Reliance Industries Confident of Unlocking Field Potential with BP

- Reliance Industries Confident of Unlocking Field Potential with BP

Friday, September 09, 2011
Dow Jones Newswires
NEW DELHI
by Rakesh Sharma & Saurabh Chaturvedi

Reliance Industries Ltd. (500325.BY) Friday said it was confident of unlocking the full potential of its prolific east coast gas field and other blocks with the help of its partner BP Plc (BP).

The country's largest private explorer is fighting a decline in gas output at its D-6 Block in Krishna Godavri Basin. Reliance on Aug. 30 closed a deal with U.K.-based BP Plc to sell a 30% stake in its 21 oil and gas exploration blocks in India.

Last month, India's junior oil minister R.P.N. Singh said that gas production from Reliance's KG-D6 block during the April-June quarter was 31% below plan. Reliance's average gas production during April-June from the block was 48.60 million standard cubic meters per day.

Based on the approved field development plan, the output should have been 70.39 mmscmd, the minister said.

India's federal auditor Thursday said Reliance Industries had violated the KG D6 production-sharing contract with the government.

The Comptroller and Auditor General said Reliance initially estimated its capital expenditure for the D-1 and D-3 gas discoveries in the block at $2.4 billion, but revised it to $8.8 billion. The company also started implementing the revised plans before the government approved them.

The Mukesh Ambani-controlled company said it had engaged global consultants Ernst & Young, IPA Inc. and Daniel Johnston & Co., who didn't find any irregularity in its capex and management of the block.

Reliance said it commenced gas production from KG-D6 in six-and-a-half years from discovery, in comparison to the global average of nine to 10 years for similar deep-water production facilities.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Russia Can Double Oil Reserves By Tapping Arctic Potential -Lukoil Exec.

- Russia Can Double Oil Reserves By Tapping Arctic Potential -Lukoil Exec.

Wednesday, September 07, 2011
Dow Jones Newswires
SINGAPORE
by Max Lin

Russia can double its oil reserves if the government is determined to exploit the potential in the Arctic, a senior Lukoil Holdings executive said Wednesday.

"The development of Arctic fields needs political will and support from the government," Sergey Chaplygin, chief executive of Lukoil International Trading and Supply Co. said, but didn't elaborate. Lukoil is the country's biggest private oil producer.

Russia, the world's top oil and gas producer, has proven oil reserves of around 60 billion barrels, Energy Information Administration data showed.

Lukoil plans to explore oil production in the Russian Arctic with state oil company Rosneft under a new long-term cooperation agreement that takes effect this month.

Rosneft will also explore in the Arctic area with U.S. energy giant ExxonMobil, in a separate deal.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Uganda's Oil Potential Arouses International Interest

- Uganda's Oil Potential Arouses International Interest

Wednesday, July 20, 2011
OilPrice.com
by Charles Kennedy

The French Ambassador to Uganda has said that the exploration for oil in the country is a key opportunity for Uganda's government to press ahead with its development agendas.

Speaking during celebrations to mark the French National Day in Kampala, Ambassador Aline Kuster-Menager said, "Exploitation of the country's oil resources offers a unique and key opportunity for Uganda to boost its development with new and substantial financial resources," The Monitor reported.

Recent discoveries of vast oil reserves, particularly the oil rich Albertine Graben, with estimated reserves of at least 2.5 billion barrels of oil, mean Uganda is set to become a key oil producer on a part with other African oil producing nations, such as neighboring Sudan, Angola, Nigeria and Equatorial Guinea. Some estimate place the Albertine Graben reserve as high as six billion barrels of recoverable oil.

On the basis of such reserves, government analysts estimate that Uganda will be able to support production of over 100,000 barrels of oil per day for the next two decades.

To exploit these resources, the government has signed several leasing contracts with international companies. The French energy giant Total has been granted a large chunk of the rights of exploitation in the Albertine Graben.

The Tullow Oil exploration has already confirmed Albertine Graben reserves of 2.5 billion barrels of oil. As hydrocarbons have been encountered in 51 out of the 55 wells drilled by Tullow Oil, the developments have put Uganda's discovery rate at 92.3 percent.

(Charles Kennedy is Deputy Editor of OilPrice.com. The original article appears here.)

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Atikwa Expands Roncott Development Potential

- Atikwa Expands Roncott Development Potential

Monday, July 18, 2011
Atikwa Resources Inc.

Atikwa Resources Inc. has significantly expanded the development potential of its Roncott property through a rolling option farm-in on 22 sections of land contiguous to its producing 7-27 well and the existing Roncott Field. Atikwa will pay 100% of the costs associated with the drilling of one vertical well to earn the right to participate in a rolling option on a 50/50 basis. The rolling option is designed to earn two sections of land for every additional well drilled.

The Company's 7-27 well is currently the best producing vertical well in the pool with stabilized production of approximately 20 barrels per day over the last year. Based on industry data, management believes that a horizontal well drilled into a similar quality Bakken reservoir could produce from five to seven times that of a vertical well. President Sean Kehoe stated: "We are very excited about finally being able to move forward with this play. We have been working for over a year with a number of entities in an effort to build a larger position in and around our successful 7-27 test well and the main pool. We now have enough running room in a Bakken pool that has a history of producing oil economically from vertical wells, due to that fact, this should be an exciting horizontal candidate."

The Roncott field in Saskatchewan was discovered in 1956 as a Bakken formation field that was capable of producing economic, 40 degree API oil, from conventional vertical wells. Government data estimates that there is 10 million barrels of oil in place, however over the life of the pool industry has only extracted about 8% of that or 800,000 barrels of oil from essentially four vertical wells. It is that remaining 9.2 million barrels that the Company plans to target and potentially expand with a horizontal drilling program.

Vertical wells in this pool will qualify for a 50,000 bbl royalty incentive volume with horizontal wells qualifying for 100,000 bbl under the same incentive; consequently the Company will only pay a 2.5% Crown royalty, during this period. The low royalties and the lighter quality crude oil, combine to give favorable cash netbacks for production.

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Kulczyk Finds Potential Gas Reservoirs in Olgovskoye Well

- Kulczyk Finds Potential Gas Reservoirs in Olgovskoye Well

Monday, July 18, 2011
Kulczyk Oil Ventures Inc.

Kulczyk Oil Ventures Inc. announced the O-14 well in the Olgovskoye Field, in north-eastern Ukraine, has been cased to total depth ("TD") after encountering eight potential gas bearing reservoirs.

