TECHNOLOGY Heavy oil expansions gather momentum worldwide

Guntis Moritis
Production Editor

Cold production, wormholes, foamy oil mechanism, improvements in thermal methods, and horizontal wells are some of the processes and technologies enabling expansion of the world's heavy oil/bitumen production.

Such processes were the focus of the International Heavy Oil Symposium in Calgary, June 19-21. Unlike conventional oil production, heavy oil/bitumen extraction is more of a manufacturing process where technology enables the business and does not just add value.

The current low price spreads between heavy oil/light oil indicate that demand for heavy oil is high.

Low spreads

Recent decreases in price differential between light and heavy oil (Fig. 1)(39115 bytes) indicate the high demand for heavy oil and have helped renew interest in producing heavy oil. But from the refining viewpoint, differentials will have to widen for heavy oil demand to increase in the long-term.

The differential between Arab light and heavy has fallen from about $4.00/bbl in 1991 to $0.70/bbl now. Mexico's Isthmus/Maya differentials were $5.30/bbl in 1991 and are now about $2.50/bbl. The largest narrowing of spreads has occurred between West Texas Intermediate and Kern River. These dropped from a high of more than $10.00/bbl in 1991 to about $2.50/bbl.

At the heavy oil symposium, experts from Texaco Inc., Exxon Co. International, and Purvin & Gertz Inc. said light/heavy crude differentials will widen by the end of the decade, although differentials may remain low in the near term as refiners continue to add conversion capacity.1-3 Purvin & Gertz sees the Mexican differential increase to $3.75/bbl in 2000.3Reasons for the low spreads include the world's increasing conversion capacity (Fig. 2)(39833 bytes), Saudi Arabia's switched focus to light oil production, Mexico's restriction on Maya oil export, additional North Sea light oil production, regional demand for fuel oil, and an exceptionally mild 1994/

1995 winter.

Sizable additions to refinery conversion capacity are forecast for the next 2 years but these are expected to drop off steeply after 1997 (Fig. 2 and Table 1)(14573 bytes) at which time the spreads between light and heavy oil are likely to start to widen.

Forecasts indicate light oil will begin to outpace heavy oil demand. One projection is that the world in 2000 compared to 1993 will need an additional 8.5 million b/d of light crude but only 2.0 million b/d of heavy crude.1 Another projection includes a lower increase in heavy oil production (Fig. 3)(39673 bytes).

To meet these forecasts, existing production will need expansion, and new projects will have to be initiated.

Currently, about 8 million b/d of heavy and extra-heavy crude are being produced. Table 2(20927 bytes) shows representative crudes that fall in the light sweet, light sour, heavy sour, and extra-heavy categories.

Canada

About 300 billion bbl of Alberta's 1.7-2.5 trillion bbl of bitumen in-place are believed to be recoverable. Alberta's National Oil Sands Task Force estimates that current technology can recover economically about 4.0 billion bbl of these 300 billion bbl.4

It forecasts that the rate for extracting heavy oil could triple by 2020 to 1.2 million b/d. Costs for this expansion are in the order of $15.3-18.3 billion ($C21-25 billion). This growth is based on an oil price of about $18.25/bbl ($C25/bbl).

The main areas of heavy oil activity in Alberta are in Athabasca, Cold Lake, and Peace River (Fig. 4)(53791 bytes). The sands containing bitumen can outcrop at the surface or be several hundred meters below ground. Surface mining projects near Fort McMurray are recovering the near-surface reserves in the Athabasca area while in situ recovery produces the bitumen from deeper deposits.

The heavy oil/bitumen is either mixed with diluent to form a blend and shipped to refineries by pipeline or is upgraded to a synthetic crude oil or other refinery feedstock streams. The mixing of a diluent such as a API 50+ stream and an extra-heavy 11 API crude, results in a 22 API heavy crude.

Oil sand activity falls into three broad categories:

1. Integrated mining extraction and upgrading projects -- In Canada, Suncor Inc. and Syncrude Canada Inc.'s projects produce over 260,000 b/d of upgraded light, sweet crude oil blends.

2. In situ projects -- In Alberta, 16 in situ projects produce about 140,000 b/d of bitumen.

3. Stand-alone upgraders -- The two-stand alone upgraders are the BiProvincial (Husky) Upgrader in Lloydminster, Alta., and the NewGrade upgrader in Regina, Sask. Each can produce about 50,000 b/d of synthetic crude oil.

Cold Lake

At Cold Lake, Imperial Oil Ltd. operates the largest in situ bitumen extraction project in the world. Its 11 API and 75,000 cp bitumen lies at a depth of 1,500 ft, and now production is about 100,000 b/d.

Imperial Oil started pilot tests on cyclic steam and electrical heating effectiveness for bitumen recovery from the Clearwater sands in the mid-1960s.

