New Techniques Improve Heavy Oil Production Feasibility

Guntis Moritis
Production Editor

• Hamaca Area (Fig. 1) [66,672 bytes]
• Petrozuata's main production station is the first of Pdvsa's joint venture facilities to be in operation (Fig. 2). [30,768 bytes]
• The Cerro Negro joint venture used the pad, shown above, to appraise the area's production potential (Fig. 3). [56,201 bytes]

The possibility of recovering heavy and extra-heavy oil or bitumen at economic rates with cold production has altered the outlook for producing the extensive petroleum accumulations delineated in areas such as the Orinoco region of Venezuela.

Not that many years ago, steam was thought of as the only option that could significantly increase production rates of this viscous petroleum substance, which can be heavier than water.

New production techniques

In the Orinoco region, operators with horizontal laterals, electric submersible pumps (ESPs), and progressing cavity pumps (PCPs) are currently obtaining cold production rates that are two to five times higher than from previously completed vertical wells, pumped with conventional sucker-rod beam units.

In one example in the Cerro Negro area, Bitor (Bitumenes Orinoco S.A., a subsidiary of Pdvsa) indicates that production rates from newly drilled horizontal laterals, both in new wells and recompletions, are between 800 and 1,500 b/d compared to the 300 b/d obtained from older vertical well completions.

Operators also have realized that traditional reservoir simulation models have not accurately forecast ultimate recovery of Orinoco heavy oil. Newer models incorporate such concepts as foamy oil that indicate that the crude retains more gas below the expected bubblepoint pressure.

Bitor says that a pseudo-bubblepoint pressure exists that can be 200-300 psi lower than the bubblepoint pressure of about 900 psi, expected for its produced bitumen.

These new models predict ultimate cold production recoveries significantly greater than previously believed. In Bitor's case, its model now indicates that cold production may economically recover as much as 20% of the bitumen in place, compared to the 12% previously forecast.

Definitions

Unitar (United Nations Institute for Training & Research) defines bitumen or extra-heavy oil as gas free petroleum or petroleum-like liquid or semisolid with a viscosity above 10,000 cp at reservoir temperature. But in the absence of viscosity data, the substance is classified as bitumen or extra-heavy oil if it has a specific gravity less than 10° API at 60° F.

Tar sands is another common name for bitumen or extra-heavy oil.

Unitar defines heavy oil as gas-free petroleum substances with a 100-10,000 cp viscosity at reservoir temperature. If viscosity data are absent, the oil is classified as heavy if it has a 10-20° API gravity at 60° F.

Bitor

In its Cerro Negro producing area, Bitor's operations are unique in that after producing the bitumen, it adds about 30% water and a surfactant (about 3,000 ppm) to stabilize the emulsion. The emulsion, called Orimulsion, is then piped to the coast and sold internationally as a boiler fuel.

Since starting production in 1987, Bitor has recovered over 100 million bbl of bitumen (Table 1 [61,157 bytes]) from its 180 sq km (44,500 acre) producing area. Current production is about 70,000 b/d.

Production is from the Morichal member of the Oficina formation. Bitor characterizes the bitumen in the Cerro Negro area as a low (8° API) gravity fluid with viscosities ranging from 2,000 to 5,000 cp at reservoir conditions.

Starting in 1983, after the exploration phase, Bitor drilled 350 vertical wells, including 143 wells spaced 150 and 300 m apart in two pilot areas.

These initial wells were completed with conventional beam or hydraulic pumping units and conventional subsurface API plunger pumps. Bitor, initially mixed water with surfactant downhole to lower fluid viscosity. But after surfactant became uneconomical, it switched to diluent for reducing produced fluid viscosity.

The diluent is recovered in a distillation tower at the field production facility and reused. After the diluent is recovered, water and surfactant are added to the bitumen in static and dynamic mixers to form Orimulsion.