O-14 Exploration Well

The O-14 exploratory well was drilled to a TD of 2,800 metres. The eight potential gas-bearing zones where encountered in the Middle and Lower Bashkirian portions of the well. The well was drilled to further increase the gas production capability of the Olgovskoye Field and was drilled into a separate fault block which had not previously produced gas. Production testing of the O-14 well is expected to commence in late August / early September.

Next Well

The drilling rig will now be moved to a new location at O-12 which lies at the north end of the Olgovskoye license area. The new well is located 500 metres northeast of the O-7 well and 7,000 metres northeast of the recently drilled O-14 location. The O-12 well is designed to test gas-bearing reservoirs in the Muscovian and Middle Bashkirian and to further develop the gas production capability of the Olgovskoye Field. The O-12 well is expected to commence drilling in late July.

Olgovskoye Field

The O-14 well is the third new well drilled on the Olgovskoye license since the Company acquired its 70% interest in KUB-Gas in June 2010 and is part of a larger development program on the KUB-Gas assets through 2011 and 2012.

Kulczyk Oil completed drilling of the Olgovskoye-8 well in early January 2011. This well is expected to be tested and completed later in the third quarter of 2011. The O-8 well was drilled to a TD of 2,780 metres and wireline logging of the open hole identified several potential hydrocarbon-bearing zones. Another well on the Olgovskoye license, the O-9 well, reached its TD of 2,638 metres in mid-April and was cased to total depth as a potential multi-zone gas well. Completion and testing of the O-9 well indicated a gas discovery in a new zone known as the R37 unit.

The Olgovskoye Field currently produces from 4 wells (O-3, O-4, O-5 and O-7) with each well producing from a separate horizon.

Through its interest in KUB-Gas, one of the largest private gas producers in the Ukraine, KOV has an effective 70% interest in the Olgovskoye Field.

Assets of Kulczyk Oil

Kulczyk Oil is an international upstream oil and gas exploration company with a diversified portfolio of projects in Brunei, Syria and Ukraine and with a risk profile ranging from exploration in Brunei and Syria to production and development in Ukraine.

In Brunei, KOV owns working interests in two production sharing agreements which gives the Company the right to explore for and produce oil and natural gas from Block L and Block M. KOV owns a 40% working interest in Block L, a 2,220 square kilometre (550,000 acre) area covering onshore and offshore areas in northern Brunei and a 36% working interest in Block M, a 3,011 square kilometre (744,000 acre) area onshore in southern Brunei.

In Ukraine, KOV owns an effective 70% interest in KUB-Gas LLC. The assets of KUB-Gas consist of 100% interests in five licenses near the City of Lugansk in the northeast part of Ukraine. Four of the licenses are gas producing.

In Syria, KOV holds a participating interest of 70% in the Syria Block 9 production sharing contract which provides the right to explore for and, upon fulfillment of certain conditions, to produce oil and gas from Block 9, a 10,032 square kilometre (2.48 million acre) area in northwest Syria. The Company has agreements to assign an aggregate of 25% in ownership interests to third parties which are subject to the approval of Syrian authorities and which, if approved, would leave the Company with a remaining effective interest of 45% in Syria Block 9.

The main shareholder of the Company, Kulczyk Investments S.A. owns almost 50% of the issued common shares. Kulczyk Investments S.A. is an international investment house founded by Polish businessman Dr. Jan Kulczyk.

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Petrobras Confirms Commercial Potential of Lula Well

- Petrobras Confirms Commercial Potential of Lula Well

Friday, July 08, 2011
Petrobras
by SubseaIQ

Petrobras announced that well 9-RJS-660, located in Lula field, registered the Company's highest volume of production for May, reaching an average production of 28,436 barrels of oil per day (bpd). This well is the first to produce on a commercial basis in the Santos Basin pre-salt.

This result confirms the high potential of Brazil's pre-salt reservoirs, and, if we consider oil and natural gas production, the volume reached 36,322 barrels of oil equivalent per day (boed).

The well is interconnected to FPSO Cidade de Angra dos Reis and is the first of six production wells to be connected to the FPSO. Besides this well, a gas injection well is already connected to the platform, which, since the beginning of April 2011, reinjects produced gas into the reservoir through 9-RJS-660. Two injection wells are also planned, of which one will be of water, and the other will alternate injection of water and gas.

The FPSO Cidade de Angra dos Reis is expected to be producing around 100 thousand bpd throughout 2012.

The consortium developing the production in block BMS-11, where Lula field is located, is composed of Petrobras, which is the operator, with a 65% stake, BG Group, with 25%, and Galp Energia, with 10%.

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Petrom Announces Potential Significant Gas Find in NW Romania

- Petrom Announces Potential Significant Gas Find in NW Romania

Thursday, July 07, 2011
Dow Jones Newswires
BUCHAREST

Romania's dominant oil company OMV Petrom said drilling success at its 4539 Totea exploration well in the southwestern region of Oltenia, in what could be the "most important onshore gas discovery in the last six years," news agency Mediafax reported.

The 4539 Totea well was drilled following a recent 3D seismic exploration program. Three successful production tests were carried out, with a maximum stabilized production rate of around 3,100 barrels of oil equivalent/day gas and associated condensate, Petrom said in a statement.

"I am happy to announce this success which might represent the most important onshore gas discovery in Romania during the last six years. The results obtained during tests confirm the reservoir's potential as well as our expectations from the Oltenia region where we directed major investments," said Johann Pleininger, member of the Petrom Executive Board, responsible for Exploration and Production.

Petrom said it will start an appraisal program to determine the size of the accumulation, which is located in an area with a high geological complexity. Experimental production on well 4539 Totea is estimated to start by year-end, once the well is linked to the nearby gas pipeline infrastructure.

Petrom is Romania's largest vertically integrated oil company. Austrian OMV owns 51% of the company's shares, while Romanian Economy Ministry and regional investment fund Fondul Proprietatea hold 20.64% and 20.11% in Petrom, respectively. The reminder 8.24% stake is traded on the Bucharest bourse.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Caza IDs Potential Pay at O.B. Ranch Well

- Caza IDs Potential Pay at O.B. Ranch Well

Thursday, July 07, 2011
Caza O&G Inc.

Caza O&G provided an operational update on the Company's Bongo Property concerning the O.B. Ranch #2 development well in Wharton County, Texas.

Caza, as operator, announced that the O.B. Ranch #2 development well has reached its target depth of 13,210 feet and electric logs have been obtained through the target depth. The logs indicate potential pay in the Frio, Yegua and targeted Cook Mountain formations.

