Chevron awards GE Oil & Gas offshore GOM contract

GE Oil & Gas will supply three customized aeroderivative gas turbine-generator modules to provide reliable electric power for a new Chevron floating production unit that will produce oil and gas from the Jack and St. Malo fields in the Gulf of Mexico, approximately 280 miles south of New Orleans and at a water depth of approximately 7,000 feet.

GE will provide three LM2500+G4 gas turbine generator modules, each mounted on a three-point support base plate, designed with marine corrosion-resistant materials to overcome footprint restrictions and withstand pitch, roll and acceleration forces anticipated for a floating production unit operating in deep waters.

Marco Caccavale, North America region leader—turbomachinery, GE Oil & Gas said: “We are delighted to have been selected by Chevron for this important Gulf of Mexico project. To optimize reliable performance and efficiency and mitigate the considerable footprint restrictions offshore, we have design-engineered three unique modular solutions featuring GE aeroderivative gas turbine technology at their core. This topside, offshore project reflects GE’s ability to supply mission-critical equipment across key segments of the oil and gas value chain and builds on our track record of supplying fixed and floating projects worldwide, including for projects offshore Angola, Brazil, China and Norway.”

The LM2500+G4 gas turbines will be manufactured by GE Aero Energy in Evendale, Ohio, while the generator package assembly and testing will take place at GE Oil & Gas’ facilities in Massa, Italy. Shipment of the equipment is scheduled to start in December of 2011, with commercial startup planned by early 2013.

Chevron’s initial development of the Jack and St. Malo fields will be comprised of three subsea centers tied back to a hub production facility with an initial capacity of 170,000 barrels of oil and 42.5 million cubic feet of natural gas per day.

BG Group doubles Santos basin net potential to 8 billion boe

BG Group issued a material upgrade for its interests in the pre-salt Santos Basin, offshore Brazil. Mean Total Reserves and Resources are now estimated to amount to some 6 billion barrels of oil equivalent (boe) net to BG Group, with an upside potential of 8 billion boe net. Existing discoveries account for 96% of the mean Total Reserves and Resources.

The mean Total Reserves and Resources represents a doubling of BG Group's previous best estimate of 3 billion boe prevailing at the time of the Group's February 2010 Strategy Presentation.

The aggregate range of Total Reserves and Resources net to BG Group is from 4 billion boe (P90) to 8 billion boe (P10).

These new estimates result from BG Group's internal analysis based on probabilistic modelling of its Santos Basin interests. The analysis used a wealth of drilling, appraisal and other data that BG Group has gained or developed in relation to those interests, including:
• a total of 29 wells drilled in our existing discoveries; two wells drilled on Lula since November 2010 proving particularly important in delineating the flanks of the field. Other wells have demonstrated excellent connectivity in the reservoir;
• a total of 19 drill stem tests on current discoveries;
• the shooting and analysis of over 14 400 square kilometres of 3D seismic;
• full analysis of a completed extended well test (EWT) on Lula Sul and early results from the Guará EWT indicating the very large hydrocarbon volumes connected to each of these wells;
• production from the first permanent floating production, storage and offloading vessel on Lula which commenced in October 2010;
• development plans that include enhanced recovery processes to improve ultimate recovery factors for these giant fields; and
• cost optimisation, potential debottlenecking of facilities and greater well productivity enhancing the economic viability of later phases of development.

BG Group Chief Executive Sir Frank Chapman said: "The doubling of our estimated Santos Basin mean reserves and resources is clearly significant and demonstrates the continued rapid evolution of our understanding of these enormous discoveries. Robust economics and solid progress with the fast-track development programme will see gross installed production capacity rising steadily to reach more than 2.3 million boe per day by 2017. I believe this - alongside progress with major ventures in Australia, the US and across our global portfolio - will transform the scope, scale and value of BG Group."

ExxonMobil continues cleanup operations in Montana

ExxonMobil Pipeline Company provided the following update as cleanup operations continued Monday following a release of oil into the Yellowstone River.

More than 280 people are now involved in the response and cleanup effort including ExxonMobil’s North America Regional Response Team, the Clean Harbors and ER oil spill response organizations and additional contractors. More than 150 people cleaned up oil along the river banks today.

A unified command has been established to manage response activities, including recovering oil, monitoring air and water quality, and addressing questions from local residents. ExxonMobil is coordinating the response with the Environmental Protection Agency; the Montana Department of Environmental Quality; U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration; Montana Fish, Wildlife and Parks; Yellowstone County Disaster and Emergency Services; and Yellowstone County commissioners.

