Upstream News

Russia laying the foundation for Arctic exploration

Gas production in Russia could pave the way for successful arctic drilling projects after new techniques helped improve efficiency during the region's harsh winters, said Sakhalin Energy Investment Co. Ltd.

The creation of Russia's first Liquefied Natural Gas (LNG) plant has meant overcoming a number of obstacles similar to those faced within the Arctic region – an increasingly attractive prospect as proven oil and gas reserves decline.

Russia's first LNG plant, with an 800km network of onshore pipeline. Photo courtesy of Sakhalin Energy Investment Co. Ltd.

Russia's first LNG plant, with an 800km network of onshore pipeline. Photo courtesy of Sakhalin Energy Investment Co. Ltd.

The success of the program – which has seen the use of "big bore wells" cutting operating costs and increasing gas flow – is an example of how viable working in such harsh conditions can be.

Andrei Galaev is CEO of Sakhalin Energy, the company running the first Russian LNG plant, which has an 800km network of onshore pipelines.

Galaev said: "One of the biggest challenges facing the oil and gas industry is that there are less resources that could be easily developed. More frequently the industry is being forced further north and into drilling deeper to discover and extract hydrocarbons.

The Lunskoye A production platform in Russian waters. Photo courtesy of Sakhalin Energy Investment Co. Ltd.

The Lunskoye A production platform in Russian waters. Photo courtesy of Sakhalin Energy Investment Co. Ltd.

"It seems almost inevitable that Arctic exploration will take place and there are a lot of similarities between the challenges the industry will face there and what we have been doing at Sakhalin. Certainly the conditions offshore are as harsh as the subarctic ones and the experience Sakhalin Energy gets could be used by those who are looking to develop these barren areas."

Sakhalin Energy is now becoming a large energy exporter to Asia Pacific's competitive energy market.

"Sakhalin Energy was the first in Russia to start developing shelf deposits with offshore platforms. The project and Sakhalin Energy activity are associated with progressive engineering and design, as well as unique, innovative technologies applied in the severe natural and climatic conditions of the remote region," said Galaev.

Apache targeting stacked-pay, liquids-rich opportunity in Canada's Kaybob development

Apache Corp. released promising drilling results in the Dunvegan oil reservoir in the Kaybob development area in Alberta, Canada. Kaybob is located 310 miles northwest of Calgary and contains 16 known productive horizons; the Cretaceous Dunvegan horizon is one of the primary targets.

The most recent of four Kaybob Dunvegan development wells — the 1-35 — tested at a rate of 300 barrels of oil per day (bopd). The well was drilled to a vertical depth of 5,700 feet with a 4,300-foot lateral and a 13-stage fracture stimulation completion.

The first well in the campaign — the 1-9 — tested at a peak rate of 280 bopd. It was drilled to a vertical depth of 5,500 feet with a 4,900-foot lateral and 13 fracture stages.

"These wells were drilled in areas which have been producing for over 40 years but which have the potential to be completely rejuvenated through the application of horizontal drilling and multi-stage hydraulic fracturing," said Tim Wall, president of Apache Canada. "These encouraging results have contributed to identifying more than 2,000 potential horizontal drilling locations across our 238,000-acre gross (179,000-acre net) leasehold."

Despite the development's early stage, the possibility for field rejuvenation through these modern techniques is reminiscent of plays like the Permian Basin and Anadarko Basin, noted Global Hunter Securities analysts in a note to investors November 21.

The Dunvegan is a widespread, high quality Upper Cretaceous sandstone reservoir. A 13-stage horizontal well is expected to recover an estimated 560,000 barrels of oil equivalent. Longer term, the Dunvegan represents a good candidate for additional production by means of secondary recovery.

While no data was provided on initial costs, the analysts cited Apache as saying the wells "can be brought to ~$5MM each in a full development scenario," also noting that Apache is considering adding a second rig to the play.

