Maximize Liquid Oil Production

from Shale Oil and Gas Condensate Reservoirs

by Cyclic Gas Injection

Project Number: DE-FE0024311

James Sheng

Texas Tech University

U.S. Department of Energy

National Energy Technology Laboratory

Mastering the Subsurface Through Technology, Innovation and Collaboration:

Carbon Storage and Oil and Natural Gas Technologies Review Meeting

August 16-18, 2016

2

Presentation Outline

• Benefits to the program

• Project overview

• Technical Status

• Accomplishments to date

• Synergy opportunities

• Project summary

3

Benefit to the Program

Program goals

• Minimize environmental impacts of UOG development

• Maximizing its economic and national energy security

benefits.

This project goals

• Develop cyclic gas injection technology to maximize

liquid oil production from shale oil and condensate

reservoirs.

Impacts

• Reduce flared gas, sequester CO2, save water, and drill

less wells, while increasing oil production.

4

Project Overview: Goals and Objectives

• Overall goal: evaluate gas injection EOR

potential

– confirmed in lab and reservoir-scale modeling

• Environmental impacts

– Sequester CO2

– Reduce gas flaring, water usage

• Technical goals/status

– Much more achieved than proposed

– Details to follow next

Technical Status

• Experimental setup

– Cyclic gas injection for shale oil and condensate experiments

worked

– Microfludic setup worked

• Fundamental studies

– Many experimental and modeling studies (details to follow)

• Field pilot tests

– Completed pilot location selection, facility design and modeling

work for a Wolfcamp reservoir

– Modeling work performed for an Eagle Ford condensate

reservoir

– Current status: tests suspended.

• More new studies initiated

– Asphaltene, air injection, water huff-n-puff, chemical or solvents 5

6

Conditions:• Soaking time 1 hr

• Production time 3 hrs

• Soaking pressure 1000 psi

Observations:• In the beginning, same oil recovery.

• Later, Huff-n-puff had higher oil recovery than flooding.

0%

5%

10%

15%

20%

25%

0 12 24 36 48 60 72

Oil r

eco

very

facto

r

Time (hour)

N2 flooding

N2 huff-n-puff

Gas huff-n-puff vs. gas flooding

7

Conditions:• Soaking time 1 hr

• Production time 3 hrs

• Soaking pressure 1000 psi

Observations:• N2 huff-n-puff had higher oil recovery than water.

Gas huff-n-puff vs. water huff-n-puff

8

Effect of Water Saturation on Cyclic N2 and CO2 Injection

Water and oil could not be split, define liquid recovery:

Results:

• Liquid RF < oil RF – water saturation negative effect!

• Confirmed CO2 RF > N2 RF

• More flow back desirable?

9

Re-vaporization mechanism of huff-n-puff gas injection in a condensate system

10

Effect of soaking time on gas huff-n-puff

0%

10%

20%

30%

40%

50%

60%

0 1 2 3 4 5 6 7 8 9 10 11 12

Oil

Rec

over

y F

act

or

Number of Injection Cycles for 4-inch diameter

soak time = 1 hrsoak time = 4 hrssoak time = 12 hrssoak time = 24 hrssoak time = 48hrssoak time = 72hrs

Core Samples

Saturation time

One cycle for 1

One cycle

for 2

One cycle

for 3Operation time: 8days

With a cycle,

Longer soaking time

Higher oil recovery

With the same operation time,

Longer soaking time

Lower oil recovery

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Optimization of huff-n-puff gas injection

Oil RF: 15% OIL RF 21%

Conclusions:

• Huff time: Injection reaches max. allowed

• Puff time: Production pressure reaches min. allowed

& puff time& puff time

12

Height 2 inches

Different diameters

Core size effect on gas huff-n-puff

13

Upscale methodology for gas huff-n-puff process in shale oil reservoirs

0%

10%

20%

30%

40%

50%

40.0 400.0

Oil

Rec

over

y F

act

or

Dimensionless time, tD

0.125*0.167 (tD)1.25*1.67 (tD)12.5 * 16.7 (tD)125 * 167 (tD)

𝑡𝐷 =𝐶𝑘𝑡

∅𝜇𝑐𝑡(𝐿2)(𝑃𝐷

2

𝑃D = 𝑃huff − 𝑃puff

= 0𝑡huff 𝑃avg𝑑𝑡

𝑆huff−

0𝑡puff 𝑃avg𝑑𝑡

𝑆puff

Puff periodHuff period

S4

S2

S3

S1

Dimensionless time:

Dimensionless pressure:

14

Asphaltene aggregation and deposition during CO2 and CH4 injection in shale

0.00%

0.01%

0.01%

0.02%

0.02%

0.03%

0.03%

0.04%

0.04%

0.05%

0.0% 20.0% 40.0% 60.0% 80.0%

Tota

l asp

hal

ten

e w

t%

Dissolved gas, Mole%

Asphaltene deposition during gas injection

CO2

CH4

0

5

10

15

20

25

30

35

3.6

-4.0

4.0

-5.0

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10000.0-…

Vo

lum

e p

erc

en

tage

[%

]

Pore size range [nm]

Before H&P

After H&P

As more gas dissolved,

more asphletne aggregation

After 6 cycles of huff-n-puff,

Large pores (100-500 nm) decreased,

Smaller pores (< 100 nm) increased.

Indicating pores blocked by deposition.