About 38 billion bbl are in place on Imperial Oil's leases. About 750 million bbl are thought to be recoverable with present technology and economics.5

In the 1980s, Imperial Oil began developing Cold Lake on a phased basis without including an upgrader. This reduced initial costs and project start-up time. Production commenced in 1985.

To reach pipeline specifications, Imperial Oil mixes about 10 bbl of bitumen with 3 bbl of diluent, which is a natural gas condensate (C5+), to obtain the 22 API Cold Lake Blend.

Typical daily sales of the blend are to:

Vancouver: 5,000 b/d
Prairies: 27,000 b/d
Ontario: 12,000 b/d
Billings: 10,000 b/d
U.S. Midwest: 67,000 b/d.

In 1977, when Imperial Oil proposed the start of its megaproject, it believed only 13% of the bitumen in place could be recovered. Now it expects recovery factors of 25% from its commercialized sites.6 Technologies that have helped improve expected recovery factors include:

Changes in well spacing
Better geological description
New steaming strategies
Improved producing strategies
Less costly fluid treatment.

The current steaming strategy (Fig. 5)(76720 bytes) includes pads with 20 wells each drilled with 4-acre well spacing. Steaming is done on a "megarow," which is the simultaneous injection of steam to all wells along a row of wells extending over all the pads. This helps control steam communications along a row.

Overlap of steaming or having more than one row of wells with steam injection helps pressurize the reservoir. The higher pressures promote distribution of steam to areas where steam previously had not reached.

Soaking helps to redistribute the steam. Another technique Imperial Oil uses to allow steam to reach new areas is to increase steam volumes in progressive cycles.

To help maintain production in the older areas, Imperial Oil is drilling horizontal wells under the old vertical well pads which are used to inject steam. It currently has three pads with horizontal wells.

Unit operation costs have significantly decreased since the project began. Costs were over $C7.10 in 1986 and are now about $C4.30. The natural gas used for fuel remains the main cost item that can fluctuate greatly. Gas, about 120 MMscfd, is obtained from nearby shallow wells and from Nova Corp.'s pipeline system.

Imperial Oil plans to increase production from the current 100,000 to about 120,000 bo/d after drilling about 500 vertical wells to finish Phases 9 and 10. Imperial says costs for a 20 well pad are about $C6 million, about $C200,000 to drill and complete each well and $C2 million for associated surface equipment and steam lines.

Phases 11 and 12 are on the drawing boards and should increase production another 30,000 bo/d to 150,000 bo/d. For these phases, Imperial Oil is considering several cost-reduction strategies, such as:

Elimination of water deoiling steps by going to ceramic membranes. These are currently being pilot tested.
Improvements in boiler design.
Going to 30+ well pads with wells on 8-acre spacing instead of the current 4-acre spacing.
Saving energy by integrating the phases with the current infrastructure.
Adding cogeneration facilities.
Improving cyclic steaming by such methods as pulsed injection which is currently being pilot tested.
Expanding the use of follow up processes such as horizontal wells.

Imperial Oil is not using steam-assisted gravity drive (SAGD) for initial development because the pay has limited vertical permeability caused by a complex channel sand deposition geology.

Other Canadian projects

A number of other heavy oil projects in Canada are also under development.

The Alberta Department of Energies underground test facility (UTF), outside Fort McMurry, is entering a second phase of testing of SAGD technology that includes horizontal laterals drilled from an underground tunnel. Current production is about 1,000 bo/d.4

Amoco Canada Petroleum Co. Ltd. is planning expansions that in the Wolf Lake field primarily involve drilling horizontal wells under vertical well pads and in the Primrose field developing the reserves with horizontal wells and SAGD techniques. These fields lie in the Cold Lake area(46461 bytes). Currently the two fields produce about 10,000 bo/d and Amoco says facilities at Wolf Lake can handle about 30,000 bo/d from both fields before needing expansion. Plans call for both areas to produce about 55,000 bo/d by late 1997.

Amoco plans a phased development and expects to spend about $73 million ($C100 million) initially in 1995. Total investment may approach $365 million ($C500 million) over the next several years.

Koch Exploration has proposed a new in situ project that would produce about 50,000 bo/d using primary production recovery in the Lindbergh area.4

Solv-Ex Corp. has plans to produce 13,500 bo/d from a project north of the existing Athabasca operations.7

Shell Canada Ltd. is experimenting with horizontal drilling at its Peace River in situ project using SAGD technology. Current production is about 8,000 bo/d and plans are to reach 50,000 bo/d.4

Suncor Inc. and Syncrude Canada Ltd. have announced expansion plans for their two bitumen-mining operations. Suncor's plans include investing $C250 million to increase production to 80,000 bo/d by 1998, while Syncrude hopes to up production another 16,000 bo/d by 2000 from the current 201,000 bo/d.4 Slurry pipelines, eliminating centrifuges, and truck and shovel operations are ways the companies are planning to lower costs and extend the areas that are economic to mine.

