Entek Flows Rates of 9.5 MMcfd at GA A133 Discovery

- Entek Flows Rates of 9.5 MMcfd at GA A133 Discovery

Tuesday, August 16, 2011
Entek Energy Ltd.

Entek announced the development of its GA A133 gas discovery, made in 2010, has been completed and gas is flowing at the planned 9.5 MMcfd on restriction. At current gas prices this should net Entek around US $250,000 per month. Entek has a 38% working interest in the block which is operated by Peregrine Oil & Gas II, LLC.

The GA A133 block has gross reserves of approximately 10 BCF associated with the recent discovery, with additional reserves linked to previous gas discovered on the block to be targeted at a later date.

Due to proximity to analogue production the GA A133 discovery well was not tested. This is common practice in the Gulf of Mexico where numerous existing producing analogues give a high level of confidence. The well is performing as predicted based on wireline log interpretation and correlation with offset analogue production.

For the same reason the Company did not flow test its recent oil discovery in VR 342. In this case analogue studies based on numerous existing producing analogues (performed independently on Entek's request) suggest potential flow rates of 500-1000 BOPD with minimal decline for the first 3-4 years.

Development planning is currently underway for the VR 342 oil discovery based on the flow rates described above and the independently certified gross reserves of circa 7.5 MMBO (1P 2.5 MMbo; 2P 4.8 MMbo; 3P 7.5 MMbo) and 9.5 Bcfg (1P 3.8 Bcfg; 2P 6.3 Bcfg; 3P 9.5 Bcfg) or 9.1 MMboe.

Additional wells are expected to be drilled in first half of 2012. First oil production is anticipated in 3Q 2012. Entek has 50% working interest in the VR 342 block.

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Leighton Olmos Flows O&G at Peeler Well

- Leighton Olmos Flows O&G at Peeler Well

Monday, August 15, 2011
Global Petroleum Ltd.

Texon has advised that the latest Leighton Olmos vertical production well, Peeler #3, has begun to flow oil and gas at the combined rate of 370 boepd from the Olmos reservoir (comprising 325 bopd and 268 mcfgpd). This is the ninth well targeting the Olmos reservoir in which Global has a 15% working interest (11.25% net revenue interest).

This is a good result as the closest three Olmos production wells, Peelers #1 and #2 and Tyler Ranch #5 tested at initial rates of 170 to 445 boepd.

The well will be connected for production to oil tanks and the gas pipeline in the next two weeks.

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Crown Point Flows Oil at Argentina Well

- Crown Point Flows Oil at Argentina Well

Thursday, August 11, 2011
Crown Point Ventures Ltd.

Crown Point has successfully completed EV 31 which is the fourth well of the 2011 drilling as a successful flowing oil well. To date this year, the Company has drilled, cased and completed four wells as successful oil wells at the El Valle field in the San Jorge Basin in Southern Argentina. Since commencing drilling operations at El Valle, the Company has drilled and completed ten wells with a 100% drilling and completion success rate.

The completion rig will be moving later this week to commence a work over operation on an EV 19 which was one of the first wells drilled by Crown Point at El Valle. Once that work over has been completed we expect to start completion operations on EV 27 which is currently drilling and is the fifth well of the current drilling program.

Completion Update: EV 31

Crown Point successfully completed a 4.0 meter thick section of the Canadon Seco formation in the EV 31 wellbore. This zone was perforated and fracture stimulated. The well during its evaluation period flowed oil through a 20 mm choke at a 24 hour extrapolated rate of 370 barrels per day of 100% oil.

Due to the excellent production test results obtained from the currently completed 4.0 meter Canadon Seco zone in EV 31, the Company has indefinitely deferred the completion of two additional highly prospective zones in the Canadon Seco.

Drilling Plans 2011-2012

This drilling program is part of a larger 20-25 well program to be conducted at El Valle over the next 24 months. Crown Point is planning to drill two to four more wells at El Valle prior to year end. At Canadon Ramirez the Company plans to drill 2-5 wells on its 100% interest exploitation concession over the next 12 months and one 50% interest well at Laguna de Piedra in the first or second quarter of 2012. At Cerro Los Leones Crown Point anticipates receiving the required environmental permits in the near term and plans to commence the shooting of the 3-D and 2-D programs shortly after receiving these permits. The completion and interpretation of the seismic program is expected to be followed by a 2-5 well 50% interest program in 2012.

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Gulfsands Flows Rate of 5516 bopd at Khurbet East Well

- Gulfsands Flows Rate of 5516 bopd at Khurbet East Well

Monday, August 08, 2011
Gulfsands Petroleum plc

Gulfsands provided an update on operations in Syria.