Bitor initially drilled vertical wells in its Cerro Negro area. But after experimenting with slant and deviated wells, it now has settled on drilling horizontal laterals in either new wells or recompleted vertical wells that have watered out.

Currently, Bitor has about 250 wells on production. Of this number, 10 are new horizontal wells and 30 are recompletions with horizontal laterals.

During 1997, Bitor re-evaluated its development plan and now believes that the optimum horizontal laterals should be about 3,000 ft long, drilled on a 130-acre spacing. Expected production could be as high as 2,500 b/d/well.

Bitor has completed its horizontal wells with 7-in. slotted liners in a 81/2-in. hole. The wells produce some reservoir fines that are recovered in the production facilities. Bitor uses both mechanical and electrostatic separators to remove gas and bs&w.

Its two production stations have a combined 125,000-b/d capacity. Bitor currently plans to increase production to about 80,000 b/d from the current 70,000 b/d, and expects to drill about five new wells per year.

About half of Bitor's horizontal wells have PCPs, while the other half are equipped with ESPs. One PCP is being tested with a downhole motor. The other PCPs operate with top drives.

Bitor says one advantage of the PCP is that these pumps require much less power than ESPs, 85 hp vs. 350 hp.

Bitor does have problems with PCP elastomer life. Currently, PCPs last between 10 and 12 months, while ESPs run for about 18 months. Bitor hopes to improve PCP performance to obtain 18-24 month runs.

Pdvsa

In the northern part of the Hamaca area (Fig. 1), Pdvsa is also producing heavy crude in the Arecuna, Bare, and Melones fields. Corpoven S.A., an affiliate of Pdvsa that has been combined with other Pdvsa affiliates to form Pdvsa Petroleos y Gas S.A, operates these fields.

Pdvsa, in the traditional heavy oil area (Fig. 1), generally produces 15-25° API gravity crude. In Bocks A, B, and C the crude gravity ranges from 6° to 16° API with viscosities of 140-2,100 cp at 140° F. Reservoir depths vary from 600 to 4,000 ft. The reservoirs have an average 32% porosity and 10 Darcy permeability. In the Arecuna and Bare reservoirs, average pressure is 1,200-1,400 psi with temperatures ranging from 130° to 150° F.

This area has shown the value of horizontal laterals and ESPs for recovering heary oil. Drilling of horizontal wells and horizontal laterals began in 1993 and crude production from some of these wells has been over 2,000 b/d. Expected cumulative oil recovery is much greater than from the cyclic-steam projects common in the area (OGJ, Aug. 14, 1995, p. 37).

Pdvsa is producing about 100,000 bo/d from these fields.

The Hamaco project

Adjacent and south of Pdvsa's Hamaca Bare production is a 657 sq km (162,000 acres) area being developed by Petrolera Ameriven S.A. (30% ARCO, 30% Pdvsa, 20% Phillips, and 20% Texaco). The Ameriven Hamaca project is expected to start production in mid-2000 at about 41,000 b/d using Pdvsa's Bare facilities while an upgrader is being constructed. Production will be switched to the upgrader in first quarter 2003.

The 40-year contract with Venezuela was signed in 1997 and includes a 5-year investment period followed by a 35-year period in which Ameriven plans to produce at a plateau of 165,000 b/d until the end of the 40-year contract period. There is an option to increase the upgrader capacity to 220,000 b/d starting in 2007.

Ameriven estimates that the upside initial oil in place is about 26-27 billion bbl with a low side of 20-22 billion bbl At the plateau rates, over 35 years, 2.6 billion bbl (about 10% of oil in place) will be recovered The production is from the Oficina formation, consisting of varying thickness sandstone channels with siltstones. Reservoir depth is between 2,000 and 3,000 ft. The 30-35% porosity, 10-20 Darcy permeability reservoirs contain a 9° API gravity crude with an 80-100 scf/bbl GOR. Crude viscosity is 4,000 cp at the 125-130° F. reservoir temperature.

