Faroe Makes Oil Discovery West of Shetlands

- Faroe Makes Oil Discovery West of Shetlands

Wednesday, August 24, 2011
Faroe Petroleum plc

Faroe announced an oil discovery in its first operated exploration well on the Fulla prospect in the west of Shetland (Faroe Petroleum 50% and operator).

Highlights

• The 206/5a-3 exploration well discovers oil in the Fulla prospect
• The well penetrated a gross oil column in the well of 133 feet and a net oil column of 45 ft. Reservoir quality is better than expected.
• The oil has been sampled and details of the oil quality will be confirmed by further analysis conducted in the onshore laboratory.
• Faroe’s first operated exploration well has been successfully drilled in accordance with UK's HSE guidelines.

Well 206/5a-3 on the Fulla prospect was spudded on July 6, 2011 and was drilled to a total depth of 7,711 feet total vertical depth sub-sea (TVDSS) in 407 feet water depth. This Atlantic Margin well, located 31 kilometers to the north east of the BP-operated Clair field platform, was targeting potentially oil-bearing Clair and Whiting reservoir sands with the primary objectives of confirming hydrocarbons within the structure and, if present, running a comprehensive suite of wireline logs and obtaining representative oil samples.

The targeted reservoirs were encountered close to prognosis. The well drilled through a gross oil column of 133 feet and a net oil column of 45 ft. The average porosity in the net interval has been estimated at 23%. Oil samples were successfully recovered to allow detailed fluid analysis to be conducted in the onshore laboratory. Detailed data analysis will now commence on interpreting the results of this well, and subsequently, we will work to identify development options that include the Freya discovery made in 1980, which is located immediately to the south in the adjoining Block 206/10a (Faroe 50% and operator).

The Awilco-owned WilPhoenix semi-submersible drilling rig, which was used for the drilling operation, is now actively engaged in operations to plug and abandon the well as planned, and is expected to move away from the location in the coming days.

In December 2010, Faroe farmed out a 50% interest in this license to Canadian Overseas Petroleum Limited on promoted terms.

Graham Stewart, Chief Executive of Faroe Petroleum plc, commented, "We are very pleased with the positive outcome of this frontier West of Shetlands exploration well. To announce a discovery in our first operated well is a significant achievement for Faroe Petroleum and is a realization of the team’s vision and ability. Further work will be conducted in the coming weeks to gain a deeper understanding of the structure and its contents. With better than expected reservoir quality and good indications of mobile oil, we believe there is potential for a commercial field development, most likely in combination with our nearby Freya discovery.

"Faroe Petroleum applied for and won this license, which also contains the Freya discovery to the south, in the 22nd UK Licensing Round in 2005, and has worked continuously to de-risk this opportunity. This important new Fulla discovery is a great testament to the diligence and skill of our technical team.

"We look forward to three further exploration wells to be drilled in Norway this year. The Butch well with Centrica as operator is currently drilling, and we have two further wells, T-Rex and Kalvklumpen planned to commence in the coming months."

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Aurora Drills Ahead at Tx. Alwan West Prospect

- Aurora Drills Ahead at Tx. Alwan West Prospect

Thursday, August 11, 2011
Victory Energy Corp.

Victory, through its partnership with Aurora Energy Partners, announced that its Alwan West (#1 Goff Mineral Trust) prospect well was spud on August 2, 2011 and is currently drilling ahead at 5,097 feet.

Prior to reaching the proposed target depth of 7,100 feet, all three target sands (first Yegua, Frio and second Yegua) will be tested. All three sands are anticipated to be reached and tested in the coming days. These sands do not require a fracking procedure to be productive. Anticipated completion after a successful testing generally occurs in less than two weeks.

The lease area is surrounded on all sides by gas condensate production and a delivery pipeline is within 1,000 feet of the well.

Alwan West lies on strike between two Yegua fields, Lost Fork (one mile west) and AVO Grande (3,000 feet east). Lost Fork has produced over 42 BCF, while AVO Grande has produced 7 BCF of natural gas. Both of these fields are stratigraphic traps, as is the Alwan West prospect. This area produces from the Frio and Yegua (Oligocene) formations.

This prospect's potential reservoir covers an area of 175 acres and has a reserve potential of 8.5 billion cubic feet (BCF) of natural gas and 43.75 thousand barrels of gas condensate.

The reserve potential is based on 50 feet of reservoir sand, one million cubic feet per acre-foot of natural gas and five barrels per million cubic feet of gas condensate. These reserve estimates are for the first Yegua sand only, which is the primary objective, and do not include potential in the secondary objectives.

The Alwan West prospect is located in far western Wharton County, Texas, near the Jackson County line. Victory Energy acquired the prospect, which includes a 5 percent working interest (WI) and a 3.8 percent net revenue interest (NRI), from Miramar Petroleum, Inc. of Corpus Christi, Texas, who will be the operator and who also owns a significant working interest in the well.

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North Atlantic Drilling Takes Delivery of Jackup West Elara

- North Atlantic Drilling Takes Delivery of Jackup West Elara

Tuesday, August 09, 2011
Seadrill Ltd.

North Atlantic Drilling Ltd., in which Seadrill has a 75 percent ownership, has taken delivery of the new harsh environment jackup drilling rig, West Elara from Jurong Shipyard in Singapore. The rig is expected to depart Singapore on August 11th and arrive at Westcon Shipyard in Olen, Norway in early October in order to undertake final contract preparation activities. The West Elara is expected to begin operations for Statoil on a five- year contract during late November 2011.

The West Elara is the first of two Gusto MSC CJ70 150A rigs to be constructed for North Atlantic Drilling Ltd. The rig is an advanced, ultra large, harsh environment, high specification drilling unit, specifically built for Norwegian requirements and matching the specifications of the largest jackup drilling units in the world. The unit can operate in water depth up to 150 meters with a higher variable deck load and a higher operating efficiency compared to earlier generation jackups. The size of the unit allows for additional opportunities in terms of logistics, well testing and early production.

