DNR Secretary Spotlights 3rd Possible Shale Play in La.

- DNR Secretary Spotlights 3rd Possible Shale Play in La.

Wednesday, August 31, 2011
Louisiana Department of Natural Resources

Louisiana Department of Natural Resources (DNR) Secretary Scott Angelle said Wednesday that the energy exploration industry has begun work on developing yet another new oil and natural gas shale play in Louisiana – giving the state one proven and producing shale formation and two that are being watched closely as the early stages of activity begin.

The potential new interest area, spanning portions of North Louisiana and southern Arkansas, is referred to as the "Brown Dense" or the "Lower Smackover," and is believed to be a layer of limestone at the base of the Smackover Formation – which itself is a well-known formation that has long been a source for traditionally produced oil and natural gas in North Louisiana.

The "Brown Dense" joins the Tuscaloosa Marine Shale as the second half of Louisiana's duo of dense rock plays believed to have the kind of production potential that has made shale plays such as Louisiana's Haynesville and the Barnett and Eagle Ford Shales of Texas the new normal in energy exploration. The Tuscaloosa Marine Shale is believed to underlie much of Central Louisiana, with potential productive areas currently being explored from Vernon Parish to East Feliciana Parish.

The energy industry is watching the development of the Tuscaloosa Marine Shale and the Brown Dense closely, as both are believed to have the potential to contain oil reserves, in addition to natural gas. New processes and technology have led to rapid gains in domestic oil and natural gas reserves, making them recoverable from ultra-dense formations once thought uneconomical to produce.

"We in Louisiana have a long and distinguished history of providing the energy that fuels this nation, and I am bullish on the future of energy production in this state and the role it will play in providing jobs and economic strength," Angelle said. "We are seeing that exploration companies and investors share that optimism and belief in Louisiana's natural resources as they seek new domestic reserves of oil and natural gas. The development of the Haynesville Shale natural gas play, the top-producing natural gas play in the nation, has helped give them that confidence."

Initial development of the Brown Dense formation, generally believed to underlie northern Claiborne, Union and Morehouse parishes in North Louisiana, has barely begun – with Southwestern Energy having begun the process of drilling its first well in Arkansas and having announced that it will seek a permit to begin drilling for a Brown Dense well in Claiborne Parish before the end of 2011.

Southwestern Energy has also announced that it has invested $150 million in leasing mineral rights for 460,000 acres to develop the play. Southwestern Energy recently applied to the Louisiana Office of Conservation for approval of an area of the Lower Smackover formation in Claiborne Parish near the Arkansas border as a designated unit for drilling.

Devon Energy has also announced that is has secured 40,000 acres in mineral leases for the Brown Dense and that the company intends to drill a test well for the play. Devon has already received a permit for a well targeting the deeper section of the Smackover in Morehouse Parish.

Devon is also active in the Tuscaloosa Marine Shale, where the company has secured 250,000 acres of mineral leases and is in the process of drilling two wells in the shale. About half a dozen wells targeting the Tuscaloosa Marine Shale – long thought to contain substantial reserves, but considered uneconomical to reach through previous methods – are currently in the process of permitting or drilling.

"New exploration methods have changed the game for development of energy prospects in Louisiana and the nation, as we saw firsthand with the incredible upswing investment and economic activity in North Louisiana in 2008," said Angelle. "This is yet another opportunity for Louisiana to show that we can be an inviting and exciting province to do the business of finding and providing new sources of domestic energy that provide economic strength and opportunity for our state and our nation."

"With that exploration of the denser formations will come the need for water for hydraulic fracturing," said state Conservation Commissioner Jim Welsh.

Welsh said that companies drilling for the Brown Dense formation have informed the Office of Conservation they intend to use surface water and recycled water for their overall project needs, in conformance with guidelines and advisories issued in nearby areas experiencing stressed ground water conditions.

The anticipated Brown Dense area of development in Louisiana underlies the Sparta Aquifer, which is currently experiencing improved water levels after combined state and local efforts to manage ground water use in the area.

"We are still discouraging new high-volume users from using ground water in that area, and giving guidance on alternative sources for water," Welsh said.

Oil & Gas Post

Promote Your Page Too
LINK

Rockhopper Boosts Estimates at Sea Lion Play

- Rockhopper Boosts Estimates at Sea Lion Play

Monday, August 15, 2011
Rockhopper Exploration plc

Rockhopper provided the following update on the interpretation of the fast track seismic data over acreage on licenses PL032 and PL033:

• Initial interpretation of fast track new seismic data in PL032 and PL033 completed
• Seismic shows Sea Lion Main Complex ("SLMC") to extend to the south and new high case area to extend over 90km2
• Two new fan prospects identified within new seismic, Casper and Kermit
• Management interpretation for SLMC potential size: 
  • Low Case: 608 MMbbls STOIIP
  • Mid Case: 1,086 MMbbls STOIIP
  • High Case: 1,279 MMbbls STOIIP

Volumes listed above are within Rockhopper's 100% owned acreage. Not included in the high case listed above, based upon the current interpretation, the Company believes that up to approximately 10% additional volume could be contained within license PL004, in which Rockhopper has a non-operated 7.5% working interest.

During 2011 the Company acquired a total of over 4000km2 of 3D seismic data in conjunction with other operators in the area. Data over the southern portion of licenses PL032 and PL033 has been fast track processed and an initial interpretation has now been completed. This initial interpretation, combined with well data from 14/10-2, 14/10-3, 14/10-4, 14/10-5 and 14/10-6, indicates that the SLMC comprises two fan lobes sourced from the same main feeder channel just to the east of the 14/10-5 and 14/10-2 wells.

The two lobes, represented as sand packages within the wells, are identified as the SL20 and SL10 units, and, from the formation pressure data acquired in the wells, are shown to be in pressure communication. The two packages together comprise the SLMC and are interpreted to comprise of mass flow turbidite sand sequences prograding from the sand input point to the east and extending beyond the southern boundary of license PL032 into license PL004, where Rockhopper has a non-operated 7.5% working interest.

The Company believes that recovery rates of 30% to 40% could be achievable using industry standard production techniques including water injection, artificial lift, deviated or horizontal wells and /or other enhanced oil recovery techniques.

Should a recovery factor of 30% be achieved, based upon the Company's mid case area, the SLMC would contain approximately 325mmbbls recoverable oil. Should a recovery factor of 40% be achieved, the mid case number would increase to 434mmbbls recoverable oil.

The fast track seismic interpretation has enabled the identification of two new feeders into the basin and the mapping of two new prospects, Casper and Kermit. Both of these comprise similar fan systems fed from eastern basin margin feeder channels and exhibit similar seismic character to the SLMC. Casper is stratigraphically shallower than the SLMC while Kermit is stratigraphically deeper than the SLMC.

