The goal of this project was to identify was of: (1) reducing the formation reservoir damage associated with fracture stimulation treatments, and (2) improving the productivity and recovery from low-permeability, under-pressured natural gas reservoirs. The objective was to (1) test a non-damaging stimulation technology known as carbon dioxide(s) and fracturing, (2) assess the market potential for this technology, and (3) transfer the technology to industry.
A unique liquid-free stimulation treatment technique, which utilized carbon dioxide (CO2) as the working fluid, was developed in Canada. The process utilizes specialized equipment to enable proppant to be mixed and transported with liquid CO2, down the wellbore, to the target formation, to help prop the fracture to prevent it from closing. 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.
Petroleum Consulting Services, L.L.C. (PCS) – Project management and all research products
Canton, OH 44720 Crockett County, TX San Juan County, NM Phillips County, MT Blaine County, MT
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 of liquid sensitive, under-pressured reservoirs and comparing the results with those from conventionally fractured 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 first six demonstrations under the project were in two characteristically separate groups of three wells, all producing from the Canyon Sands at depths ranging from 6,700 to 7,000 feet in the Val Verde Basin of South Texas near the town of Ozona.
The Canyon Sands are known for the capillary retention of liquids and each of the two groups of three candidate wells were considered, for three reasons, to be viable candidates for demonstrating the liquid-free CO2\sand technology: (1) sensitivity of Canyon Sands to liquids; (2) UPRC’s expressed interest in this process; and (3) UPRC’s ability to effectively evaluate the results.
At the time of the demonstrations, a typical completion consisted of a 2 7/8-inch production tubing, cemented in a 7 7/8-inch diameter hole. A 1 1/4-inch coiled tubing was installed for liquid removal. The wells were produced through the tubing, some with intermitters, and no plunger lift hardware was present. Because the smaller diameter tubing would create excessive friction pressure losses at the 50-60 barrel per minute injection rates used in the CO2\sand stimulations, UPRC agreed to install a 4 1/2-inch casing for completions of the DOE-approved candidate wells.
The first three wells (G & H Sand completions) were a single stage stimulation. The reservoir pressure was about 80 to 90 percent of the original. For these wells, the estimated ultimate recovery (EUR) had to exceed 300 MMcf for minimum economic hurdles to be met.
The second three demonstration wells (C & E Sand completions) were a two stage stimulation. The reservoir pressure was about 50 percent of the original (when they were drilled on 320 acre spacing) and the EUR’s had to exceed 1,500 and 4,500 MMcf for economic success.
The second group of three wells (C & E Sand completions) stimulated with the CO2/sand technology is considered an economic success by UPRC and are producing at the average of the economic hurdle rate. The first group of three wells (G & H Sands) is producing at lower levels and is considered to be economically indefensible.
Three demonstrations were carried out in Fruitland Coal wells operated by Amoco Production Co (purchased by BP) in San Juan County, NM (3 wells – 3 stages). The three candidate wells were selected and stimulated with CO2/Sand in January 1996. The wells had limited sand volumes placed and have not produced at economic rates. Production from all three wells has been generally lower than that from conventionally stimulated wells. The limited placement of sand is suspected to be a result of the very large number of perforations (approximately 300) which reduced the transport velocity.
The fourth group of wells treated were situated within the Williston Basin on the Bowdoin Dome. These wells, located in Phillips County near the town of Saco, were selected on the basis of production projections from conventionally stimulated offset control wells and were hydraulically fractured with CO2/sand in July 1998.
The Phillips Sandstone is a low-pressure, nearly dry-gas formation which produces a small quantity of water, primarily as a vapor. These wells generally have EURs ranging from 175 to 400 MMcf and are typically stimulated with nitrogen foam and 40,000 lbs of sand proppant. However, the long time required to reach maximum production rates, following conventional foam stimulations, led to the suspicion that the spent stimulation liquids were damaging the formation and that liquid-free CO2/sand stimulation could potentially provide a significant benefit.
The CO2/sand demonstration stimulations utilized approximately the same proppant volume and it was anticipated that the comparable-length hydraulic fractures generated with the CO2/sand process should be more productive. Unfortunately, the results were disappointing in that the 24 month cumulative gas production from the three candidate wells stimulated with CO2/sand have not out-performed the seven control wells stimulated with conventional nitrogen foam. The cumulative production performance for the CO2/sand and nitrogen foam stimulations are essentially identical.
One possible explanation for this response could be the smaller size proppant used in the CO2/sand stimulations. The three candidate wells utilized 20/40 mesh proppant while the control wells employed larger 12/20 size proppant.
The final demonstration well group was four wells operated by Ocean Energy (purchased by Devon Energy), producing from the Eagle Sand in Blaine County, Montana. The overall combined cumulative production for these four wells, after slightly more than 19 months of production, is 204.4 MMcf and the incremental production increase attributable to the stimulations is 68.3 MMcf (33 percent of the total).
Current Status and Remaining Tasks:
This project is completed. A second project (DE-AC21-904MC26025) includes similar data collection, CO2/sand fracturing treatments and post-frac analysis. The stimulations in that project were performed in the Appalachian Basin. That project is also completed.
Project Start: September 30, 1994
Project End: August 31, 2004
DOE Contribution: $1,496,441
Performer Contribution: $475,624
NETL – Gary Covatch (firstname.lastname@example.org or 304-285-4589)
PCS – Raymond L. Mazza (email@example.com or 330-499-3823)
Final Report [PDF-76183KB]