Vanoil Wraps Up Seismic Program in Kenya Block

- Vanoil Wraps Up Seismic Program in Kenya Block

Tuesday, September 13, 2011
Vanoil Energy Ltd.

Vanoil has completed its 2011 2D seismic program on Block 3B in Kenya. Vanoil's 100% owned Blocks 3A and 3B in Kenya cover approximately 24,000 square kilometers and are part of the vastly under-explored prolific Cretaceous Central African Rift Basin System in Kenya.

Vanoil's 2011 seismic program in Block 3B covered approximately 398 line-km and was completed on budget and schedule. The program was designed to cover several leads previously identified on the re-processed 1975 Chevron and the 2010 Vanoil seismic data in Block 3B. The 2011 seismic data is high quality with location, time and amplitude content having been jointly assessed and controlled by the contractors; Bureau Geophysical Prospecting (BGP) and RPS. This premium data has been gathered to further image some specific structural leads and as a reconnaissance program to identify more new leads in Block 3B. In addition, the 2011 seismic program was also designed to enable Vanoil to improve on the geologic model in the Lamu Basin, one of the three basins identified on the Vanoil Blocks.

The 2011 2D seismic program in Block 3B consisted of 398 kilometers of additional seismic bringing the cumulative total to 845 kilometers of 2D seismic coverage completed by Vanoil to date on Blocks 3A and 3B in 2010/2011.

The 2011 Vanoil 2D seismic program data will now be sent to Statcom in Calgary Alberta for processing, following which, the data will be interpreted and integrated with the reprocessed and interpreted 1975 Chevron and 2010 Vanoil data. With the newly acquired data, the Company expects to add significantly to the resource assessment incorporated in the previously announced Sproule 51 101 report.

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Halliburton Wraps Up 1st HZ Shale Well in Argentina for Apache

- Halliburton Wraps Up 1st HZ Shale Well in Argentina for Apache

Thursday, August 18, 2011
Halliburton Co.

Halliburton has successfully executed the first horizontal, multistage hydraulic fracture shale gas completion in Argentina's Neuquén Basin for Apache. Halliburton provided all major well construction and completion services for the project, resulting in the successful delivery of South America's first horizontal and deepest shale gas well.

As global development of unconventional resources materialize, Halliburton is in the process of pre-positioning Unconventional Reservoir Solutions Teams around the world. These teams draw upon the extensive knowledge and experience garnered from Halliburton's unrivalled position in North America's unconventional reservoir development. Halliburton, chosen by Apache because of its Buenos Aires-based Unconventional Reservoir Solutions Team's expertise and understanding of the specific complexities of the Los Molles shale formation, placed 10 hydraulic fracture stages in the horizontal section at a depth of over 4,400 meters.

"Halliburton's ability to apply its expertise globally will assist operators to efficiently develop frontier unconventional reservoirs," said Roberto Munoz, vice president, Latin America Region, Halliburton. "With the third largest estimated unconventional reserves after China and the United States, Argentina's shale gas potential will benefit greatly from the application of these technologies."

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Statoil Wraps Up First Phase at Gudrun Platform

- Statoil Wraps Up First Phase at Gudrun Platform

Wednesday, August 03, 2011
Statoil

The steel support structure for the Gudrun platform is now in place on the North Sea field, completing the first phase of the extensive installation work being carried out there.

"The entire operation has been carried out according to plan and in a secure manner," reported Anders Opedal, senior vice president for projects in Statoil's Technology, Projects and Drilling business area.

"We've passed an important milestone for coming on stream at the right time and to budget. With the jacket solidly positioned on the seabed, we'll be able to start drilling in the fourth quarter as planned."

Installation of the steel structure began on July 24, and the job of attaching it to the seabed was completed on August 2 when the last of 12 60-meter piles was driven home.

Saipem 7000, the world's second-largest crane vessel, has been used to carry out the installation work on Gudrun.