Following well 14/10-6 the Company believes that the B15 sand, which forms part of the lower fan complex, has the potential to contain up to 161 mmbbls STOIIP on a high case basis. Formation pressure testing indicates that B15 is also in communication with the SLMC.

Fan prospects currently mapped on the Company's acreage are now SLMC, Lower Fan (B sands), Chatham, Casper and Kermit.

In addition to the SLMC, management interpretation of potential in place resources across the other fan prospects within the licence is set out below (All mmbbls STOIIP):

	Low	Mid	High
Lower Fan (B15)	100	130	161
Casper	135	163	194
Kermit	39	47	55
Chatham	28	93	318

The balance of the newly acquired 3D seismic data is still being processed and the Company expects it will be available for interpretation before the end of 2011.

Future Drilling Plans

Following completion of drilling operations on well 14/10-6, the Company is currently committed to drill three further wells using the Ocean Guardian drilling unit. The Company is discussing the possibility of drilling additional wells under an assignment agreement.

The Company intends to drill the next well 3.3km north west of the 14/10-2 discovery well. The second well in the sequence is currently planned to be located approximately 4.1 km to the south south east of the 14/10-2 discovery well. The third well in the sequence is currently planned to be located approximately 5.5km south west of the 14/10-2 discovery well. The second and third locations are subject to change depending upon drilling results and technical work and are subject to gaining the relevant regulatory consents. The Company currently intends to wait for the result of well 14/10-7 before deciding whether to take any additional drilling slots. Estimates of in place and prospective resource information are based upon wells drilled to date and could alter with future well results. Once the Company completes its current drilling campaign, all estimated potential in place resource estimates will be further refined.

Operations continue at the 14/10-6 location and a further announcement will be made once 14/10-7 has been spudded.

Sam Moody, Chief Executive, commented, "We are highly encouraged by the interpretation of new seismic data which identifies both significant reservoir extension and the existence of two additional fan prospects above and beneath the Sea Lion Main Complex. We look forward to continuing our drilling program as we seek to further refine our understanding of Sea Lion and the other prospects on our licenses."

Oil & Gas Post

Promote Your Page Too
LINK

Entek Preps Battle Mountain Well for Testing in Niobrara Play

- Entek Preps Battle Mountain Well for Testing in Niobrara Play

Thursday, August 11, 2011
Entek Energy Ltd.

Entek provided an update on the Niobrara Shale Oil Project Appraisal Program in the Green River Basin.

Battle Mountain 14-10L – The well is currently being prepared for testing in the Frontier Sandstone secondary objective. The completion procedure, which includes testing and fracture stimulation for the potential Niobrara pay zones is currently being refined by Halliburton.
Completion operations for the Niobrara are expected to start in September 2011.

Slater Dome (SD) Federal 24-9DL – The well has been spudded and is currently drilling the surface hole section at 400 ft. Casing is planned to be set at 2,500 ft before drilling the remainder of the well. The planned total depth of the well is 8,627 ft.

Entek holds a 55% interest in the Green River Basin Joint Venture (GRBJV) with Emerald Oil & Gas holding 45%. Entek is the Operator. The GRBJV now controls close to 80,000 gross acres, approximately 60,000 net acres, covering the Niobrara Shale Oil Play.

Oil & Gas Post

Promote Your Page Too
LINK

ConocoPhillips Expands Presence in Niobrara Play

- ConocoPhillips Expands Presence in Niobrara Play

Friday, July 29, 2011
ConocoPhillips

ConocoPhillips has entered into an agreement to acquire up to 46,000 net acres of leasehold from Lario Oil & Gas Company in the Colorado counties of Arapahoe, Adams, Elbert and Douglas. This agreement represents a significant investment by ConocoPhillips in this area south and east of the greater Denver metroplex.

"ConocoPhillips is pleased to have this opportunity to participate in the emerging Niobrara exploration and development play," said Larry Archibald, senior vice president of Exploration and Business Development at ConocoPhillips. "Building on the strong relationships developed by Lario, we look forward to working with all local stakeholders as a first step in demonstrating our commitment to act as a steward of this region's natural resources."

ConocoPhillips will become operator of the acquired leases and will begin exploration efforts as soon as possible with the acquisition of a 3-D seismic survey and drilling of test wells. The company has a long track record of safe and environmentally prudent development of unconventional plays in North America and will leverage the knowledge and expertise it has gained in plays such as the San Juan Basin, Bakken, Barnett and Eagle Ford.

"Lario Oil & Gas Company is pleased to make this significant transaction with an industry leader such as ConocoPhillips," said Mike O'Shaughnessy, President/CEO of Lario. "As demonstrated by ConocoPhillips' safe and successful history of developing unconventional plays, the project will be operated with the greatest regard for the local residents and environment, and for the benefit of all parties concerned."

Oil & Gas Post

Promote Your Page Too

Floating LNG to Play Greater Role in Global Gas Development

- Floating LNG to Play Greater Role in Global Gas Development

Thursday, July 21, 2011
Rigzone Staff
by Karen Boman

While floating liquefaction technology has yet to be commercially proven, the success of floating liquefied natural gas (FLNG) could open previously stranded or non-commercial gas reserves worldwide.

In May, Shell made the final investment decision to proceed with the development of its Prelude floating LNG project. Shell's Prelude facility, which will be deployed in the Browse Basin offshore Northwest Australia, will be the largest floating structure ever built.

While Shell's decision to push ahead with the Prelude project is a major breakthrough for FLNG liquefaction, the unit will not come on stream until the second half of the decade, said Douglas-Westwood analyst Lucy Miller. There are a number of other projects ongoing, but it's likely that these will also fall into this timeframe; no other projects have been approved. "On the whole, onshore developments are still favored; however, FLNG may prove to be more competitive in certain cases depending on the specific project's requirements."

Austral-Asia is seen as a key region for FLNG, particularly the Timor Sea offshore Australia and Papua New Guinea; other key areas include Southeast Asia and offshore Brazil, Miller said.

Douglas Westwood last year estimated that over $23 billion would be spent on FLNG development from 2010 to 2016, most of which will be spent on liquefaction facilities. During that time, Australia is expected to dominate the FLNG market with $5.3 billion in projects, followed by Africa with $5.2 billion in projects and Asia with $4.7 billion in projects. While North America has the greatest number of FLNG prospects, North American projects are expected to account for only seven percent of global expenditures from 2010 to 2016.

Douglas-Westwood views FLNG solutions as a solution for monetizing stranded gas assets that lie far offshore and distant to production infrastructure, addressing the security issues of onshore facilities and pipelines or boundary disputes such as the Timor Sea and South China Sea, and creating a market for gas that would normally be flared.

Accessing stranded gas reserves will be critical to meet the anticipated rise in global gas demand due to population and economic growth, particularly in emerging economies such as China. Douglas-Westwood notes that 6,531 Tcf of gas reserves remain worldwide; 3,000 Tcf of these reserves are considered stranded gas assets.