Noble Energy makes GoM discovery, hits dry hole offshore Falkland Islands

Noble Energy Inc. has made a discovery at the Big Bend exploration prospect in the deepwater Gulf of Mexico and hit hydrocarbon-bearing, but low permeability rock in the Scotia wildcat well in the Eastern Falklands Basin.

The Big Bend well, located in 7,200 feet of water on Mississippi Canyon Block 698, was drilled to a total depth of 15,989 feet. Open-hole logging identified approximately 150 feet of net oil pay in two high-quality Miocene reservoirs.

Noble Energy operates with a 54% working interest in Big Bend. Other interest holders are Red Willow Offshore LLC with 15.4%, and Houston Energy Deepwater Ventures V LLC with 10.6%.

A note to investors from Jefferies & Co. Inc. following the announcement said that Noble is now confident that the well "will at least meet their pre-drill mean resource estimate of 40 MMboe gross."

Noble's Scotia exploration well offshore Falkland Islands was drilled to a depth of 18,226 feet and reached its Cretaceous objective as expected on 2D seismic. According to Global Hunter Securities, Noble had given the well a 30% chance of success, with a resource range of 145-960 MMbbl. While the well experienced hydrocarbon shows while drilling to the Cretaceous target zone, initial log analysis identified 164 feet of low quality reservoir. The operator of the well, Falklands Oil and Gas plc. (FOGL), now intends to plug and abandon the well.

Susan M. Cunningham, Noble Energy's senior vice president of Exploration and Business Innovation, commented, "Although we did not see a substantial amount of reservoir section, virtually all sandstones with significant porosity in and below the target contained hydrocarbons. Following our imminent acquisition of 3D seismic, we will integrate well results and assess the economic viability of this particular prospect. The 3D seismic will also help identify future exploration activity on our 10 million gross acre position."

Noble Energy holds a 35% interest and will become operator of the Northern Area Licenses on March 1, 2013. Partners include FOGL with 40% and Edison International Spa with 25%.

In a note to investors following the update, Global Hunter Securities analysts said, "the Scotia dry hole is disappointing, but is only the first of up to three wells to be drilled in the farm in agreement. NBL is taking a longer term view of the Falklands, with plenty of time for interpretation of 3D seismic before well #2 is spud." As for Big Bend, "it, along with Troubadour, could be a material development for NBL's GoM program, where development execution has to date been outstanding."

ExxonMobil to withdraw from Iraq project

Dallas-based Exxon Mobil Corp. has informed the government of Iraq that it plans to sell its share in an energy project in the southern part of that southwest Asian nation.

The company's decision to pull out of the $50 billion West Qurna-1 field project could exacerbate tensions between the government in Baghdad and the autonomous region of Kurdistan where Exxon has signed more lucrative deals. Relations between the central government and Kurdistan have been strained for years, and this pull-out by the American company could make the situation worse, according to an Iraqi official quoted by the Reuters news agency.

Abdul -Mahdy al-Ameedi, director of Iraq's contracts directorate, said Exxon told the government that it is in negotiations with several international companies with respect to selling its stake, but Exxon has not commented publicly on its plans, says Reuters.

Royal Dutch Shell is a minority partner in the huge oilfield that pumps roughly 400,000 barrels of oil per day. It is unclear what company would replace Exxon in the project.

Lundin Petroleum discovers gas offshore Peninsular Malaysia

Lundin Petroleum AB has completed Tembakau-1 well in PM307 Block, offshore Peninsular Malaysia, as a gas discovery.

Tembakau-1 was a vertical well drilled to a depth of 1,565 meters in 67 meters water depth. The well discovered a series of stacked gas pay sands in the target Miocene objective. Overall the well penetrated approximately 60 m of net gas pay in five high quality sand intervals.

Tembakau-1 is located 30 km to the west of the nearest oil and gas infrastructure.

An extensive data acquisition program was completed, including rock and fluid samples, pressure profiles and mini-DST's. Following logging the well was plugged and abandoned. Further work will follow to estimate recoverable resource ranges.