Weighing some 7,000 tonnes all told, the traditional jacket comprises two main structures of almost 2,300 tonnes each, tied together by six horizontal frames and various bracings.

Important contribution

"Gudrun is the first of a number of new installations in an area of the Norwegian North Sea which is both highly interesting and mature," observes Ivar Aasheim, senior vice president for field development in the Development and Production Norway business area.

"By exploiting existing infrastructure for processing and transport, we're ensuring production from new fields. Gudrun will also make an important contribution to maintaining high production levels going forward."

The next development milestone is the start of pre-drilling production wells on the field. These will be tied back to the platform for partial processing and oil and gas export.

Final processing of Gudrun's output will take place on Sleipner A, with the gas piped to the adjacent Sleipner T platform for carbon dioxide removal.

In addition, electricity to operate the Gudrun installation once it comes on stream in two years' time will be supplied from Sleipner A.

Gudrun ranks as one of Statoil's largest development projects on the Norwegian continental shelf, and contains some 127 million barrels of oil equivalent.

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Providence Wraps Up Seismic Acquisition Offshore Ireland

- Providence Wraps Up Seismic Acquisition Offshore Ireland

Monday, July 04, 2011
Providence Resources plc

Providence has, on behalf of itself and its partners, successfully completed the 3D seismic acquisition project over the Barryroe oil discovery ("Barryroe") in the North Celtic Sea, offshore Ireland. The partners believe that modern 3D seismic data, in tandem with modern well completions in the current high oil price environment, will be key components to unlocking value at Barryroe. This survey forms part of the planned pre-development drilling program on the Barryroe, where drilling is scheduled to commence in September utilizing the already contracted semi-submersible rig, the GSF ARCTIC III.

Providence operates Barryroe (50%) with partners San Leon Energy (30%) and Lansdowne Oil & Gas (20%).

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Spectrum Wraps Up Reprocessing at Adriatic Proj.

- Spectrum Wraps Up Reprocessing at Adriatic Proj.

Tuesday, June 21, 2011
Spectrum

Spectrum has completed the reprocessing of approximately 9,000 km of regional 2D seismic data from the Italian sector of the Adriatic Sea on a Multi-Client basis. The original surveys were acquired by the Italian government as part of a study to highlight the hydrocarbon potential of the Adriatic Sea.

The majority of production in the region is from Pliocene age gas fields, many of which have multi-TCF reserves. However, the deeper potential of the Adriatic has yet to be fully explored and this reprocessed data library, which shows many un-drilled structures, should lead to a greater understanding of the hydrocarbon potential within the Adriatic Sea.

The reprocessing was carried out in Spectrum's state-of-the-art processing center. The data is now available and it has already triggered significant industry interest through the direct hydrocarbon indicators highlighted.

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Dragon Oil Wraps Up Ops at Dzheitune Well

- Dragon Oil Wraps Up Ops at Dzheitune Well

Friday, June 17, 2011
Dragon Oil plc

Dragon Oil announced the completion and initial testing of the Dzheitune (Lam) 28/156 development well. The Dzheitune (Lam) 28/156 well reached a depth of 2,000 meters and was completed as a single producer by the NIS rig. The initial test result from the well was 3,038 barrels of oil per day ("bopd"). The NIS rig has skidded to the next slot to spud the Dzheitune (Lam) 28/158 well shortly. The Iran Khazar rig is currently drilling the Dzheitune (Lam) B/157 well.

Dr. Abdul Jaleel Al Khalifa, Chief Executive Officer, commented, "I am pleased to report the successful completion and initial testing of the Dzheitune (Lam) 28/156 development well, the fifth well to have been completed within the 2011 drilling program. We continue to optimize well locations to ensure good potential while accessing different areas of the reservoir."

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Ithaca Wraps Up Ops at Athena Field

- Ithaca Wraps Up Ops at Athena Field

Monday, June 06, 2011
Ithaca Energy Inc.

