Ninth Annual CO2 Conference and North Hobbs Unit Visit, December 2003, Midland, Texas, USA

The Kyoto commitment by the UK and other countries around the world to reduce CO2 (and other green house gas) emissions to the atmosphere has prompted a renewed interest in the possibility of capturing CO2 at power plants and other industrial sources and using it for EOR. David Hughes (david.hughes@senergyltd.com), Principal Reservoir Engineer with Senergy Ltd in Aberdeen, attended the Ninth Annual CO2 Conference organised by the SPE Permian Basin section in Midland, Texas. Here he presents his overview of the conference, including his observations on the visit to Oxy Permian Ltd's CO2 flood in the North Hobbs Unit in New Mexico .

The 9th Annual CO2 Conference was held during 10-12 December 2003 in Midland, Texas, USA. It is perhaps indicative of the growing popularity of CO2 flooding that the words "Permian Basin" have been dropped from the event title. This popularity is not without its downsides as the organisers had to relocate from their usual venue at the Center for Energy and Economic Development (CEED) near the airport to the larger downtown Midland Center for part of the event. Overall around 240 delegates attended representing 12 different countries.

My over-riding impression is that with a CO2 supply of <$1/Mscf (<$20 per tonne), CO2 flooding in the Permian Basin and elsewhere in the US and Canada is established technology operated with the same ease as waterflooding. A lot of what was presented related to improved technological sophistication and optimisation of economic performance. The challenge to us with offshore assets developed from fixed or floating production facilities is firstly to secure a CO2 supply delivered at a price not much higher than that pertaining in Texas, and secondly to adapt the hardware approaches to work within the space and weight limitations imposed by offshore developments.

Visit to North Hobbs Unit CO2 Flood

The first day was spent visiting Oxy Permian Ltd's CO2 flood in the North Hobbs Grayburg-San Andres Unit to the west of Hobbs City just over the border into New Mexico. In 2003 there were 54 active CO2 floods in the Permian Basin producing 160 Mstb/d of incremental oil. 16 of these are operated by Oxy Permian. Hobbs is the newest addition to the world's most prolific CO2 flooding region.

Around 100 of us took the bus trip to Hobbs for the approximately 110 mile journey. During our journey we were acquainted with some of the basics of CO2 flooding by Reid Greg, of the New Mexico Petroleum Recovery Research Center .

On arrival at Hobbs City we went to New Mexico Junior College for a briefing on the project by Gary Bullock, Barry Petty and Fred Forthhuber of Oxy Permian Ltd.

Oxy Permian is converting around half of the North Hobbs Unit from waterflooding to CO2 injection. This first phase will involve around 250 wells, including 60 new wells, 30 reactivated wells and 30 more undergoing major workovers. Original oil-in-place in North Hobbs is around 1 billion stb.

CO2 is supplied to the field by Trinity CO2. A new 10 mile, 12 inch diameter spur costing $3 million was built off the West Texas pipeline, part of the Permian Basin-wide CO2 pipeline system, to bring the CO2 to Hobbs. The CO2 originates from natural sources at McElmo Dome, Bravo Dome and elsewhere and is supplied for <$1/Mscf.

Preliminary laboratory work indicated a minimum miscibility pressure (MMP) with the Hobbs 34 °API reservoir oil of 1300 psia for pure CO2 increasing to 1450 psia if the CO2 contains 20% impurities. Reservoir pressure during water flooding is typically 1900 psia with fracture pressure estimated to be 2800-2900 psia. CO2 is supplied at 1950 psia with the BHP maintained at around 2400 psia. However, the injection pump and its control system is an Oxy patented system which varies the THP to ensure that gas is injected at a constant rate despite the changing density of the static column (from variations in the composition, temperature and BHP). The reservoir temperature is 110 °F.