Flow Testing of Khurbet East 19H ("KHE-19H")

The Khurbet East 19H ("KHE-19H") well has achieved a flow rate of 5516 barrels of oil per day ("bopd") on production test with an oil gravity of approximately 26 degrees API, similar in quality to the oil produced in the central portion of the Khurbet East Field. This production rate was obtained during a 2 hour main flow period under a 48/64th inch choke size and with an average wellhead pressure of 132 psi and with no associated production of formation water. The choke size was subsequently reduced to 32/64th inch, after which the well was flowed for a further 3 hours at an average rate of 3828 bopd, at an average wellhead pressure of 210 psi and with no production of water. The test was then terminated due to all available oil storage tank capacity being filled. The 67 meter horizontal productive section of this well is located in a sidetrack drilled in a south-southeasterly direction from the original KHE-19 vertical hole.

The oil flow rate of 5516 bopd from KHE-19H is the highest yet measured from any well within the Khurbet East field. This well has demonstrated that excellent reservoir quality exists from the central portion of the field all the way to the northern limit of the field.

Commissioning of Khurbet East Sub-station Production Facility

The oil processing capacity for the Khurbet East Field has been increased by approximately 3000 bopd after the construction and commissioning of a new oil processing sub-station ("EFP 2") with a design capacity of approximately 3000 bopd and located approximately 1.8 kilometers west of the Khurbet East Early Production Facility ("EPF"). At this new facility, gas is separated from the produced oil and the stabilized crude is pumped into storage tanks located within the EPF complex followed by subsequent delivery into the Khurbet East export pipeline. Well KHE-19H has been tied into the new sub-station and is estimated to be producing at a rate of more than 2900 bopd on a restricted choke.

As a result of these operational and construction activities, Block 26 oil production facility capacity is now more than 24,000 bopd. The reconciled production rate achieved at the expanded facilities as of 6th August, 2011 was 24,054 bopd, comfortably achieving and exceeding the Company's previously announced year-end 2011 production target of 24,000 bopd.

Block 26 Drilling Operations

Gulfsands drilling operations in Syria Block 26, using the Crosco E-401 and E-501 drilling rigs, are continuing as planned on the Yousefieh East and Safa exploration prospects. The results of these exploration drilling operations will be the subject of a future news release.

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Bowleven Flows Oil at Sapele-2 Offshore Cameroon

- Bowleven Flows Oil at Sapele-2 Offshore Cameroon

Monday, August 01, 2011
BowLeven plc

Bowleven announced the following update on activities on block MLHP-5, Etinde Permit, offshore Cameroon.

Highlights

• Sapele-2 testing program completed despite compromised well bore conditions and operational issues, with oil and gas produced from the Deep and Lower Omicron intervals
• Peak flow rate of 2,738 boepd, including high quality light oil, produced by DST 2 in the Deep Omicron interval
• Drilling results, comparisons with Sapele-1 and seismic interpretation infer a laterally extensive Deep Omicron system, allowing updates to our views of system volumetrics
• P90 unrisked in place estimates for Sapele Deep Omicron discovery area and Mean for Deep Omicron fairway assessed by Bowleven as 87 mmboe and 477 mmboe respectively
• Flowed gas condensate from Lower Omicron interval; operational issues curtailed testing
• P90 unrisked in place estimates for Sapele Lower Omicron discovery area and Mean for Lower Omicron fairway assessed by Bowleven as 14 mmboe and 203 mmboe respectively
• Further appraisal drilling will be carried out as part of the appraisal plan

Kevin Hart, Chief Executive of Bowleven plc, commented, "We are delighted to have now flowed oil on test from the Deep Omicron interval at both Sapele-1ST and Sapele-2 and to have achieved the first hydrocarbon flow from the Lower Omicron interval. Comparisons with Sapele-1 and seismic interpretation indicate that we have a laterally extensive Deep Omicron system. The Sapele discoveries provide a foundation to Bowleven's strategy of moving resources to reserves on block MLHP-5 and the preparation of an appraisal plan for the area is already underway. With extensive remaining potential yet to be targeted, Bowleven's strategy will also comprehensively embrace the exploration opportunities on the acreage and we now look forward to drilling Sapele-3."

Sapele-2 test update

The principal objective of Sapele-2 was to appraise both the Lower and Deep Omicron discoveries encountered in the Sapele-1 exploration well.