Data from the logs and core samples from the well have confirmed Caza's geologic and seismic modeling, which hypothesized that the O.B. Ranch #1 discovery well (which originally targeted a deeper Wilcox structure) was producing from the fringe of a more extensive Cook Mountain sand package. The O.B. Ranch #2 development well has been drilled closer to what Caza believes to be the center of the Cook Mountain anomaly with the aim of gaining valuable geologic knowledge of the Bongo/Cook Mountain sand and the regional Cook Mountain sand picture, while adding further production to the Company's portfolio.

The O.B. Ranch #2 is in a higher structural position than the O.B. Ranch #1 well, and log and seismic data support thicker, better sorted, potential pay sands with better porosity within the Cook Mountain section than those found in the O.B. Ranch #1. Due to concerns over existing downhole conditions, Caza was unable to run the micro imaging tool used in the O.B. Ranch #1 well, which helps to identify net effective pay. However, the Company was able to run a high resolution triple combination logging tool, which was more than adequate to define lithology and potential pay sections within the wellbore.

Caza is currently running production casing and preparing the O.B. Ranch #2 well for further completion operations in the Cook Mountain. The completion procedure will include a fracture stimulation program, which is scheduled for the end of July, 2011. The initial rate will be announced following completion of the fracture stimulation procedure.

The log data also indicates potential pay in the shallower Frio and Yegua formations at approximately 5,530 feet and 9,000 feet respectively.

Caza currently has a 45.28% working interest and an approximate 33.51% net revenue interest in the Bongo property and wells.

W. Michael Ford, Caza's Chief Executive Officer commented, "We are very pleased with the results of the O.B. Ranch #2 well. The data from this well has confirmed our scientific model and will be instrumental in efficiently developing the Bongo property. Additionally, Caza is beginning to receive the initial data from our proprietary seismic reprocessing in this area, which looks very promising. The Company currently has several exploration prospects under lease that should benefit from this newly gathered data as should Caza's future exploratory prospect development in Wharton County."

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Tower Updates Namibia Prospect Potential

- Tower Updates Namibia Prospect Potential

Thursday, June 30, 2011
Tower Resources

Tower Resources plc has provided details of the outcome of a second detailed technical and economic evaluation of the 0010 Licence, located offshore Namibia. Tower has a 15% working interest in the Licence and is fully carried financially by Arcadia Expro Namibia (PTY) Ltd (“Arcadia”) through an initial exploration well and a contingent second well.

The Tower Board has now received an updated Competent Persons Report, compiled by Oilfield International Limited (OIL), over Licence 0010. The CPR update follows the interpretation of the high quality 3D seismic data acquired in 2010 over the primary drilling target "Delta". OIL conducted a detailed review of the “Delta” structure and calculated the Expected Monetary Values (EMV’s) of the prospects and leads identified. OIL also updated the EMV of two other structures, ”Alpha” and “Gamma” which were the subject of the previously reported June 2010 CPR on Licence 0010.

The main conclusions of the CPR are summarised below.

The Delta Maastrichtian prospect remains the principal target for an exploration well. Best estimate prospective resources (50% probability) have been estimated as follows:

In the event of volatile oil, gross recoverable resources amount to 2.2 billion barrels and 3.4 trillion scft of natural gas. Net figures for Tower are 317 million barrels and 484 billion scft of natural gas.

In the event of gas condensate, gross recoverable resources amount to 267 million barrels and 8.1 trillion scft of natural gas. Net figures for Tower are 38 million barrels and 1.15 trillion scft natural gas.

In the event of dry gas, gross recoverable resources amount to 20 million barrels and 8.2 trillion scft natural gas. Net figures for Tower are 3 million barrels and 1.17 trillion scft natural gas.

Gross un-risked prospective recoverable resources from the Delta Palaeocene supplementary prospect and the other Licence wide supplementary leads at the 50% probability level amounts to about 10 billion barrels and 15 trillion scft of gas for the volatile oil cases and 35 trillion scft in the case of predominantly gas.

OIL has calculated for the Licence net risked prospective resources to Tower as 150 million barrels oil and 719 billion scft natural gas (together ca 270 million barrels oil equivalent). More importantly, the corresponding numbers for the target Delta Maastrichtian prospect alone are 55 million barrels oil and 257 billion scft of natural gas (together ca 98 million barrels oil equivalent).

OIL has calculated an EMV for the prospective resources of Tower and, in just the Delta Maastrichtian prospect, an EMV of US$744 million has been calculated. The Board believe there is also a very high upside in the other Delta horizons.

OIL has determined that there are now two prospects at Delta. The Maastrichtian prospect has been confirmed and the Palaeocene lead has been upgraded to a prospect. There are now three supplementary leads within the Delta structure: the Upper Campanian; the Campanian “wedge”; and at a deeper Albian horizon. The Alpha Palaeocene and Gamma Palaeocene leads are separate structures and would be the subject of further 3-D seismic before drilling.

OIL has used the seismic data, the two Namibian wells on the block and regional data to evaluate the likelihood that the reservoirs would be predominantly light oil-bearing; gas condensate-bearing or dry gas-bearing. For Delta, OIL concludes probabilities of 50%, 40%; and 10% respectively. The Gamma and Alpha structures are rated 45%, 44% and 11% respectively.

OIL have engineered the most likely development approach and associated capital cost, operating cost and production profiles for each case together with currently traded oil and gas prices (gas into Europe), escalated to 2020 first production and beyond. They have calculated NPV 10% after-tax values on that basis for each case. Each has been valued on an independent standalone basis to avoid trying to determine economies of shared facilities.

The final step has been to estimate a geological chance of success (“GCOS”) for each structure. DeltaM has been assessed as having a 40% GCOS and DeltaP a 24% GCOS. The leads have a GCOS ranging between 10 and 20%. An economic confidence factor has then been applied to the geological COS’s to calculate the economic COS “ECOS” which is used in the determination of risked reserves and the EMV calculations. DeltaM has a 31% ECOS; DeltaP a 19% ECOS; and the leads between 8% and 12%.

The OIL review team included two geophysicists, a geologist and a petroleum engineer having a total of 125 years of experience as technical specialists in the oil and gas industry. In particular, two of them have considerable experience of South America where South Atlantic exploration is most advanced. The OIL assessment has been undertaken in compliance with the SPE Petroleum Resources Management System (SPE-PRMS). OIL has had access to all available data from the Licence and a wide variety of regional technical information. They reviewed the work undertaken by Arcadia and specialist consultants and where relevant, undertook technical analysis of their own to accommodate their own wide and relevant experience, particularly of the Brazilian basins, and any publicly available information. Interaction with Arcadia took place to understand their technical approach but the conclusions drawn are entirely those of OIL.