Ithaca announced the final production well on the Athena field has been drilled and fully cased. The well encountered a considerable section of oil saturated net reservoir, with good porosities. Development drilling has now been successfully concluded and the project remains on schedule for production start up in 4Q 2011 at approximately 22,000 barrels of oil per day ("bopd") (gross), approx. 5,000
bopd (net to Ithaca), in-line with previous disclosure.

Athena field development well 14/18b-A2Z ("the Well") intersected 515 feet (measured depth) of net reservoir in the sub horizontal section of the well bore which was drilled to a total measured depth of 15,497 feet. The drilling rig, Sedco 704, is now proceeding to run completion equipment and perforate the Well, the three existing suspended production wells and the water injection well.

The Well was directionally drilled to the northwest of the Athena field where it encountered the principal reservoir section, the Scapa A reservoir, at 11,967 feet (measured depth), 8,851 feet (true vertical depth subsea), in line with prognosis. Electric logs acquired across the entire reservoir section of interbedded Scapa age sandstones and shales confirmed a series of reservoir sands with porosities up to 20%. Two of the thickest, high porosity sandstone units were encountered close to the top of the reservoir section and Management anticipates that these will contribute to strong flow rates when the Well comes into production. A production liner has been run across the reservoir section.

The ongoing modification and recertification work on the Floating Production, Storage and Offloading ("FPSO") vessel, 'BW Athena' (currently in dry dock in Dubai) is well advanced. The vessel has been successfully separated for installation of a turret docking section which is currently being welded into the structure amidships. The vessel will be extended by approximately 65 feet. The FPSO will return to UK waters for 'hook up' to the turret mooring buoy by the end of 3Q 2011.

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Buccaneer Wraps Up Ops at Kenai Loop Proj.

- Buccaneer Wraps Up Ops at Kenai Loop Proj.

Wednesday, June 01, 2011
Buccaneer Energy Ltd.

Buccaneer provided the following final flow testing results from its 100% owned Kenai Loop # 1 well.

Highlights

• Successfully completed 4 point flow test for 2 zones totaling 87';
• Absolute Open Flow Potential (AOFP) calculated as 33.2 million cubic feet per day (4,150 BOEPD)
• Long term production rate targeted at 6 - 8 MMCFD (750 - 1000 BOEPD)1; from 87' gross pay tested;
• Net revenue of US $1.05 million per month at 7.0 MMCFD, US $12.6 million per annum;
• 14 zones (423' gross pay) remain to be tested.

A flow test over 4 different choke sizes, a 4 point test, has been successfully completed. This test includes the measurement of pressures which allows for the calculation of the AOFP. The AOFP estimates the well's flow rate without a choke.

The AOFP was calculated as 33.2 million cubic feet per day (MMCFD) which is significantly higher than the expectations. The high AOFP demonstrates the excellent permeability and porosity of the 2 zones perforated and tested.

The long term deliverable production rate from the well has been estimated as 6 - 8 MMCFD (750 - 1000 BOEPD). This steady deliverable production rate is anticipated for approximately 2 years and will facilitate a favorable gas sales contract.

Based on the average production rate of 7.0 MMCFD and the expected floor price of gas in south central Alaska of US $7.00 / MCF this would result in net revenue to the Company of approximately US $1.05 million per month (US $12.6 million per annum). The gas price in
recent contracts has a floor of US $7.00 / MCF and cap of US $10.00 / MCF.

Net revenue is after all royalties, production taxes and expected normal operational costs and amount to ~US $2.00 / MCF. Fixed royalties account for approximately 65% of these costs. An upside potential exists in the area from the remaining 14 zones (423' of gross pay) that have not yet been tested. Buccaneer's contiguous block in the area is in excess of 8,900 acres. An internal estimate of recoverable reserves is currently being finalized after which the Company will engage a third party engineer to complete a reserve report.

Kenai Loop Development Program

The Company is in the process of finalizing a development program for the Kenai Loop project which will include:

• Drilling Kenai Loop # 2 well;
• Commencement of production;
• Acquisition of new seismic; and
• Additional drilling beyond Kenai Loop # 2 well.