FLNG may allow Europe other gas supply options that could wean its dependence on Russian gas. More than 40 percent of the European Union's gas is imported -- about half of which comes from Russia – and imports are expected to rise to 75 percent by 2030. Europe's dependence on Russian imports makes it vulnerable to price hikes and supply cut-offs, as demonstrated when Gazprom doubled prices and cut supply going to the Ukraine, Lithuanian, Belarus and Georgia from 2006-2009.

FLNG import terminals are operating in Argentina, Brazil, Kuwait, the UK and the U.S. These include a mix of technological concepts such as regasification vessels and floating storage and regasification units. Some of the technologies involved in proposed FLNG projects have yet to be proven, Douglas-Westwood noted. Technical challenges facing FLNG development include development of sloshing-resistant containment systems; cryogenic offloading, side by side by loading arms or by tandem offloading; marinisation of liquefaction processing equipment; field specific and general topside modules; and the need to develop multiple small-scale or large-scale FLNG vessels, or vessels between 1 and 3 mmtpa and greater than 3 mmtpa.

Besides Shell, other companies seeking to develop liquefaction FLNG facilities include Flex LNG, Petrobras, SBM Offshore, Bluewater, Hoegh LNG, Excelerate Energy, ConocoPhillips and Sevan Marine are developing FLNG liquefaction design concepts, but no specific fields have been announced.

The anticipated start of operations on Flex LNG's FLNG project in Papua New Guinea (PNG) in 2014 is "perfect timing" for the anticipated wave of Asian LNG demand, Flex LNG reported earlier this year. Flex LNG in April entered agreements agreement with Interoil, Pacific LNG, Liquid Niugini Gas Ltd., and Samsung Heavy Industries for a FLNG project in PNG that would liquefy natural gas from the onshore Elk and Antelope gas fields in PNG's Gulf Province.

Samsung last month began field specific front-end engineering and design work (FEED) for the hull portion of the FLNG vessel. WorleyParsons and Kanfa Aragon will carry out the FEED work for the topsides. Samsung will remain responsible for the overall design, engineering, construction and commissioning of the FLNG vessel. FEED is set to be completed in time for the project to reach a Final Investment Decision before the end of this year, with operations in PNG targeted to begin in 2014.

FLEX LNG has already completed a generic FEED in 2009 and the field specific FEED will tailor the vessel for the PNG project where the FLNG vessel is expected to be moored alongside a jetty and have a nominal production capacity of close to 2 million tons of LNG per annum and to process an estimated 2.25 trillion cubic feet of gas over a firm 25-year period. The Elk and Antelope gas fields have substantial certified gas resources, with 6.5 Tcf of P90 resources and 8.6 Tcf and 10 Tcf in P50 and P10 estimates respectively.

Flex LNG reported that LNG projects are more costly than ever to develop, as the capital expenditures/ton of installed liquefaction capacity has made a permanent shift over the last decade from an average figure below 500USD/ton to typical range of 1,500-2,500 USD/ton. Due to the uniqueness of projects, current LNG development costs exceed the average cost for the oil and gas industry. Flex LNG anticipates that it will be in the lower end of the USD550-700 ton/liquefaction capacity CAPEX range for its PNG project.

Oil & Gas Post

Promote Your Page Too
LINK

Newfield All Smiles over Uteland Butte HZ Play

- Newfield All Smiles over Uteland Butte HZ Play

Wednesday, July 20, 2011
Newfield Exploration Co.

Newfield Exploration provided a comprehensive update on its Uinta Basin oil development programs. The update follows the May 2011 closing of two acreage acquisitions for approximately $300 million. Combined, the two transactions added approximately 70,000 net acres. Newfield today owns interest in approximately 250,000 net acres in the Uinta Basin where its average working interest is more than 70%. Multiple oil-productive geologic targets exist across the acreage and an active drilling campaign is underway.

"We have a proven growth history in the Uinta Basin," said Lee K. Boothby, Newfield's Chairman, President and CEO. "We have been growing our oil production and reserves in the region since our entry in 2004. It's clearly an oil play where we have a competitive advantage. We drill 'best in class' wells, operate substantially all of our operations and have the personnel in place today to increase our activities cost effectively. We plan to aggressively develop our 6,000-plus well inventory of oil locations."

"We are excited about the potential of our new Uteland Butte horizontal oil play, as well as the early successes in our Wasatch development. These two new oil plays provide some of the highest return projects in our drilling portfolio today. We will optimize our drilling programs and continue to grow our domestic oil production in 2012. Over the last two years, we have effectively demonstrated our ability to shift people and capital to projects that yield both growth and returns."

For 2012, Newfield plans to increase its operated rig count in the Uinta Basin from an historic five-rig count to at least eight rigs. The Company expects 2012 Uinta Basin daily production will grow at least 25% over 2011. The increased play options combined with fewer permitting constraints will allow Newfield to significantly increase its future growth in production and reserves from the basin.

The Company's net resource potential in the Uinta is estimated today at more than 700 million barrels of oil (MMBO) equivalent. In addition to the shallow Green River oil play, Newfield today provided results from recent drilling in deeper oil objectives prevalent throughout the Company's acreage. A table summarizing the plays and their net resource potential is included within this release.

Uteland Butte

Recent transactions have added acreage north of the Company's traditional area of drilling -- Monument Butte. This area is referred to as the "Central Basin." Uteland Butte is a new horizontal oil play being developed by Newfield from 6,000' – 9,000' (total vertical depth, or TVD) and is prevalent across Monument Butte and the Central Basin – or approximately 80% of Newfield's total acreage in the basin. Portions of the play are geopressured and are expected to result in higher production rates and estimated ultimate recovery (EUR).

During the last year, Newfield has drilled six horizontal wells in the play. All of the wells to date have been drilled in the Monument Butte field. Initial gross 24-hour production rates from the Company's most recent wells have averaged 24-hour initial production (IP) of approximately 500 barrels of oil equivalent per day (BOEPD), or more than six times the IP rate of a traditional, vertical Green River well.

Based on an estimated inventory of at least 1,800 locations (160-acre spacing), Newfield's net resource potential associated with the Uteland Butte formation is nearly 300 MMBO equivalent. The Company estimates that the wells will have an average gross EUR of approximately 300,000 BO equivalent and can be drilled and completed on average for approximately $2.8 million.

Newfield plans to complete an additional four horizontal wells in the Uteland Butte play in the second half of 2011. In 2012, the Company plans to drill more than 30 horizontal wells in the play.

Wasatch

The Wasatch formation is being developed throughout the Central Basin and is prospective at depths of 9,000' – 11,000' TVD. This is a southerly extension of the giant Altamont Bluebell field which has cumulative production to date of more than 400 MMBO equivalent. Over the last year, eight vertical wells have been drilled on Newfield's acreage. Recent vertical wells have average gross 24-hour IP rates of more than 1,000 BOEPD.

