Harold Hamm is a big advocate of the potential of the Bakken field and it appears his confidence in the play is well placed. Continental Resources has increased its estimates by 57%, to the tune of 903 billion barrels of original oil in place. There’s been no word on what the recoverable rate would increase to with this new data.

Earlier this year, Continental estimated the Bakken holds 24 billion Boe of recoverable reserves. With the US Geological Survey slated to complete its reassessment of the Bakken in 2013, it seems these numbers will only go up if the trend continues.

OKLAHOMA CITY, Dec. 3, 2012 – Continental Resources, Inc. (NYSE: CLR) announced today it successfully completed the Charlotte 3-22H (91% WI), the first horizontal well to test the third bench (TF3) of the Three Forks zone in the Bakken field of North Dakota and Montana.

The Charlotte 3-22H flowed 953 barrels of oil equivalent per day (Boepd) at 1700 psi on a 28/64 choke in its initial one-day test period. Located in McKenzie County, North Dakota, it was drilled to a total depth of 21,324 feet, including a 9,701-foot lateral section, and was completed with Continental’s standard 30-stage fracture stimulation design.

“We’re very pleased with the initial performance of the Charlotte 3-22H,” said Harold Hamm, Chairman and Chief Executive Officer. “The well has been producing for 15 days and its performance compares favorably with other first bench (TF1) and second bench (TF2) producing Three Forks wells.”

Continental has been a pioneer in the discovery and development of the Three Forks reservoir in the Bakken field. The Company was the first to demonstrate incremental reserves from the TF1 in 2008 and the first to establish commercial production from the TF2 in 2011. Establishing production from the TF3 is yet another significant milestone in the growth of the Company’s assets in the world-class Bakken oil field. If the Charlotte 3-22H continues to perform in line with the second bench Charlotte 2-22H, it will be the first well to establish commercial production in the third bench.

“This could be a real game-changer,” Mr. Hamm said. “The Charlotte 3-22H is the first well in a 14-well program that we plan to complete by year-end 2013 to test productivity of the second, third and fourth benches of the Three Forks over a broad area of the play.”

The 1280-acre Charlotte unit is the first unit in the Bakken field to have wells producing from three separate horizons – the Middle Bakken, TF2 and TF3 zones.

Continental estimated in late 2010 that the Bakken field would eventually yield 24 billion barrels of oil equivalent (Boe), based on technology available at that time. This estimate included 20 billion barrels of oil and 4 billion Boe of natural gas, and assumed 577 billion barrels of original oil in place in the Bakken and TF1. With the addition of oil found in the lower Three Forks benches, which includes the TF2, TF3 and TF4, the Company now estimates the field has 903 billion barrels of original oil in place, a 57 percent increase.

“The successful completion of the Charlotte 3-22H is another step in our efforts to assess the productivity and reserve potential of the lower benches of the Three Forks which is one of the goals of our 2013 drilling program” said Jack Stark, Senior Vice President of Exploration. “The results are very encouraging and indicate there may be upside to our estimate of 24 billion Boe of recoverable reserves for the Bakken field.”

Retrieved 1-3-2013. Dakota Oil Jobs.

Dickinson, ND –

In 2012, North Dakota made oil headlines by taking over as the number two producer in the nation.

While production continues to ramp up daily, there is one part of western North Dakota were the excitement of oil has gone bust.

Chesapeake’s attempt to find the southern edge of the Bakken, is being described as the largest failure in drilling in the state since the 1980’s.

There are a few well sites in western North Dakota that look more like ghost towns than multi-million dollar holes.

Chesapeake secured leases in a large part of the state, south of I-94.

They drilled 8 wells, only 3 produced oil — but at minimal amounts.

So little that all holes have been shut in.

Director of Mineral Resources for the state of North Dakota, Lynn Helms, says “geologically, there were some surprises. We knew that there wouldn’t be any lower Bakken Shale in that area. What surprised us was to find out there’s no upper Bakken Shale in that area.”

Chesapeake’s wells, a bust.

It’s the largest failure in recent oil history in North Dakota.

“That pretty much condemns an area, if you don’t have Bakken present, the risk for finding oil goes way up and you need to have some structure,” says Helms.

The wells are scattered to the south of I-94 between Dickinson and Belfield.