Alf C. Thorkildsen, Chief Executive Officer in Seadrill Management AS and Chairman of North Atlantic Drilling Ltd, said, "We are pleased to take delivery of the West Elara, the first of two new ultra large and harsh environment jackups to be added to the North Atlantic Drilling fleet. We look forward to seeing this new and advanced drilling unit operating on the Norwegian Continental Shelf, creating growth for North Atlantic Drilling ahead of its listing on the Oslo Stock Exchange, increasing our presence in this key region and further strengthening our relationship with Statoil, one of our most important customers."

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Rockhopper Extends Sea Lion Find West

- Rockhopper Extends Sea Lion Find West

Tuesday, August 09, 2011
Rockhopper Exploration plc

Rockhopper provided an update on the 14/10-6 appraisal well. The third appraisal well on the Sea Lion feature was drilled 4.1km to the west of the 14/10-2 discovery well on license PL032 (100% Rockhopper) and to a total depth of 2706m (drilled depth).

• Sea Lion Main Fan Complex
  • Results at upper end of expectations
  • Well confirms significant reservoir development and hydrocarbon charge within Rockhopper's currently interpreted Sea Lion mid-case area
  • Wireline log analysis indicates Sea Lion main fan net oil pay is 36.4m (119 feet)
  • Gross reservoir interval in Sea Lion main fan is 42m (138 feet) with net to gross of 87%
  • Management interprets this well as confirming Sea Lion main fan is full to spill
  • Reservoir quality good:
    • average porosity 21.6%, maximum 28.8%
  • Average Sw (water saturation) 21%
  • No oil water contact observed in the Sea Lion main fan
  • Formation pressure tests indicate reservoir at the well in communication with wells 14/10-2, 14/10-4 and 14/10-5
  • Downhole fluid samples collected confirmed as oil
  • Following this well, the board considers Sea Lion to be commercially viable
• Sea Lion Lower Fan Complex
  • Well developed lower sand package (sand B15) intersected beneath oil water contact of -2477m tvdss (total vertical depth subsea) and was water wet with no shows
  • 34m (112 feet) gross reservoir package with 85% net to gross
  • Reservoir quality good:
    • average porosity 20%, maximum 25.3%
  • Sand B15 showed significant thickening away from wells 14/10-2 and 14/10-5 as prognosed
  • Formation pressure tests indicate B15 sand to be in pressure communication with the Sea Lion main fan complex giving significant updip exploration potential
  • Deeper thin lower fan sands penetrated in wells 14/10-2 and 14/10-5 showing a separate deeper oil column not developed at this well location

Well 14/10-6 was designed to investigate reservoir and hydrocarbon presence within the Company's mid-case Sea Lion mapped area. 14/10-6 was the first well to penetrate the Sea Lion main fan to the west of the mapped structural low that runs north-south through Sea Lion. The well has been highly successful, proving a thick, high quality reservoir package and a substantial oil column.

Wireline logging operations have been completed. A number of mini DST (downhole Drill Stem Tests) were carried out within the main fan complex and oil was successfully flowed from the main fan. The results will now be interpreted and integrated with other wireline logging data to give an estimate of the potential well productivity. The Company does not consider it necessary to perform a full production test and the well will now be plugged and abandoned.

Once the results of this well have been integrated into the fast-track seismic covering the southern portion of licenses PL032 and PL033, a further announcement will be made detailing the seismic interpretation and the implications of well 14/10-6 for management estimates of resources within Sea Lion.

Upon completion of operations on 14/10-6 the Company intends to drill an exploration well 3.3km to the North West of the discovery well 14/10-2, outside of the Sea Lion Discovery Area. The well is designed to investigate the presence of reservoir and hydrocarbon charge towards the northernmost currently mapped extent of the Sea Lion Main fan.

Sam Moody, Chief Executive, commented, "The results of this well are at the upper end of expectations for the Sea Lion main fan complex and we are delighted to see these oil charged sands extending to the west as prognosed. The thickness and quality of reservoir encountered in the lower fan complex gives additional potential updip."

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Baker Hughes Lands Gig at Lukoil's West Qurna Field

- Baker Hughes Lands Gig at Lukoil's West Qurna Field

Monday, August 08, 2011
Baker Hughes Inc.

Lukoil has awarded Baker Hughes a two-year contract to provide full drilling and completion services for 23 wells in the West Qurna field in southeast Iraq, 50 kilometers (31 miles) west of Basra.

Under the terms of the contract, Baker Hughes will provide engineering and project management for the turnkey drilling and completions scope of the project. Baker Hughes will supply drilling services, formation evaluation, casing and tubing running services, completion tools and services, wellbore intervention services, and wireline logging as well as perforation operations. Baker Hughes also will contract all third-party services, equipment, personnel, tools and materials required for the project, including the provision of up to five drilling rigs and three workover rigs.

Some of the wells will be drilled directionally, targeting the Mishrif formation, with step outs of up to 3,000 meters (9,842 feet). The wells are closely spaced, so the operation will employ a cluster (pad) drilling technique. The five drilling rigs and three workover rigs will be mounted on skids for fast, efficient rig moves.

Baker Hughes is well positioned in Iraq to execute the West Qurna project. In 2010 Baker Hughes opened a 120,000 square-meter (1.3 million square-feet) operations base in Basra to serve the Iraq oil and gas industry. The base includes a workshop to support a wide range of Baker Hughes products and services. The facility also houses chemical blending capabilities and inventory, as well as bulk drilling fluids storage for quick response to customers' requirements.

In addition to the LUKOIL drilling and completions award, Baker Hughes manages and operates drilling and workover rigs in the Zubair field for an international oil company. Baker Hughes also has a strategic alliance with the South Oil Company to support the development of Iraqi wireline capabilities; and supplies electrical submersible pumping (ESP) systems and services—including real-time remote monitoring and automation capabilities to optimize production—to three major international operators.