The first exploration well, currently anticipated at the end of Q1 2012, will test as many as five zones of interest including two prospects and three leads targeting a “best estimate” resource potential of an estimated 6-12 billion barrels of recoverable oil equivalent (gross) depending on whether the fluid is predominantly gas or oil respectively.

Peter Kingston, Chairman of Tower Resources plc, commented: “The comprehensive independent reassessment of the prospectivity of Namibia Licence 0010 has confirmed its potential as a world class group of oil and gas prospects. It is particularly encouraging that the 3-D seismic survey has substantially increased the reserve potential of the Delta structure and has led to an improvement in the chance of success with the first well. This well alone, still on schedule for the end of Q1 2012, will test a resource potential of significantly more than 5 billion barrels of oil equivalent.”

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BG Doubles Santos Basin Net Potential

- BG Doubles Santos Basin Net Potential

Thursday, June 30, 2011
BG Group

BG Group on Thursday 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 kilometers of 3D seismic;
• full analysis of a completed extended well test (EWT) on Lula Sul and early results from the Guara 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 optimization, 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 program 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."

* Total Reserves and Resources are defined by BG Group as the aggregate of proved and probable reserves plus discovered resources and risked exploration.

** The Total Reserves and Resources upgrade announced today is based upon probabilistic modelling by BG Group of its interests in the Santos Basin, in accordance with Society of Petroleum Engineers (SPE) guidelines. The data has been analyzed, interpreted and verified by BG Group and not by the Operator or other Consortium partners.

BG Group has interests in five blocks in the Santos Basin, offshore Brazil

• BM-S-9 (30%) containing the Guara, Carioca, Abare and Iguacu discoveries and prospects.
• BM-S- 10 (25%) containing the Parati and Macunaima discoveries and prospects.
• BM-S-11 (25%) containing the Lula, Cernambi and Iara discoveries and prospects.
• BM-S-50 (20%) containing prospects including Sagittario.
• BM-S-52 (40%) containing the Corcovado discovery.

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Skrugard Estimates Reaffirms Norwegian Continental Shelf Potential

- Skrugard Estimates Reaffirms Norwegian Continental Shelf Potential

Monday, June 20, 2011
Rigzone Staff
by Karen Boman

Statoil reported that its Skrugard discovery provides renewed optimism for the whole Barents Sea region and reaffirms its long-term prospective of the Norwegian Continental Shelf.

Statoil now estimates that the Skrugard discovery in the Barents Sea to contain approximately 250 million boe recoverable resources, with a significant upside potential in the license. The Skrugard well has significantly improved Statoil's understanding of other prospects in the area.

Finding new discoveries and enhancing production from existing fields will be critical for Norway's future. In 2010, the nation recorded the largest decline worldwide in oil production in 2010, according to the BP Statistical Review of World Energy June 2011.

BP reports that Norway had 3.3 million b/d of oil production in 2000; at the end of 2010, the country had 2.1 million b/d. Norway had estimated proved oil reserves of 11.4 thousand million barrels at the end of 2000; at the end of 2010, the country had 6.7 thousand million barrels.

Oil production in non-OPEC countries in 2010 grew by 860,000 b/d, or 1.8 percent, the largest increase since 2002, according to the review. Growth was led by China, which recorded its largest production increase ever, the U.S., and Russia, while continued declines in Norway and the UK partly offset growth elsewhere.

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Operators Look to Unlock Tuscaloosa Marine Shale Potential

- Operators Look to Unlock Tuscaloosa Marine Shale Potential

Monday, June 06, 2011
Rigzone Staff
by Karen Boman

The Tuscaloosa Marine shale play, located on the border of southwestern Mississippi and northeast Louisiana, could emerge as the next big oil shale play as oil and gas producers shift their focus from gas to oil drilling and seek to unlock unconventional resources in unexplored shale plays.

The Louisiana Department of Natural Resources Office of Conservation will hold a public hearing on June 7 in Baton Rouge to approve a drilling production unit that Devon Energy has applied for in the Tuscaloosa play near Ethel in East Feliciana Parish.

Devon holds 250,000 acres in the Tuscaloosa Marine shale play. Devon spokesperson Chip Minty said it is still too early to quantify the liquids content of this acreage. The company plans to drill two horizontal wells this year on its Tuscaloosa shale acreage, which Devon officials said is stratigraphically equivalent to the Eagle Ford shale play and has a low average acreage cost of $180/acre. The company will have a rig on site in this year's second quarter.

The company's Tuscaloosa activity is part of Devon's goal of identifying and establishing large acreage positions in highly economic plays at reasonable prices. "We have continued building these new venture positions and now have roughly 850,000 net acres and a handful of new plays, primarily targeting oil and liquid rich gas," the company said.

The Tuscaloosa shale on Devon's acreage is approximately 200 to 400 feet thick, at depths of 11,000 to 14,000 feet across Devon's acreage position. Oil production has been established, up dip in the play from the Tuscaloosa Shale, said David Hager, Devon's executive vice president of exploration and production, during Devon's first quarter 2011 earnings conference call in early May. "We plan to utilize horizontal drilling and fracture simulation to enhance the productivity of the reservoir in both the oil and liquids-rich portion of the play."

Denbury Resources recently signed a small joint venture covering its Tuscaloosa Marine Shale acreage wherein the partner will complete one well and drill another at no cost to us, leaving Denbury with a small retained interest in future activities. Denbury in late 2009 agreed to acquire EnCore, which had drilled four horizontal wells targeting the Tuscaloosa Marine Shale play in 2007 and 2008. The JV will allow Denbury to develop this acreage it acquired with the EnCore acquisition.

The first Tuscaloosa Marine shale well was tested in 1975; to date, five well have been tested and produced. The Tuscaloosa Shale has an unproven unconventional resource estimate of 7 billion barrels of oil, according to a report by researchers at Louisiana State University in Baton Rouge.

The marine shale section lies between sands of the upper and lower Tuscaloosa sections and varies in thickness from 500 feet in southwestern Mississippi to more than 800 feet in the southern part of the Florida parishes in Louisiana. The Tuscaloosa Marine Shale is very similar in geology to the Eagle Ford, and is believed to have the same potential for development and production.