Tanks are there, collecting nothing.

Well heads are in place, abandoned.

And at one site a pumping unit has been partially removed.

Helms says, “there’s only one well that’s made any measurable oil, and it’s about 10 percent oil at best, 90% water.”

Chesapeake was after the chance they may hit oil in this less developed area.

Helms says Chesapeake invested 60 million in the prospect of hitting oil.

That excludes money spent on leases.

“Because all the drilling had been taking place north of there and the geological risk was zero, it made it look too easy. So in terms of the technology of drilling and fracking, well prepared but in terms of geology probably not,” says Helms.

Chesapeake’s risk taking — provided large clues about where the Bakken ends. “It looks like 4-6 miles south of I-94 the Bakken Shale disappears,” says Helms.

Their experimental drilling will also provide answers about what else could be below.

Kathy Neset with Neset Consulting says, “they’re taking that information and they’re studying it. They are going to learn everything they can from those wells.”

Neset provides geology services to oil companies.

She says this is not the end of Chesapeake in North Dakota.

“They’re not going to say, we’re going to drill one well, if it doesn’t work, we are out of here. They have a very committed program in drilling and evaluating, I think we’ll see Chesapeake back here. They may be disappointed right now. But I think they’ll be back,” says Neset.

Maybe back and drilling in another formation.

Both Neset and Helms say there’s potential in the Tyler formation.

Helms says, “the area does lie between two producing Tyler fields and has mature Tyler source rock, so it’s not the end of the story by any means.”

Helms says Chesapeake will be forced to either reenter the well sites or to plug and abandon them soon.

The state only allows a non paying well to stay on the landscape for a year.

Retreived 1-2-2013. KX News.

BISMARCK, ND – Eighty-nine percent of North Dakotans statewide said they favor oil and gas development in state, and 55 percent said they strongly favor it according to a survey commissioned by the North Dakota Petroleum Council (NDPC) in November.

“North Dakotans continue to overwhelmingly support oil and gas development in the state because of the strong impact it has on growing our economy, creating tens of thousands of new, good-paying jobs, and in helping increase our nation’s energy security,” said Ron Ness, president of the NDPC. “We have seen an increase in the number of residents who strongly favor oil and gas development, and I believe that is an indication that the industry is developing these resources responsibly and with great consideration to the communities and landowners in western North Dakota.”

The survey is conducted annually to help the industry better gauge how North Dakotans feel about oil and gas development in the state and to identify key issues and challenges that the industry may work to address. The survey found that while a majority of North Dakotans favor oil development, more than 70 percent are concerned about truck traffic and cost and availability of housing. When asked about progress in these areas, however, 45 percent said progress was being made on roads and highways, 41 percent said progress was being made on availability of housing, and 60 percent said progress was being made on affordable housing.

Despite concerns for these and other areas, about the same number (71 percent) of North Dakotans believed that the benefits of oil development outweigh the risks. In fact, when asked if oil development should slow down on private land, 76 percent of North Dakotans said no, and 58 percent said development should not be slowed down on public lands.

“The industry recognizes that communities in western North Dakota are impacted by the rapid growth brought on by oil development, but this survey shows that we are making progress,” said Ness. “By and large, North Dakotans agree that while we do have challenges with our growth, these are good challenges to have, especially in light of high unemployment and a struggling economy nationwide.”

Since 1952, the Petroleum Council has been the primary voice of the oil and gas industry in North Dakota. The Petroleum Council represents more than 400 companies involved in all aspects of the oil and gas industry, including oil and gas production, refining, pipeline, mineral leasing, consulting, legal work, and oil field service activities in North Dakota, South Dakota, and the Rocky Mountain Region. For more information, go to www.ndoil.org.

View or Download the Survey here.

TransCanada Corp. remains confident that the amended plans for the northern portion of its Keystone XL oil pipeline project will obtain the approvals it needs from both Nebraska and the White House, the company said Wednesday.

The public comment phase of Nebraska’s consideration of the pipeline re-routing that avoids an environmentally sensitive region will conclude soon and the Canadian pipeline company expects it will be able to complete its reapplication for a Presidential Permit later by the end of the year.