Figure 1: CO2 Injector Wellhead (Inset: Location of Hobbs ) (Click for larger view)

The San Andres formation depth is 4000 ft. Porosity and permeability are typically 25% and 100 mD respectively with gross pay thickness typically 200ft. The watercut at producers prior to conversion to CO2 flooding varies between 95-98%. The field is developed with a 40 acre well spacing with line-drive, 5-spot and 7-spot patterns. CO2 breakthrough is seen in 2-4 months. Expectations (based on simulation studies) are that the post waterflood oil cut of 3-5% will increase to 10-30%. Typical gross liquid rate per well is 2000 b/d. Typical CO2 injection rate per well 2 MMscf/d. In late 2003 the total injection rate was 85 MMscf/d (65 MMscf/d of purchased gas and 20 MMscf/d recycled).

Figure 2: Satellite Battery Showing Water and Gas Injection Manifold (Click for larger view)

An initial 20% HCPV slug is planned followed by water-alternating-gas (WAG). However, the size of the initial slug and WAG ratios will be revised on a pattern basis according to performance. Total CO2 injected is planned to be 60% HCPV (300 billion scf purchased - and around as much again recycled) with an anticipated additional recovery factor of 14-15% of original oil-in-place in the converted area which amounts to 75 MMstb. All produced gas is reinjected (i.e. the CO2 diluted somewhat by hydrocarbon gas) into dedicated injectors (some of these are new wells) located in a specific area. These numbers point to a gross CO2 utilisation of around 8 Mscf/incremental barrel, with a net value around half this. Lifting cost is approximately $5/barrel plus the cost of the CO2.

Phase 1A (implemented during 2002-2003) of the project involves 52 producers (all with ESPs) and 20 injectors (14 injecting CO2 and water and 6 injecting produced gas and water). Phase 1B will follow in 2004. 7 new production/injection batteries handle the production and injection related to the tertiary project. 1 new central injection battery combined with a re-injection compressor facility was required and 2 other central batteries were extensively modified.

The total cost of the capital investment was $70 million. The engineering and design contractor was Mustang Engineering (a Wood Group company).

Figure 3: Central Tank Battery and Injection Plant (Click for larger view)

Following the briefing we had lunch at the New Mexico Junior College and then set off on a bus tour of the facilities. We saw various CO2 injection well heads, injection and production facilities at a satellite battery, the Central Tank Battery and Injection Plant, the new electrical substation, and the combined Western Injection Battery site and Re-injection Compressor Facility.

Figure 4: Part of Re-injection Compressor Facility (Click for larger view)

Overall this was a very enjoyable visit to a state-of-the-art project. Thanks go to Oxy Permian for their hospitality and also to New Mexico Petroleum Recovery Research Center for their part in the arrangements.

Technical Presentations

The technical sessions began on the second day at the Midland Center. Proceedings kicked off with an ice-breaker (apparently a tradition) hosted by Chuck Fox of Kinder Morgan based on the theme of a TV quiz. The $1,000,000 question (or maybe it was $100) in this Kinder Morgan sponsored quiz was "Who is the biggest supplier of CO2 in the world?". I can't remember the correct answer!

The first presentation was on new trends in the surface processing of CO2-rich produced gas to separate the hydrocarbon gas for sale and the CO2 for re-injection by John Morgan of John M Campbell and Company. The main trend that came out was that the more exotic materials such as stainless steel need only be used sparingly - coatings and even carbon steel are fully satisfactory for many components. The next three sessions were by Ken Havens, Jim Gross and Jeff Layne of Kinder Morgan. These described the growth of the CO2 pipeline system, the new Centerline CO2 pipeline in West Texas and a recent hydrotest on a 30 year old pipeline. Kinder Morgan has a total network capacity 4.3 billion scf/d, delivering over 1 billion scf/d into the Permian region. The new 16 inch Centerline Pipeline covers the 120 miles from Denver City to Snyder. This primarily supplies the SACROC Unit, but is also available for third-party delivery to CO2 projects in the Horseshoe Atoll area. The hydrotest of the 131 mile pipeline from Snyder to McCamey was completed in 35 days (compared to an estimated 30 days) despite the loss of 17 days mainly to the weather. All valves were replaced. The pipeline was successfully tested to 2750 psig enabling operations to continue at the established maximum operating pressure of 2025 psig.