Kenai Loop # 1 Previous Results

In the initial phase of the testing program, the Kenai Loop # 1 has successfully tested gas to the surface at a rate of 10 million cubic feet per day on a 20/64" choke with a FTP (flowing tubing pressure) of 3,495 psi.

The Company has up to 16 zones totaling 510' of gross pay identified by logs as test candidates in the Beluga and Upper Tyonek Formations. As the rig needed to be released back to Marathon on June 1, 2011, 2 of the 3 high graded zones in the Upper Tyonek
Formation were chosen to be perforated and tested.

The 2 zones total 87' of gross pay were described as follows:

Zone 1 has an upper sand of 37' of gross pay which logs have confirmed as being quality reservoir with high porosity and good permeability. This upper sand package had a "gas kick" during drilling operations. There is an additional 12' of lower sand which is a lesser quality sand, but remains attractive. Only the upper portion of this zone is included in the testing program.

Zone 2 is an additional massive sandstone zone of approximately 50' of gross pay which logs indicate has good porosity and permeability.

Depending on rig availability a second well is planned for the third quarter 2011. The Company is in the progress of formulating a development program for the field, including a production schedule, beyond the initially anticipated 2-3 wells.

Background

The closest wells to the Company's Kenai Loop # 1 well are the Cannery Loop #3 and #4 wells located in the Cannery Loop Field, which were drilled from the same surface location approximately 6,325 feet (1.2 miles) from the Kenai Loop # 1 well location. The Cannery Loop # 3 and # 4 wells have produced a combined 25.5 BCF (3.18 MMBOE) from pay zones whose equivalents are expected to be present in the Kenai Loop # 1 well, but separated from the Cannery Loop Field by geological deposition rather than fault. Drilling to date in the Kenai Loop # 1 well has confirmed that the formations encountered to date are likely separated from the Field.

There were 11 wells in the adjacent Cannery Loop Field which produced 175 BCF (21.9 MMBOE) One well produced from the Sterling Formation which is not one a target in Kenai Loop # 1 well, the other 10 wells produced from the Beluga and Upper Tyonek. The Upper
Tyonek is the primary target Formation of the Kenai Loop #1 well.

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ATP Wraps Up Ops at Telemark Hub

- ATP Wraps Up Ops at Telemark Hub

Thursday, May 26, 2011
ATP O&G Corp.

ATP has completed the drilling phase of deepwater Mississippi Canyon Block 941 A-2 well located at ATP's Telemark Hub, and all pay sands in the MC 941 A-1 well were present essentially confirming pre-drill estimates. The main pay sands are approximately 500 feet structurally higher than the MC 941 A-1 well and 1000 feet above the original oil-water contact. Plans are to run casing to total depth, install temporary barriers in the well permitting removal of the drilling riser and installation of the production riser. Tie-back of the production casing to the surface and perforating and completing the initial production zones will follow. Installation of production tubing and a subsea tree will be performed prior to testing and initialization of production. First production from this well is expected in the early part of the third quarter.

ATP was the first Gulf of Mexico operator to begin drilling in the deepwater after the BOEMRE began issuing permits though the company received the third permit issued on March 18, 2011. ATP is also first to successfully achieve its drilling objective since the moratorium was lifted and of the initial ten permits issued, ATP was the only entity to receive two of the permits, demonstrative of the confidence government regulators have in the company.

T. Paul Bulmahn, Chairman and CEO stated, "Our preparedness enabled us to swiftly assemble a crew and commence testing the BOP stack within 36 hours of obtaining the permit. We look forward to production from this well during the third quarter through the state-of-the-art ATP Titan facility."

ATP operates the deepwater Telemark Hub with a 100% working interest and owns 100% of the subsidiary that owns the ATP Titan and associated pipelines and infrastructure.