"Tembakau is very encouraging given its location in an unexplored area of PM307. We are hopeful this discovery has the potential to be commercial on a stand-alone basis given its close proximity to existing gas infrastructure and the strong demand for gas in Peninsular Malaysia. The discovery is the second successful well completed in PM307 in 2012 and continues our robust exploration performance in Malaysia that commenced in 2011 with six discoveries made from nine wells drilled," said Lundin president and CEO Ashley Heppenstall.

Following Tembakau-1 the West Courageous rig moves south to execute the fifth and final well of the 2012 exploration campaign, the Ara-1 well in the PM308A block where Lundin Petroleum holds a 35% interest and is operator.

Lundin Petroleum holds a 75% interest in PM307 through its subsidiary Lundin Malaysia BV. Lundin Malaysia BV's partner is PETRONAS Carigali Sdn Bhd with 25% interest. Lundin Malaysia BV operates six blocks in Malaysia, namely PM307, PM308A, PM308B, SB303, SB307 & SB308.

ERHC Energy to pursue rift margin plays in Kenya and Chad

Houston-based ERHC Energy Inc. plans to pursue rift margin plays in the republics of Kenya and Chad. Based on existing data, ERHC has delineated exploration focus areas in Block 11A in northwest Kenya and BDS 2008 in Chad.

"Kenya is at the intersection of two major rift systems – the Cretaceous Central African rift system and the Tertiary East Africa rift system – and we are very excited that our block's excellent location enables us to exploit the high potential for hydrocarbons that the geological occurrence promises," said ERHC Exploration Manager Gertjan van Mechelen. "We will basically pursue the same kind of rift margin play that has yielded major discoveries in neighboring Uganda as well as recent large discoveries in Kenya to the east of our Block 11A."

ERHC expects to begin exploration operations in Kenya's Block 11A by the end of 2012.

In Chad, ERHC has delineated two focus areas situated directly north of numerous major discoveries on a rift margin along the Central African Shear Zone. Regional stratigraphic mapping indicates the presence of alluvial fan deltas and lacustrine deltas in ERHC's areas of interest, which provide both reservoir and seal rocks.

"We believe there is great promise for a series of hydrocarbon discoveries in BDS 2008, along that rift margin," said ERHC president and CEO Peter Ntephe.

ERHC is planning for exploration operations to commence in Chad by early 2013.

In addition to its oil and gas exploration interests in the Republic of Kenya, the Republic of Chad, the company holds interests in the Sao Tome and Principe Exclusive Economic Zone (EEZ) and the Nigeria-Sao Tome and Principe Joint Development Zone (JDZ).

ERHC Energy Inc. is a Houston-based independent oil and gas company focused on growth through high-impact exploration in Africa and the development of undeveloped and marginal oil and gas fields.

TGS-NOPEC begins extension of 3D survey offshore Angola

TGS-NOPEC Geophysical Co. ASA has commenced an extension to the offshore Angola 3D multi-client survey. The extension, covering 1,569 square miles (4,064 square kilometers) over blocks 36 and 37, will add to the original survey of 4,826 square miles (12,500 square kilometers) which has completed acquisition.

"We are very pleased to continue our relationship with Sonangol and to support oil and gas exploration in the Republic of Angola," commented Stein Ove Isaksen, Senior VP Eastern Hemisphere for TGS. "Angola's conjugate margin pre-salt basins, similar to hydrocarbon rich basins offshore Brazil, provide exciting new opportunities in petroleum exploration."

The seismic data is being acquired by the M/V Geco Eagle. Data processing will be performed by TGS and preliminary data will be available to clients from 4Q 2013.

The survey is supported by industry funding.

New Zealand makes fifth oil discovery in Taranaki Basin

New Zealand Energy Corp. has made its fifth oil discovery in the Taranaki Basin of New Zealand's North Island.