As previously announced, the Sapele-2 well encountered log evaluated net pay of approximately 19 meters and 16 meters within the Deep Omicron and Lower Omicron intervals respectively. The well was drilled to a TD of 3,749 meters in water depths of around 25 meters approximately five kilometers south west of the original Sapele-1 vertical well.

The results of the three drill stem tests (DSTs) performed at Sapele-2 are outlined below:

Deep Omicron

DST1

The basal sand situated on top of the cross-cut event, encountered at Sapele-1 and Sapele-1ST but not tested, flowed light oil on test at Sapele-2, the first hydrocarbon flow from this interval. A peak flow rate of 381 boepd, comprising 233 bopd of light oil and 0.89 mmscfd of associated gas on a 12/64 inch choke was produced. While no MDT data was acquired to confirm connectivity, all three wells have log evaluated net pay at this level and based on seismic correlation, the interval can be mapped between all three wells and over a wide area.

DST2

A peak rate of 2,738 boepd, comprising 1,818 bopd of light oil and 5.52 mmscfd of associated gas on a 32/64 inch choke was produced. Reservoir pressure was seen to re-charge over the period of the DST, inferring a wider hydraulic system. Based on initial log evaluation, lower productivity was encountered on test than anticipated, potentially due to formation damage sustained during drilling activities.

Light oil ranging from 39 to 42 degree API was produced from the two DSTs performed in the Deep Omicron interval. The Sapele-1 well had a confirmed oil pressure gradient at Deep Omicron and oil samples were obtained during logging activities. The oil quality, gas-oil ratio and pressures measured on test at Sapele-2 are comparable to the samples and pressures taken at Sapele-1. DST pressures, the log correlation between wells and seismic interpretation infer a laterally extensive Deep Omicron system. Pressure communication between Sapele-1 and Sapele-2 at an individual reservoir level cannot be confirmed given the inability to acquire MDT data due to borehole conditions.

Lower Omicron

DST3

The interval flowed gas at rates of up to 3.1 mmscfd, the first hydrocarbon flow from this interval, however testing operations were curtailed due to a pressure leak in the test string. Consequently, although liquids were present their flow rate was not recorded.

Forward plan

With the testing programme now concluded at Sapele-2, the Sapphire Driller rig is expected to move to the Sapele-3 location. A further announcement will be made on commencement of drilling operations at Sapele-3. The proposed location for Sapele-3, an exploration well with an appraisal component, has been selected, subject to attaining government approval. The well design on Sapele-3 has been optimised to take into account the pressure regimes encountered on the Block so far. Sapele-3 is targeting a prospect size of 50 million barrels. The joint venture partner, Vitol, has elected not to participate in the drilling of the Sapele-3 exploration well. Consequently Bowleven, as operator, has proposed drilling this well on a sole risk basis, as Sapele-3, which is designed to appraise the sands of the D1-R Discovery and explore the periphery of the Upper and Lower Omicron fairways, is a potentially significant well with material upside.

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Eni Flows First Oil from GOM Appaloosa Field

- Eni Flows First Oil from GOM Appaloosa Field

Wednesday, July 06, 2011
Eni S.p.A.

Eni has started oil production from the Appaloosa field, located in the US Gulf of Mexico deepwater, 60 miles offshore the Louisiana coast southwest of New Orleans, in 2500 feet (approximately 760 meters) of water depth.

The producing well is located within the MC 459 Federal Unit (comprising blocks MC 459, 460 and portions of MC 503 and 504). Eni holds a 100% working interest in the field.

Appaloosa production commenced on June 21, 2011 through a subsea development and a twenty-mile long flow line tied back to the Corral Platform (operated by Eni). The well is presently flowing at a rate of approximately 7,000 barrels of oil equivalent per day. This is the second Eni field producing on the Corral Platform, which in aggregate is now processing 46,600 gross barrels of oil equivalent per day (33,000 net to Eni).

This development, the second start-up this year for Eni in the US following the Nikaitchuq field start up in Alaska, further strengthens Eni's role as an operator and enhances Eni's position as one of the top producers in the Gulf of Mexico.

In the US, Eni owns lease interests in 333 blocks in the Gulf of Mexico and in 411 leases in the Barnett gas shales onshore Texas, in partnership with Quicksilver. In addition, Eni owns interests in 140 leases in Alaska, between offshore and the North Slope, where it is currently operating the Nikaitchuq oil project.

Eni's total daily net production in the US is in excess of 100,000 barrels of oil equivalent (60% of which is operated).

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TAG Flows Rates of 8.8 MMcf/d at Sidewinder-2

- TAG Flows Rates of 8.8 MMcf/d at Sidewinder-2

Thursday, June 23, 2011
TAG Oil Ltd.