For the purposes of the response, the area downriver of the spill has been organized into four zones. Cleanup activities are focused in the first two zones, Laurel to Duck Creek Bridge, a distance of seven miles from the spill location, and Duck Creek Bridge to Johnson Lane (12 miles). Reconnaissance and evaluation activities are under way in the second two zones, Johnson Lane to Miles City (144 miles) and Miles City to Glendive (78 miles).

Active clean up continues in the first two zones closest to the spill site. More than 48,000 feet of absorbent boom and 2,200 feet of containment boom and 2,300 absorbent pads are on site and being used to clean up oil adjacent to the river. Vacuum trucks and tankers have also been deployed to pick up and dispose of the oil.

As of this evening, we have received 94 calls to the community claims line. Of those, 36 were reports from landowners related to oil on their property. We continue to encourage individuals in the community who might have been impacted by this event to contact the claims hotline number (1-888-382-0043).

We are actively conducting reconnaissance in the second two zones. We are ready to deploy resources as needed to clean up oil that may be identified from the spill in these areas.

Daily aerial flights over the river are being undertaken to identify additional oil locations and monitor and direct cleanup activity. As part of our reconnaissance, we are also walking the parts of the shorelines where it is safe to do so.

Given the current flooding and very swift river currents, we will need to wait until it is safe to get into some areas. When we have determined that conditions are safe, we have eight boats staged at Coulson Park for deployment for reconnaissance and monitoring on the river.

We continue to monitor air quality and all previous reports have confirmed no danger to public health. The EPA has conducted water quality sampling and will publicize those findings when they receive the results. Municipal water systems are being notified to monitor water quality but no reports of impacts have been received to date.

Workers from the International Bird Rescue have arrived in Billings. The Montana Audubon Conservation Education Center and Yellowstone Valley Audubon have offered to provide wildlife recovery services and facilities. We have not received any confirmed reports of impacted wildlife but will continue to monitor the area.

Samson Oil & Gas to acquire additional Bakken acreage

Samson Oil & Gas Limited announced that it has agreed to acquire up to 90,000 net acres of oil and gas leases in the Fort Peck Indian Reservation in, Roosevelt County, Montana, from Fort Peck Energy Company LLC (FPEC) for an undisclosed price.

Samson’s new Roosevelt Project is being acquired in three tranches:
Tranche 1 is a 20,000 acre block to be acquired immediately upon closing that includes a two well drilling obligation. Tranche 2 is an option to acquire an additional 20,000 acres upon the completion of the initial two wells in Tranche 1. The location of Tranches 1 and 2 are shown in yellow marked “FPEC” on the map included with this news release. Tranche 3 is a 50,000 acre area covered by an Area of Mutual Interest where Samson and FPEC have agreed to jointly acquire additional leases.

Samson plans to fund its acquisition costs and the drilling of the initial two appraisal wells from its existing cash resources. While Samson’s ultimate ownership interest in the three Tranches will vary, depending on FPEC’s future decisions whether to back in to an interest in the acquired acreage, Samson will hold at least a 66.66% working interest (53.34% net revenue interest) in all of the acquired acreage.

The Roosevelt Project is located in a technically attractive, but largely undrilled part of the Williston Basin. After exhaustive study, Samson’s technical staff has concluded that the area is part of the Bakken continuous oil accumulation with adequate porosity and oil saturation for commercial production. Samson is not alone in reaching such a conclusion as the acreage block is surrounded by leases held by other well-known energy industry participants.

The initial two well drilling program will be initiated as soon as practicable, with a target spud date of September 1st for the first well. Drilling of the second well would be expected immediately following the completion of the first well. Both wells are planned to be drilled as 4,500 foot laterals in the middle Bakken formation and then fracture stimulated using a multi stage, external casing packer completion technique.

Samson has contracted with Halliburton’s (NYSE: HAL) Consulting and Project Management business line to provide well construction planning, and drilling and completion supervision for the initial two wells. This agreement builds on the existing relationship with Halliburton developed through Samson’s Hawk Springs project and brings the considerable expertise of the largest service provider of fracture stimulation completions to Samson’s new Roosevelt Project.

FPEC is owned by Native American Resource Partners (NARP) and the Assiniboine and Sioux Tribes. NARP, a portfolio company of the private equity fund Quantum Energy Partners, has substantial experience in energy transactions with Indian Nations. While Samson is not part of FPEC or NARP, the importance of having both of these Fort Peck Tribes as equity partners, albeit indirectly, was an important part of Samson’s decision to invest in the Roosevelt Project.

The ownership information in the map was developed from public sources and, while Samson believes it to be substantially accurate, neither Samson nor FPEC can guarantee that it is complete or up to date, as subsequent or unrecorded transactions could result in substantial modifications.

