot Tests

2017

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“…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

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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.

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“…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%

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

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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.

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Hydraulic Fracture Orientation for Miscible Gas Injection EOR in Unconventional Oil Reservoirs

Cited by 25 publications

References 7 publications

Factors Affecting CO₂-EOR in Shale-Oil Reservoirs: Numerical Simulation Study and Pilot Tests

Factors Affecting CO₂-EOR in Shale-Oil Reservoirs: Numerical Simulation Study and Pilot Tests

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

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Hydraulic Fracture Orientation for Miscible Gas Injection EOR in Unconventional Oil Reservoirs

Cited by 25 publications

References 7 publications

Factors Affecting CO2-EOR in Shale-Oil Reservoirs: Numerical Simulation Study and Pilot Tests

Factors Affecting CO2-EOR in Shale-Oil Reservoirs: Numerical Simulation Study and Pilot Tests

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

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Factors Affecting CO₂-EOR in Shale-Oil Reservoirs: Numerical Simulation Study and Pilot Tests

Factors Affecting CO₂-EOR in Shale-Oil Reservoirs: Numerical Simulation Study and Pilot Tests

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