Brammer Engineering and Indigo II Louisiana Operating hold permits in the same area as the Tuscaloosa shale. Indigo Chairman and Chief Executive Officer Bill Pritchard said he sees potential for Tuscaloosa shale production in the acreage it received from Roy O. Martin Minerals, Louisiana's largest private landowner, in exchange for equity in Indigo.

The company put together about 240,000 acres in central Louisiana, of which half has been leased to timber companies; Indigo will focus its Tuscaloosa exploration efforts on the remaining half. Indigo drilled the Bentley Lumber 32-1 vertical well, and will drill the Indigo Bentley Lumber 23H-1 horizontal well in July.

The company's acreage is northwest of the area where Devon and EnCore have drilled, but the interval Indigo is targeting sits above the Edwards carbonate formation; to the east, the Eagle Ford/Tuscaloosa play overlies the main body of the Lower Tuscaloosa sandstone. Indigo's acreage features a higher percentage of calcite, which makes it more brittle and easier to frack. The company set intermediate casing just above the shale and drilled with oil based mud. "That and the fact that we are more calcitic through the section allowed us to drill through the TMS [Tuscaloosa Marine Shale] without incident," Pritchard said.

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Crown Point Logs Potential Zone at Argentina Well

- Crown Point Logs Potential Zone at Argentina Well

Monday, May 30, 2011
Crown Point Ventures Ltd.

Crown Point has logged the EV-25 well bore and has cased it as a potential multiple zone oil well. This well is the second of a six well drilling program at El Valle in the San Jorge Basin in Argentina. Logs and samples taken while drilling indicate the presence of four principal zones in the Canadon Seco and Caleta Olivia formations with a combined potential pay thickness of 16.5 meters having an average porosity of 22%.

El Valle has three distinct productive sedimentary formations, which, in order of surface to deepest, are the Canadon Seco, Caleta Olivia and Mina el Carmen. Each of these formations may contain multiple discrete hydrocarbon bearing zones. Typically, the Canadon Seco formation produces medium grade oil (API gravity that ranges from 16-22 degrees), while the Caleta Olivia and Mina el Carmen produce light oil (API gravity of approx. 30 degrees).

The drilling rig is now moving to the location of the third well EV-29 - this well has principal geological targets located in the Caleta Olivia, with secondary targets in the Canadon Seco.

This drilling program is part of a larger 20-25 well program to be conducted at El Valle over the next 24 months, the Company plans to drill 2-5 wells 100% interest wells on the Canadon Ramirez exploitation concession in the Province of Chubut over the next 12 months and one 50% interest well at Laguna de Piedra in the first quarter of 2012. At Cerro Los Leones we anticipate receiving the required environmental permits in the near term and expect to commence the shooting of the 3-D and 2-D seismic programs shortly after receiving the environmental permit.

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Madalena Cases Argentina Well as Potential Oil Discovery

Madalena Cases Argentina Well as Potential Oil Discovery

Tuesday, May 10, 2011
Madalena Ventures Inc.

Madalena Ventures Inc. and its wholly owned subsidiary Madalena Austral SA ("Madalena" or the "Corporation"), announced Tuesday that the Corporation's CAN X-4 exploratory well on the Coiron Amargo Block has been cased as a potential oil discovery. The well is situated on a separately defined 3D drilling anomaly located between the CAN X-1 and CAN X-2 wells.

The CAN X-4 exploration well was drilled to total depth ("TD") of 11,027 feet and has been cased to TD. Both oil and gas shows were evident during the drilling of the Vaca Muerta and Sierras Blancas formations. Based on electric logs, the Vaca Muerta formation had similar thickness and characteristics to the other four wells the Corporation has drilled on the block. In the Sierras Blancas formation, the well encountered a potential gross hydrocarbon column of 92 feet.

The Corporation now plans to return to the CAS X-1 well drilled in April 2011 in the southern portion of the block to test both the Sierras Blancas and Vaca Muerta formations encountered by the well. Part of the test is expected to include a fracture stimulation of the Vaca Muerta formation and combined test results will be reported as soon as they are available. Completion operations at the CAS X-1 well have commenced to be immediately followed by testing of the CAN X-4 well.

Madalena is a publicly traded international junior Canadian oil and gas exploration company. The Company is actively evaluating international oil and gas opportunities with a primary focus on South America.

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IHS: Niobrara Resource Potential Not Yet Proven

IHS: Niobrara Resource Potential Not Yet Proven

Friday, April 29, 2011
Rigzone Staff

Despite enthusiasm by exploration and production (E&P) companies and investors, successful development efforts to unlock the Niobrara horizontal oil play's resource potential has been limited, and more time is needed to further delineate its true potential as a resource play, according to a special report by IHS.

IHS studied the performance of a few modern horizontal oil wells present in the Niobrara and compared initial production rates of these wells against initial production rates for median-producing oil wells in the core of the Bakken/Three Forks shale play.

According to IHS, the median Bakken horizontal well completed since 2009 in the play's core averaged about 230 b/d of oil in its six month online. Two modern Niobrara horizontal wells matched or exceeded that oil production level, with the remaining 10 wells producing between 10 b/d and 190 b/d. In their sixth month, five of these wells produced 70 b/d of oil or less; three produced between 100 b/d and 125 b/d; and the remaining two wells produced approximately 185 b/d.

While enthusiasm for the Niobrara is likely tied to the success of the Bakken/Three Forks play, study author and IHS principal energy equity analyst Sven Del Pozzo noted that definitive conclusions of the Niobrara potential can't be made at this early stage, since fewer than 20 modern horizontal Niobrara wells in the DJ and North Park basins have 365 days of IHS production history, "and just 10 of those have a meaningful oil cut."

The author said he doesn't necessarily disagree with the expectations of E&P companies that experience will enhance both well performance and predictability in the Niobrara. However, Del Pozzo said those who have cited the Niobrara play's best wells as indicative of future results are being a bit premature due the variability and lack of production data.

"The Niobrara is situated at various depths and has diverse rock properties as it spans multiple basins, making it very risky to generalize about its prospectivity at this stage," Del Pozzo said. In comparison, the Bakken's production is predictable over a wide area, compared with the Niobrara, where well performance still varies considerably, even in the same field.

The Niobrara play extends from Wyoming and Colorado into Nebraska and Kansas.

Horizontal Drilling Boosts 2010 Oil Production

Horizontal drilling activity in the Bakken and other U.S. oil shale formations helped boost U.S. oil production. The U.S. Energy Information Administration (EIA) reported this week that U.S. oil production grew in 2009 and 2010 after experiencing declines in all but one year from 1986 to 2008.