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Gastar Tests Marcellus Wells in West Virginia

- Gastar Tests Marcellus Wells in West Virginia

Thursday, July 28, 2011
Gastar Exploration Ltd.

Gastar provided an update on its recent Marcellus operational results.

Gastar has completed the drilling and stimulation of its first two horizontal Marcellus wells in Marshall County, West Virginia, the Wengerd 1H and 7H, with lateral lengths of 4,700 and 5,700 feet, respectively. These two wells have been tested at a combined stabilized rate of approximately 15.5 MMCFD of 1285 Btu natural gas and 1,100 barrels of condensate per day ("BCPD") while each well was flowing at approximately 1200 psi of flowing casing pressure and each well was producing over 150 barrels of frac water per hour. The Wengerd 1H and 7H are expected to be placed on sales in mid-August following delivery and installation of separators capable of handling the condensate volumes. Gastar owns a 44.5% working interest ("WI") and 37.5% net revenue interest ("NRI") in these wells.

Gastar currently has three drilling rigs running in the play. We are currently drilling on two multi-well pads in Marshall County and we will commence drilling on a third multi-well pad in Marshall County in early August. Also, we have recently completed the drilling of the Hickory Ridge 2H well (GST 100% WI) in Preston County, West Virginia on the acreage that was acquired in December 2010 and plan on a mutli-stage fracture stimulation of the Hickory Ridge 2H well in the second half of August.

J. Russell Porter, Gastar's President and CEO, commented, "We are extremely pleased that the initial test results from the Wengerd wells have confirmed our assumptions for reservoir characteristics in this portion of the play and may exceed our individual well assumptions on deliverability and condensate yield. We currently have 72 additional locations within the immediate vicinity of the Wengerd wells. We collected a full array of micro-seismic data during these completions and we anticipate using that data to improve our results and become more efficient with our completions."

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Solimar Doubles Stake in Paloma West Project

- Solimar Doubles Stake in Paloma West Project

Thursday, July 14, 2011
Solimar Energy Ltd.

Solimar has confirmed terms to increase its working interest to 25% (doubling the original 12.5%) in the Paloma West project and is soon to be participating in an appraisal well on the project.

The Paloma Deep -1 appraisal well will be drilled using Nabors Rig #710 which is expected onsite at the end of July supporting commencement of drilling in early August.

The Paloma West project is operated by Neon Energy and covers some 1400 acres all within the structural closure of the Paloma oil and gas field which has produced some 61 million barrels of light oil and 432 billion cubic feet of gas (133 MMBOE) since discovery in the 1930s. The Paloma field is a large anticline structure some 12 miles long by 4 miles wide.

The well location has been chosen using 3D seismic which was acquired after the prior development of the field. The 3D data has been used to help identify favourable reservoir trends within the field closure and all the targeted sandstone reservoirs at the well location are characterised by amplitude anomalies on the seismic. This is believed to support the presence of hydrocarbons and may also be indicative of reservoir quality.

There are seven (7) individual, stacked reservoir targets in the well commencing at approximately 10,000 feet. The well has a planned total depth of 15,500 feet and will take up to 2 months to drill. All the targeted sandstone and shale reservoirs are part of the Miocene age Monterey Formation, the famous oil source and reservoir formation in the southern San Joaquin Basin. The estimated unrisked in place hydrocarbon volumes are up to 300 million barrels OIP and based on an 11% recovery factor (equivalent to the historic recovery from the main producing reservoir of the Paloma field) the targeted recoverable resource is 33 MMBOE. Significant upside to these estimates is possible if higher recoveries are attainable.

The well will drill though a series of shallower Pliocene mostly dry gas reservoirs on the way down that are expected to be depleted by historic production. Some of these sand reservoirs are equivalent to the San Joaquin Formation gas sands that Solimar is attempting to develop at its SELH gas project further to the northwest in the basin. The shallow sands produced 23 Billion cubic feet (Bcf) of gas at Paloma.

The first reservoir to be evaluated will be in the Antelope Shale member of the Monterey which envelopes the main reservoir of the field, the Paloma or Upper Stevens Sandstone. This sand has produced 58 mmbbls and 415 Bcf and is likely to be at least partially depleted at the well location and is therefore considered a secondary target. All the Monterey Formation sandstone reservoirs including the Paloma Sandstone were originally formed as submarine fans derived from the NE and deposited into the deep water basin prevalent in the San Joaquin Basin during the Miocene. The anticlinal structure which traps the hydrocarbons was formed much later and has a
different, NW – SE orientation. So there has been varying sand quality encountered across the field which affected the historic field development, particularly for the Lower Stevens Sandstone reservoirs which were not discovered until 1973.

Only three wells have penetrated to the deeper reservoir levels in the west half of the field area (the most recent being some 26 years ago in 1985) each encountering extensive live oil and gas shows and with two wells flowing oil and gas at low rates.

Solimar believes that the 3D seismic data and modern drilling and completion technologies provide an excellent chance for a successful appraisal of the sandstone reservoirs in the western Paloma oil field. Unlike most of the original field wells that were drilled using water based muds that can react with clays in the reservoir reducing permeability (or ability to flow), the Paloma Deep - 1 will be drilled with a synthetic oil based mud to reduce drill time and minimise formation damage.

With the exception of one old vertical well recompleted for production in the Antelope Shale in 1993, the fractured oil shale potential of the acreage remains untapped. In the context of the escalating production and re development of equivalent rocks in other fields in the area, the fractured oil shales present an exciting opportunity for the new joint venture.

Solimar is increasing its interest via a farmin with Neon. The increased position in the project will be subject only to any consents to assignment of the interests that may be required by the underlying lessors and to completion of Solimar's previously announced private placement to raise A$7 million which will be processed at an EGM on July 29.

The dry hole cost of the Paloma Deep -1 is estimated at US $4.9 million. Solimar will be funding its share from cash reserves and the proceeds of the placement.

