Unconventional Resources
Maximize Liquid Oil Production from Shale Oil and Gas Condensate Reservoirs by Cyclic Gas Injection   Last Reviewed
December 2017

DE-FE0024311

Goal
The project goal is to evaluate the oil recovery potential of cyclic gas injection. Detailed project objectives include:

  • Studying the dominant mechanisms of gas injection in shale reservoirs (e.g., pressure maintenance or miscibility)
  • Finding the most effective mode of gas injection in shale oil and  gas condensate reservoirs (e.g., gas flooding or huff-n-puff)
  • Exploring the economic value of effective gas injection modes (is it economical in a real field project?)
  • Designing field pilot tests and acquiring test data

Performer
Texas Tech University, Lubbock, TX 79409-1035

Background
The United States holds large resources of shale oil in place. Maximizing liquid oil production in shale reservoirs is of great interest to North American operators when oil prices are high and gas prices are low. The primary recovery stage for shale oil wells drilled horizontally and stimulated with multiple transverse fractures yields less than 10 percent of the oil in the reservoir, and typically recovers closer to only five percent. Because the oil recovery factor is very low, improvements in enhanced oil recovery can add significant economic and environmental benefits to ensuring adequate oil and gas supplies for the country. Earlier work at Texas Tech showed that the enhanced oil recovery potential of gas injection in shale reservoirs is higher than that of waterflooding.  This project was initiated to investigate cyclic natural gas injection, which includes both gas flooding and huff-n-puff processes. In both of the processes, a fraction of produced gas is cyclically injected into shale reservoirs to maximize liquid oil production. Both types of shale reservoirs—oil and gas condensate—will be investigated. Cyclic re-injection of produced natural gas reduces gas flaring and sales potential, but it increases oil recovery and avoids the need for water to enhance oil and gas recovery.      

Impact
The proposed cyclic gas injection technology makes efficient use of natural gas—readily available in liquid-rich reservoirs—to produce more in-demand oil. The proposed technology can also use carbon dioxide (CO2) with the added benefit of sequestering  CO2, thus making it useful from the perspectives of both broad and long-term impacts. In addition, the technology does not require water, which does not exacerbate water scarcity, or require drilling more wells. Because the produced or associated gas can be re-injected into the reservoir, oil production can continue without the need to flare the gas. The proposed research will provide an environmentally prudent technology to produce oil from large shale resources that typically experience very low recovery. The technology developed through this research will help to ensure an adequate oil supply by significantly increasing U.S. oil production.  

Accomplishments (most recent listed last)
Experimental data and simulation results show that air injection leads to slightly higher oil recovery than nitrogen injection, which does not have thermal effect. Practical issues such as safety, feasibilities of required air injectivity and combustion effect, need to be further studied.

Reservoir sector models have been built, and typical well performance has been reasonably matched for both shale oil and gas condensate reservoirs. Production forecasts show significant oil-rate increase after gas huff-n-puff injection. Laboratory gas injection experiments on shale oil cores showed that a lower pressure depletion rate will reduce incremental oil recovery. Laboratory experiments also showed that with larger matrix sizes, the oil recovery factor was lower. Laboratory flow experiments on gas condensate cores demonstrated a vaporization effect when natural gas was injected, thus indicating that liquid dropout near the wellbore could be reduced. Both experiments and simulation studies showed that huff-n-puff gas injection will result in higher oil or condensate recovery than gas flooding.

It was observed in the laboratory that the effect of water saturation in the core reduced liquid (oil and water) recovery, indicating more flowback would help producing oil during a huff-n-puff gas injection. Initial screening studies of air injection indicated the possibility of enhanced oil recovery (EOR) in shale oil reservoirs. The investigation of the effect of asphaltene on formation damage during a huff-n-puff gas injection shows that partial pore plugging could result in an increase in the percentage of pore sizes smaller than 100 nm. The hypothesis is that asphaltene particles adsorbed into the surface of rock pores and made the pore diameter smaller. The measured permeability was reduced after huff-n-puff CO2 injection. A modeling study shows that higher pressure may result in higher permeability reduction which will reduce oil recovery, but higher injection pressure increases oil recovery. The combined effect shows that the higher pressure is favored for oil recovery. A study of the effects of other operation parameters also supports the conclusion that although asphaltene deposition reduces permeability, it does not change the operation conditions which will lead to high oil recovery without asphaltene deposition.