While the 2009 production increase resulted from deepwater Gulf of Mexico activity, EIA attributed the 2010 growth to oil shale drilling. "Operators are combining horizontal wells and hydraulic fracturing – the same technologies used to significantly boost shale gas production – to do the same for oil," EIA said.

Total oil production in North Dakota has approximately tripled since 2005 thanks to development of the Bakken play, which extends into Montana and parts of Canada. North Dakota Bakken production has increased from less than 3,000 b/d in 2005 to over 230,000 b/d in 2010, and the Bakken's share of North Dakota oil production rose from about three percent to about 75 percent during the same period of time.

Shale plays known primarily for gas production also are seeing an acceleration of oil-focused drilling as strong oil prices has prompted producers to switch their focus from shale gas to shale oil. In Texas, oil production from the Barnett shale play has more than tripled from 2005 to 2010, while Woodford shale oil production in Oklahoma passed the 4,000 b/d mark in 2010, up 42 percent from 2009 and nearly three times 2008 volumes.

The Eagle Ford oil shale play in Texas, which had negligible production in 2005, approached 30,000 b/d in 2010. Oil production from Appalachia's Marcellus shale more than doubled in 2010 from a year earlier and has grown nearly thirteen-fold since 2007.

The Baker Hughes rig count currently shows more active oil-directed rigs than gas-directed rigs. Natural gas rigs generally accounted for between 80 percent and 90 percent of the total weekly rig count during most of the 2000s. However, the number of rigs targeting oil deposits climbing began climbing significantly in mid-2009.

The importance of horizontal drilling to increasing oil production is also underscored by the Baker Hughes rig count data, EIA noted. Horizontal rigs comprised less than one-third of oil-directed rigs in September 2008; since then, the number of horizontal oil rigs has tripled, increasing that share to about 46 percent.

The increase in crude oil prices relative to gas prices is one factor responsible for the shift towards oil-focused drilling. The crude oil-to-natural gas price ratio, which through mid-2009 averaged over eight from 2000 through mid-2009, has since risen considerably. EIA noted that, when the Brent crude spot price in dollars per barrel is divided by the Henry Hub spot price of gas in dollars per MMBtu, oil is five times more valuable than gas on an energy-equivalent basis.

OGX Notes 4 Bboe Increase in Potential Resources Offshore Brazil

OGX Notes 4 Bboe Increase in Potential Resources Offshore Brazil

Monday, April 18, 2011
OGX S.A.

OGX disclosed the results of the reports prepared by petroleum consultants DeGolyer & MacNaughton ("D&M"), which estimate new volume of resources held by the Company in Brazil's Campos and Parnaiba basins and three basins in Colombia. These reports indicate net potential resources for OGX of 5.7 billion barrels of oil equivalent ("boe") in the Campos Basin, 1.0 billion boe in the Parnaíba Basin and 1.1 billion boe in Colombia. When combined with the estimates from the previous report for the Santos, Espírito Santo and Pará-Maranhão Basins (Sep/09), these new results present a total volume of net potential resources of 10.8 billion boe.

These results validate the successful and accelerated evolution of the Company's asset portfolio and its ability to grow organically, through massive discoveries as well as via the acquisition of new areas, demonstrating a unique capacity of to create value and deliver results.

"These results, presented by an independent, internationally-renowned consulting group, confirm the extraordinary success of our business strategy and execution, which has been to focus on world-class assets located mostly in shallow waters. We have discovered accumulations of scale and levels of productivity comparable to those found in the pre-salt areas, and will be able to develop them at a much lower cost, utilizing fully tried-and-tested technologies," commented Eike Batista, Chairman and CEO of OGX.

"OGX has demonstrated that it has the technical and managerial expertise to discover billions of barrels in accumulations in basins which vary greatly in their geological formations, and to transform their prospective resources into contingent resources. At the same time, we have expanded our exploration portfolio with high-potential assets. We have also made huge strides in the delineation of new discoveries and production, while continuing to grow and create value for all stakeholders," emphasized Paulo Mendonça, General Executive Officer and Head of Exploration for OGX.

The five reports submitted by D&M were prepared with the information available as of December 31, 2010, for the Campos and Parnaíba Basins, and as of March 31, 2011 for Colombia. The documents cover a period of approximately 15 months of exploration and 22 wells, and do not include the wells drilled subsequently. For the Campos Basin, only the post salt sections were considered. The new reports update the figures that were previously available for these two basins and present the first estimates for the five blocks held by OGX in Colombia. D&M's potential resource report dated September 2009 continues to apply for the Santos, Espírito Santo and Pará Maranhão basins.

The results of these studies reflect the success of OGX's strategy to prioritize, in the initial phase of its campaign, the accomplishment of ANP work program and the exploratory drilling of wildcat wells to maximize the discovery of accumulations. In response to the large number of discoveries made, the Company is intensifying its appraisal campaign in preparation for Declarations of Commerciality and the start-up of production.

"The identification of our discoveries and the recent chartering of five FPSOs and two WHPs with OSX, which will be followed by new orders, represent an important step towards production. We have rapidly executed on our business plan and achieved important milestones, enabling us to the begin production and commercialization within a timeframe that is unprecedented for the oil and gas industry," stated the Production Officer, Reinaldo Belotti.

Pacific Rubiales Acquires Maurel & Prom Stake in Colombia

Pacific Rubiales Acquires Maurel & Prom Stake in Colombia

Thursday, March 31, 2011
Pacific Rubiales Energy Corp.

Pacific Rubiales announced the acquisition of 50% of the interests held by Maurel et Prom in the Sabanero, Muisca, SSJN-9, CPO-17 and COR- 15 blocks, which are all located on-shore in Colombia.

