Alberta Oil Sands Technology and Research Authority (Aostra) has completed a horizontal well in situ steam injection project it calls a major breakthrough in commercially producing bitumen from the vast Athabasca oilsands deposit in Alberta.
Aostra said its $71 million (Canadian) proof of concept pilot underground test facility (UTF) near Fort McMurray, achieved a 60% bitumen recovery rate, compared with less than 20% recovery typically achieved with Alberta bitumen. More than 100,000 bbl of bitumen was produced during the project.
Less than 10% of the almost 1 trillion bbl Athabascan oilsands deposit can be developed economically through current technology. The rest is too deep for surface mining.
RESOURCE, OPERATIONS
Aostra, in a paper given at a technical conference at Banff, Alta., said its technology exposes a resource of almost 500 billion bbl of oil to the North American market that had been uneconomic.
The paper, written by Project Manager J.C. O'Rourke and four coauthors, estimates a commercial project could produce bitumen for $11-13/bbl, including capital and operating costs.
UTF operations involved development of a steam assisted gravity drainage technique with two horizontal wells at the base of the reservoir and a shaft and tunnel access system enabling drilling and control of eight horizontal wells from tunnels 15 m below the oilsands and 180 m subsurface.
In addition to the high bitumen recovery rate, the technology that's used features a low steam:oil ratio, no well workovers, and good production rates.
Aostra and industry participants last year began work on a precommercial pilot phase estimated to cost $65 million by March 1994. At that time, a decision is to be made on whether to proceed with a commercial project. Total UTF spending by March 1994 is projected at $150 million, with Aostra's share $95 million.
Industry participants in UTF are Amoco Canada Petroleum Co., Chevron Canada Ltd., Conoco Inc., Esso Resources Canada Ltd., Mobil Corp., Petro-Canada, and Shell Canada Ltd. By participating in the project, they gain access to the technology and earn an 8 1/3% interest in the 49,400 acre lease at the UTF site.
THE PROCESS
The UTF pilot involved two vertical shafts penetrating 143 m of overburden, 20 m of oilsands, and 15 m of limestone below which are horizontal tunnels and three pairs of parallel horizontal wells at the bottom of the pay zone.
The horizontal tunnels are 8 m wide and 5 m high where the horizontal wells are drilled.
Aostra used a self-propelled, track mounted drill to drill 160 m long horizontal holes 25 m apart upslope from the tunnels into the bottom of the oilsands.
In the process, Aostra injects steam into the upper horizontal well just below formation fracture pressure, liquefying the bitumen, which flows with condensed steam to the lower horizontal well.
Temperature of produced fluids is maintained at 5-10 C. below saturated steam temperature in the formation to maintain flow.
Bitumen and produced water is pumped to an inverted high temperature/high pressure separator at the surface, then to a flash separator where the remaining water is removed.
THE RESULTS
Aostra did not disclose production rates from the concept pilot but extrapolated results to longer horizontal well pairs-500 m of net pay-in an effort to estimate commercial scale production.
Projected in situ horizontal well production rates are two to four times higher than other heavy oil projects, it said.
Aostra noted bitumen production occurs early in the process, the steam:oil ratio is fairly consistent throughout the process, and almost all the steam is utilized and comes out as produced water.
The agency contends positive results stem from:
- A net pay zone in the horizontal wells far exceeding that in vertical wells.
- A recovery geometry in a well pattern consisting of many long, trough-like steam chambers with horizontal wells that is superior to the conical steam chambers associated with vertical wells.
- The nonfracture nature of the Aostra process uses steam heat more completely than fracture based processors, which can lose steam and result in higher steam:oil ratios.
ECONOMICS
Based on the proof of concept pilot, Aostra contends the economics of a 10,000 b/d, 15 year, project using its technology compares favorably with other heavy oil projects in Alberta, with supply costs estimated at $10,88/bbl.
The hypothetical model is based on drilling 70 horizontal well pairs 600 m long. Three tunnels, a center tunnel for the horizontal wells, an air intake tunnel, and an exhaust tunnel, would connect the system.
Aostra projects capital spending for such a project at $155 million and operating costs at $22 million/year.
The $10.88/bbl supply costs include a 10%/year discount of capital and operating costs, taxes and royalties excluded.
Additional wells would cost only $1.03/bbl, low considering each well costs about $600,000 and tunnels are about $2,800/m, Aostra noted, adding that the high well costs are offset by greatly improved performance.
PRECOMMERCIAL PILOT
Under the precommercial pilot project, bitumen production is expected to reach 2,000 b/d.
Goal of this phase is to confirm that the Aostra process is technically and economically feasible for commercial scale wells. This project began in early 1990 and is to extend at least to Mar. 31, 1994.
Three horizontal well pairs 600 m long and 70 m apart are planned, which called for blasting another 550 m of new tunnel. Two of the three well pairs have been drilled, with the third pair expected to be complete by the end of May. Production from the first well pair is to begin in September.
Aostra also will build a surface process plant, to be complete in summer 1992, consisting of facilities for surface steam generation, fresh water treatment, bitumen dehydration, and produced water treatment and disposal. All three well pairs are to be on production by September 1992.
IMPROVED TECHNOLOGY
Improvements in current technology will add to technical and economic feasibility of its process, the agency said.
Measurement while drilling survey systems operating independently of the earth's magnetic field would greatly speed the drilling process. Aostra predicts 600 m long horizontal wells could be drilled in 15 days, compared with the 23 days it took for its fastest drilled well.
Technology for surface production control is needed so horizontal wells can be drilled from the surface instead of from tunnels. In surface controlled wells, produced fluid would be in gas and liquid phases at the wellhead, with large steam and gas volumes making it difficult to control fluid rates. One solution would be development of a downhole remote control flow valve.
Aostra also notes there could be advantages to using the process in a single horizontal well, rather than well pairs. However, Aostra's analytical modeling shows cost savings of drilling one well instead of two may be offset by reduced production and increased operating costs.
OTHER APPLICATIONS
Aostra said its technology could be applied to other areas of the Athabasca deposit and to other oilsands and heavy oil deposits.
It conducted a study of the Athabasca deposit and determined that as much as 460 billion bbl could be produced with the process in just the areas where there is more than 75 m of overburden.
Aostra projects that the process could be economic with as little as 30 m of overburden.
The technology should be applicable in any area where in situ steam stimulation is used to produce bitumen or heavy oil, Aostra said.
The agency expects recovery ratios with its technology to be significantly better than in commercial steam huff and puff operations.
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