Commenting on the drill program Solimar CEO John Begg said, "It is very pleasing to be announcing another step up in the scale of the Company's assets in the San Joaquin Basin focus area. The Paloma West project perfectly illustrates Solimar's strategy of acquiring
material interests in oil prone assets that have targets in both conventional and unconventional reservoirs. Further, where hydrocarbons have already been discovered. Solimar has the opportunity to be part of the first joint venture to apply modern, off the shelf technologies to evaluate and exploit the assets. The Paloma Deep -1 is an ambitious drill program designed to evaluate a series of targets within part of a known field where the reservoirs have not been adequately tested by the historic drilling. The project provides an exciting opening to a virtually continuous 12 month program of drilling and production testing on the Company's core projects which is well illustrated in the activity schedule accompanying this release. Each of these projects represent stand - alone, technically independent opportunities for growth."

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Victoria O&G Updates Ops at West Medvezhye

- Victoria O&G Updates Ops at West Medvezhye

Thursday, July 07, 2011
Victoria O&G plc

Victoria O&G provided an update on its appraisal and delineation program in the West Medvezhye, (West Med) oil, gas and condensate license area in Russia.

West Med Regional Background

VOG's wholly owned subsidiary, ZAO SeverGas-Invest (SGI), holds a 20-year Exploitation License for West Med covering 1,224 km2. The block is located in the Yamal Peninsula in the Nenets region of Siberia and was independently assessed in 2006 by DeGolyer and MacNaughton (D&M) to have total prospective resources of approximately 1.1 billion barrels of oil equivalent (boe). West Med is located in one of the most prolific oil and gas producing areas of the world and is adjacent to Gazprom's giant Medvezhye field that has already produced over 70 trillion cubic feet of gas.

In total, D&M identified 25 leads and prospects and the Company's first discovery in West Med, Well 103, was based on a prospect defined by D&M. The discovery has C1 and C2 reserves, independently assessed, under the Russian classification convention of 14.4 million boe as approved by the Russian Ministry of Natural resources.

West Med Appraisal Update

While VOG's principal focus has been the development and commencement of gas and condensate production at Logbaba in Cameroon which is scheduled for 4Q 2011, SGI's technical team and consultants Blackwatch Petroleum Services (Blackwatch) have been utilizing this time to acquire data and to carry out integrated multi-discipline studies in West Med.

This work has involved integration of new data with previous seismic and well data to screen and firm up the prospects and leads identified by D&M.

Passive Seismic and Gas Tomography Surveys

New data acquired in 2010 included 155 passive seismic points recorded by GeoDynamics Research S.r.l. (GDR) and 289 km lines of gas tomography data recorded by Exotrad Limited. The surveys identified direct hydrocarbon indications in six areas covering a total of 79 km2 in the opinion of GDR and VOG.

Preliminary internal volumetric estimates by the Company, based on these passive seismic areas and regional well and seismic data for reservoir properties, indicate hydrocarbons initially in-place estimated at 400 mmboe by SGI and Blackwatch.

The features are all part of previously identified prospects by D&M, based on conventional seismic, and the volumes were incorporated into the overall assessment of 1.1 billion boe Un-risked Prospective Resource potential for the West Med Block.

Conventional Seismic work

Further to these positive results, in February 2011, the Company commissioned a seismic reprocessing and geological modelling study to be carried out by a Russian geoscience consulting institute, Mineral. The first phase of the technical work, which included reprocessing of 845 km of 2D seismic, was completed in June 2011.

Re-interpretation of the reprocessed seismic data has now commenced and will incorporate the passive seismic and gas tomography results. The results of Mineral's work are scheduled to be considered in a workshop in Tyumen, Russia in July 2011.

West Med Appraisal / Development Planning

In addition to the subsurface technical studies, development studies have commenced for commercialization of the large prospective resources and exploitation of the Well 103 discovery. These include but are not limited to the following:

Drilling & Well Engineering

Studies have commenced on well design and engineering for future appraisal and development well drilling planned for 4Q 2012. The company is in discussions with international and Russian service companies and has compiled initial budgetary estimates for the wells and drill pads.

These studies conclude that the wells may be drilled in clusters of 3 to 10 to significantly reduce location preparation and access cost. This will have a marked impact on development economics.

Surface Production Facilities & Infrastructure

Conceptual design work has commenced to establish costs and schedules for oil, gas and condensate production facilities and supporting infrastructure. The gathering and distribution network design and engineering will be phased with facilities design, starting with fast track development of the Well 103 discovery.

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Krafla West Delivers for Statoil

- Krafla West Delivers for Statoil

Tuesday, June 28, 2011
Statoil

Oil and condensate have been proven by Statoil and its partners, Det Norske Oljeselskap ASA and Svenska Petroleum Exploration AS, in the North Sea's Krafla West prospect.

Located about 26 kilometers south-west of Oseberg South, the discovery well found hydrocarbons in two columns with a total thickness of 300 meters.

Preliminary calculations indicate that the find contains some 12.6-37.7 million recoverable barrels of oil equivalent (boe).

"The North Sea still has a considerable exploration potential," observed Gro Gunleiksrud Haatvedt, senior vice president for the North Sea in the Exploration business area.

"Through the discoveries in Krafla and now Krafla West, we've proven reserves of 50-75 million boe. This must be considered a very substantial figure in a near-field context."

The two wells are the first drilled by Statoil in the license, she noted. "Discoveries with both wells indicate that we've understood how the hydrocarbon systems in this area function."

"The Krafla and Krafla West discoveries provide the basis for a robust fast-track project," added Tom Dreyer, head of exploration for the northern North Sea. "They show that growth opportunities still exist in this mature part of the North Sea."

A fast-track development of both discoveries through tie-backs to existing infrastructure in the Oseberg area will be considered.

Krafla and Krafla West lie in the same area as Stjerne, formerly Katla, which was proven in 2009 and is already covered by a plan for development and operation (PDO) from Statoil.