Newfield estimates that the net resource potential for this play is more than 45 MMBO equivalent. To date, the Company has identified approximately 380 locations (320-acre spacing) with expected average EURs of more than 260,000 BO equivalent. Gross completed well costs vary by geologic depth and are estimated to range from $1.2 – $3.3 million. The Company believes significant upside exists with future application of horizontal drilling and completion technology and through increased drilling density, which could double the expected net resource potential.

The Company expects to complete an additional 25 wells in the Wasatch in the second half of 2011. In 2012, Newfield expects to drill at least 50 wells in this play.

Green River

Newfield has been actively developing the shallow Green River formation since entering the Uinta Basin in 2004. Approximately 2,100 wells have been drilled to date on the Company's acreage. Newfield's Green River oil play is economically productive across at least 165,000 net acres.

The Company estimates that more than 4,000 undrilled locations remain to ultimately develop the Monument Butte field on 20-acre spacing and the Central Basin acreage on 40-acre spacing. Substantially all of the Company's acreage at Monument Butte is located on acreage under Bureau of Land Management jurisdiction. At the current pace of drilling activity, this equates to more than a 10-year inventory. To date, Newfield has drilled more than 300 wells on the Central Basin acreage and, with additional data, believes the area could be prospective for future waterflood and 20-acre development. Current resource estimates do not include the potential for 20-acre spacing or secondary recovery in the Central Basin.

Newfield estimates that the Green River formation has net remaining resource potential of approximately 360 MMBO equivalent (includes developed and undeveloped waterflood potential only in Monument Butte). At year-end 2010, Newfield had proved reserves in the Green River formation of approximately 140 MMBO equivalent.

Gross production from the Uinta Basin has grown from approximately 7,000 BOPD to approximately 22,000 BOPD today. Green River wells are today being drilled and completed in four to five days for approximately $930,000 gross. The wells have a gross EUR of approximately 75,000 BO equivalent. Since the Company's 2004 entry into the Monument Butte field, expected recovery of oil in place has increased from about eight percent to 16% or more. Newfield expects to drill about 300 wells in the shallow Green River in 2011. For 2012, Newfield expects to drill 250 – 300 wells as additional resources are allocated toward the new Uteland Butte and Wasatch plays.

Infrastructure Investments

Newfield is investing approximately $75 million into field infrastructure projects in 2011 – nearly matching the Company's cumulative investment in infrastructure from 2004-10. As development drilling has moved northeast and into deeper geologic horizons, the gas:oil ratio has increased. As a result, additional compression and enhanced gathering infrastructure is now required to accommodate the increased gas production. Once fully operational, the new facilities will allow for increased oil production from these areas. The Company expects to invest about $100 million into infrastructure projects in 2012 to accommodate long-term oil growth objectives from the Uinta Basin.

Oil & Gas Post

Promote Your Page Too
LINK

Nextraction Increases Position in Provost Viking Play

- Nextraction Increases Position in Provost Viking Play

Thursday, July 14, 2011
Nextraction Energy Corp.

Nextraction has substantially increased its leasehold position in the Provost Viking A oil pool by 92%, increasing its net acreage position from 1.625 to 3.125 sections (1040 acres to 2000 acres). Nextraction acquired one section at a 100% working interest (640 acres net to Nextraction) at a cost of $701,584, and one section at a 50% working interest (320 acres net to Nextraction) at a cost of $401,088. The two newly acquired sections are contiguous to each other and are one mile from the Company's existing 50/50 joint venture acreage, allowing for the potential to use existing infrastructure. The acquisition essentially doubles the Company's drilling inventory of horizontal locations up to 36 wells. Nextraction has identified 21 locations on 400 meter spacing whereby the Company could drill at least 4 wells owning 100% interest, and own a 50% interest in 17 locations (resulting in a further 8.5 net wells). In addition, another 15 locations may be drilled at a 50% interest (7.5 net wells), should down spacing be warranted.

The acreage is also prospective for light oil production from the Dina formation that is approximately 150 meters below the Viking formation. A historical well on the acreage produced 18 Mbbls of oil from the Dina formation.

The Company is also pleased to announce that it participated in the successful re-completion of a well on its existing acreage. The well had not been previously fracture stimulated, so the well was fractured using the same technique the Company plans to use on its first horizontal well. Prior to re-completion of the well in mid-June, it produced three barrels of oil per day and is now currently producing 29 barrels of light oil per day, a ten-fold increase. Payout is projected at three months.

The Company is encouraged by the results of the frac as it confirms the high productivity potential of the Company's acreage. The well has been producing for two years and is located directly between two wells that have cumulatively produced 520 Mbbls to date and continue to produce 20 bbls per day of oil. Reservoir pressure measured after completion was near original pressure, suggesting little depletion. The high production rates from the well are consistent with the high pressure and indicate good quality reservoir, as expected. The Company is currently drilling its first horizontal well in the pool offsetting these wells and plans to multi-stage fracture this first horizontal well in the Viking zone in the coming days. The Company also plans to drill a second horizontal well on this joint venture acreage in the third quarter of 2011.

Mark S. Dolar, President & CEO of Nextraction, commented, "We value the Crown leases acquired yesterday as a strategic asset to our Company's growth. We believe the acreage to be very prospective for a multi-well development program and will expand our ability to focus on developing the Viking formation for value added reserves. With our experience and expertise in developing the Viking sand by horizontal drilling and multi-stage fracturing, we see this project as an excellent way to add significant oil reserves as we move towards our goal of being 80% light oil weighted by the end of this year."

Oil & Gas Post

Promote Your Page Too
LINK

Gulfport Adds Acreage in Utica Play

- Gulfport Adds Acreage in Utica Play

Monday, July 11, 2011
Gulfport Energy Corp.

Gulfport reported an increased acreage position in the Utica Shale of Eastern Ohio and resource assessment and provided an update on the TEW-E exploratory well in Thailand.

Utica Shale Leasing Update

Gulfport continues to actively expand its acreage position in the Utica Shale of Eastern Ohio. To date, Gulfport has acquired leasehold interests in approximately 35,000 gross (17,500 net) acres. Gulfport currently has commitments which could bring its position in the Utica Shale to approximately 110,000 gross (55,000 net) leasehold acres if it acquired all such committed acreage. Gulfport is also currently evaluating additional acquisitions in the Utica Shale that could potentially increase its commitments to approximately 130,000 gross (65,000 net) leasehold acres in the coming months. Gulfport will serve as operator of its acreage in the Utica Shale and currently plans to bring a rig into the play in early 2012 to begin drilling its acreage.