Effect of minimum miscible pressure on EOR potential in shale oil cores was studied. The results show that the minimum miscible pressure (MMP) estimated from slimtube tests is higher than the effective MMP from huff-n-puff experiments derived from oil recovery vs. injection pressure. This is because ultra-low permeability results in the significant pressure drop from the surface of matrix to the center of the matrix, and the pressure near the matrix surface is the injection pressure, which is higher than the average pressure within the matrix.

A compositional modeling study was conducted to compare huff-n-puff solvent injection with gas injection in improving oil recovery from shale gas-condensate reservoirs. The solvents used are methanol and isopropanol, and gases are methane and ethane. Results from core-scaling modeling and reservoir-scale modeling show that ethane injection is a novel idea and proves to be the best injection fluid on account of higher and faster recovery as compared to methane, methanol, or isopropanol. This is attributed to ethane being a lighter fluid and aiding in revaporizing the condensate. While this is also true for methane, the most significant difference between the two is that ethane is also able to reduce overall dew point pressure of the mixture, ensuring lower injection volume and time for the same recovery factor.

Additional laboratory work resutled in the following conclusions:

  • Laboratory gas injection experiments on shale oil cores showed that a lower pressure depletion rate would reduce incremental oil recovery.
  • Laboratory experiments showed that with larger-diameter matrix cores, the oil recovery factor was lower.
  • The design of field testing operations was completed and a new pilot location was identified. However, the execution of the pilot test was canceled due to the low oil price and the operator’s budget cut.
  • A simulation study using Eagle Ford PVT data was completed for a gas condensate reservoir. The results show that a longer huff-n-puff cycle is needed for a gas condensate reservoir than for a shale oil reservoir because of high gas compressibility.
  • The effect of water imbibition on shale core permeability has also been studied. The results show that water imbibition may initially generate microfractures or open existing microfractures, but later those microfractures will be closed under confinement.
  • Studies on the effect of gas composition showed that ethane is a superior gas to enhance recovery of oil and liquid condensate and gas is a better agent than solvents (methanol and isoproponal).
  • Studies on low velocity non-Darcy flow showed that in a vertical well, the production rate of non-Darcy flow is much smaller than that of Darcy flow, and the ultimate oil recovery of non-Darcy flow is approximately 48 percent of the Darcy flow. The production rate of a multi-fractured horizontal well, if non-Darcy flow, is considered smaller in the beginning but greater than the corresponding Darcy flow rate after some time. The ultimate recovery factor of non-Darcy flow is 80 percent of the Darcy flow, which indicates that multi-fractured wells are less affected by the low-velocity non-Darcy phenomenon compared with the vertical wells. Multi-fractured horizontal wells exhibit a significant advantage in developing shale and tight reservoirs, and low velocity non-Darcy flow plays a significant impact on the well production performance in tight and shale reservoirs.
  • Studies showed that the particle size of the asphaltene precipitation generated during CO2 and CH4 injection in the shale oil sample was large enough to cause pore plugging in the tested core samples.

Current Status (December 2017)
The project was completed on September 30, 2017.

Project Start: October 1, 2014
Project End: September 30, 2017

DOE Contribution: $1,195,800
Performer Contribution: $4,925,500

Contact Information
NETL – Gary Covatch (gary.covatch@netl.doe.gov or 304-285-4589)
Texas Tech University – (james.sheng@ttu.edu or 806-834-8477)

Additional Information:

Maximize Liquid Oil Production from Shale Oil and Gas Condensate Reservoirs by Cyclic Gas Injection (Aug 2016)
Presented by James Sheng, Texas Tech University System, 2016 Carbon Storage and Oil and Natural Gas Technologies Review Meeting, Pittsburgh, PA