Ameriven describes the reservoir drive mechanism as a "viscous solution-gas drive." It prefers not to use the foamy oil term because foam is not formed. In the viscous solution-gas drive, the critical gas saturation at which gas starts to flow in a continuous phase is much higher, in the range of 9-10%, than normally would be expected. The gas comes out of solution as bubbles and not foam.

Artificial lift plans for the area have been changing. In the 1993-94 period, rod pumps, such as used by Pdvsa, were thought to be the most economical. Then Ameriven looked at ESPs, but now it expects to install PCPs with top driven rods.

It plans to develop the area with horizontal producers, spaced out based on reservoir geometries. Horizontal wells will be drilled in a regular pattern with 1,600-3,000 ft laterals.

Initially, Ameriven planned on 100-125 acre spacing but now favors 200-225 acre spacing. This wider spacing has lowered the number of wells needed to 750 from the initial 1,100 estimate. All producers will be drilled from pads to minimize disturbance of the environment.

The wells will be completed with 41/2-in. tubing in 51/2 or 7-in. slotted liners, depending on sand thickness. It expects producing rates of 1,500-2,000 b/d/well from the thicker sands and 400-600 b/d/well in thinner sands.

Ameriven plans on adding diluent to the produced fluid at the surface, near the wellhead. The diluent lowers the produced fluid viscosity and increases its API gravity to 15°. The fluid moving though the production separators will contain about one-third diluent. Ameriven initially will use about 36,000 b/d of light crude bought from Pdvsa as the diluent.

Ameriven hopes that no sand will be produced because Pdvsa in the adjacent area has not had that problem. Also, it expects no water production in the first 10-25 years. The produced fluid has a low H2S content of about 5-10 ppm.

Besides separators, the field production facilities may require installation of heated vessels to remove bs&w. Also, Ameriven plans on installing storage tanks that can hold about 1-week's production. The field storage helps ensure that a constant stream will be availabe for the crude upgrader being built on the coast.

Ameriven will purchase electric power for the field facilities and downhole pumps from an existing power grid. It expects lifting costs in the range of $0.75-1.00/bbl.

Currently, Ameriven is completing a 3D seismic survey. Only 2D seismic was available for the initial plans.

To evaluate the area, Ameriven has drilled 19 recent vertical stratigraphic test wells and will have drilled about 25 test wells by the end of 1998.

Petrozuata

In the Zuata area, Conoco (50.1%) and Pdvsa (49.9%) recently announced that they started producing from their Petrozuata extra-heavy oil project at a rate of 30,000 b/d. In the second half of 2000, Petrozuata expects to start its 35-year plateau production of 120,000 b/d.

The 55,000-acre project by the end of 1998 will have about 42 producing horizontal wells. A total of 530 horizontal wells are expected to be drilled during its 35-year life.

The horizontal wells include the longest-displacement horizontal well drilled in Venezuela. The well has a 7,222 ft measured depth with a total displacement of 5,743 ft.

Petrozuata describes the producing Oficina formation, at a 1,800-2,200 ft depth, as a fluvial sand system of Miocene age. The producing structure is a homocline.

Fig. 2 shows the main field facilities.

As in other projects in the area, a diluent will be added at the well head to raise the 9-10° API produced fluid to a 15-17° API stream. Mesa crude will initially be used as the diluent.

Petrozuata has reported that it expects lifting costs to range from $1 to $2/bbl.

Sincor

The Sincor project (47% Total, 38% Pdvsa, and 15% Statoil) is also in the Zuata area.

The development planning is still in its early stage. Sincor now plans on drilling all horizontal producing wells from pads in a "butterfly pattern," with 4,000-4,500 ft laterals The contract area covers about 500 sq km (124,000 acres). Estimated oil in place is about 38 billion bbl, and Sincor expects to recover about 2.4 billion bbl of 8.5° API gravity crude during the 35-year producing term of the contract.