The Krafla/Krafla West wells were drilled from Ocean Vanguard, which is now moving to production license 569 at the southern end of Norway's North Sea sector to drill for Statoil on the Theta North-East prospect.

The licensees in the latest discovery are Statoil as operator with 50%, Det Norske Oljeselskap ASA with 25% and Svenska Petroleum Exploration AS with 25%.

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Seadrill to Sell Jackup West Janus

- Seadrill to Sell Jackup West Janus

Tuesday, June 21, 2011
Seadrill Ltd.

Seadrill has entered into an agreement to sell the 1985 built jackup drilling rig West Janus to Harrington LLC in Dubai for a total consideration of US $73 million.

Seadrill expects to record a gain on the sale in excess of US $50 million on closing. Closing of the agreement and the transfer of ownership of the unit is scheduled upon completion of the rig's present drilling assignment in the second half of 2011.

Seadrill's fleet of jack-up rigs remains the world largest modern jack-up fleet with a total of 19 units built after 2006, including rigs under construction. Furthermore, Seadrill has options for construction of six further units at attractive prices.

Alf C Thorkildsen, CEO of Seadrill Management AS said, "We remain optimistic about the market outlook for premium jack-up rigs, and at the same time continue to highgrade our fleet by disposing some older units, while adding new rigs to it. The disposal of West Janus further reduces the average age of the modern Seadrill jack-up fleet to 2.6 years, and is in line with our strategy of focusing our company on modern, premium offshore drilling units."

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Energy XXI Granted Operatorship on West Delta Fields

- Energy XXI Granted Operatorship on West Delta Fields

Thursday, June 16, 2011
Energy XXI

Energy XXI provided an operational update, including results of the first recompletion at the South Pass 89 field and drilling of the Onyx prospect at the Main Pass 73 field.

In addition, the company announced it has been granted operatorship of the West Delta 30 and West Delta 73 fields obtained in the ExxonMobil asset acquisition in December 2010. "Gaining control of these fields allows us to move forward with our production optimization and capital programs," Chairman and Chief Executive Officer John Schiller said. "We expect to have the last field, South Timbalier 54, under our control by the end of the month."

Exploration and Development Activity

Within the company's core producing properties, located offshore Louisiana, the first of a six-well recompletion program at the South Pass 89 field has been successful. The A-15 well is currently flowing 18 million cubic feet per day and 300 barrels of condensate per day, with 3,100 pounds of flowing tubing pressure. The well, forecast to deliver 800 barrels of oil equivalent per day (BOE/d) net, is producing 2,500 BOE/d net. These production levels equal the company's pre-work estimate for the entire six-well program.

At the Grand Isle 16 field, the company perforated a prospective natural gas zone in the J 21 well, which instead tested mostly oil at approximately 1,200 BOE/d. That well has been shut in until a platform rig is mobilized to complete work. In addition, the Rowan EXL 3 rig, previously working for McMoRan, will be mobilized to Grand Isle 16 to perform three recompletions that have been identified to optimize production.

Quarter-to-date, production has averaged approximately 42,500 BOE/d, benefitting from the success at South Pass 89 and other previously announced recompletions. Current production exceeds 46,500 BOE/d. This production level has been achieved despite the fact Energy XXI did not have operational control over the West Delta 73 and South Timbalier 54 fields, which are the largest fields added in the December 2010 acquisition.

Near-term production also should be augmented by two successful wells at the Main Pass 73 field. The Onyx well was drilled to 5,635 feet and encountered two pay zones that were previously modeled as salt. The well was completed and initial testing is beginning today. The rig currently is being moved to begin completion operations on the Ashton well which, as previously announced, encountered seven pay zones. Combined initial production from Ashton and Onyx is expected to approximate 1,500 BOE/d within the next 30 days.

Within the shallow-water, ultra-deep Gulf of Mexico shelf program, the McMoRan-operated partnership (in which Energy XXI has various interests) has continued activity at the Blackbeard East and Lafitte exploratory wells and the offset appraisal well at Davy Jones.

The Davy Jones offset well, located on South Marsh Island Block 234 in 20 feet of water, has been drilled and cased to 30,450 feet. Logging operations have been completed and the logs are being evaluated. As previously announced, wireline logs indicated over 200 feet of gross sand and approximately 100 net feet of sand, based on porosity data available, in multiple Wilcox zones that appear to be hydrocarbon bearing. Below the identified Wilcox section the well encountered Upper Cretaceous, Tuscaloosa and Lower Cretaceous sections. The well is being readied for production once equipment has been procured, with expected first production to occur during the second quarter of calendar 2012. Energy XXI has a 15.8 percent working interest and 12.6 percent net revenue interest in Davy Jones.

The Blackbeard East exploration well, located in 80 feet of water on South Timbalier Block 144, was drilled to 32,559 feet before encountering mechanical issues. McMoRan is continuing to make progress recovering drill pipe and tools stuck in the hole. After recovering 1,866 feet of stuck pipe, the remaining 1,374 feet of pipe and tools appear to have slipped further down the wellbore. The operator has washed and reamed the wellbore to a depth of 29,227 feet and has yet to reencounter the top of the stuck pipe. Progress to date provides encouragement that the wellbore may be preserved to the previous depth and deepened to the permitted depth of 34,000 feet. Energy XXI has an 18 percent working interest and 14.35 percent net revenue interest in Blackbeard East.

The Lafitte exploration well commenced drilling on Oct. 3, 2010 towards a proposed total depth of 29,950 feet, targeting Miocene objectives below the salt weld. A liner has been run below the salt to 22,982 feet and the well is currently drilling at 23,645 feet.. Lafitte is located on Eugene Island Block 223 in 140 feet of water. Energy XXI has an 18 percent working interest and a 14.6 percent net revenue interest.

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Penn West Expects A Hit Due To Canadian Wildfire

- Penn West Expects A Hit Due To Canadian Wildfire



Jun 13, 2011

Penn West Petroleum Ltd. (NYSE: PWE) expects a hit on its cash flow from wildfires that are still blazing through northern Alberta, Canada. The company's chief operating officer Murray Nunns stated at a conference Monday that they expect to see a C$60 million to C$70 million hit due to the fires.