“The outcome of the U.S. election doesn’t change our opinion that Keystone XL will be approved” and built by the end of 2014 or early 2015, said Alex Pourbaix, president of Energy and Oil Pipelines at an Investor Day event in Toronto. It was just about a year ago that the U.S. State Department delayed a decision on the project and then, in January, President Obama rejected the permit application.

The project has encountered significant opposition from environmentalists, politicians and others concerned that the carbon emissions of oilsands crude production and consumption would worsen global warming and that the pipeline put a major aquifer at risk of contamination from an oil spill.

Pourbaix’s comments came before Obama, in his first press conference since winning reelection, spoke of the need to address climate change. “I am a firm believer that climate change is real and impacted by human behavior and carbon emissions,” he said. “I think we have an obligation to do something about it.”

Obama went on to say he wasn’t aware of what Democrats or Republicans were prepared to do, but that taking on climate change in a serious way “would involve some tough political choices.”

For TransCanada, the need for the full Keystone pipeline system (stretching from Hardisty, Alberta to Houston and Port Arthur, Texas) grows stronger the longer it is delayed. At 1.4 million b/d and capable of exporting one third of all projected Canadian oil production, the completed Keystone system will provide crude oil delivery volume that can’t be matched by rail or truck, Pourbaix said.

In the last year, shippers previously committed to long-term contracts on Keystone XL have remained so and enough volume has been added to make the line fully committed for 20 years, said Russ Girling, TransCanada’s president and CEO. Nervousness about long-term commitments has given way to worries that oil production will outstrip takeaway capacity which, even with Keystone XL in place could occur by 2017.

TransCanada executives also discussed the progress of the proposed Eastern Mainline. Studies of both  economic and technical feasibility are well underway for the project that would involve the conversion of natural gas pipeline that runs east to Montreal and Toronto and the construction of new pipeline to connect the converted pipeline to the Hardisty hub. Capacity projections range between 500,000 to 1 million b/d, depending on where interest lies.

Executives reported that eastern Canada’s highest-in-the-country fuel prices, familiarity with crude oil movement (unlike British Columbia where pipeline construction is encountering significant opposition) and refiners’ desire to obtain crude cheaper than waterborne imports have stakeholders looking favorably on the project.

Allowing “a couple of years in permitting and a couple more in construction” makes 2017 a probable startup date if the Eastern Mainline Oil Pipeline were to go ahead, company executives said.

–Beth Heinsohn, bheinsohn@opisnet.com   |  www.opisnet.com

Eco-Trade Corp., an independent oil and gas exploration company, said on Monday that it has signed a Letter of Intent to purchase the South Bakken Prospect in Montana in an area that has the potential to produce between 80 and 120 million of barrels of oil recoverable.

Eco-Trade will have the rights to the exploration, drilling and production rights on a property in Lewis & Clark County in Montana, near Great Falls, totaling over 5,800 acres called the South Bakken Prospect.

The property is located in the southern part of the Alberta Bakken Fairway, which is at least 175 miles long (north-south) and 50 miles wide (east-west), and which extends from Alberta southwards through Montana’s Glacier, Toole, Pondera, Teton and Lewis & Clark counties.

The Alberta Bakken Fairway is time-equivalent to the Bakken Petroleum System of the Williston Basin, and is considered a proven play with production and DST hydrocarbon recoveries from the Bakken, and Exshaw Formation in Canada. While management believes that the letter of intent and subsequent agreement may conclude successfully, the company cannot warranty or guarantee success.

In October, Eco-Trade said it had begun an internal review of its business model and is exploring options in new businesses ventures and industries. The company is also studying its options for raising capital and is in discussions with various groups in that regard. This was quickly followed by a company announcement on Nov. 1 to enter the petroleum industry in Montana Bakken.