Mr. Ronald Pantin, Chief Executive Officer of the Company, commented, "We are very pleased to join forces with Maurel et Prom. This acquisition adds significant resources and exploratory potential to our already robust resource base. Moreover, this acquisition fits synergistically with our other assets located in the same basins, paving the way to significant efficiencies in production and transport. With this acquisition we continue raising the bar as the premier explorer and operator in Colombia."
Upon completion of the transaction, Pacific Rubiales will partner with Maurel et Prom in respect of the following interests:

• 100% participation in the Sabanero Block ("E&P Contract No. 17 of 2007 Sabanero") located in the central region of Colombia in the Department of Meta.
• 100% participation in the Muisca Block ("E&P Contract No. 20 of 2008 Muisca") located in the central region of Colombia in the Departments of Boyacá and Cundinamarca.
• 50% participation in the SSJN-9 Block ("E&P Contract No. 47 of 2008 SSJN- 9") located in the northern region of Colombia in the Departments of Bolivar, Cesar and Magdalena. The remaining 50% interest is currently held by HOCOL.
• 50% participation in CPO-17 Block ("E&P Contract No. 40 of 2008 Llanos Orientales - Area Occidental CPO-17") located in the central region of Colombia in the Department of Meta. The remaining 50% interest is currently held by HOCOL.
• 100% participation in the COR-15 Block ("Special Technical Evaluation Agreement Type 3 Contract") located in the central region of Colombia in the Department of Boyacá.

This agreement is subject to legal and regulatory approvals of the ANH and certain contractual approvals with the partners in Colombia.
The general terms of the agreement with Maurel et Prom are as follows:

• Pacific Rubiales will pay to Maurel et Prom cash consideration to a maximum of US $66 million as a reimbursement for past exploration costs in the blocks, as at March 31, 2011.
• Pacific Rubiales will assume a full carried obligation on the exploration and delineation activities in the Sabanero Block with a reimbursement out of the free cash flow. The Company will also secure the financing required by Maurel et Prom to execute its portion of the development activities in such block.
• Reimbursement will also be made by means of free cash flow derived from future hydrocarbon production. Pacific Rubiales offers to assume a full carried obligation of up to US $120 million in three years for exploration activities in the SSJN-9, CPO-17 and Muisca Blocks. This obligation will be subject to revisions pending the activity results and negotiations with the other applicable partners.
• Pacific Rubiales will assume a full carry obligation on exploration activities for Block COR-15, with reimbursement by means of free cash flow derived from future hydrocarbon production. The Company will also secure the financing required by Maurel et Prom to execute its portion of the development activities in such block. Reimbursement will also be made by means of free cash flow derived from future hydrocarbon production.

TGS Commences Reprocessing Program Offshore Indonesia

TGS Commences Reprocessing Program Offshore Indonesia

Thursday, March 31, 2011

TGS-NOPEC Geophysical Co. ASA

TGS has commenced an extensive multi-phase reprocessing program of 2D seismic data located in the Makassar Strait, Indonesia. The first phase consists of 2,700 km of seismic data in the Northern Mahakam Delta.

The original and reprocessed data support the exploration potential of the deepwater area of the Mahakam Delta. Interpretation of the seismic data since 2001 has demonstrated potential hydrocarbon prospectivity in the basin, resulting in the award of exploration acreage and the drilling of several exploration wells. Partial relinquishment of the exploration blocks have also recently created opportunities for new exploration in the area.

The data will be reprocessed with customized techniques to enhance imaging of the main structures and reservoir targets in the basin. The reprocessed data is intended to enhance definition of Direct Hydrocarbon Indicators (DHIs) and Amplitude Versus Offset (AVO) anomalies associated with turbidite reservoirs seen on the original 2D seismic data.

Data from this initial phase of reprocessing will be available for clients in 3Q 2011. This project is supported by industry funding.

Solimar: Potential Oil Pay at San Joaquin Basin

Solimar: Potential Oil Pay at San Joaquin Basin

Wednesday, March 30, 2011

Solimar Energy

Zodiac Exploration of Canada has announced potential oil pay of up to 1,000 feet in sandstone and fractured oil shale reservoirs in its Zodiac 4-9 well in the NW San Joaquin Basin. Solimar Energy has a 1.13% carried interest in the well and in a very large, approximately 101,000 acre surrounding acreage position. Solimar also owns a small, 0.5% royalty over some 26,000 acres of this acreage position.

In addition to the minority position in the Zodiac acreage, Solimar has approximately 20,000 mostly operated acres with interests from 33.33% to 75% in other leases within and adjacent the NW San Joaquin Basin oil shale play trend. Oil shales of the Kreyenhagen and McLure (Monterey equivalent) Formations are proven producers in the area and the main targets.

The Company also has a back in right for a 10% interest in a further approximately 2,900 acres in the trend flanking the Kettleman Middle Dome which is also productive from the fractured oil shales and is the subject of a redevelopment program.

There is accelerating industry activity in California oil shales lead mainly by major oil companies that is revaluing Solimar Energy's San Joaquin Basin acreage.

Key offset industry activity includes:

• The Zodiac 4-9 well which is being prepared for a flow testing program after encountering potentially 1,000 feet of pay in both sandstone and shale reservoirs
• Occidental Petroleum have become the biggest acreage holder in the NW San Joaquin oil shale trend and are already producing 45,000 bopd from fractured oil shales in California
• Chevron are redeveloping the giant Kettleman Dome field immediately adjacent Solimar's acreage focusing on production from the Kreyenhagen Shale
• A multi party JV has been successfully redeveloping the Kettleman Middle Dome which is productive from sandstone reservoirs and both the Kreyenhagen and McLure Oil Shales. Additional appraisal drilling immediately adjacent Solimar's back in right acreage is planned within 12 months

Update Summary

The Board of Solimar provided this brief update note to inform shareholders that very positive commercial activity is occurring within and adjacent the Company's asset focus area the San Joaquin Basin, with particular emphasis on the development of fractured oil shales.

The Company has been aggressively building its acreage position and adding to its California (Ventura) based operating team over the past 15 months and is positioning to exploit both its conventional (sandstone which includes the recent Guijarral Hills discovery) and unconventional (oil shales) reservoir projects.

The timing of execution of the Company's strategy to accumulate oil prone acreage focussed in the San Joaquin Basin has been excellent:

• Oil prices are now very high relative to the USA domestic gas price supporting robust project economics
• Land prices for oil shale acreage are increasing in California. However Solimar believes large uplifts are still likely to bring California into line with other states of the USA where oil shale land prices can be up to 10 times higher than in California.

The Schematic Map attached to this release shows the position of Solimar's acreage within and adjacent the NW San Joaquin Basin oil shale play trend, highlighting the acreage position relative to the key industry players.

More detail will be provided in due course about each of the Company's projects that have potential for oil shale production as the individual work plans are crystallized. The following brief descriptions are examples however of two large projects the Company has that are expected to significantly impact the Company in 2011.

The Company's largest project is at Kreyenhagen with over 15,000 operated acres under lease and containing extensive occurrences of thick Kreyenhagen and McLure Formation oil shales within targetable depths. Both these formations are oil productive in the adjacent oil fields where these rocks are the subject of active field redevelopment programs.

