North Slope Development Details Revealed

SAN DIEGO, Oct. 9, 2012 (GLOBE NEWSWIRE) -- Royale Energy, Inc. (Nasdaq:ROYL) today notes new operational details concerning Great Bear's plans to accelerate testing and production on its North Slope acreage adjoining Royale.

As reported in last week's Petroleum News, Great Bear's request seeks to modify its plans by extending the 15 day test period to 180 days with up to 7 truckloads (1,000 barrels) of oil per day. In addition, Great Bear has requested permission to drill an additional well (Alcor No. 2) on the same location as the Alcor No. 1, enabling them to set larger casing to a deeper depth to target the Shublik formation.

Additional details can be found in the Petroleum News story, reprinted with permission:

Great Bear applies to extend testing: Change from 15 to 180 days could cover as much as 1,000 bpd of production, company tells state; also applies for another Alcor well by Kristen Nelson

Great Bear has applied to the Alaska Department of Natural Resources, Division of Oil and Gas, to amend its plan of operations to extend a proposed production flow test from 15 days to up to 180 days and to drill an additional well at the Alcor pad.

The company is working on a North Slope oil shale prospect, with early wells close to the James Dalton Highway, the "Haul Road," south of the Kuparuk River and Prudhoe Bay units.

Ed Duncan, Great Bear's president and CEO, told the Alaska Oil and Gas Congress Sept. 19 that the company's change of plan could accelerate the shale oil development program (see story in Sept. 23 issue of Petroleum News).

Great Bear's existing approvals allow for 15 days of flow days, but the company told the division in a plan amendment dated Sept. 10 that after further review and analysis of testing in analogous plays in the Lower 48, it has concluded that the first 15 days of a production test would likely consist mostly of water used for hydraulic fracturing.

Great Bear said in its amendment that its exploration and evaluation program "is designed to recover critical information, including the amount of oil and gas saturation found in the rock formations; the mechanics of the rock formations and their reaction to methods of hydraulic fracturing; initial production rates following fracturing; and how rapidly those production rates decline in order to develop a type curve to determine estimated ultimate recovery (EUR) on a per well basis as well as for the play."

That type curve, the company said, will be an important element in determining the commercial viability of the play.

Analogous plays

Great Bear said that considering typical production profiles of analogous Lower 48 unconventional wells, the decline curve is expected to lessen or flatten out during the first six months, providing information the company needs to determine estimated ultimate recovery on a per well basis.

After its wells are fracture stimulated, the company said, "production flow testing will begin through flowback equipment consisting of a sand separator, line heater, 4-phase separator and test tanks."

Produced water and any sand or solids will be trucked to BP's disposal site at Prudhoe Bay and oil will be processed using modular processing equipment on site and then trucked for sales.

Subject to Alaska Oil and Gas Conservation Commission approval, natural gas will be flared on site.

Stable production the goal

Great Bear said hydraulic fracture stimulation should allow the well to flow liquids to the surface, with pressure decreasing as oil flows, reducing the flow.

"Even after fluids will no longer flow to the surface unassisted, the evaluation of the well will likely not be complete," the company said, and either gas assist or a submersible pump may be needed.

"A complete well test will evaluate the declining production rates from the well and determine when the well (with these additional assistance methods) reaches a level of stable production."

A coiled tubing string may be run into the casing near the bottom of the vertical well and nitrogen gas pumped into the well if the well loses pressure before a complete well test can be run, an operation which would require additional equipment, which would remain on site during the nitrogen pumping operation, expected to last approximately 14 days.

If two weeks of gas assist does not provide a complete well test, the nitrogen will be discontinued and a submersible pump system will be installed, requiring a workover rig, Great Bear said.

"Tubing (probably 3 or 4 inch diameter), packer, and a submersible pump will be run into the hole to continue the well test until stable production rates are obtained or until a decline curve can be determined (but not to exceed 180 days)," the company said.

Traffic volume on Haul Road

Great Bear said it expects flow testing at the Alcor and Merak wells to begin in October and November.

The volume of traffic on the Haul Road, assuming 1,000 barrels per day, based on an analogue with the Eagle Ford play in south Texas, would mean some seven tanker trips a day between the drill site and the Prudhoe Bay unit daily, "diminishing rapidly over the six month period as production declines," the company said.

Great Bear said it cannot say for sure what the volume of truck traffic associated with an extended production test would be, but "based on other unconventional wells, it is fairly certain" the volume would peak during the initial 15 days of the flow test and continue to decrease over time as the "initial flowback water production rate" decreases as "the water flow transitions into (hopefully) oil flow," Great Bear said.

"As additional wells are drilled and tested there will likely be simultaneous testing going on. Given the likely gap between wells, and the potential decline rate, Great Bear estimates that the maximum number of tanker trips aggregated from all wells at any given day is approximately 20," the company said.

In response to comments from AGOCC on the requirement for custody transfer and associated metering before production leaves the lease, Great Bear said it would work closely with the commission to acquire the required approvals.

The company will also be required to provide monthly production reports to the commission.

Additional Alcor well

Great Bear has also applied to drill an additional well at the Alcor drill pad. Drilling of the Alcor No. 1 began June 19; drilling of the Merak No. 1 began Aug. 22.

A second well at Alcor is needed so that the Shublik formation can be tested at that location.

The second well at the Alcor drill pad would be directionally drilled into the Shublik formation, Great Bear said. That well would be some 10-15 feet from the Alcor No. 1.

Great Bear told the state it has identified the Shublik formation as the primary target for production testing of the North Slope's unconventional resources.

The Alcor No. 1 was the first well drilled into the Shublik formation for shale oil exploration, the company said.

"As such, a lot was learned about the exact locations of the formations and the rock mechanics."

Why drill the Alcor No. 2?

Great Bear said that due to circumstances encountered in drilling Alcor No. 1, planned 7-inch casing was "set 2,500 feet too high in order to isolate severe lost circulation zones."

The well was cased to total depth with 4.5-inch casing, and Great Bear said it cannot drill out of the 4.5-inch casing into the Shublik formation.

Benchmark costs needed

Attempting to sidetrack from the 7-inch casing "to drill directionally into the higher pressure strata of the deeper target intervals will require higher mud weights through the same severe lost circulation zones that resulted in the 7 inch casing being set shallow," the company said, resulting in a low probability of successfully drilling into the Shublik formation.

The company also said using the knowledge gained from drilling the Alcor No. 1 to drill the Alcor No. 2 "should enable Great Bear to get a realistic benchmark of what an expected development well cost might be. Drilling optimization and cost control is essential in establishing the commerciality of the unconventional resource play."

Drilling the Alcor No. 2 and extending production testing to 180 days would enable Great Bear to conduct two extended Shublik formation production tests through the end of 2012 and into 2013, the company said.

The Merak No. 1 is expected to be completed in about mid-October, with fracture stimulation and flow testing beginning in mid-October. The rig would then be moved to drill the Alcor No. 2, with a lateral into the Shublik, with completion expected in mid-December, followed by fracture stimulation and flow testing from December until approximately July 2013.

Forward Looking Statements

In addition to historical information contained herein, this news release contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995, subject to various risks and uncertainties that could cause the company's actual results to differ materially from those in the "forward-looking" statements. While the company believes its forward looking statements are based upon reasonable assumptions, there are factors that are difficult to predict and that are influenced by economic and other conditions beyond the company's control. Investors are directed to consider such risks and other uncertainties discussed in documents filed by the company with the Securities and Exchange Commission.

CONTACT: Royale Energy, Inc. Chanda Idano, Director of Marketing & PR 619-881-2800 http://www.royl.comSource:Royale Energy