TEW-E Exploratory Well Update

Tatex Thailand III, a company in which Gulfport owns a 17.9% interest, concluded drilling operations on the TEW-E well in March 2011, the second exploratory well drilled by Tatex III on an approximate one-million acre concession block in Northeastern Thailand. The well was drilled to a total depth of 15,026 feet and logged over 5,000 feet of apparent possible gas saturated column. TEW-E experienced gas shows and carried a flare measuring up to 25 feet after drilling below the intermediate casing point of 9,695 feet.

As previously announced, Tatex III recently conducted a coil tubing operation meant to remove compacted debris that formed a blockage in the open-hole portion of the TEW-E wellbore. Due to the limited pumping capacity of the coil tubing unit, the operation was unsuccessful in removing the blockage. Consequently, Tatex III has scheduled a drilling rig to return to the TEW-E by September 2011 and commence operations to remove the debris and test the well.

Oil & Gas Post

Promote Your Page Too
LINK

Doxa to Acquire Additional Interest in Mississippian Oil Play

- Doxa to Acquire Additional Interest in Mississippian Oil Play

Friday, July 08, 2011
Doxa Energy Ltd.

Doxa has exercised its option to acquire a twenty percent (20%) leasehold interest in an existing project situated in the emerging Mississippian Oil Play ("Mississippian Oil Play") in Oklahoma. Under the terms of a previously announced Letter of Intent (see Doxa news April 27, 2011) with Dynamic Production, Inc., as amended, the Company was granted the right to acquire up to twenty percent (20%) interest in existing leases, as well as an ongoing lease acquisition program primarily in Alfalfa, Garfield, Grant and Kay Counties, Oklahoma. Dynamic Production, Inc. of Fort Worth, Texas, is managing the project and has a stated goal of acquiring approximately 18,000 acres within the play. The play is led by Chesapeake Energy Corporation, SandRidge Energy, Inc. and Eagle Energy of Oklahoma, LLC. Doxa estimates that it will ultimately acquire 3,600 net acres in this round of leasing, at a cost of approximately US $2,200,000.

John D. Harvison, President and CEO of Doxa stated, "The Mississippian Oil Play is an emerging horizontal play that has the potential to become one of the most profitable domestic onshore oil plays today, and as such has the potential of providing significant growth for Doxa as well as exceptional value for our shareholders."

According to recent public disclosures by these leading companies, this play exhibits excellent economics with single well estimated ultimate recovery projected at 300-500 MBOE and with drilling and completion costs estimated at US $3.0mil per well. In recent presentations to various professional associations over the past months, SandRidge has reiterated that it expects to achieve over 100% (i)ROR, and a net present value per well of approximately US $5.9mil, based on recent Nymex strip pricing. Based on current knowledge of well spacing disclosures from area operators, Doxa anticipates that up to 72 gross wells may ultimately be drilled on the acreage block, or 14 wells net to Doxa, based on its twenty percent (20%) participation level. The Company plans to release additional information on the proposed acquisition once details are finalized.

Oil & Gas Post

Promote Your Page Too
LINK

Breitling Charges Ahead in Haynesville Play

- Breitling Charges Ahead in Haynesville Play

Tuesday, July 05, 2011
Breitling O&G Corp.

Breitling O&G issued an operational update on the company's recent activity related to the development of various oil and gas properties in its portfolio. Oil and Gas is working very hard to retain all of its viable Haynesville leases in this difficult pricing environment.

Through June 15, 2011 the company participated in 171 new wells, 21 operated and 150 non-operated. The company is running 4 rigs currently. Breitling Oil and Gas expects to drill an additional 112 wells in the second half of 2011. The company has two frac fleets on retainer and had an inventory of ten wells awaiting completion as of June 2011. Breitling Oil and Gas has leaseholds in Texas that are prospective for the Eagleford Shale; leaseholds in Colorado that are prospective for the Niobrara Shale; leaseholds in Oklahoma that are prospective for the Woodford Shale; and leaseholds in Louisiana that are prospective for the Haynesville and Bossier Shales. The company recently hydraulic fractured its fifth Eagleford well in Guadalupe County, Texas and will commence production operations on this well sometime in August 2011. The company is working in partnership with Sandridge Energy on three wells in Gaines County, Texas and is preparing to spud a well with Devon Energy in Hemphill County, Texas.

Breitling Oil and Gas is developing the Haynesville Shale on acreage in Louisiana, and has three gross wells waiting on completion. The company expects hydraulic fracturing capacity to be available in August 2011 and will start completion operations on this backlog at that time.

Breitling Oil and Gas is working in the Woodford Shale in Oklahoma. The company has six prospects it plans to drill during the second half of 2011. It expects production to commence from the field in early 2012.

Breitling Oil and Gas chief executive officer Chris Faulkner stated, "Breitling has done a great job shifting its focus to liquids during a very difficult gas commodity trading price this year." Faulkner added, "Breitling Oil and Gas is carrying very little debt, is involved in no litigation and lawsuits, has a perfect safety record and has positioned itself for triple-digit revenue growth for the foreseeable future."

The company continues driving innovation within its EnviroFrac™ program which the company started in January 2010. Breitling Oil and Gas' EnviroFrac™ calls for the elimination of any additive not critical to the successful completion of the well and determines if greener alternatives are available for all essential additives.

Oil & Gas Post

Promote Your Page Too
LINK

Abraxas Ramps Production at Bakken/Three Forks Play

- Abraxas Ramps Production at Bakken/Three Forks Play

Wednesday, June 29, 2011
Abraxas Petroleum Corp.

Abraxas provided an operational update.

Rocky Mountain – North Dakota / Montana

In McKenzie County, North Dakota, Abraxas drilled the Stenehjem 27-34 1H to a total measured depth of 16,504 feet, including a 5,965 foot lateral in the middle Bakken formation, and completed the well with a 17-stage fracture stimulation. The well was recently placed on production, including gas (and natural gas liquids) directly into the sales line, and is currently in the early stages of cleaning up and producing at rates in excess of 800 barrels of oil equivalent per day, which is comprised of approximately 600 barrels of oil, 100 barrels of natural gas liquids and 700 Mcf of residue gas. We anticipate providing initial rates (after recovery of frac fluid) when 30-day rates are also available. Abraxas owns an approximate 79% working interest in this well.

In various counties in North Dakota and Montana, fourteen non-operated horizontal wells, targeting the Bakken or Three Forks formation, in which Abraxas owns a working interest are currently in progress or recently placed on-line. Four gross (0.15 net) wells went on production in mid-June, three gross (0.15 net) wells have been fracture stimulated and are currently cleaning up, three gross (0.50 net) wells are waiting on completion and four gross (0.07 net) wells are waiting on a drilling rig. Since January 2010, Abraxas has elected to participate in 19 gross (1.02 net) non-operated wells in the Bakken / Three Forks play.