The wildfires are affecting around 35,000 barrels of oil a day as well as production. Nunns stated that about half of the shut-down facilities are ready to restart, and all of them will be ready by the end of June. By July, they expect to be back at full production.

Penn West Petroleum has a potential upside of 32.3% based on a current price of $23.13 and an average consensus analyst price target of $30.78.

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Noble Extends Footprint in West Africa

- Noble Extends Footprint in West Africa

Wednesday, June 08, 2011
Noble Energy Inc.

Noble has joined a venture that is exploring the AGC Profond block located offshore Senegal and Guinea-Bissau in West Africa. The AGC Profond block, covering more than two million gross acres in water depths up to 11,500 feet, is in a designated cooperation area between the two countries. The venture has identified a number of prospects and leads on the acreage. Approximately 45 percent of the block is covered by existing 3D seismic.

The first target to be drilled is the Kora prospect in the northern part of the block, nearly 65 miles offshore in approximately 8,600 feet of water. The Kora prospect has a Cretaceous oil target with gross resources estimated at 450 million barrels of oil equivalent. The chance of success at the prospect is estimated by Noble Energy to be 20 percent. Total well depth is planned to be approximately 15,200 feet. Drilling is anticipated to begin in late June 2011 utilizing the Maersk Deliverer rig, with results expected by the end of August 2011.

David L. Stover, Noble Energy's President and COO, commented, "We are pleased to be adding this new exploration area to the portfolio. Offshore West Africa is a region where the industry has had numerous recent exploration successes, including our own offshore Equatorial Guinea and Cameroon. The AGC Profond block is an area that has not previously been explored and we believe it has significant oil potential. Our new ventures team did a great job of capturing this opportunity for Noble Energy, expanding our already large exploration inventory."

Ophir will operate the Kora-1 exploration well and, in the event of a discovery, Noble Energy will become the operator for appraisal and development activities. Noble Energy has a 30 percent working interest. Other interest owners are Ophir with 36.7 percent, Rocksource AGC Profond AS with 12.5 percent, and FAR Ltd. with 8.8 percent. The remaining interest is held by L'Entreprise, the AGC state-owned entity, with 12 percent.

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East West Petroleum Enters MOU to Develop Romania Blocks

- East West Petroleum Enters MOU to Develop Romania Blocks

Wednesday, May 25, 2011
East West Petroleum Corp.

East West Petroleum and Naftna Industrija Srbije j.s.c. Novi Sad ("NIS") announced the final stage of conclusion of agreements for upstream cooperation which is to rapidly advance the development of its four Romanian onshore blocks EX-2 (Tria), EX-3 (Baile Felix), EX-7 (Periam) and EX-8 (Biled). The joint exploration programs planned will include the collection and processing of approximately 900 km of 2D and 600 sq km of 3D seismic data with a minimum of 12 wells to be drilled on the four blocks in Romania. The terms of the agreement are: NIS will fully fund all environmental work, 2D and 3D seismic acquisition and processing, and the drilling of 12 wells, to earn an 85% participation interest. NIS will also refund 100% of EWP's sunk costs which total C$525,000 and EWP will retain a 15% carried interest to commercial production on all four blocks.

In an earlier agreement the Company signed Concession Agreements for four onshore exploration blocks EX-2 (Tria) EX-3 (Baile Felix), EX-7 (Periam) and EX-8 (Biled) with the Romanian National Agency of Mineral Resources.

The new petroleum licenses are located in the western region of Romania within the prolific Pannonian Basin. The blocks have a combined area of approximately 1,000,000 acres. The blocks, which contain multiple exploration targets, lie within a major producing region of western Romania. The blocks have been only moderately explored, with previous exploration on the acreage generally limited to shallow structural traps. The Company has identified a number of structural and stratigraphic leads in the deeper section and plans to focus its exploration activities on the conventional oil and gas potential in addition to unconventional shale gas potential.

EWP and NIS plan to cooperate extensively to explore for and produce oil and gas from the four concession areas. Both conventional and unconventional resource potential has been identified on the acreage, which is situated close to numerous oil and gas fields. The joint work programs planned will include the acquisition and processing of approximately 900 km of 2D and 600 sq km of 3D seismic data during the first two years of operations. The new seismic data will be used to high-grade a number of prospective conventional oil and gas leads already identified on the acreage, to further study the unconventional shale potential and select drilling sites. Under the terms of the agreement East West will retain a 15% carried interest through Phase 1 (compulsory) and Phase 2 (optional) exploration periods as well as a carried interest on any discovery through to the declaration of commerciality. EWP will retain a 15% share of all production realized from the four concessions.

NIS is a leading explorer in this sector of the Pannonian Basin. NIS is currently carrying out extensive E&P operation in the Vojvodina region of northern Serbia, immediately adjacent to the Romanian Periam and Biled Concessions. NIS's operational capabilities and knowledge of regional geology are expected to contribute significantly to the success of the Romanian exploration programs.

The exploration programs are subject to final ratification of the Concession Agreements by the Government. The farmout to NIS will be subject to further agreements and approval of NAMR, which is expected to take place soon after the Government of Romanian ratifies the Concessions.

"The cooperation agreement with East West will allow NIS to expand its presence outside Serbia and to implement NIS's strategy of becoming an active player in the Balkan energy market. Participation of NIS in the project as operator will allow us to further our experience in the region and to apply innovative technologies for developing conventional and unconventional resources," commented Kiril Kravchenko, NIS Chairman of the Management Board.

Denis Sugaipov, the COO of NIS Company said, "The deal with East West Petroleum has several operational synergies for both companies and benefits for the Romanian energy sector. NIS's geological knowledge of Pannonian basin and its success in development can be applied to an area which is analogous to the Serbian North Banat region. In addition, EWP can contribute its technical expertise in unconventional resources. I hope that this deal will show results in the near future and contribute to the development of the Romanian energy sector, enabling the sustainable development of the entire region."