–Edgar Ang, eang@opisnet.com  |  www.opisnet.com

By Lynn Helms – NDIC Department of Mineral Resources

Jul Oil 20,963,713 barrels = 676,249 barrels/day
Aug Oil 21,735,166 barrels = 701,134 barrels/day (preliminary)(NEW all-time high)

Jul Gas 22,295,369 MCF = 719,205 MCF/day
Aug Gas 23,616,598 MCF = 761,826 MCF/day (preliminary)(NEW all-time high)

Jul Producing Wells = 7,467
Aug Producing Wells = 7,701 (preliminary)(NEW all-time high)

Jul Permitting: 183 drilling and 0 seismic
Aug Permitting: 261 drilling and 1 seismic
Sep Permitting: 273 drilling and 0 seismic (NEW all-time high)

Jul Sweet Crude Price = $71.13/barrel
Aug Sweet Crude Price = $80.65/barrel
Sep Sweet Crude Price = $84.98/barrel
Today Sweet Crude Price = $89.50/barrel ND (all-time high was $136.29 July 3, 2008)

Jul rig count 211
Aug rig count 198
Sep rig count 190
Today’s rig count is 186 (all-time high was 218 on May 29, 2012)

Comments:
August weather was great for drilling and hydraulic fracturing resulting in a 3.7% oil production increase from July to August. A combination of several factors has led to lower stable drilling activity, but continued rapid production growth. Rig count has stabilized at around 190 as operators transition to higher efficiency rigs and implement cost cutting measures. The idle well count decreased significantly indicating an estimated 300 wells (a 25% decrease) waiting on fracturing services. Rapidly escalating well costs that consumed capital spending budgets faster than many companies anticipated and uncertainty surrounding future federal policies on hydraulic fracturing are impacting capital investment decisions. Over 95% of drilling still targets the Bakken and Three Forks formations.

Crude oil take away via pipeline is now 43% of daily production, but transportation by rail at 46% and truck at 2% plus Tesoro refining 9% are adequate to keep up with near term production projections.

Rig count in the Williston basin is stable. Utilization rate for rigs capable of +20,000 feet is stable at about 90%, but for shallow well rigs that drill to 7,000 feet or less utilization remains about 60%.
Drilling permit activity has increased to accommodate more multi-well pads and the need to build locations before winter weather comes.

The number of rigs actively drilling on federal surface in the Dakota Prairie Grasslands is up to 7.

The number of rigs drilling on the Fort Berthold Reservation has dropped to 27 with 0 on fee lands and 27 on trust lands.
There are now 706 wells (101 on trust lands & 605 on fee lands)
Producing 119,644 barrels of oil per day (7,309 from trust lands & 112,925 from fee lands)
139 wells are waiting on completion
259 approved drilling permits (244 on trust lands & 15 on fee lands)
1,566 additional potential future wells (1,426 on trust lands & 140 on fee lands)

Seismic remains busy with 7 surveys active/recording, 1 remediating, 0 suspended, and 6 permitted.

North Dakota leasing activity is much slower, mostly renewals and top leases in the Bakken – Three Forks area.

Daily natural gas production is increasing slightly faster than oil production. This indicates that gas oil ratios may be increasing and more gathering and processing capacity will be needed. Construction of processing plants and gathering systems is in full swing due to the dry summer weather. US natural gas storage has dropped to 8% above the five-year average but this still indicates low prices for the foreseeable future. North Dakota shallow gas exploration is not economic at near term gas prices.

Natural gas delivered to Northern Border at Watford City is up to $2.96/MCF. This results in a current oil to gas price ratio of 30 to 1, but the high liquids content makes gathering and processing of Bakken gas economic. Additions to gathering and processing capacity are helping and the percentage of gas flared dropped to 29%. The historical high was 36% in September 2011.
Draft BLM regulations for hydraulic fracturing on federal lands were published in the Federal Register. The comment period closed at 5pm EDT on September 10, 2012. BLM has given no indication of when a final rule will be published.

Draft EPA Guidance for permitting hydraulic fracturing using diesel fuel has been published. The comment period closed at 5pm EDT on August 23, 2012. There is no indication from EPA of when a final guidance document will be published.

Graphic Courtesy of Hart Energy.

By: Edgar Ang, opisnet.com

The U.S. may be marching toward the politically charged “energy independence day” amid growing domestic oil production.

However, “the gap between U.S. oil production and consumption is large and may not close in the forecast period (2022),” Credit Suisse said in a report on U.S. oil production outlook.

“North American oil independence (U.S., Canada, Mexico) looks more achievable with appropriate policies to promote safe drilling, energy efficiency, regional coordination and gas substitution. However, we don’t hold out high hopes of the same low cost dividend to the U.S. economy provided by natural gas due to the relatively higher cost of oil shales and Canadian oil sands. Natural gas appears the best low cost energy policy bet,” the bank said.