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Surge Wraps Up Ops at Valhalla Well

- Surge Wraps Up Ops at Valhalla Well

Monday, May 16, 2011
Surge Energy Inc.

Surge provided the results of its third horizontal multi-frac well at Valhalla South and to announce the closing of its previously announced light oil asset acquisition in North Dakota. Surge also announced that it has syndicated its bank facility and increased its bank line from $90 million to $120 million.

Operations Update at Valhalla South

Surge's third horizontal well (14-19-74-8W6M, 53.5 percent working interest "WI") in the Valhalla South Doig light oil pool (40 degree API) has been successfully drilled and completed. The well encountered approximately 1,000 meters of Doig Formation and was completed with ten frac stages averaging approximately 30 Tonnes of proppant per frac. A five day flow test on the well has been recently completed, resulting in flow rates averaging 1,450 boe/d (77 percent light oil and NGLs) with the last day of the test flowing at a rate of 1,225 boe/d ( 77 percent light oil and NGLs). The well produced through the 114mm (4.5") tie back liner which is currently being replaced with a more optimum production string of 89 mm (3 1/2") tubing.

This very encouraging result compares very favourably to the previously disclosed flow test on Surge's second horizontal well at 2-7-74-8W6M (100 percent WI) which averaged 945 boe/d (85 percent light oil and NGLs) over a similar five day flow period, with the fifth day flowing at 835 boe/d (79 percent light oil and NGLs). The 2-7 well has since been flowing for more than a month with a first month average rate of 635 boe/d (80 percent light oil and NGLs). The last day of the first month, the well flowed at 615 boe/d (80 percent light oil and NGLs).

Surge has identified at least 22 gross (15.8 net) more horizontal multi-frac locations to drill into the pool and has budgeted to drill, complete and tie-in at least three more wells this year. Drilling of the next well is scheduled to spud later this month.
In addition, Surge has now completed operations on the re-fracing of four of the 22 original vertical wells in the Doig pool. The first four were selected in order to sample and evaluate a representative cross section of the re-frac opportunities that the team initially envisioned. Two of the wells have now produced for over one month free of frac fluid and have far exceeded the team's initial expectations. In the first month, the two wells averaged a combined rate of 350 boe/d (50 percent light oil and NGLs) versus a combined pre re-frac rate of 50 boe/d. The other two wells are recovering re-frac load fluid and the team ultimately expects to see production improvements from these wells. A total of $1.4 million was spent on the program which has resulted in first month average incremental production additions of 300 boe/d ($4,700/boe/d production efficiency). With the results of the first four wells known, the team now views half of the remaining 18 vertical Doig wells as attractive re-frac candidates. The costs of these re-fracs are forecasted to be approximately $300,000 per well. These opportunities will be blended in with the future drilling and muti-frac operations in the Doig light oil pool. Surge is also evaluating plans for a secondary recovery pilot program in the area.

In addition to its operations at Valhalla South, Surge has budgeted four more Bluesky light oil wells at Windfall and ten more light oil Spearfish wells planned at Waskada to achieve its 2011 exit production estimate of 7,500 boe/d (greater than 70 percent light/medium oil & NGLs).

Closing of the Second Light Oil Asset Acquisition in North Dakota

Surge is pleased to announce that it has closed its second light oil asset acquisition in North Dakota. As previously disclosed, the first light oil asset acquisition in North Dakota closed on March 31, 2011. The assets from both acquisitions were acquired by Surge Energy USA Inc., a wholly owned subsidiary of Surge Energy Inc.
Through the two acquisitions, Surge acquired 100 bbl/d (2010 exit rate) of high quality, high netback, light oil production, 6,000 net acres of highly prospective land in the Spearfish light oil resource play and greater than 100,000 acres of high working interest, undeveloped land for total consideration of $21.5 million in cash. The acquisitions added an internally estimated 205 gross (120 net) horizontal Spearfish drilling locations and approximately 126 mmbbls gross DPIIP1. Surge now has approximately 329 gross (231 net) horizontal Spearfish drilling locations in southwest Manitoba and North Dakota and greater than 460 gross (350 net) oil drilling locations in the Company.