Samson’s Ordinary Shares are traded on the Australian Securities Exchange under the symbol "SSN". Samson's American Depository Shares (ADSs) are traded on the New York Stock Exchange AMEX under the symbol "SSN". Each ADS represents 20 fully paid Ordinary Shares of Samson. Samson has a total of 1,996 million ordinary shares issued and outstanding (including 269 million options exercisable at AUD 1.5 cents), which would be the equivalent of 99.8 million ADSs. Accordingly, based on the NYSE AMEX closing price of US$2.68 per ADS on June 23rd, 2011 the company has a current market capitalization of approximately US$262 million. Correspondingly, based on the ASX closing price of A$0.125 on June 23rd, 2011, the company has a current market capitalization of A$245 million. The options have been valued at their closing price of A$0.11 on June 22nd, 2011 and translated to US$ at the current exchange of 1.05 for the purposes of inclusion in the US$ market capitalization calculation.

Canacol Energy begins heavy oil exploration drilling program in Colombia

Canacol Energy Ltd. Has announced the start of its heavy oil exploration drilling program on its Tamarin and Cedrela Exploration and Production contracts located in the Caguan - Putumayo Basin in Colombia. The Corporation has 100% working interest and is operator of both contracts, which represent approximately 388,000 net acres. The Corporation plans to drill two stratigraphic wells, one on each of the Tamarin and Cedrela contracts, in a back to back drilling campaign that will commence in mid July 2011. This will be followed by the drilling of five conventional exploration wells, the first to start in late Q3 2011, and the last to end midyear 2012.

Charle Gamba, President and CEO of the Corporation, commented "The stratigraphic wells will target two large structures recently defined by the new 2D seismic acquired on the Tamarin and Cedrela blocks. These wells, which can be drilled relatively inexpensively compared to conventional exploration wells, have the potential to yield useful information concerning the presence and type of oil, as well as basic reservoir thickness and quality information, in advance of the conventional exploration drilling program the Corporation plans to start in late Q3 2011. Since the discovery of the Capella heavy oil field by Canacol and its partner in 2008, the Corporation has been able to leverage its proprietary knowledge of the geology and potential of the area. The Corporation is now positioned to execute a significant heavy oil exploration program in this emerging heavy oil play in Colombia."

Tamarin ESTR-1 Stratigraphic Well

The Tamarin ESTR-1 well is planned to be drilled to a depth of 3,260 feet measured depth ("ft md") and will target potential heavy oil bearing reservoirs in the Mirador sandstones, the main producing sandstones in the Corporation's Capella heavy oil field. The Corporation has a 100% working interest and is operator of the Tamarin contract, which represents 68,000 net acres and is located on trend approximately 25 kilometers to the southwest of the Capella heavy oil field.

The Corporation has executed a contract with LT Geoperaciones y Mineria Ltda., a service company that will provide the drilling rig. The Corporation anticipates that the well will take approximately 8 weeks to drill, core, and log. The information that the Corporation anticipates to collect include cores through the prospective reservoir intervals and a full suite of conventional openhole wireline logs. This data will yield information concerning the thickness, porosity, permeability, and fluid content of any prospective reservoir intervals that may be encountered within the well. Given the small size of the wellbore, the Corporation will be unable to flow test any of the prospective reservoirs.

The Corporation is currently constructing the surface location and anticipates that the Tamarin ESTR-1 will commence drilling in mid July 2011.

Cedrela ESTR-1 Stratigraphic Well

The Cedrela ESTR-1 well is planned to be drilled to a depth of 2,600 feet measured depth ("ft md") and will also target potential heavy oil bearing reservoirs in the Mirador sandstones, the main producing sandstones in the Corporation's Capella heavy oil field. The Corporation has a 100% working interest and is operator of the Cedrela contract, which represents 320,000 net acres and is located on trend approximately 50 kilometers to the southwest of the Capella heavy oil field.

The Corporation anticipates spudding the Cedrela ESTR-1 stratigraphic well after the drilling of the Tamarin ESTR-1 well has been completed. The Corporation anticipates that the Cedrela ESTR-1 well will take approximately 8 weeks to drill, core, and log. The same information that the Corporation plans to collect in the Tamarin ESTR-1 well will also be collected in the Cedrela ESTR-1 well.

Solimar has 33 million bbl target in drilling Paloma field appraisal well

Solimar Energy Limited has announced that the Nabors Rig # 710 has been contracted to drill the Paloma Deep - 1 well and is expected onsite in late July. Commencement of drilling is likely 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 1930’s. 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 Paloma Deep -1 will be the first appraisal well drilled on the field using 3D to help identify favourable reservoir trends within the field closure.

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 OPI 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.

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 farmin with Neon. The increased position will either be a minimum 17.5% with 25% targeted and pending closure of arrangements with a third party. Once the level of increase has been finalised this will be confirmed via a further announcement by the Company.

The increased position in the project will be subject 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. 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.