Sincor expects early production to start in November 2000 at a rate of 40,000 b/d. During this period, Mesa crude will be used as the diluent. After adding diluent, the fluid volume through the production facilities will increase to 60,000-70,000 b/d.

Plateau production over the 35-year contract period is expected to be 200,000 b/d of heavy crude that could be increased to 300,000 b/d.

Sincor will produce from the Oficina formation that it describes as an unconsolidated sand with permeabilities in the 10-12+ Darcy range.

The reservoirs are at about 2,000 ft with a temperature of 120° F.

Sincor expects production rates to be about 1,250 b/d/well. It estimates that about 900 horizontal wells with 1-km drains (3,280 ft) will be needed. At start-up of the upgrader, it plans on having already drilled 200 wells.

Plans call for 81/2-in. laterals completed with 7-in. slotted lines.

Sincor is still studying the type of downhole pump to install. Either ESPs or PCPs could be used. In either case, Sincor expects to set pumps deep in the well bore, at about a 70° angle.

Sincor will inject diluent into the produced stream near the wellhead. When producing at its plateau rate, it will need about 70,000 b/d of diluent to obtain a 17° API stream through the production facilities.

Sincor expects the wells not to pose any problems regarding paraffins, asphaltenes, scaling, or sand. Only a trace of H2S is expected in the produced fluid. If a well starts producing water, Sincor plans to shut it in.

The planned field production facilities will accommodate heated vessels, dehydration, dilution, and storage. Sincor expects to provide storage for about 2 days of production. Gas will be used for power generation on site. Enough gas should be available after a few years' production.

Sincor indicates that roads from the Venezuelan coast to the field are in good condition. During 1998, it plans on continuing basic engineering, drilling three vertical and three horizontal appraisal wells, and completing a 3D seismic pilot. By early 1999, it expects to have the results from a full-field seismic survey and plans to start development drilling by mid-1999.

Cerro Negro

Besides the ongoing Bitor operation, a joint venture group consisting of Mobil, 412/3%, Pdvsa 412/3%, and Veba Oel, 162/3%, are developing another Cerro Negro project in a 34,000-hectare (84,000 acres) area. This group will also produce from the Morichal sand, which has an average 30% porosity and about a 10 Darcy permeability.

The group describes the Morichal as braided stream deposits that can be 200-300 ft thick. About 35 billion bbl of oil are in place and the group expects that with cold production about 7-10% will be recovered. The producing formation is at a depth of 3,500 ft. Reservoir pressure is 1,000 psi and reservoir temperature is 130° F. The group expects well head temperatures to be in the range of 110-120° F.

The wells are expected to produce about 1,300 bo/d with GORs of 100 scf/bbl that may increase to about 150-200 scf/bbl. A test well has produced at a rate of 1,800 b/d.

At reservoir conditions, the 8.5° API gravity produced fluid has a viscosity of about 2,000 cp. The Group will add a diluent at the well head that will increase the gravity of the produced stream to 19° API.

Fig. 3 shows an appraisal pad used for evaluating the area's potential.

The Cerro Negro group expects initial production to start in the 4th quarter of 1999 and last through 2001 at a rate of 60,000 b/d. During this period, condensate imported from the Oso field in Nigeria will be used as the diluent. About 12,000 b/d will be required. The planned plateau production rate over the 35-year contract period is 120,000 b/d.

The group plans to develop the area with horizontal wells drilled from pads. These wells will be drilled in a parallel pattern, spaced about 600-m apart. Typically, the wells will have 133/8-in. surface casing, 95/8 in. casing, and a 7-in. slotted liner in a 81/2-in. horizontal lateral.

The group expects to install 5-in. tubing and top-drive PCPs.

Field production facilities will include separators, fired vessels, desalters, and dehydrators. The crude contains about 300 lb of salt/1,000 bbl of crude. The field production station plans four storage tanks with a combined capacity of about 700,000 bbl.

A regional electric-power grid will furnish power for the field facilities and downhole pumps.

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