TAG Oil reported that a 4-Point Isochronal flow test was completed over the main discovery zone in the Sidewinder-2 discovery well, which achieved stabilized flow rates of 8.8 million cubic feet per day (~1467 BOE per day) with less than a 25% drawdown.

The results from Sidewinder-2 further strengthen the already robust project economics, with anticipated full-time commercial production commencing upon completion of the new Sidewinder production facilities in a few months time. The Sidewinder-2 well is the fourth Sidewinder well that has been flow tested, all of which have achieved excellent flow rates, as summarized below:

Sidewinder Discovery Flow Test Results

Sidewinder Well	Gas Flow Rate (MMcfpd)	BOE Flow Rate (boepd)	Final Drawdown Rate	Net O&G Encountered
Sidewinder-1	7.40	1,233	28%	14 meters
Sidewinder-2	8.80	1,467	25%	47 meters
Sidewinder-3	7.21	1,202	40%	15.4 meters
Sidewinder-4	6.98	1,163	25%	19 meters
Totals	30.39 MMcfpd	5,065 Boepd

The Sidewinder-2 exploration well was drilled to a depth of 1,597 meters (5,238 feet), intersecting the main Sidewinder discovery zone, as well as four other separate oil-and-gas charged zones of interest totaling 47 meters (157 feet) of net pay. The interpreted pay zones are primarily within the Miocene-aged Mt. Messenger Formation; however oil shows were also encountered in the shallower Urenui Formation.

The Sidewinder oil and gas discoveries are located in TAG Oil's Petroleum Exploration Permit 38748 (TAG 100%) in the Taranaki Basin, New Zealand, with further exploration drilling in the lightly-explored area scheduled to recommence in September 2011. TAG will continue to target the widespread high-impact prospects identified in the Mt. Messenger Formation.

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Aminex Flows 8.1MMcf Per Day at Alta Loma

- Aminex Flows 8.1MMcf Per Day at Alta Loma

Friday, June 03, 2011
Aminex plc

Aminex provided a further update on progress at the Sunny Ernst-2 well ('SE-2') on its Alta Loma property, Galveston County, Texas.

Enhanced treatment facilities have now been successfully installed and other production facilities upgraded. Production is being increased gradually during pressure monitoring and is currently producing at 8.1 million cubic feet gas per day and 345 barrels condensate (1,695 Barrels oil equivalent) from the recently perforated 'S' sands formation, with no significant decline in pressure. Higher production rates should ultimately be achieved but the well is being prudently managed for the time being in compliance with Federal regulatory limits and current pipeline availability. Gas and condensate produced from SE-2 is sold to market at a premium respectively over posted gas prices and over the West Texas Intermediate marker price for crude oil in the USA.

Aminex USA, Inc. (a wholly-owned subsidiary of the Company) has a 37.5% interest in this well which is operated by El Paso E&P, LP. Several other parties share ownership of the remaining 37.5% of the property. Aminex's working interest share of production equates to approximately 636 barrels oil per day, of which 20% is condensate and 80% is gas.

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Kenai Loop Flows Rates of 10 MMcfpd

- Kenai Loop Flows Rates of 10 MMcfpd

Thursday, May 26, 2011
Buccaneer Energy Ltd.

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

Highlights

• Successfully tested gas at a rate of 10 million cubic feet per day (1,250 BOEPD)1 on a 20/64" choke;
• Only 2 zones totaling 87' of pay perforated and tested in the Upper Tyonek;
• An additional 14 zones totaling 423' of gross pay in the Upper Tyonek and Beluga Formations to be tested at a later date;
• Results to date exceed expectations;
• Testing ongoing with additional results to be released.

1 Gas to Oil Ratio of 8:1

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. Testing will continue to better predict long term deliverability.

Gas is being safely flared, smaller choke sizes were required causing some modifications to the testing program to limit the flare to approximately 100'.

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 must 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.

Both zones were perforated simultaneously and resulted in an immediate build up of pressure. The testing program will continue over the next 48 hours to complete a 4 point test which has just been initiated. Additional details of the testing results will be made available after detailed analysis of the bottom hole pressure measurements.

Although testing is not yet complete, calculated Absolute Open Flow Potential (AOFP) is expected to exceed expectations, based on testing thus far.

Once testing is complete, these two zones will be completed and will be the initial producing interval for this well.

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 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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First Gas Flows at Ascent's Slovenia Well

- First Gas Flows at Ascent's Slovenia Well

Tuesday, May 24, 2011
Ascent Resources plc

Ascent has flowed gas from an open-hole test of the Karpatian reservoir of the Pg-11A well and now continues drilling to the planned total depth of 3,500m. The Pg-11A well is positioned to become the first re-development well in the Petišovci Project in Slovenia where the Company has a 75% interest.