Over lunch Jim Slutz from the DOE spoke about the US Government's programmes related to the geological sequestration of CO2.

The afternoon began with a presentation on the flammability of mixtures of CO2, hydrocarbon and other gases by Bob McCallum of Oxy Permian and Ken McIntosh from Trimeric Corp. This is very important in field operations. The recommendation is to undertake flammability tests. However, in their absence predictions can be made using established empirical algorithms. CO2 suppresses flammability more than N2.

Bill Daily of Lawrence Livermore National Laboratory then spoke about field trials of electrical resistance tomography. Trails have been undertaken at a steam flood in Bakersfield and at a ChevronTexaco operated CO2 injection project near Hobbs. Electrodes are connected to well heads and small currents are measured between well pairs in all combinations over a short time interval. The results are then deconvoluted to establish the saturation distribution. The process can be repeated at later times and the results compared. It works on the basis that CO2 increases and steam reduces resistivity. Results to date show changes that can be correlated with a reservoir's production history.

Bob Mannes spoke about Core Energy's two Niagaran Reef CO2 projects in the Michigan basin. CO2 is supplied via a pipeline from a nearby amine plant processing Antrim formation gas production. By the end of 2003 around 700 Mstb of incremental oil had been produced. Frank Lim from Anadarko Petroleum rounded off the day's presentations with an overview of a new tertiary CO2 project in the Monell Unit Patrick Draw Field in Wyoming. The unit was developed by primary depletion followed by waterflooding. Recovery factor is 35% with 72 MMstb remaining. A pilot was initiated in a single 40 acre 5-spot pattern, with CO2 injection in the central well, water injection in the 2 wells each side of the CO2 injector to ensure containment of the slug, and production from the remaining 2 wells. The pattern swept by the CO2 was assessed using time lapse 3D vertical seismic profile (VSP) surveys. Results suggest that a unit-wide development could produce 25+ MMstb of incremental oil bringing the recovery factor up to 58% (a 23% increase in RF!). Gross CO2 usage is 5-8 Mscf/stb. Unit wide redevelopment is expected to be complete by 2005.

During the evening a networking reception was held at the Midland Petroleum Museum ( http://www.petroleummuseum.org ). The museum boasts the largest public collection of antique petroleum equipment and interactive displays trace the history of oil development in West Texas .

Figure 5: The Petroleum Museum, Midland (Click for larger view)

The final session of the conference on the morning of day three was held at CEED. Tom Thurmond of Anadarko Petroleum presented the design of a shallow low-temperature miscible tertiary CO2 project at Salt Creek, Wyoming. This presents unique challenges. Normal operating conditions are below the MMP so injection pressure will need to be raised to near the fracture pressure requiring careful control and monitoring. An increased well density reduces the range of operating pressures within a pattern. Throughput of larger amounts of CO2 through recycling is beneficial. The process has been tested successfully in a pilot. Field-wide application is planned following completion of a new 125 mile pipeline to Powder River Basin in 2004. The next presentation was by Scott Wehner of Kinder Morgan who went through the history of SACROC and discussed the latest developments. Increased understanding of how miscibility is achieved and maintained, improved containment of the CO2, either by closed patterns or "water curtains" and WAG optimisation are among the techniques that have increased the expected incremental recovery from CO2 to around 13% of oil-initially-in-place.

The final two presentations were by Ryan Adair of En Cana who described the redevelopment of the Weyburn field in Saskatchewan using CO2 injection, and Mike Uland of iReservoir.com and Ken Kosco of Amerada Hess who presented the results of an intensive reservoir characterisation study at the Seminole San Andres Unit where there is a mature CO2 flood. The Weyburn project was reviewed in some detail in the last issue ( http://ior.rml.co.uk/issue6/articles/RML/weyburn.htm ) and Mike and Ken have kindly provided an article on their characterisation study for this issue.

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