David Sidoo, Chairman of East West commented, "These agreements are the culmination of many months of hard work and we are confident that in Naftna Industrija Srbije, a subsidiary of Gazprom Neft, we have sourced a key and strategic partner, with substantial operating experience and the necessary financial and operating capabilities which can be applied to the Romanian concessions and can very quickly advance with the development of the Romanian concessions."

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North Atlantic Drilling Awarded Contract for West Alpha

- North Atlantic Drilling Awarded Contract for West Alpha

Wednesday, May 18, 2011
Seadrill Ltd.

North Atlantic Drilling Ltd., in which Seadrill has a 75 percent ownership, has received a letter of award for the semi-submersible drilling rig West Alpha for operations on the Norwegian Continental Shelf.

The letter of award covers a two-well commitment in the Balder field, with an estimated firm contract period of 210 days and an estimated value of US $100 million. Commencement of the assignment is scheduled for the third quarter 2012, in direct continuation of the present contract. The contract has provisions at the operators sole discretion for extension of up to four additional wells.

Alf C Thorkildsen, Chief Executive Officer in Seadrill Management AS and Chairman of North Atlantic Drilling Ltd. said, "We are pleased to report a new contract for the drilling unit West Alpha. The contract demonstrates the continued strong demand for quality drilling units in the North Atlantic - Norway area and further enhances the value of North Atlantic Drilling."

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ExxonMobil Launches EOR Project in West Texas

ExxonMobil Launches EOR Project in West Texas

Tuesday, May 10, 2011
Exxon Mobil Corp.

ExxonMobil Production Co. announced Tuesday that drilling and construction have started on an enhanced oil recovery project at the Means Field in Andrews County, Texas. The first phase of the project has the potential to recover as much as five million barrels of additional oil, an amount equal to the annual energy needs of about 170,000 Texas households.

ExxonMobil has more than two decades of experience with carbon dioxide injection for enhanced oil recovery at the Means Field. The new project will apply technology to produce oil that until recently was technically and economically challenging to develop. Carbon dioxide injection is expected to begin before year end 2011. This first phase could lead to future development phases, which could significantly increase oil recovery from the field.

"ExxonMobil's investment in the field is part of an ongoing effort to find, develop and produce more domestic supplies of oil and gas to meet the country's growing energy needs," said Lyndal Trout, the company's senior field superintendent for western Texas.

ExxonMobil discovered the Means Field in the early 1930s. Since then, the company has produced more than 300 million barrels of oil from the field.

Over the past three years ExxonMobil's capital expenditures in Texas has exceeded $790 million. These investments help create jobs and contribute to economic growth across the region. They also help maintain Texas' position as the leading U.S. oil and natural gas producing state.

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BME UK Announces West Africa Contract Win

BME UK Announces West Africa Contract Win

BME UK

BME UK on Wednesday announced a contract worth GBP500,000 for the provision of its Specialised Machinery And Reduced flow Technology (SMART) in West Africa.

The company which designs and manufactures engineering equipment for the construction, marine and oil and gas industries will deploy seven of its personnel from Aberdeen, to carry out the work in the Bonga Field in Nigeria. This landmark deal follows the award of two further contracts with Hunting Energy Services International Ltd and BIS Salamis, both of which will be delivered by BME's operations in Aberdeen.

Scot Borland, director of BME UK comments, "The contract win in West Africa has been achieved in conjunction with local our partner, GCA. The work on the Bonga Field will utilise our revolutionary SMART system, to undertake deep tank and vessel cleaning. We have specially designed this technology to deliver outstanding results while reducing the waste, which deep tank and vessel cleaning produces; in some cases the level of waste is reduced by as much as 80%.

"Seven people from Aberdeen will travel to Nigeria to install and operate the SMART equipment. Training provision also forms part of the contract scope and six West African nationals will receive on-site training."

Aberdeen based Hunting Energy Services International Ltd will also be using BME UK's SMART system. Scot continues, "We have been awarded a contract by energy services provider Hunting Energy Services (Well Intervention) Ltd. This will be fulfilled from our offices in Aberdeen and is for the provision of a containerised ultra high pressure jetting unit and associated training."
Additionally the company has been contracted to undertake activity for leading international industrial services firm, BIS Salamis with the award of an order for the provision of six vertical air receiver frames.

Scot continues, "The technologies we supply are designed to provide results of the highest quality whilst having the added benefit of producing lower amounts of waste. This is therefore better for the environment and helps companies to comply with waste minimisation program requirements. Customers using our SMART system also benefit from lower costs because the amount of contaminated waste products which need to be treated or disposed of is reduced.

"We have recently invested GBP750,000 in the launch of our Specialist Cleaning Services; these initial contract wins validate our decision to make this level of investment and mean that we are well on the way to achieving our target of doubling our turnover to GBP3.4 million."

BME UK designs and manufactures a range of equipment for the construction, marine, oil and gas and decommissioning sectors. This includes decontamination modules for the treatment and disposal of NORM, high pressure fluid pumps for on and offshore use, munchers, handling systems, pipe cleaning systems phosphate systems, heat exchanger and bundle cleaning equipment, as well as traditional spoolers, powerpacks, workshops.

From its headquarters in Aberdeen, BME UK also offers a 24/7 maintenance back up services for clients who own or operate their own water/fluid pumps/pipe handling and cleaning systems. BME's skilled engineers have a wealth of knowledge on a range of pumps and work in global locations. Specialised Cleaning Services, a division of BME UK, provides full bundle cleaning services including surface preparation, internal and external pipe cleaning, drain cleaning, vessel cleaning and shutdown, waste removal and decommissioning services for global operators.

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W&T Offshore to Add Acreage in West Tx. Permian Basin

W&T Offshore to Add Acreage in West Tx. Permian Basin

Tuesday, April 26, 2011
W&T Offshore Inc.