Following the re-commencement of operations on the Pg-11A in April 2011, the well was re-drilled to a depth of c. 3,000m where a 7" liner and tie-back string was successfully set and cemented immediately above the Karpatian reservoir. The top part of the sandstone reservoir was cored and the well deepened to expose approximately 50m of reservoir. An open hole test on this section produced and flared good quality hydrocarbon gas at a constrained rate of c. 2,500m3 per day (c. 90 Mscfd). On-site gas analysis indicated a better than expected carbon dioxide concentration of less than 1%. Gas samples and the core will now be analyzed and integrated with the extensive geological and engineering data already obtained from the well. While the preliminary results from the Karpatian reservoir are positive, the delineation of the full extent of the reservoir is the primary purpose for the extra 450m drilling to the planned total depth of 3,500m. Although the Karpatian may produce at commercial rates unstimulated, hydraulic fracturing maybe required or economically justified to optimize production rates.

With the high pressures and temperatures experienced in this well, drilling conditions were challenging and have led to some delays in the previous hole section.

Ascent's Managing Director, Jeremy Eng commented, "Operations are progressing steadily at our Petišovci Project in Slovenia and we are pleased that the first test on the Karpatian proved the presence of producible gas. The lower than expected carbon dioxide levels in the gas, if confirmed by laboratory analysis, will be advantageous as CO2 processing equipment may not be required in the early stages of the redevelopment."

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Reef Resources to Test Flows at Ausable Well

Reef Resources to Test Flows at Ausable Well

Tuesday, April 19, 2011
Reef Resources Ltd.

Reef Resources has agreed to complete and flow test the Ausable #5 well in SW Ontario, Canada.

A decision has been made to mechanically complete the well and to conduct flow tests on the basis of the existing data. Further analysis of electric logs and cores from the wells will continue.

Following production testing; the well will be connected to the existing central production facility and placed on production as an oil and natural gas liquids (NGL) producer. The Company's objective is to have the well on production within the next four to six weeks.

Due to the presence of extensive oil and natural gas liquids pay zones in the Ausable #5 well, the Company will now begin detailed scheduling for the drilling of the Ausable #6, #7, #8 and #9 wells and the expansion of the Ausable production facility. Currently it is hoped to complete this additional work by the end of 2011.

The Company will issue additional status reports during the testing and completion of Ausable #5 and as plans for the full Enhanced Oil Recovery and Natural Gas Liquids Program (EOR) are finalized. The Ausable reef is currently on production and is generating revenue from the initial EOR program which commenced in 4th quarter 2010 through the Ausable #1 and #4 wells.

Company President, Arnie Hansen, commented, "We see this as a turning point in the development of the Ausable Reef as the results of the well fully support our geological model and demonstrate the viability of the EOR scheme. We look forward to a busy period over the remainder of the year as we plan and execute the necessary well program."

Oil Flows at Breezer's Tx. Well

Oil Flows at Breezer's Tx. Well

Wednesday, April 13, 2011
Breezer Ventures Inc.

Breezer announced that their first well of a ten well rehabilitation and production development program in Callahan County, Texas, has successfully established oil flow in Jackson #6 Well. The drilling program was able to re-open Well #6 and discovered a considerable amount of free oil and oil pressure build-up.

The Company's field operator, Whitt Oil and Gas, and project manager, Firecreek Global Inc., both stated: "we've re-entered and deepened Well #6 (the former Magnolia/Mobil Oil well) and we are very encouraged by the amount of free oil encountered while drilling deeper into the Moran Sand."

The Company plans to utilize modern oil stimulation techniques, which will enhance the production rate of Well #6 once in full production. The field operator, Whitt Oil and Gas, will complete the final stage of drilling and completion phase and start production testing of Well #6 later this week. The well also has proven Tannehill, Cisco, Cook and Palo Pinto oil and gas formations, which the Company plans to develop in the future.

Breezer Ventures Inc. has ten (10) existing oil and gas wells that are currently in for rehabilitation and reactivation on the Jackson Lease, which contains 870 acres, and is situated on the western side of the Bend Arch in the Fort Worth Basin. The lease is situated 5 miles north of Baird, Texas.

The Company's objective is to develop stable long-term oil and gas production from the proven formations located on the Jackson Lease at very low capital costs. This project is expected to yield stable cash flow for years and will be profitable especially with oil prices at current record levels.