In McKenzie County, North Dakota, two gross (0.11 net) non-operated horizontal wells targeting the Mission Canyon have been drilled and completed and are currently waiting on production facilities.

Abraxas anticipates being in a position in the near future to discuss long-term service availability to allow a multi-year continuous development plan on its Bakken / Three Forks acreage.

Rocky Mountain - Wyoming

In Campbell and Niobrara Counties, Wyoming, a two well oil development program is scheduled to begin this fall. One of these horizontal wells will target the Niobrara formation and one will target the Turner formation. Abraxas owns a 100% working interest in each of these wells.

Rocky Mountain – Alberta Basin Bakken

Abraxas has been approached by a number of companies in the industry with respect to a joint venture or similar arrangement; however, Abraxas has elected to wait for more definitive results from wells drilled to-date in the play before planning a course of action. Abraxas' leases have a primary term of 5-10 years providing plenty of time to evaluate the results of other operators in the play.

South Texas – Eagle Ford

Abraxas currently owns a 50% equity interest in Blue Eagle, which is a joint venture between Abraxas and Rock Oil Company, LLC.
In DeWitt County, Texas, Blue Eagle's first well, the T-Bird 1H, continues to outperform expectations and is currently producing approximately 1,100 barrels of oil equivalent per day, which is comprised of approximately 200 barrels of condensate, 340 barrels of natural gas liquids and 3.2 MMcf of residue gas. The well has produced approximately 200,000 barrels of oil equivalent during its first 150 days on production. Blue Eagle owns a 100% working interest in this well.

In DeWitt County, Texas, Blue Eagle participated in a non-operated horizontal well with its 43.9% working interest. The well, the Matejek Gas Unit 1, was drilled to a total measured depth of approximately 17,865 feet, including a 3,600 foot lateral, and recently completed with a 14-stage fracture stimulation. The well flow tested at restricted rates in excess of 780 barrels of oil equivalent per day through a choke while recovering frac fluid. The well is currently shut-in waiting on pipeline hookup.

In Atascosa County, Texas, the Grass Farms 1H should spud this week as the rig is currently rigging up. This well is located in the oil window of the play and will be drilled to a total measured depth of approximately 12,500 feet, including a 5,000 foot lateral. A fracture stimulation date has been secured for this well in August. Blue Eagle owns a 100% working interest in this well.

South Texas – Portilla

In San Patricio County, Texas, seven wells have been drilled and completed to-date in the multi-well in-fill drilling program and one additional well was recently recompleted. Three of the new wells targeted the dual objectives of the 7,400 and 8,100 foot Frio sands and four targeted the 7,400 foot Frio sand. These wells have increased production in the field by 100% and have added approximately 300 barrels of oil equivalent per day, 82% of which is oil. This drilling program has met the Company's economic expectations and six additional locations remain to be drilled, all of which are scheduled for later this year. Abraxas owns a 100% working interest in each of these wells.

West Texas

In Nolan County, Texas, the Spires 126 2H recently reached a total measured depth of approximately 9,000 feet, including a 2,000 foot lateral. Completion operations will commence on this well in the near future. Abraxas owns a 100% working interest in this well.
In Coke County, Texas, in the NE Millican Reef field, Abraxas anticipates drilling two vertical delineation wells targeting the Canyon Sand play which is located approximately 30 miles to the southwest of Spires Ranch in the near future. The rig that drilled the Spires Ranch well will move to drill one of these two wells, after which, the rig will return to Spires Ranch for a continual horizontal development program, and assuming favorable results on the first well, the rig will return to NE Millican when convenient to drill the second well. Abraxas owns a 100% working interest in these wells.

In Reeves County, Texas, Abraxas recently acquired 640 net acres, for a total of approximately 3,000 net acres, in the emerging Wolfbone play. Two wells directly adjacent to our acreage are being currently drilled by the industry.

Canada - Pekisko

In Alberta, Canada, production from the Twining 9-11 remains relatively stable at approximately 100 barrels of oil equivalent per day. Two wells offsetting the successful Twining well will be drilled back-to-back, the first of which spudded this week. The two wells will be drilled horizontally and will target the Pekisko formation. Canadian Abraxas owns a 100% working interest in each of these wells.

Comments

"With the expected performance of the Portilla and Twining wells and the recent new production in the Bakken / Three Forks play, we have more than offset production disruptions from wells shut-in in the Williston Basin due to unprecedented high water and flooding. With all of our drilling activity, we should be in a position to continue sequential quarterly production growth for the foreseeable future," commented Bob Watson, Abraxas' President and CEO.

Oil & Gas Post

Promote Your Page Too

Fountain Quail Expands Ops into Eagle Ford Play

- Fountain Quail Expands Ops into Eagle Ford Play

Friday, June 24, 2011
Aqua-Pure Ventures Inc.

Fountain Quail, a wholly owned subsidiary of Aqua-Pure Ventures, announced it will expand operations into the Eagle Ford Shale in South Texas through a subcontracting agreement with NAC Services, LLC, an affiliate of Noise Attenuation Construction Services. Terms of the agreement were not released.

Fountain Quail will initially send two Nomad units to NAC's water purification treatment center in Kenedy, Texas, to recycle wastewater generated during the process of extracting oil and natural gas from the Eagle Ford Shale. The Company expects to employ approximately 15 workers at the new facility, which will have the capacity to recycle roughly 5,000 barrels of flowback and produced water per day. The agreement calls for an initial term of five years, with the option to renew for another five-year term.

"We have been eyeing the Eagle Ford for some time, looking for the right opportunity to expand into this emerging shale play," said Jake Halldorson, chief executive officer of Calgary-based Aqua-Pure Ventures, the premier recycler of industrial wastewater in North America. "We're pleased to have negotiated a mutually beneficial relationship with NAC, and we look forward to bringing our industry-leading recycling technologies to a region where preserving fresh water resources is paramount."

Fountain Quail has developed and refined its patented, industry-leading technology for recycling flowback and produced water over the past seven years in North Texas' Barnett Shale. During that time, the Company has recycled more than 14 million barrels of shale gas wastewater that would otherwise have been injected into disposal wells and permanently removed from the hydrological cycle. The company's technology is also currently being utilized in the Marcellus Shale.

"We contracted with Fountain Quail because they provide the most advanced, cost-effective recycling technology in the industry," said Mando Gutierrez of Noise Attenuation Construction (NAC), LLC of Weatherford, TX. "The need for their services in the Eagle Ford is already great, and expected to grow exponentially over the months ahead."

In addition to recycling wastewater into distilled or treated water for re-use in hydraulic fracturing operations, Fountain Quail and NAC will sell the concentrated brine and other byproducts of the recycling process.

Aqua-Pure is currently evaluating opportunities to expand into additional shale plays across North America later this year.