Elan Energy Inc. has patented the use of an insulated coiled tubing to deliver steam to the end of a horizontal well. It calls this a single-well SAGD process.

Steam is injected into the well through insolated coiled tubing, and oil is produced from the same wellbore. Elan developed the technology with Nowsco Well Servicing Ltd. In the first well test at its Cactus Lake operation, Elan says this technology has more than doubled production, to 600 b/d from 300 b/d.

In Elan's recently purchased Elk Point-Lindbergh area Elan says it has reactivated 75 of the 500 shut-in wells and is targeting another 165 wells by the end of August. Production has increased by about 2,500 b/d of 11-12 API bitumen or 34 b/d/reactivated well, according to Elan.

Cold production

A number of companies in Canada are having success with cold production, heavy oil production without steam. In some cases, initial high rates of sands are produced with the heavy oil. With time sand production decreases but oil production remains. In other cold production, no sand is produced.8-10

In the case of no sand production, foamy oil behavior is believed to be the key to the higher production rates than would be predicted by classical Darcy models. The foamy oil mechanism results from dispersed gas bubbles retained in the bitumen. These microbubbles appear as reservoir pressure depletes and significantly reduce the bitumen viscosity.

Where sand is produced, "wormholes" may be created that greatly increase the permeability. Laboratory experiments have confirmed the possibility of wormholes. Foamy oil behavior also may contribute to the higher oil producing rates seen with sand production.

Co-sand production is said to sustain production rates at 30-95 bo/d, and recover 5-12% of the oil in place. Without sand production, cold production in most cases would be uneconomical.11 Typical reservoirs where co-sand production has been tried are 20-80 ft thick, lie at depths of between 980-2,000 ft, and contain 10-16 API oil.11

Venezuela

Venezuela has about 45 billion bbl of proven heavy and extra-heavy crude compared to only 19 billion bbl of proven light and medium crude. With possible additions and including the Orinoco belt(12721 bytes), technically proven reserves (Fig. 7)(59299 bytes), total recoverable reserves are estimated to be 289 billion bbl of heavy and extra-heavy crude and 61 billion bbl of light and medium crude.12

Fig. 8(40709 bytes) indicates that Venezuela plans to increase production capacity to 4.3 million b/d by 2000 from 3 million b/d in 1994. The expected increase in heavy and extra-heavy crude is 293,000 b/d.

In 1995, Venezuela expects to sell 44% of the heavy oil to third parties. Pdvsa (Petroleos de Venezuela) wants to refine 34% in refineries abroad and 22% locally. By 2000, only 38% is expected to be sold to third parties, with 35% being refined abroad, and 27% locally.

Four major associations with foreign companies are planned to produce Orinoco tar sands and upgrade them to a synthetic crude with API gravities ranging from 21 to 31 (Table 3). Total investment in these four projects is expected to be $9.75 billion.

The Conoco Inc./Maraven SA project foresees production costs of $2.20-3.00/bbl. If recovery of investment is included, costs are in the range of $3.50-4.80/bbl.12

Venezuela also produces a direct combustion production that is called Orimulsion, a mix of bitumen, emulsifier, and water. Bitor S.A. (a subsidiary of Pdvsa) is the operator for extracting and marketing Orimulsion. Current production is about 45,000 b/d and is expected to increase to 180,000-200,000 b/d by 2000.

Corpoven

Corpoven SA is having considerable success in the Orinoco tar sands belt with cold production from horizontal wells.13 The success is attributed to the foamy oil mechanism with which dispersed gas bubbles retained in the bitumen increase production rates above those expected from traditional calculations. No sand is produced.

Historically, calculations indicated to Corpoven that cyclic steam would only recover 10% of the oil in place. This recovery factor increased in the late 1980s when analysis indicated that compaction increased recovery to 13%. But now with the foamy oil mechanism, even without steam Corpoven believes that recoveries of about 20% of the original oil in place can be achieved in its Hamaca area, in which three blocks are being exploited (Fig. 9)(65794 bytes).

Corpoven started drilling horizontal wells to test possible cold recoveries in December 1993. One of these wells in 1 year has produced over 800,000 bbl of oil compared to a vertical well that in 10 years of cyclic steam injection produced about 1.4 million bbl.

Corpoven plans to drill about 300 horizontal wells in the next 5 years. Electric submersible pumps (ESPs) will be used to pump the wells. About 70% of the wells are expected to be on cold production with the others on steam. Expected production is between 1,000 and 2,000 bo/d/well.

