The goal of this project was to increase the recovery of natural gas from fractured shale reservoirs through the development and demonstration of improved, non-damaging fracture stimulation techniques. This would be accomplished by (1) demonstrating (in the Appalachian Basin) a unique, non-liquid, non-damaging carbon-dioxide-based fracturing technology, (2) evaluating the results, and (3) comparing them to results from conventionally-fractured shale wells in the same areas.
This unique liquid-free stimulation treatment technique, which utilized carbon dioxide (CO2) as the working fluid, was developed in Canada. The process utilizes specialized equipment, enabling proppant to be mixed and transported with liquid CO2 down the wellbore to the target formation. It was expected to result in a propped fracture to prevent the formation from closing. This technology was previously unavailable in the U.S. prior to the initiation of this project. The technology held promise for stimulating liquid-sensitive reservoirs in that the CO2 is pumped as a liquid to hydraulically create fractures, and then vaporizes at reservoir conditions, leaving liquid-free fracture.
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Canton, Ohio 44720
Perry County, Kentucky
Pike County, Kentucky
Chautauqua County, New York
Mercer County, Pennsylvania
Putnam County, West Virginia
The project demonstrated a unique liquid-free stimulation technology which was unavailable in the U.S. prior to the initiation of this project. The project demonstrated the technology’s effectiveness in stimulating production from fractured shale reservoirs, which are liquid sensitive, and comparing the results with those from conventionally fractured shale wells in the same areas. The demonstrations provided benefit in some areas and the technology is now offered commercially in the U.S. by Byron Jackson (BJ) Services.
The approach was to obtain the cooperation of gas well operators and for them to provide candidate wells for the demonstrations in return for cost-shared support. The post-stimulation production responses from the candidate wells were compared to those from conventionally stimulated control wells to determine if any advantage would be realized from this process. Initially, the effort provided for a single-stage stimulation event in each well, however, after the work commenced it was recognized that more than one stimulation stage would be required. At that point, a decision was made to direct the limited project funding toward a representative number of stimulation stages irrespective of the number of wells. In the end, a total of 21 simulation stages were performed in 17 wells, during two project phases.
During Phase I of the demonstration project a total of 14 stages were pumped in 10 wells. Three of these wells were in Perry County and seven in Pike County, both in the eastern Kentucky’s Big Sandy gas field. These treatments were pumped in January 1993. All of these wells produce from the Devonian Shale, a formation easily damaged by liquid-based stimulation processes. Six of the wells were stimulated with single-stage treatments while the four others received two-stage treatments. All stages contained approximately 120 tons of CO2 per stage, and proppant quantities on the order of 45,000 pounds per stage.
The five-year cumulative post-stimulation production performance data of the three Perry County, KY demonstration wells were compared to those of a 13-well control group stimulated with comparable nitrogen-based stimulations (12 nitrogen gas and 1 nitrogen foam). The results showed that in the three Perry County demonstration wells the stimulations were not as effective as the best conventional technology (nitrogen gas), realizing a stimulation cost of $0.69 per Mcf of added reserves versus $0.43 per Mcf for the conventional nitrogen gas stimulations. A time-dependent increase in the CO2 well’s performance relative to the N2 gas group may be a result of the proppant contained in the CO2/sand stimulations and absent from the N2 gas treatments, but it was not enough to recommend the carbon dioxide treatment alternative in that area. The carbon dioxide-treated wells did, however, perform better than the nitrogen foam-treated wells, by a factor of 3.57.
However, in the Pike County KY demonstration wells (where the shale section is 1,025 feet thick versus 350 feet thick in Perry Country), the wells stimulated with the CO2/sand process added reserves at a cost of $0.47 per Mcf versus $1.14 per Mcf for nitrogen. This equates to a five-year production benefit of 135.4 MMcf per well, or a 3.41 benefit ratio over the nitrogen alternative. The control group of wells in this case was made up of five CO2 foam and nine CO2 gas stimulations. The relative improvement of CO2/sand stimulations over N2 gas treatments was much greater for the nitrogen foam comparison, as before.
During Phase II of this project the process was demonstrated on three groups of wells situated in Chautauqua County, NY (3 wells), Mercer County, PA (1 well), and Putnam County, WV (3 wells). One stimulation was performed in each of the seven wells and the results compared with the performance of nearby control wells. In this case, no significant benefit was seen in any of the three groups, although casing failures and perforating practices may have been contributing factors to the demonstration wells relatively poor performance.
Current Status and Remaining Tasks:
This project is completed. A second project (DE-AC21-94MC31199) included similar data collection, CO2/sand fracturing treatments and post-frac analysis. Six wells were successfully fractured; three wells in the Canyon Sands of Crockett County, Texas, operated by Union Pacific Resources and three wells operated by Amoco Production Co in the Fruitland Coals in San Juan County, New Mexico.
Project Start: May 3, 1990
Project End: September 30, 2003
DOE Contribution: $2,196,802
Performer Contribution: $0
NETL – Gary Covatch (email@example.com or 304-285-4589)
PCS – Raymond L. Mazza (firstname.lastname@example.org or 330-499-3823)
Phase I Final Report
Phase II Final Report