Oil & Gas Post

Promote Your Page Too

Samson O&G Acquires Additional Acreage in Bakken Play

- Samson O&G Acquires Additional Acreage in Bakken Play

Friday, June 24, 2011
Samson O&G Ltd.

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

Samson's new Roosevelt Project is being acquired in three tranches:

Tranche 1 is a 20,000 acre block to be acquired immediately upon closing that includes a two well drilling obligation. Tranche 2 is an option to acquire an additional 20,000 acres upon the completion of the initial two wells in Tranche 1. Tranche 3 is a 50,000 acre area covered by an Area of Mutual Interest where Samson and FPEC have agreed to jointly acquire additional leases.

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

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

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

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

Oil & Gas Post

Promote Your Page Too

Goodrich Adds Acreage in Tuscaloosa Play

- Goodrich Adds Acreage in Tuscaloosa Play

Monday, June 13, 2011
Goodrich Petroleum Corp.

Goodrich has purchased leases totaling approximately 74,000 net acres in the Tuscaloosa Marine Shale oil trend in Louisiana and Mississippi. The Company paid approximately $13 million, or an average of $175 per net acre for the acreage.

The Company anticipates development to commence in the first quarter of 2012.

Oil & Gas Post

Promote Your Page Too

Tag Extends Mt. Messenger Play with Oil Discovery

- Tag Extends Mt. Messenger Play with Oil Discovery

Tuesday, June 07, 2011
TAG Oil Ltd.

TAG Oil reported that the recently drilled Cheal-C1 exploration well has now set production casing to total depth, in order to production flow test the light oil potential identified in both the Mt. Messenger (~1600m), and the deeper Moki (~2,200m) formation targets. The Cheal-C1 well was drilled directionally from the new "Cheal-C site" in TAG Oil's Petroleum Mining Permit 38156 (PMP 38156) in the Taranaki Basin, New Zealand.

The Cheal-C1 well was drilled approximately 3.5 km to the northwest of the existing Mt. Messenger producing wells, with results extending the Mt. Messenger oil saturation area over a considerably larger area than previously known. Over 15 meters of net oil-and-gas bearing sandstones were intercepted in the Mt. Messenger with good porosity and free oil encountered while drilling through the zone.

The Mt. Messenger was the primary objective of the Cheal-C1 well however it was deepened to a total depth of 2382 meters (7815 feet), to test the down-dip edge of a large closure within the deeper Moki Formation. Strong oil and gas shows were encountered within a 73-meter thick, high quality section of porous and permeable sandstone. Any future wells directly targeting this Moki Formation structure will be drilled in an updip position, which could potentially intersect substantially more of the hydrocarbon-charged Moki sandstones.

"We are very pleased to have extended the Mt. Messenger play into the "C" block, and look forward to further exploiting this oil-prone area," TAG Oil CEO Garth Johnson commented. "We're also very optimistic about the Moki Formation discovery potential, which is a prolific oil producer in the offshore Maari oil field. However, very few wells have targeted this formation onshore so we will need flow-test data before any conclusions are reached in regards to its commercial potential."

Oil & Gas Post

Promote Your Page Too

Nexen to Take Stake in Marathon's Polish Shale Play

Nexen to Take Stake in Marathon's Polish Shale Play

Wednesday, April 27, 2011
Marathon Oil Corp.

Marathon Oil has signed an agreement with a wholly owned subsidiary of Nexen under which Nexen will acquire a 40 percent working interest in 10 of Marathon's concessions in Poland's Paleozoic shale play.

"We are pleased Nexen will be joining Marathon to explore the resource potential of the substantial shale play acreage position we have established in Poland," said Annell R. Bay, Marathon's senior vice president of Worldwide Exploration. "This partnership provides not only financial risk mitigation but combines the extensive unconventional drilling and completion experience of Marathon and Nexen to fully evaluate the potential of these concessions."

Marathon currently holds an interest in 11 concessions in Poland, encompassing 2.3 million acres. The shales are Lower Paleozoic and located at depths of between 8,000 and 13,000 feet. Marathon plans to acquire 2D seismic during the first half of 2011, potentially followed by the drilling of one to two wells in the fourth quarter of 2011 and seven to eight wells during 2012. Marathon will remain operator of the 11 concessions.

MicroSeismic Bags 2nd Contract in Marcellus Play

MicroSeismic Bags 2nd Contract in Marcellus Play

Thursday, April 21, 2011
MicroSeismic Inc.

MicroSeismic has been awarded a second BuriedArray™ contract in the Marcellus Shale play in northern West Virginia by Gastar Exploration.

"We are excited about our continued work in the Marcellus," said Peter Duncan, CEO and Founder of MicroSeismic, Inc. "This second award demonstrates the work we are doing in the Marcellus and other plays is creating value for our customers."

Gastar's Vice President and Exploration Manager, Keith Blair, commented, "Gastar has used MSI's FracStar in East Texas and because of the knowledge gained we have decided to implement their BuriedArray in our Marcellus Shale Play. We look forward to optimizing our completion techniques and in turn maximizing our production and minimizing our capital investment from the microseismic data gathered."

El Paso Corp. to Solely Develop Eagle Ford Play

El Paso Corp. to Solely Develop Eagle Ford Play

Thursday, April 14, 2011
El Paso Corp.

El Paso Corporation has decided to develop its Eagle Ford Shale program without a partner. This decision follows an extensive evaluation of proposals from potential partners.

"While interest in our Eagle Ford shale position was high, we believe that we will create greater value for shareholders by developing it
ourselves," said Brent Smolik, president of El Paso Exploration & Production Company. "The Eagle Ford shale program is one of our most
valuable assets, and we are very excited about the future of this program. It is a key resource for oil reserves and production growth;
the wells in our Central area in LaSalle County, Texas are exceeding our expectations, and we continue to drive efficiencies in our
drilling and completion processes as we have in the Haynesville shale program."

RAM to Test Productivity of Osage Play

RAM to Test Productivity of Osage Play

Monday, April 11, 2011
RAM Energy Resources Inc.

RAM updated on activity in its Mississippian oil play in Osage County, Oklahoma. Approximately $5.4 million, or 15%, of RAM's 2011 capital expenditure budget totaling $35 million is allocated to the company's 56,320 acre concession, a part of the broad Mississippi Chat / Mississippi Solid / Arbuckle oil play in the region. Interpretation of the first phase of 3-D seismic, acquired in 2010, and initial drilling results indicated that a substantial portion of the acreage surveyed could be prospective. Although the Mississippi Chat has been the company's primary objective to date, the company's practice is to drill through the Chat and through the Mississippi Lime formation in order to gather additional science for future development. The initial wells drilled have encountered Chat zones 40-70 feet thick and porosities ranging from 20% to 35%. Similarly, initial wells have drilled through Mississippi Lime zones of 100 feet, or more, in thickness with a porosity range similar to the 5% to 15% range of porosities experienced by other operators in the western portions of the play.