W&T Offshore has entered into a purchase and sale agreement with private sellers to acquire approximately 21,900 gross leasehold acres (21,500 net acres) in the West Texas Permian Basin for a purchase price of $366 million, subject to adjustments and an effective date of January 1, 2011. The reserves are over 91% oil and natural gas liquids. At January 1, 2011, estimates of proved reserves to be acquired are approximately 27 million barrel equivalents (164 Bcfe); and, estimates of proved and probable reserves to be acquired are approximately 53 million barrel equivalents (318 Bcfe) (both using a 6 to 1 Mcf to barrel equivalency). The current wells produce around 2,800 barrel equivalents per day. Since the effective date of the proposed acquisition, production has increased from about 1,900 barrel equivalents. The sellers have three active rigs drilling in the field and ongoing completions are being made on the new wells. We expect to keep at least three rigs working in the field throughout the remainder of 2011. Accordingly, we would expect daily production to increase.

There is significant upside potential in the acquisition with hundreds of proved undeveloped and probable well locations. Capital expenditures associated with planned development activities for these properties for the rest of 2011 are currently estimated at $35 to $40 million. The closing, which is subject to customary closing conditions and normal closing price adjustments, including effective date adjustments, is anticipated in the second quarter and will be funded from cash on hand and borrowings under our revolving bank credit facility.

Tracy W. Krohn, Chairman and Chief Executive Officer, commented, "The acquisition of the Permian Basin oil properties will allow us to continue with our goals of a steadier growth pattern coupled with good cash flow and positive full cycle economics. We believe that there are many more attractive acquisition opportunities for us both onshore and offshore."

Victory Energy Acquires Interest in Alwan West

Victory Energy Acquires Interest in Alwan West

Monday, April 25, 2011
Victory Energy Corp.

Victory Energy, through its partnership with Aurora Energy Partners, announced the acquisition of a working interest in the Alwan West natural gas prospect.

The Alwan West prospect will be the largest natural gas well drilled by Victory Energy to date. This prospect's potential reservoir covers an area of 175 acres. It has a reserve potential of 8.75 billion cubic feet (BCF) of natural gas and 43.75 thousand barrels of gas condensate. The reserve potential is based on 50 feet of reservoir sand, one million cubic feet per acre-foot of natural gas and five barrels per million cubic feet of gas condensate. These reserve estimates are for the first Yegua sand only, which is the primary objective, and do not include potential in the secondary objectives.

The Alwan West prospect is located in far western Wharton County, Texas, near the Jackson County line. There are two natural gas lines that cross the lease within 1,000 feet of the proposed location. Victory Energy acquired the prospect, which includes a 5 percent working interest (WI) and a 3.8 percent net revenue interest (NRI), from Miramar Petroleum, Inc. of Corpus Christi, Texas, who will be the operator and who also owns a significant working interest in the well. The well is anticipated to spud in early June of this year.

This area produces from the Frio and Yegua (Oligocene) formations. The lease area is surrounded on all sides by gas condensate production. The first Yegua sand is the primary objective. Secondary objectives are the Frio and second Yegua sand. Alwan West lies on strike between two Yegua fields, Lost Fork (one mile west) and AVO Grande (3,000 feet east). Lost Fork has produced over 42 BCF, while AVO Grande has produced 7 BCF of natural gas. Both of these fields are stratigraphic traps, as is the Alwan West prospect.

Robert Miranda, Victory Energy's chairman and CEO, stated, "This prospect represents our largest gas play to date and it has the potential to deliver a stable and predictable gas flow to the company. Unlike many other gas sands, the Yegua sand is known for its consistent production and very low annual decline rates. This well is supported by both significant nearby production and quality seismic data."

Golar LNG Notes Execution of West Java FSRU

Golar LNG Notes Execution of West Java FSRU

Friday, April 22, 2011
Golar LNG Energy

Golar LNG announced that the long term Floating Storage and Regasification (FSRU) and Mooring time charter with PT Nusantara
Regas, a joint venture between Pertamina and PGN (West Java FSRU Project) has been concluded and was executed on April 20, 2011.

The contract duration is for an initial term of approximately eleven years with automatic conditional extension options up to 2025. The West Java FSRU Project contract value for the initial period is approximately US $500 million.

Since the execution of the Letter of Intent in November 2010, Golar has ordered the long lead items, carried out conversion engineering and the vessel nominated for this contract, KHANNUR has been positioned to Singapore where the physical conversion works are now underway at Jurong Shipyard in Singapore.

Upon completion of conversion and delivery in the first quarter of 2012, KHANNUR will be permanently moored at a purpose built mooring structure located 15 km offshore West Java. The converted KHANNUR will be capable of storing ~ 125,000 cubic meters of LNG and delivering up to 500 MMSCFD (~3.8 MTA) of regasified LNG via Nusantara Regas's pipeline to fuel for two Power Plants owned and operated by Perusahaan Listrik Negara ("PLN"), Indonesia's national power company.

The Golar group has already completed three FSRU conversions over the last three years. The FSRU for the West Java FSRU Project will be similar in design to the latest of these three projects, the GOLAR FREEZE, which recently delivered under a long term contract in Dubai. The West Java FSRU Project will be Indonesia's first LNG regasifcation terminal and significantly, the first FSRU project in Asia. Golar is currently bidding on PGN's FSRU, Mooring and Pipeline tender to be located offshore Medan, Sumatra.

Golar Energy's FSRU technology offers reliable and cost effective solutions to fast track the import and regasification of LNG.

Golar Energy's CEO, Doug Arnell said "We are very proud to have executed this foundation agreement for the West Java project. We also wish to express our appreciation to the Nusantara Regas team for their dedication in finalizing the contract. We believe this contract for Indonesia and Asia's first FSRU will be the catalyst for the development of additional floating LNG projects within the Asia Pacific region. Indonesia has announced plans for more FSRU projects to include small scale LNG projects and we look forward to having the opportunity to deliver more fast track and low cost solutions."