U.S. oil production could reach just over 10 million b/d by 2020 and maintain this level for a number of years, according to Credit Suisse. The strong oil production growth estimate is based on high oil prices, a 27% higher oil well count by 2016 versus 2012, (58% higher than 2011) and a 25% improvement in 30-day initial production (IP) rates per well. Although the well count increases by 27%, the oil rig count only increases by 11% owing to improvements in drilling efficiency, which is defined as the number of days to drill a well.

Key shale plays to watch include the Eagle Ford, Bakken and Permian. After recent exploration success, the offshore Gulf of Mexico and potentially Alaska should also contribute some growth.

Single well economics suggest breakevens in the $60-75/bbl range for U.S. shales today. However, driving growth at forecast rates requires substantial capital — access to capital could be a greater constraint.

In a simple calculation, the U.S. oil industry needs around $95/bbl Brent near term to fund the capex required to deliver this growth, based on self-generated cash flow alone. This could be lowered by external funding, but we are already seeing some companies reduce capex when WTI recently fell through $90/bbl.

As U.S. oil production volumes rise, this breakeven could fall toward $80/bbl. It is important to note that the average recovery of a gas well is three to five times the recovery of a typical oil well on a Btu basis. The shale oil revolution should help meet rising global demand but looks less likely to lead to a collapse in domestic pricing similar to U.S. gas markets.

Price Impact

For downstream implications, the U.S. will require new trunkline pipes and gathering system to accommodate 600,000 b/d of annual oil production growth from the U.S. and 300,000 b/d of Canadian annual production growth through 2017, the bank said.

“Our short term model suggests WTI-LLS will remain wide through the second half of 2012 but narrow as Seaway, southern Keystone XL and Permian pipes are built through 2013,” Credit Suisse said. “Even as WTI-LLS spreads narrow, it is likely that a wider discount will remain for Bakken and Canadian Heavy crude through 2014,” it added.

Although oil supply from the U.S. and Canada is visibly growing, outside North America, non-OPEC supply growth is negative in 2012. Oil spare capacity increases towards 3% by 2015 (from 2% today) but markets may still reflect some risk premium over marginal costs, the bank said. “Risks to this view seem balanced. Spare capacity could rise faster if curtailments in Nigeria, Iran, Venezuela, Sudan were resolved. Spare capacity could fall, if a global economic recovery takes hold,” Credit Suisse said.

The rising oil and gas production is also expected to have an impact on the U.S. economy. The bank’s U.S. industry capex model suggests around $1.3 trillion dollars of spend between now and 2020. Low U.S. gas prices should encourage some $35 billion of petrochemical capex and a manufacturing renaissance. The logistics to bring shale hydrocarbons to market could total an additional $80 billion this decade.

Article republished, courtesy of Oil Price Information Service

(HELENA) The State of Montana will offer detailed training on a range of topics that includes air quality and discharge permitting, compliance requirements, and best business practices for contractors, opencut mining, materials processors, and the oil and gas industry.

The trainings will be in Sidney on October 1 – 3 at the Mondak Heritage Center, 120 3rd Ave SE,  and will be conducted by representatives of the Departments of Environmental Quality (DEQ) and Transportation (MDT). The trainings are free of charge and open to qualified registrants.

The three-day series is designed specifically to address practices surrounding opencut mining and associated development and growth seen in recent years throughout northeastern Montana.

“This training series provides valuable information that will save owner-operators and contractors time and money as they grow with the region,” said Darrick Turner, manager of DEQ’s Small Business Environmental Assistance Program. “Attendees will come away with a better understanding of the state’s environmental regulations and the permitting processes.”

Topics will include air quality and discharge permitting, and inspections. A full day is devoted to siting and compliance requirements and permitting for opencut operations. Enforcement and transportation issues will also be addressed.

Registration is available by calling 800-433-8773 or by emailing Darrick Turner at: dturner2@mt.gov.