Plans call for the wells to be drilled from pads with each well being on 120-acre spacing and having 1,500-1,800 ft laterals. Corpoven plans to employ twelve drilling rigs. The time to drill and complete each well is estimated to be about 20 days.

Corpoven expects operating and development costs to be $1.50/bbl. This does not include the pipeline to San Jose which is expected to be finished in 1997.

Fig. 10(81660 bytes) shows the conventional cyclic steam completion used in the past as compared to the current proposed completions, that can be either re-entries or horizontal wells. In the past, diluent was mixed with the 9 API crude at the bottom of the well and rod pumps were used. In the new completions, diluent only enters the production stream at the wellhead, and progressing cavity pumps or ESPs provide artificial lift.

For a diluent, Corpoven uses the 22-24 API crude being produced in the heavy oil traditional area north of the present activity that produces a 9 API extra-heavy crude. The blend of the two crudes is a 16 API crude.

Kern River

In Texaco Inc.'s Kern River steamflood significant cost savings have been realized in the last few years.14 Texaco says production costs in 1990 were $6.27/bbl and by 1994 had decreased to $4.86/bbl. Texaco is targeting costs of $4.40/bbl by 2000. Costs have been reduced by better heat management, sand control, and going upstream with processing such as delivering fuel oil to specifications.

Also in October, Texaco says it will start receiving payments for the Kern River field water released to the agricultural aqueduct.

Current recovery in Kern River is about 60% of the oil in place and Texaco is chasing a target of 80% (Fig. 11)(28220 bytes). The 10,000-acre, 10,000-well field produces 125,000 bo/d with Texaco's operated portion producing about 80,000 bo/d.

Texaco says one of the processes that is helping the recovery factor is gravity and steam override. The 4-5% dip causes steam to gradually sweep downdip creating average residual oil saturations of 6.3% with some areas having residual oil saturations as low as 2-3%.

Texaco's production strategy also involves combining upstream, downstream, and cogeneration. It saves the refinery money by delivering oil with less bs&w. Although specification only requires 3.0% bs&w, Texaco has decreased the bs&w in 1992 to 2.1% and 1.3% in 1993. It plans to go down to 0.5% bs&w.

In the field, Texaco processes some heavy oil to fuel oil specifications in the field with 0.1% bs&w. This is sold directly without going through a refinery.

References

1.Greenstein, G., "World Heavy Oil Supply and Demand: A Refiner's Perspective," International Heavy Oil Symposium Calgary, June 19-21, 1995.

2.Kerrigan, T.J., "An Assessment of Heavy Oil Prices and Market Dynamics," International Heavy Oil Symposium Calgary, June 19-21, 1995.

3.Crandall, G.R., "Supply and Demand for Heavy Oil: An International Perspective," International Heavy Oil Symposium Calgary, June 19-21, 1995.

4.The Oil Sands: A New Vision for Canada, National Task Force on Oil Sands Strategies of the Alberta chamber of Resources, 1995.

5.Boone, D.J., and McGregor, K.J., "Cold Lake Profitability Improvement," International Heavy Oil Symposium Calgary, June 19-21, 1995.

6.Dingle, H.B., "The Role of Technology in the Commercialization of the Cyclic Steam Steam Stimulation at Cold Lake," International Heavy Oil Symposium Calgary, June 19-21, 1995.

7."Solv-Ex Corp." OGJ, June 26, 1995, p. 25.

8.Claridge, E.L., and Prats, M., "A Proposed Model and Mechanism for Anomalous Foamy Heavy Oil Behavior," International Heavy Oil Symposium Calgary, June 19-21, 1995.

9.Solanki, S., and Metwally, M., "Heavy Oil Reservoir Mechanisms, Linbergh and Frog Lake Fields, Alberta, Part II: Geomechanical Evaluation," International Heavy Oil Symposium Calgary, June 19-21, 1995.

10.Tremblay, B. Sedgwick, G., and Forshner, K., "Imaging of Sand Production in a Horizontal Pack by X-ray Computed Tomography," International Heavy Oil Symposium Calgary, June 19-21, 1995.

11.Dusseault, M.B., and Geilikman, M.B., "Practical Requirements for Sand Production Implementation in Heavy Oil Applications," International Heavy Oil Symposium Calgary, June 19-21, 1995.

12.Lazardo, L.C. "Supply/Demand Heavy Oil," International Heavy Oil Symposium Calgary, June 19-21, 1995.

13.Figueredo R.C., "Venezuela Heavy Crude," International Heavy Oil Symposium Calgary, June 19-21, 1995.

14.Sustek, J., "Turning Heavy Oil into Light at Kern River," International Heavy Oil Symposium Calgary, June 19-21, 1995.