The Company is in the early stages of evaluation of the Kreyenhagen Project which also contains a large, known shallow oil accumulation in a sandstone reservoir.

There may be up to 300 million barrels of oil in place within this reservoir in the project acreage.

The Kreyenhagen Project will be the subject of considerable field activity by Solimar commencing in 2011 including re entry and production testing of some suspended wells.

The Company is also watching closely the progress of the Zodiac 4-9 well which Canadian listed Zodiac Exploration recently drilled to almost 15.000 feet and announced on 21 March a potential oil pay of over 1,000 feet in the well. Solimar has a 1.13% interest free carried through the Zodiac 4-9 and a following well in a very large acreage position totaling some 101,000 acres. In addition the Company owns a small 0.5% royalty over approximately 26,000 acres within this overall acreage position but not at the well location.

The well is being prepared for production testing as part of a program to verify the commercial potential of the multiple potential pay zones encountered.

Commenting on the evolving potential of Solimar's San Joaquin Basin acreage, CEO John Begg said, "We spent much of last year securing an acreage position focused on the oil prolific San Joaquin Basin. This strategy has placed the Company in an exciting position literally and figuratively. In most cases our immediate neighbors are major oil companies that are accelerating their work programs in the San Joaquin Basin on play types represented in our acreage. So not only do we have active programs of our own that could deliver a substantial uplift in value but escalating industry activity in and adjacent our acreage that could also be transformational at no cost to the Company."

Australia Players Still Pursuing Cooper Basin Shale Gas Potential

Australia Players Still Pursuing Cooper Basin Shale Gas Potential

Tuesday, March 29, 2011
Rigzone Staff
by  Karen Boman

Despite once-in-a-generation rainfall and flooding that disrupted exploration and production activity last year, Australia-based oil and gas producers are forging ahead this year with plans this year to drill for and develop the Cooper Basin's conventional and unconventional oil and gas resources.

Santos Ltd., noted that reports of the death of Australia's onshore Cooper Basin, which stretches across the northeast corner of South Australia into southwestern Queensland, are "greatly exaggerated" as the basin contains unconventional gas resource potential of more than 39,000 petajoules (PJ) and booked contingent resources of about 5,000 pj. Santos reports that undeveloped unconventional shale gas resources lay beneath the developed conventional resource Moomba basin, while tight gas and deep coal exist below shale gas. Gross gas thickness in the Cooper is approximately 1,600 feet.

Another Australia-based oil and gas company, Beach Energy, reports it has an aggressive exploration and development program planned for this year in its Cooper Basin holdings, and better land access for these activities following the Cooper Basin floods of last year, which washed out roads and prevented companies from accessing work sites.

The company currently operates 19 oil fields in the Cooper-Eromanga with five gas discoveries awaiting development and owns an approximate 21% interest in the Cooper Basin project operated by Santos. Since late 2006, Beach has participated in more than 100 oil wells operated by Santos, delivering net reserves of 4 million barrels. Beach Energy is in discussions with Santos, to supply its Gladstone liquefied natural gas (LNG) project.

Cooper Basin

 

Beach said its Cooper Basin position will allow it to tap the growing eastern Australian gas markets while also feeding the growing LNG demand in Asia. Beach noted that current Australian gas demand is approximately 700 pj per year, with around 100 pj to come from the Cooper Basin. Demand for more Cooper Basin gas is anticipated as domestic gas demand for use in power generation is expected to grow to around 1,100 pj by 2025.

The company estimates the Nappamerri Trough, which runs beneath its PEL 218 license, holds potential gas in place of more 200 Tcf, and holds properties similar to the best U.S. shale plays. Beach has drilled off-structure to determine the trough's deep basin gas potential, and found the target section thicker than anticipated at 1,289 feet and the target section gas saturated and over-pressured. Beach noted that no water bearing permeable sections were intersected in the target zone and immediately above and below target; the lack of water in these zones will assist in fracture stimulation.

The company has drilled two wells in PEL 218, which contains the Nappamerri Trough. The shale and sandstone target area for Beach's Encounter-1 well was 30 percent thicker than expected; Beach also spudded the Holdfast-1 well in January of this year.

Beach notes it has had encouraging results to date and expects material resource booking to take place this year. Results will assist in the design of future activities, including fracture stimulation in this year's second quarter and a pilot well program in the third or fourth quarter.

The company also sees near-term growth opportunities for oil in the Western Flank of the Cooper Basin. Beach began an operated 16-well development program here last month to accelerate production and will drill 12 exploration/appraisal wells with prospects ranging from .5 million barrels to 5.5 million barrel (gross).

The Cooper/Eromanga Basin

 

Drillsearch, which holds significant interests in the Cooper Basin, will began a five-well drilling program next month at its PEL91 license in Cooper's Basin's Western Flank. The five prospects, whose primary targets are the Namur and Birkhead channel, have estimated recoverable mean barrels of between 430,000 and 1.1 million. These prospects were defined using 3D seismic analysis; historically, Drillsearch has had 50 percent success rates using 3D seismic. Multiple commercial discoveries have been made on adjacent permits, and Drillsearch anticipates a short development cycle for the wells.

The company anticipates a formal award at mid-year for nine blocks in southwest Queensland, which will expand its Cooper Basin holdings. Drillsearch expects potential farm-outs of select areas starting in this year's second quarter.
Drillsearch is planning a significant drilling program for its estimated wet gas resources of 11.5 million BOE in the Cooper Basin. The company has made 10 gas/condensate discoveries in the area, including four declared commercial, and will pursue potential pilot development of the Middleton, Brownlow and Canunda discoveries. In the near term, the company plans a five well appraisal, development and near-field exploration program in PEL106B and PEL107.

Bengal Energy reports it has defined numerous leads and prospects on the Tookoonooka exploration permit ATP 732P, which the Queensland government announced a final grant of title to for Bengal effective April 1. Bengal will begin gather seismic data on the block and plans to drill between five and eight wells over the next 18 months. The company said the large block is offset by producing oil and gas fields, and features seven different play types, including four conventional light oil plays, two conventional gas and gas liquid plays, and one unconventional gas play.

The company also reports finding new potential fairway for oil-bearing Cretaceous Murta sandstones in its Cuisinier 1 discovery well, which began production in May 2010. Three wells are awaiting completion and testing either this month or in April, with the Cuisinier 3 cased as a potential oil well.