Exploration/Development Briefs

July 22, 2013

Oman

DNO International ASA, Oslo, has taken a farmout from Allied Petroleum Exploration Inc. that provides for the transfer to DNO Oman AS of a 75% participating interest (100% paying interest) in Block 36 in the Rub al Khali basin.

The block covers more than 18,000 sq km, and two exploratory wells have confirmed the presence of source rock in the basal Silurian hot shale, an organic-rich shale that has sourced the majority of the oil and gas fields discovered on the Arabian Peninsula and North Africa.

Multiple stacked potential reservoir units have also been identified and mapped on the existing seismic data comprising 10,000 line-km of 2D complemented by high-resolution gravity and aeromagnetic surveys. Technical work to date suggests potential lead sizes in excess of 100 million bbl, the company said.

DNO Oman will assume operatorship and fund reprocessing of existing and acquisition of new 2D seismic data and drill two exploratory wells.

Completion of the Block 36 transfer is subject to satisfaction of certain conditions, including approval by the Ministry of Oil and Gas of the Sultanate of Oman.

Russia

OAO Rosneft and Statoil ASA have begun shooting geophysical surveys on three blocks in the Sea of Okhotsk offshore the Russian Far East.

OJSC RN Shelf Far East, a Rosneft subsidiary, is using the Academik Fersman research vessel to collect 2D seismic and shipborne gravity and magnetic surveys. Planned scope is 5,300 line-km on the Lisyansky block, 2,000 line-km on the Kashevarovsky block, and 2,700 line-km on the Magadan-1 block.

Environmental and fishery research are to be carried out on all three blocks in 2013 by LLC Environmental Co. of Sakhalin, a contractor. Another planned environmental protection measure is a study of the subsea wellhead of the Khmitevskaya-2 well drilled on the Magadan-1 block in the 1990s.

Rosneft obtained licenses for geological study and hydrocarbon production on the three blocks in late 2011. Rosneft and DeGolyer & MacNaughton judge the total prospective recoverable resource on the blocks at 1,741 million tonnes of oil equivalent.

Alaska

Buccaneer Energy Ltd., Sydney, paused drilling at 5,600 ft at its Cosmopolitan-1 well in Alaska's Cook Inlet after encountering hydrocarbon liquids shows in the Lower Tyonek formation about 400 ft higher than expected.

The company will run wireline logs and pressure tests and take sidewall cores before drilling ahead. It will set casing at 5,485 ft before drilling through the Lower Tyonek and into the proven oil-bearing Starichkof and Hemlock formations and reach target depth of 8,000 ft after drilling the prospective West Foreland formation.

The well has penetrated three primary gas zones totaling 175 ft in which logging while drilling equipment indicated good resistivity, permeability, and porosity. The results need to be confirmed with wireline logs and flow testing, if warranted. No flow tests are planned for the oil formations.

The current plan is to take cores in the oil formations to augment known reservoir data. The objective of this coring operation is to further optimize the future oil plan of development.

The gas zones were all accompanied with a sharp increase in gas relative to background gas measurements. Generally, gas levels over background gas amounts increased by a multiple of 5-10, measured resistivity from 10-30 ohms, and permeability and porosity characteristics would indicate production-capable sands based on previous basin experience, Buccaneer said.

There are four more potentially gas-bearing zones of interest, similar in total thickness to the primary zones, that the company classifies as secondary zones of interest. The well will ultimately be plugged back to the bottom of the Tyonek gas-productive zones and be temporarily abandoned as a future gas producer.

Buccaneer Energy acquired 25% interest and became operator of Cosmopolitan last year, and BlueCrest Energy II LP, Fort Worth, has 75% (OGJ Online, July 23, 2012).

Louisiana

Saratoga Resources Inc., Houston, has upgraded facilities to enable its Main Pass 25 field off Louisiana to return to optimal uninterrupted production.

For nearly 6 months the company has experienced production curtailments that resulted from third-party handling issues and temporary lack of gas lift. Saratoga has installed a four-pile jacket and deck and an oil storage barge to handle the field's production.

The facility upgrade is designed to allow lower system operating pressure, which is expected to result in increased well productivity. The upgrade also is expected to allow Saratoga to handle additional third-party production and add gas supply for gas lift while reducing operating costs through direct cost savings and cost sharing for common use systems.

Meanwhile, the company on May 27 began its production enhancement program that involves tubing replacement, recompletions, workovers, gas lift optimization, and gravel pack remediation in Grand Bay and Breton Sound 32 fields.

That program is on track, and the company has completed and brought to productive status five of six wells that have undergone tubing changeouts. Those wells are being evaluated relative to additional work to optimize production that may entail, among other operations, chemical stimulation to clean up existing perforations and improve hydrocarbon inflow and additional perforations.

Only one PEP well to date was unsuccessful due to split casing, and that well has been temporarily abandoned for future work. Combined initial production rates from the five successful PEP wells was 92 b/d of oil equivalent. One well is expected to add proved developed producing reserves, and potential new perforations in two other wells are also expected to add reserves.

Costs are below authorization for expenditure by 3% on PEP projects to date, including the unsuccessful job, and under AFE by 11% on successful jobs only. Payout of the PEP projects completed to date is estimated at 8.9 months, including the unsuccessful job, based on initial production rates and without chemical stimulation or additional perforations that are expected to hike production and accelerate payout.

The cost of expected recovery from the PEP wells to date is estimated at $20.29/boe.

Ohio

Magnum Hunter Resources Corp., Houston, has spudded the first well on its Stalder pad in eastern Monroe County, Ohio.

The pad has been designed and permitted to drill as many as 18 wells, 10 to the Marcellus shale and eight to the Utica shale, using the company's new Schramm T500XD robotic drilling rig. The first well will test the Marcellus and the second the Utica. The company's Triad Hunter LLC subsidiary is operator with a 50% working interest in the drilling unit.

The development plan is to drill both Utica and Marcellus wells first, then fracture stimulate them, and subsequently test them in the fourth quarter of 2013. The company's Eureka Hunter Pipeline LLC unit is laying a 20-in. high pressure gas line to the Stalder pad. First deliveries are anticipated in October.