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Breitling Wraps Up Ops at Ok. Well

Breitling Wraps Up Ops at Ok. Well

Tuesday, April 26, 2011
Breitling O&G Corp.

Breitling O&G announced that the Breitling-Yardeka #1, the first well in its new Arkoma Basin gas field in McIntosh County, Oklahoma, is being completed as a possible natural gas producer after reaching a total vertical depth of 3,500 feet.

From log analysis, the well encountered several potentially productive zones over a gross interval in the Jefferson Sand from 3380 feet to 3390 feet; the Upper Gilcrease Sand from 2246 feet to 2378 feet; the Lower Gilcrease Sand from 2868 feet to 2870 feet; and the Cromwell Sand from 3227 feet to 3236 feet. Testing and completion plans were finalized April 21 and a completion rig and crew moved into location April 25. Natural gas pipeline tie-in is slated for the week of May 16.

Chris Faulkner, CEO of Breitling Oil and Gas, said, "We are excited about developing this shallow gas field." Faulkner added, "We have good serendipity even though we are only drilling to 3500 feet."

Breitling ran a density-neutron log, microlog and an induction log and decided to run pipe based in analysis by Breitling's engineers and geologists. Joe Simo, Chief Geologist for Breitling Oil and Gas, said, "We had good gas shows on the way down and from the logs we have some good-looking formations in this well and hopefully throughout the field."

China North East Petroleum Wraps Up Shengyuan Acquisition

China North East Petroleum Wraps Up Shengyuan Acquisition

Monday, April 25, 2011
China North East Petroleum Holdings Ltd.

China North East Petroleum has completed its acquisition of Sunite Right Banner Shengyuan Oil and Gas Technology Development Co., Ltd. ("Shengyuan"). As a result of the Acquisition, Shengyuan is now a wholly-owned subsidiary of Songyuan. Pursuant to a 25 year lease signed in 2010, Shengyuan has exclusive oilfield exploration and drilling rights to the Durimu oilfield in Inner Mongolia.

As is common among all private, independently-owned and operated oil companies in China, NEP does not directly own its oil fields in China and is only allowed to obtain exploration and drilling rights from qualified state-owned-enterprises ("SOE's"). The Durimu oilfield belongs to Yanchang Petroleum Group ("Yanchang"), the fourth largest SOE for oil and gas exploration in China. Yanchang has assigned management over oil exploration and production activities in the Durimu oilfield to Sunite Right Banner Jianyuan Mining Co. Ltd. ("Jianyuan"), a local SOE. In turn, Jianyuan has entered into an agreement with Shengyuan, granting Shengyuan exclusive oilfield exploration and drilling rights in the Durimu oilfield (the "Lease"). Yanchang has qualified Shengyuan to operate in the Durimu oilfield subject to the supervision of Jianyuan. The Company will benefit from the 24 years remaining under the Lease and Shengyuan has the first right of refusal to renew the Lease at the end of its term.

Ralph E. Davis, an independent worldwide petroleum consultant based in Houston, Texas, conducted a proven reserve study of the portion of the Durimu oilfield subject to the Lease in accordance with generally accepted petroleum engineering and evaluation principles and in conformity with SEC definitions and guidelines. The Ralph E. Davis study was based on the performance of the three existing exploration wells. The Ralph E. Davis study estimated total proven reserves ("total P1") in the Durimu oilfield at 1.54MM Barrels and the PV10 at approximately $46.4MM. The PV10 includes the estimated future gross revenue to be generated from the production of the proven reserves, net of estimated production and development costs, and with an annual discount rate of 10%. The PV10 also excludes the 25% royalty to the SOE.

According to a geological study conducted by PetroChina's North Center Branch Exploration and Development Research Institute, the Durimu oilfield has geological reserves of 77.5MM tons (approximately 573.5MM barrels), and a recoverable reserve of approximately 19.38MM tons (approximately 143.4MM barrels). PRC geologists have also suggested that the optimal number of wells that can be drilled in the Durimu oilfield is in excess of 2,000.

