Successful CO2 Floods Require Project Management, Experience, Teamwork

(Tech Connections Column, January 2002, American Oil and Gas Reporter)

The 2001 Carbon Dioxide Conference held Dec. 4-5 
in Midland, Tx., is the preeminent CO2 conference for domestic oil and gas operators interested in CO2 flooding. The Center for Energy and Economic Diversification (CEED), University of Texas of the Permian Basin, and other sponsors (including PTTC’s Texas and Southwest regions) work hard each year to address current issues and present experience-based case studies. This year’s event was no exception.

As a teaser before presenting technology highlights, I would like to present critical nontechnical issues outlined by Dane Cantwell with Anadarko Petroleum Corporation. First and foremost, the Catch-22 rule of CO2 flood design: How does one determine whether a flood is economic before doing all the design work? An obvious first question relates to knowing how close the project is to an existing CO2 supply. A follow-up question relates to how the project performs under secondary recovery, assuming it is being waterflooded. Given favorable answers there, screening predictions using Kinder Morgan’s prediction tool or CO2-Prophet are appropriate. Finally, one must discover which economic factors will exert the greatest influence on project economics.

Before launching a CO2 project, one must recognize that project management skills are essential–both for inventorying tasks and establishing (and keeping) a project time line. Close teamwork with clear responsibility and accountability are essential, and credentials and experience of contractors to whom one outsources work must be strong. When it comes to actually implementing the CO2 flood, the team that designs it will generally be the best team to operate it.

For those operating existing CO2 floods, conformance control is often a major issue. Oxy Permian shared its experience addressing conformance problems in the Central Mallet San Andres CO2 flood in the West Texas Slaughter Field. CO2 injection began there in 1984, so the flood is relatively mature. Oxy Permian staff worked closely with Halliburton Energy Services staff in an integrated, open-door team environment. The team approached candidate selection on a fieldwide reservoir basis as opposed to evaluating individual wells. Montage plots, which showed the individual well injection and production histories in relation to the actual location of the wells, allowed the team to identify areas of the reservoir with direct fluid communication between injectors and producers.

Mechanical conditions of leading candidates, developed from a prioritized list of injector/producer pairs, were reviewed and additional diagnostic tests performed. Multirate injection profiles were run during both water and CO2 injection cycles, using a carefully controlled procedure and equipment that enabled the team to determine where fluids had gone at different conditions. Areas needing improvement were noted, best practices identified, and a successful team process developed.

Six wells have been treated using an in-situ generated (temperature-activated) polymer system. Economic success has led to six additional wells being identified for a second phase, and the nearby Slaughter Estate Unit CO2 flood is being analyzed for probable candidates. Readers are referred to SPE Paper 70068 (www.spe.org) for a thorough description of the process and early results.

However successful conformance control programs are, gas processing to remove hydrogen sulfide from recycled CO2 is a fact of life. Oxy Permian has experience with amine/Claus tail-gas treating (TGT) combinations and aqueous-iron liquid redox processes, and has been pilot testing the nonaqueous CrystaSulf process at a large pilot facility in its Denver Unit CO2 recovery plant. CrystaSulf, a service mark of the Gas Technology Institute, is marketed by CrystaTech Inc., an independent company formed to commercialize process technologies for the energy industry.

CrystaSulf’s nonaqueous components do not react with CO2, so selective H2S removal is possible in the presence of extremely high CO2 partial pressures without the complications that accompany aqueous approaches. At the pilot facility, the CrystaSulf process removes 2,000 ppmv H2S from a 300 psig, 85 percent CO2 stream. The pilot has proven reliable through 5,000 hours of processing. Beyond its ability to meet processing requirements, the process eliminates the root causes of many operational problems (solids plugging, foaming, corrosion).

Given satisfactory performance, economics strongly favor the CrystaSulf process. Cost comparison for a 40 million cubic-feet-a-day stream with 2,000 ppmv of H2S and 150 psig CO2 partial pressure indicates, on a capital operating or total annual cost basis, costs less than half an MDEA/Claus/TGT process. Additional information about CrystaSulf is available on Crysta Tech’s Web site, http://www.crystatech.com.
The conference included case histories on several field projects, including Little Creek Unit (Denbury Resources), SACROC (Kinder Morgan CO2 Company), Lost Soldier and Wertz Field (Merit Energy Corporation), the Spraberry Trend CO2 and water injection pilot (Pioneer Natural Resources), and the Seminole San Andres Unit residual oil zone flood (Amerada Hess), providing ample evidence that there was something for everyone to learn.

Contact CEED Director Robert Trentham, trentham_r@utpb.edu, for further information about the 2001 conference and proceedings.