By Lynn Helms – NDIC Department of Mineral Resources

• May Oil: 19,839,420 barrels = 639,277 barrels/day
• Jun Oil: 19,809,662 barrels = 660,332 barrels/day (preliminary) > NEW all-time high
• May Gas:  21,360,912 MCF = 689,062 MCF/day
• Jun Gas: 21,381,942 MCF = 712,7312 MCF/day (preliminary) > NEW all-time high
• May Producing Wells = 7,205
• Jun Producing Wells = 7,352 (preliminary) > NEW all-time high

May Permitting: 180 drilling and 2 seismic
Jun Permitting: 204 drilling and 0 seismic (all time high was 245 in Nov 2010)
May   Sweet Crude Price = $79.44/barrel
Jun   Sweet Crude Price = $72.58/barrel

Today Sweet Crude Price = $80.00/barrel ND (all-time high was $136.29 July 3, 2008)

• May rig count 211
• June rig count 213
• July rig count 211

Today’s rig count is 203 (all-time high was 218 on May 29, 2012)

Comments:

Great weather and additional crews resulted in increased hydraulic fracturing activity and increased production. Rig count has now decreased slightly to around 200-205 and rig efficiency continues to improve with the spud to TD time now averaging 20 days.  Daily production increased 3.3% from May to June. Over 95% of drilling still targets the Bakken and Three Forks formations. The idle well count stayed about the same indicating an estimated 347 wells waiting on fracturing services. This is expected to lead to significant production increases through the summer as additional fracturing crews are added.

Crude oil take away via pipeline is now less than 50% of daily production, but rail and truck transportation are adequate to keep up with near term production projections. The North Dakota Sweet posted price basis is now -14% to NYMEX-WTI and NYMEX-WTI basis is now -18% to Brent.  This is resulting in an increasing amount of North Dakota crude oil transported on rail so it can reach destinations that pay Brent price.

Mail: U.S. Department of the Interior, Director (630), Bureau of Land Management, Mail Stop 2134 LM, 1849 C St. NW., Washington, DC 20240, Attention: 1004-AE26.
Fax: Office of Management and Budget (OMB), Office of Information and Regulatory Affairs, Desk Officer for the Department of the Interior, fax 202-395- 5806.

There are a significant number of concerns with the rule as proposed, but the major points that should be commented on are as follows:

1)  This is a state’s rights issue.  States that have adopted hydraulic fracturing rules that include chemical disclosure, well construction, and well bore pressure testing should be exempted from the rule.

2)  The EPA study of potential hydraulic fracturing effects on ground water is not finished and there are currently no known environmental contamination incidents.

3)  As Chairman Hall has testified, the required consultation with the Three Affiliated Tribes has not occurred.

Draft EPA Guidance for permitting hydraulic fracturing using diesel fuel has been published.  The comment period has been extended to 5pm EDT on August 23, 2012.  I urge all of our readers to submit comments to the EPA as follows:

Submit your comments, identified by Docket ID No. EPA-HQ-OW-2011-1013 by one of the following methods: www.regulations.gov: Follow the on-line instructions for submitting comments. Email:OWDocket@epa.gov@epa.gov
Mail: Permitting Guidance for Oil and Gas Hydraulic Fracturing Activities Using Diesel Fuels—Draft, Environmental Protection Agency, Mailcode: 4606M, 1200 Pennsylvania Ave. NW, Washington, DC 20460.

There are a significant number of concerns with the guidance as proposed, but the major points that should be commented on are as follows:

1)  This is a state’s rights issue.  States that have adopted hydraulic fracturing rules that include chemical disclosure, well construction, and well bore pressure testing should be explicitly exempted from the guidance.

2)  The definition of diesel fuel is too broad because it includes six CASRNs as well as any materials referred to by one of these primary names or any associated common synonyms.

3)  EPA made no attempt to identify dangerous concentrations of these materials.

Hydraulic fracturing treatments that utilize concentrations of less than 10% of any material defined as diesel fuel should be exempt from permitting requirements.

4)  The guidance is written for Enhanced Oil Recovery wells or disposal wells completed with tubing and packer.  It shows a serious lack of understanding of the horizontal drilling-hydraulic fracturing process.  Most of the requirements will not work mechanically on wells completed with swell packers and fractured down the production casing.

“Director’s Cut.” By Lynn Helms – NDIC Department of Mineral Resources (2012-8-15). Retrieved 9-5-2012.