"We are encouraged with the initial results from our Osage concession and have allocated a large proportion of our capital budget to test the productivity of the area. The combination of rig availability, relatively low drilling cost per well and ample infrastructure in the area allows us to aggressively pursue the play in the coming year," said Larry Lee, CEO of RAM.
Stepped up Pace of Drilling Planned in Osage Mississippian Exploration Play

Following the drilling of the company's three initial vertical wells in the concession during 2010, the company drilled the Farmland #1 during the first quarter 2011, targeting the Mississippi Chat formation. Currently the company is evaluating cores taken from the well. Also during the first quarter 2011, the Surber #3-SWD, a salt water disposal well, was drilled to service existing and future producing wells in the area. In the Surber #2-Twin, drilled during the first quarter near the Surber #3 SWD, core samples have been taken and casing set. RAM is awaiting the evaluation of the core data prior to completing.

The Rickets #3 well and the Surber #1 well, which were drilled to the Mississippi Chat formation late in 2010, have been fracture stimulated in order to test the impact of the slick water frac technique on reservoir permeability, thus advancing the science and knowledge associated with completion techniques in the area. Completion of the salt water disposal well facilitated the ability to fracture these and other planned wells in the area. The company has spud the next well in the series, the Surber #2-27, approximately one section to the west of the Surber #2-Twin. This offset to the Surber #1 and Surber #2-Twin is an exploration well targeting the continuation of the Mississippi Chat formation through seismic identification and sample cuttings from a previously drilled well by another operator. In mid-April the Farmland #2-16, an exploratory well, is scheduled to spud, also targeting the Mississippi Chat. The well, located approximately 2 sections northwest of the Surber #2-Twin, has been permitted and the location built. Immediately following the drilling of this well, the rig is scheduled to move to the location of the Christiansen #3-2. This exploration well is scheduled for a spud date later in April. The well targets the Arbuckle formation and will evaluate the Mississippi Chat and Lime formations. Two wells initially planned for the fourth quarter, the Surber #1-35 and the Rickets #1-35, are now likely to be drilled late in the second quarter as a result of rig availability. The drilling permit application process is underway for both of these wells. The location of the wells is anticipated to be immediately south of the successful Surber #1 well drilled in late 2010 which recorded an initial production rate of 80 barrels of oil per day (BOPD) in the Mississippi Chat formation.

Subsequently, in the third quarter 2011, the company plans to drill the Farmland #1-20 exploration well located southwest of the Farmland #2-16. At the northern boundary of RAM's initial seismic survey, the company plans to drill three wells; the Kendrick #1-27, the Stuart #1-28 and the Jones #1-33. These three exploration wells are designed to test the productivity of the Mississippi Chat and Lime formations in this unexplored part of the concession. If commercial potential exists, then RAM is likely to also drill another salt water disposal well to service these and potentially other future wells in this area of the lease. Archeological studies are proceeding on these wells which are precursors of the drilling permitting process.

In May 2011 the company plans to initiate acquisition of a second round of 3-D seismic on its Osage concession adjoining that of its first round of seismic acquisition. This second phase of 3-D seismic acquisition is planned to cover an additional 19,840 acres in the company's concession and is anticipated to add additional drilling prospects principally for 2012 and beyond when interpreted, later in 2011.
Advantaged Revenue Stream

Within the broad Mississippian play, the portion of the area covering RAM's Osage concession appears to yield primarily oil. Accordingly, commercialization of the company's acreage could add significantly to RAM's already above-industry-average mix of oil and oil-price driven natural gas liquids (NGL) in its hydrocarbon mix. The proportion of crude and NGLs as a percent of total BOE produced rose to 66% in December 2010 (adjusted to exclude assets sold in December 2010). Similarly, based on RAM's proved reserves at year-end 2010, oil and NGLs accounted for 64 percent of total proved reserves.

Crimson Fires Up Production at Eagle Ford Play

Crimson Fires Up Production at Eagle Ford Play

Monday, April 11, 2011
Crimson Exploration Inc.

Crimson announced the successful completion of the Littlepage McBride #1 (53.0% WI), located in Karnes County, TX and targeting the Eagle Ford Shale, commencing production in the first week of April at a gross daily rate of 876 barrels of oil and 717 Mcf of natural gas on a 14/64th choke with 2,845 psi of flowing tubing pressure. The well was drilled to a total measured depth of 15,885 feet, including a 4,800 foot lateral, and was finalized, from spud to first production, in 70 days. The Littlepage McBride represents Crimson's first well on its 1,250 gross acre position in Karnes County, which is adjacent to other significant drilling and producing activity in the oil window of the Eagle Ford play. The Company intends to follow its restricted rate philosophy, currently being utilized in the East Texas Haynesville play, in its Eagle Ford program and does not anticipate increasing the rate further, although the well performance to date suggests it is capable of much higher rates.

Allan D. Keel, President and Chief Executive Officer, commented, "The successful completion of the Littlepage McBride validates Crimson's position in the oil bearing window of the Eagle Ford Shale in Karnes County. Given this initial success in Karnes County and current crude oil prices, Crimson plans to reallocate additional capital to accelerate drilling activities in Karnes County in 2011 to optimize cash flows and shareholder return on oil weighted opportunities. We have also been fortunate enough to have obtained scheduling commitments from our drilling and completion services providers that will enable us to pursue our drilling plans for all of 2011 without delay risks related to the tight market for those services."

In Liberty County, TX, the Catherine Henderson #A-9 (66.0% WI) commenced production at the end of March at a gross daily rate of 9.6 Mmcfe, or 4.4 Mmcf, 578 barrels of condensate and 286 barrels of natural gas liquids on a 12/64th choke and 7,200 psi of flowing tubing pressure. This well was drilled to a total measured depth of 13,150 feet in the Cook Mountain formation. Crimson is currently drilling below 12,850 feet on the Catherine Henderson B-4 (64.0% WI) toward a total measured depth of 13,500 feet and is scheduled to spud the Catherine Henderson A-10 (66.0% WI) in May.

In our Bruin Prospect Area of San Augustine County, TX, we have successfully completed 14 stages of frac on the Kodiak #1 well (70% WI) in the Mid Bossier Shale and expect initial production to begin within the next two weeks. Completion operations have commenced in the Haynesville Shale formation on the Blue #1 well (70.7% WI), also in the Bruin Prospect Area, with initial production expected around the first of May.

We anticipate spudding the KM Ranch #1 well, our first Eagle Ford well in Zavala County, TX, by the beginning of May. We have approximately 4,675 gross acres (50% WI) in Zavala County that we believe to be prospective in the oil window of the Eagle Ford Shale. This operated well is expected to be drilled to a total measured depth of approximately 12,500 feet, with a projected 5,500 foot lateral.