Permeability reduced from 127 to 78.5 nD

15

Air injection

Conducted laboratory screening tests and simulation study

• TG and DSC tests

• Small batch reactor

Work done:

• Estimated kinetic parameters:

• Reaction order and activation energy etc. for Wolfcamp oil

• Studied low-temperature oxidation

Differential Scanning Calorimetry(DSC)

Thermogravimetry (TG)

Accomplishments to Date

• Publications:

• 2 patent disclosures filed

• 14 peer-reviewed journal papers published

• 17 papers submitted for review

• 21 conference papers presented

• Graduated students:

• 3 PhDs

• 2 Masters

16

Synergy Opportunities

– We focus more on macroscale (reservoir)

– LBNL focus more microscale (molecular, nano-

scale simulation)

– Wish for future collaboration

• Joint proposals

• Summer interns for students (co-supervise students)

• Collaboration with the industry

– We are looking for:

• micro- or nano- CT

• Instruments to measure diffusion

• Combustion facilities for air injection 17

Summary

– Key Findings

• Confirmed gas injection EOR potential

• Gas injection better than water injection

• Huff-n-puff injection mode better than gas flooding

• CO2 has higher recovery than other gases

– Lessons Learned

• A field test will take a long time to execute

– Future Plans

• More studies to compare with other methods

• Fundamental studies of mechanisms

• Field data collection and analysis18

Appendix

19

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Organization Chart

• Texas Tech University (contractor)– Responsible for fundamental studies, field test design

and data analysis

– PI: James Sheng, Co-PI: Marshall Watson, Students,

Postdocs

• Apache Corporation (partner)

– Field tests, cost share

• Los Alamos National Lab (subcontractor)

– Microscale experiments and modeling

– Hari Viswanathan and Mark Porter

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Gantt Chart

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

Maximize oil production from shale oil reservoirs

Fundamental research (lab and simulation)

Pilot test design

Field pilot test data acquisition & analysis

Maximize oil production from condensate reservoirs

Fundamental research (lab and simulation)

Design pilot test

Field pilot test data acquisition & analysis

Gas injection pore-scale experiments and simulation

Project schedule

10/14-9/15 10/15-9/16 10/16-9/17

Now

Bibliography

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1. Huang, S., Jia, H., and Sheng, J.J. 2016. Exothermicity and oxidation behavior of tight oil with cuttings from the Wolfcamp

shale reservoir, Petroleum Science and Technology, accepted.

2. Meng, X., *Sheng, J.J., and Yu, Y. 2016. Experimental and Numerical Study on Enhanced Condensate Recovery by Huff-n-Puff

Gas Injection in Shale Gas Condensate Reservoirs, SPE Reservoir Evaluation & Engineering-Reservoir Engineering, accepted.

3. Li, L. and *Sheng, J.J. 2016. Experimental Study of Core Size Effect on Methane Huff-n-Puff Enhanced Oil Recovery Method in

Liquid-rich Shale Reservoirs, J. of Natural Gas Science and and Engineering, accepted.

4. Yu, Y., Meng, X., and Sheng, J.J. 2016. Experimental and Numerical Evaluation of the Potential of Improving Oil Recoveryfrom Shale Plugs by Nitrogen Gas Flooding, The Journal of Unconventional Oil and Gas Resources, 15, 56-65.

5. Zhang, Y. and Sheng, J.J. 2016. Oxidation Kinetics Study of the Wolfcamp Light Oil, Petroleum Science and Technology, in press.

6. Huang, S., Jia, H., and Sheng, J.J. 2016. Research on Oxidation Kinetics of Tight Oil of Wolfcamp Field, Petroleum Science and Technology, 34(10), 903-910.

7. Huang, S., Jia, H., and Sheng, J.J. 2016. Effect of shale core on combustion reactions of tight oil from Wolfcamp reservoir, Petroleum Science and Technology, in press.

8. Jia, H. and Sheng, J.J. 2016. Numerical modeling on air injection in a light oil reservoir: Recovery mechanism and scheme optimization, Fuel, 172, 70-80.

9. Jimenez-Martinez, J., M.L Porter, J.D Hyman, J.W. Carey, and H.S. Viswanathan, 2015. Mixing in a three-phase system: Enhanced production of oil-wet reservoirs by CO2. Geophysical Research Letters. doi: 10.1002/2015GL066787.

10. Sheng, J.J., Mody, F., Griffith, P.J., and Barnes, W.N. 2016. Potential to increase condensate oil production by huff-n-puff

gas injection in a shale condensate reservoir, J. of Natural Gas Science and Engineering, 28, 46-51. DOI: 10.1016/j.jngse.2015.11.031

11. Sheng, J.J. 2015. Increase liquid oil production by huff-n-puff of produced gas in shale gas condensate reservoirs, Journal of Unconventional Oil and Gas Resources, 11, 19-26. Downloaded 384 times by Dec. 10, 2015.

12. Sheng, J.J. 2015. Enhanced oil recovery in shale reservoirs by gas injection, Journal of Natural Gas Science and Engineerin, 22, 252-259 (invited review). Downloaded 2079 times since its publication (Dec. 2, 2014) to Feb. 1, 2016.

Bibliography

13. Hyman, J.D, J. Jimenez-Martinez, M.L. Porter , S. Karra, J.W. Carey, and H.S. Viswanathan, 2016. Understanding hydraulic

fracturing: A multi-scale problem. Philosophical Transactions of the Royal Society A. Accepted.

14. Porter, M.L., J. Jimenez-Martinez, R. Martinez, Q. McCulloch, J.W. Carey, and H.S. Viswanathan, 2015b. Geo-material

microfluidics at reservoir conditions for subsurface energy resource applications. Lab on a Chip, 15, 4044-4053. doi:

10.1039/C5LC00704F.

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