The Waitapu-2 well was drilled to a total measured depth of 6,841 feet, encountering approximately 20.3 feet of net pay in the Mt. Messenger Formation, a thick sequence of turbidite sandstones in New Zealand's Taranaki Basin. The Waitapu-2 well is currently flowing at a rate of 325 barrels of oil per day and 800 thousand cubic feet of natural gas per day through a 24/64th inch choke. The well is producing sweet, high-quality 40 degree API oil that is being trucked to the Shell-operated Omata Tank Farm, approximately 45 km north of the site, and sold at Brent pricing. To date the Waitapu-2 well has produced 1,880 barrels of oil. The well will be flowed for approximately two weeks and then shut-in for pressure build-up. Subject to assessment of ongoing production, a decision will be made to lay .8 miles (1.3 kilometers) of new pipeline to tie-in to the Waihapa Production Station through the existing Copper Moki pipeline.

"The fact that the Waitapu-2 well is flowing from natural reservoir pressure, as the Copper Moki wells did, further confirms NZEC's geological model," said Bruce McIntyre, executive director of NZEC. "Most Mt. Messenger wells in the region have required artificial lift almost immediately. We are continuing to refine our geological model based on drilling success to date and interpretation of the recently completed 3D seismic survey, and have many more prospects to drill that we feel are comparable to the Copper Moki and Waitapu discoveries."

The company's first well drilled at the Waitapu site, the Waitapu-1 well, was drilled to a measured depth of 7,260 feet, then cased and completed across a gross interval of 98 feet in the Mt. Messenger Formation. While a significant sand interval was identified with oil and natural gas shows, the permeability and porosity was such that the well did not yield economic production. The well has been suspended pending further evaluation and/or sidetrack to an alternate target.

NZEC has reached target depth on the third well in its current eight-well program. The Arakamu-2 well, NZEC's first well at the Arakamu site, has reached target depth at a measured depth of 7,808 feet. NZEC has commenced casing the well, with completion to follow. The well encountered 26.6 feet of net pay in two potentially productive zones in the Mt. Messenger Formation. The lower zone will be completed first with the second zone to follow. Following completion of the Arakamu-2 well, NZEC will move the rig to spud Arakamu-1A, which is targeting the deeper Moki formation.

NZEC will drill four more wells after Arakamu-1A with the objective of completing its eight-well program and increasing production to 3,000 barrels of oil equivalent per day by the end of 1Q-2013.

Kea Petroleum starts Puka 2 drilling

Kea Petroleum plc has started drilling of Puka 2 onshore well in New Zealand's Taranaki Basin. Using the DrillForce Mayhew Rig 1, the plan is to drill the well to a total depth of 1890 meters. The drilling is expected to be suspended after surface casing is run at approximately 400 meters to allow for the commencement of the 3D seismic program over the area in mid-December and to be recommenced using the DrillForce Rig 6 in mid-January. Testing is expected to begin in February.

Puka 2 is designed to appraise the Puka field and test whether the Puka 1 discovery is a stratigraphically controlled rather than a simple structural field.

As a simple structural field, directors remain confident that the Puka 1 discovery should be in the region of a 1 million to 3 million barrels of oil discovery. However, should it prove to be stratigraphically controlled, then the size of the discovery could be considerably larger, perhaps in the region of 7 to 10 million barrels of oil.

Puka 1 was drilled as an exploration hole with a small diameter well bore and is not ideal for production given the waxy nature of oils commonly produced in the Taranaki basin. In contrast, Puka 2 is being drilled with a larger diameter more suitable for addressing build up issues.

Puka 1 achieved maximum flow rates of 310 bopd and 1.8 mmcf/d, although sustainable rates are expected to run between 150 to 200 bopd. Puka 1 is presently shut in for testing pressure build up. The company hopes the combination of the drilling results of Puka 2 and the 3D seismic will help the company reach its 2,000 bopd target.

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