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.

Petroleum Consulting Services, L.L.C. (PCS) – Project management and all research products

Location:
Canton, OH 44720 Crockett County, TX San Juan County, NM Phillips County, MT Blaine County, MT

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.

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.

• Collaborated with four operators in three states located in the western U.S. to develop a portfolio of candidate wells for demonstrating CO₂/sand fracturing and control wells for performing post-treatment performance comparisons,
• Selected a group of 16 wells (19 stages) for cost-shared demonstrations in Montana, New Mexico, and Texas, and performed single- and two-stage CO₂/sand fracture treatments, and
• Gathered 5-year cumulative production data from demonstration wells and control wells and performed comparative analysis to quantify effectiveness of new CO₂/sand fracturing technology for different areas.

This project was completed in two phases. Phase 1 consisted of data collection activities and Phase II of actual carbon dioxide/sand fracturing treatments and post-frac analysis. Sixteen wells (19 stages) were successfully fractured with the carbon dioxide/sand fracturing process: six wells (9 stages) in the Canyon Sands of Crockett County, Texas, operated by Union Pacific Resources (UPRC, purchased by Anadarko); three wells (3 stages) operated by Amoco Production Co (purchased by BP) in the Fruitland Coals in San Juan County, New Mexico; three wells (3 stages) operated by WBI (now Fidelity E&P) in the Phillips Sand in Phillips County, Montana; and four wells (4 stages) operated by Ocean Energy (purchased by Devon Energy) in the Eagle Sand in Blaine County, Montana.

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).

and Remaining Tasks:
This project is completed. A second project (DE-AC21-90MC26025) 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.

$1,496,441

$475,624

NETL – Gary Covatch (gary.covatch@netl.doe.gov or 304-285-4589)
PCS – Raymond L. Mazza (o.g@worldnet.att.net or 330-499-3823)

Final Report [PDF-76183KB]