Pursuant to the terms of the Share Transfer Agreement and the Share Issuance Agreement, the final acquisition price is approximately $43.4 million payable in cash and shares of the Company's common stock. No later than May 16th ("or within the next 15 business days"), the Company's subsidiary Songyuan Yu Qiao Oil and Gas Development Co., Ltd. will pay the former Shengyuan shareholders RMB70 million (approximately US$10.6 million) in cash. In addition, the Company will issue to Bellini 5.8 million shares of the Company's restricted Common Stock (the "Acquisition Shares"), which carries a value of $32.8 million based on the 30 day trading average from December 6, 2010-January 7, 2011. The cash portion of the purchase price will be paid utilizing cash on hand. In addition, Bellini has entered into a lock-up agreement pursuant to which Bellini is prohibited from disposing of any Acquisition Shares for a period of six months after the closing date of the Acquisition and is prohibited from disposing of 50% of the Acquisition Shares for a period of 12 months after the closing date of the Acquisition.

Mr. Jingfu Li, CEO of China North East Petroleum commented, "This acquisition will allow NEP to expand its operations and secure additional oil reserves that can provide better overall returns on our investment. The Durimu oilfield is nearly three times larger than the four oilfields we currently lease in PetroChina's Jilin oilfield with much larger oil extraction and drilling opportunities. We have the knowledge and experience to scale production in the Durimu oilfield aggressively in the coming years and further establish NEP as a major independent, regional oil producing and oilfield services company in China."

Additional Acquisition Details

According to the terms of the Lease, Shengyuan is entitled to 75% of all production revenue while 25% is allocated to Yanchang. Shengyuan will only be subject to income tax on its 75% portion of the oil production revenue. All oil produced by Shengyuan is required to be sold to refineries/buyers already qualified by Yanchang.

Over time, the Company intends to shift the focus of its oil production segment from its four fields within the Jilin oilfield to the Durimu oilfield. The Company has already issued requests for bids from qualified independent geological consulting firms in China for the preparation of the survey plan and seismic test program for the Durimu oilfield. The Company expects to complete the bidding process and select the winning firm by the end of the second quarter, and to begin seismic testing by the beginning of July. After seismic testing begins, the Company expects the initial survey results to be completed within 30 working days. The Company's in-house engineering team will then work with the geological consulting firm to develop a preliminary production plan. The Company expects initial test drilling to commence by the end of the third quarter.

The Company currently plans to utilize two or three drilling rigs that belong to its subsidiary Song Yuan Tiancheng Drilling Engineering Co., Ltd. ("Tiancheng") to conduct the initial test drilling. The Company intends to charge Shengyuan for such drilling services at market rates. This initial stage is expected to last approximately 12-18 months, and during such period, any oil produced will be sold to qualified buyers which will generate revenue and cash flow to support the Durimu oilfield exploration program. After this initial stage is complete, the Company intends to begin drilling in Durimu with an expected overall increase in production, which will in turn generate greater revenues and more stable cash flows. The Company believes its activities in the Durimu oilfield will not affect current production levels and operating cash flow from the Company's four existing Jilin oilfields.

Breitling Wraps Up Ops at Tx. Well

Breitling Wraps Up Ops at Tx. Well

Wednesday, April 06, 2011
Breitling O&G Corp.

Breitling announced that the Breitling-Turner #1 in Hardeman County, Texas is being completed as a possible oil and gas producer after reaching a total vertical depth of 7,900 feet.

The well was subsequently logged by Halliburton and based on analysis by Breitling's engineers and geologists as well as Halliburton's analysis of the Turner #1 logs. Chris Faulkner, CEO of Breitling Oil and Gas, said, "We have a couple of good-looking zones in this well and both had good porosity and permeability, and we look forward to another successful completion."