Oilfield Technology correspondent, Gordon Cope concludes his explanation of how although combining enhanced oil recovery with carbon sequestration sounds like a win-win situation, significant hurdles stand in the way.

Problems

Using manmade CO₂ for EOR faces several significant challenges, however. First, not all reservoirs are good candidates. The oil must be relatively light oil, above 25 API. The reservoir temperature must be sufficiently warm to promote miscibility. The process works best in carbonate rocks that lack natural water drive, gas caps and major fracture patterns. CO₂ EOR also requires special field infrastructure to handle corrosion. When CO₂ mixes with water in the oilfield, it produces carbolic acid. Fields that have a high CO₂ or hydrogen sulfide content are fitted with stainless steel production lines to withstand the corrosion, but most fields are equipped with less expensive standard steel.

Even for the right candidate, production rates for CO₂ EOR projects vary widely. Pilot tests that indicate viability may not apply to a field that sprawls for hundreds of square kilometres; a US$ 1 billion investment in a large CO₂ EOR project might peter out after five years.

But the biggest issue is cost. Kinder Morgan recently presented a paper at the Society of Professional Engineers’ Annual Technical Conference and Exhibition in Denver on the economics of manmade CO₂ EOR. The company noted that, for a US$ 85 barrel of oil, the return is about US$ 17/bbl, or slightly under 20%. Costs include US$ 20 for operating expenses, US$ 18 for royalty and production taxes, US$ 10 for capital expenditures and US$ 20 for CO₂.

Unfortunately, US$ 20 does not come close to covering the amount spent to capture manmade CO₂. In order to get Shell Canada’s Scotford facility built, the governments of Canada and Alberta agreed to invest C$ 865 million in public funds. Various estimates place the operating cost of capturing CO₂ from US$ 15/t for gasification plants, to US$ 75/t for coal-fired power plants.

Transportation investment would also be expensive. Several years ago, the Interstate Natural Gas Association of America (INGAA) Foundation released a research paper in which they examined US CO₂ infrastructure needs. The INGAA study looked at two scenarios; the low and high case. In the low case, the US would have a CCS capacity of 300 million tpy by 2030, and in the high case, 1 billion tpy (or about 50% of annual coal-fired plant emissions). In the low case, the network would need 7900 miles of pipe costing US$ 12.8 billion (with over US$ 7 billion spent for compressors). In the high case, the network would need up to 56 000 miles of pipe costing US$ 65 billion (with almost US$ 25 billion for compressors).

Finally, storage facilities will need hundreds of millions of dollars to construct tankage and injection wells. The cost of injection is expected to range from US$ 0.50 - US$ 8/t.

Assigning who pays for what in all of this is problematic; producers want a low CO₂ price and modest transportation tolls, emitters are looking to offset their Opex with healthy sale prices and the government is reluctant to intervene in the market place to supply infrastructure. Delays have already had an impact on projects. Swan Hills Synfuels was proposing to build a combined in-situ coal gasification and electricity generation plant in central Alberta. The process generates synthetic gas in coal seams at depths below 1000 m. The flue gas, up to 1.4 million tpy of pure CO₂, was to be piped to nearby fields for EOR floods. The government of Alberta committed to pay C$ 285 million over 15 years to support the project, but the deal was cancelled due to poor economics.

Solutions, of course, can be found. The pricing of carbon through a tax or cap and trade rules has eluded US and Canadian legislators for some time now, but eventually a price for CO₂ emissions will be established that will engage emitters more avidly in the process. If the price is high enough, intermediaries might be willing to build CCS systems to obtain credits that they can sell over the open market. Field operators can be encouraged through royalty and fiscal regimes that benefit manmade EOR-produced oil.

The future

So far, most CO₂ EOR has focused on conventional fields, but geoscientists are now looking to new horizons. Scott Frailey and Robert Finley at the Illinois State Geological Survey, and John Rupp at the Indiana Geological Survey, recently published a paper exploring the potential for EOR in unconventional resources. The introduction of horizontal drilling and hydraulic fracturing into shale gas and shale oil have revolutionised the oil and gas industry in North America, reversing decades-long production declines and reducing US reliance on imported oil by almost 25%. Although the resource is too new to require EOR, the time will eventually come when unconventional resources will benefit from enhanced recovery. The vast trove of EOR process data from conventional fields can be combined with the increasingly sophisticated 3D seismic visualisation and intelligent production well information in order to design sophisticated EOR projects for unconventional fields

Researchers at the North Dakota University and the New Mexico Institute of Mining & Technology are examining chemical imbibitions (the displacement of one fluid by another immiscible fluid) using surfactant or brine formulations to stimulate oil recovery from the Bakken Shale of North Dakota. Their focus is to identify a surfactant formulation that minimises clay swelling and formation damage. Other research seeks to gain more knowledge of sweep and mobility control of CO₂ EOR. Such knowledge would be invaluable to operators seeking to introduce EOR into shale plays.

Bridging the gap between CCS costs and CO₂ EOR viability will require advances in technology, regulations and cooperation among stakeholders. Clearly, CO₂ EOR has vast potential; a recent report by the US Chamber of Commerce’s Institute for 21st Century Energy suggested that EOR could economically recover 67 billion bbls. of oil. Assuming a price of US$ 85/bbl, that would translate into US$ 6 trillion (with US$ 1.4 trillion in new government revenue). It is amazing how that level of investment can focus minds.

Part 1 of this article can be reached here.

Part 2 of this article can be reached here.

Adapted by David Bizley  from an article in the September 2013 issue of Oilfield Technology. Sign up for a free trial here.

Read the article online at: https://www.oilfieldtechnology.com/exploration/20092013/what_can_you_do_with_co2_part_3/