Friday, February 29, 2008

EOG Resources announces 4 new oil plays

EOG Resourcse has about 600,000 acres in these four new plays which estimated combined reserve potential of 1.2 to nearly 1.6 billion BOE

Barnett Shale Oil Play: After drilling 8 horizontal oil wells in the Fort Worth Basin they see reserve potential of 225 to 460 million BOE here on their acreage across three counties. First significant production will come in 2009 (part of the reason for the upped oil guidance.

North Park Basin, Colorado - Horizontal Oil Play - they see 10-80 million BOE reserve potential here (again, we're talking oil and 2009 when this impacts numbers). "This could be as big as their Bakken oil play of North Dakota"

British Columbia - Horn River Basin - Shale Gas Play Analogous To The Barnett. Drilled 3 horizontal gas wells with encouraging results so far. No economics given, just some IP's in the 3 to 5,000 Mcfepd range. Esimated reserve potential of 6 Tcfe here which is pretty stunning given: 1) their normal predisposition towards conservatism and 2) the early nature of the play - they must really like what they see here.

Jefferson Davis County, TX - Mississippi Chalk Play where they see 200 Bcf of reserve potential having drilled 3 horizontal wells to date.

Wednesday, February 27, 2008

StackFrac drilling system makes Bakken formation economic

Packers Plus Energy Services Inc., Calgary-based company, says its unique technology can deliver precisely-controlled fracs along a horizontal wellbore at an affordable price. "Without our StackFrac system, the Bakken formation in southeastern Saskatchewan would still be uneconomic for the most part," says Dan Themig, president of the seven-year-old private firm.

Producers had already attempted straightforward stimulation of open hole horizontal well bores, sometimes dubbed "Hail Mary" fracs. That tactic sometimes worked but more often the formation would crack mainly at its weakest point rather than along the entire wellbore. Overstimulation at one point not only limits the increase in oil or gas production but sometimes triggers water incursion into the well.

An alternative approach was attempted on horizontal wells which had been cased with a production liner and then cemented. The wellbore would be segmented with bridge plugs, then stimulated through perforations in the steel liner. This technique required multiple coiled tubing trips. Fracing each segment of the wellbore involved rig up and rig down of the stimulation equipment. This type of operation may take weeks and generates expenses that frequently prove uneconomic. Although horizontal drilling was well established by the turn of the century, the oilpatch still hungered for a satisfactory horizontal stimulation method - quick, consistently cost-effective and repeatable on a large scale.

A StackFrac operation begins with the insertion of a steel liner into the well. The liner is segmented with tire-shaped rubber seals called packers, capable of sustaining differential pressure ratings of 10,000 psi at 400 degree Fahrenheit. (See the drawing above.) Between each pair of packers are one or more ports. Each port includes two features, an aperture and a specific diameter. The aperture, when opened, permits frac fluid to flow into the annulus - the space between the liner and rock formation. Also, the internal diameter of each port is smaller than its neighbour, with the smallest diameter at the end of the liner (the importance of this feature will become clear in a moment).

Once the liner is fully in place, frac fluid is pumped through it into the well. After full circulation is achieved, the rubber packers are expanded. They can increase in size by 40% and will conform to hole irregularities like ovalities and washouts. A small ball is then inserted into the frac fluid and is pumped along the liner until it seats itself within the last port. (For example, the ball may be two inches in diameter, the diameter of the final port a half inch smaller.) As pressure rises against the seated ball, the adjacent port aperture opens and frac fluid flows into that "stage" or segment of the wellbore. The fracturing or rock cracking process is sometimes tracked with microseismic gear to ensure that it's effective.

When the bottom segment of the well has been fraced, the crew will inject a slightly larger ball into the well, which will seal and open the next port. The process will be repeated until the entire wellbore has been stimulated. Acidizing can also be handled through the ports. Well sections not worth stimulating can be passed by. Each stage can be production-tested individually if desired. Frac design can be tailored to avoid overstressing any section of the wellbore, greatly reducing the risk of water incursion. If water does invade a portion of the wellbore, that stage can be sealed off. The liner is left in place and, if appropriate, can be designed for use in further downhole operations.

To date, the record TVD (true vertical depth) is more than 15,000 feet and the deepest well has been more than 25,000 feet MD (measured depth). Themig is confident that 30,000 feet will be manageable within six months.

Despite mounting successes across the Western Sedimentary Basin as well as the United States, the novel technology didn't make much splash until two years ago. That's when Petrobank began applying it in the Saskatchewan Bakken. Unstimulated, a Bakken horizontal well typically makes 10 to 30 barrels per day, hardly an economic return for an expenditure of $1.2 million. When stimulated using earlier technologies, however, water cuts routinely jumped from near nothing to 70% of total production. StackFrac enabled Petrobank to stimulate oil flow with minimal additional water, which transformed the Bakken into Canada's hottest oil play.

Canadian oil and gas trust paid $120,000 per flowing barrell for Bakken lands

Canadian insurer Manufacturer’s Life, in a 50 percent interest in a partnership with NAL Oil and Gas Trust (NOIGF.PK) on February 11, 2008, set a record in purchasing Bakken Lands in Southeast Saskatchewan.

The MLI/NAL partnership acquired two private companies, Tiberius Exploration and Spear Exploration, for a total of $115 million. The new partnership receives 3,336 acres of land, 2.1 million barrels of P+P reserves and a current 925 barrels of daily production.

The key metric in this purchase for investors to be aware of is the 120,000 dollar per flowing barrel cost the partnership paid in this transaction.

If the investor looks at Crescent Point Energy Trust’s (CPGCF.PK) January 16, 2008 purchase of Pilot Energy, you see that CPT in a very comparable deal paid 73,000 dollars per flowing barrel or 66 percent of what NAL/MLI did for their Bakken purchases several weeks later.

CPT received 24 percent more acreage with 22 identified low risk drill locations in addition to a full 1,000 BOE a day of production for 76 million dollars as compared to NAL and MLI’s $115 million purchase.

The American side has yet to see the consolidation like the Canadian side due to a much larger land area that offers plenty of “running room” for explorcos. Inevitably, it is a matter of time before drilling success is achieved in the Dakotas and Montana with increasing 3-D seismic delineation and improved technology to extract the oil source. With that will come consolidation, but not for awhile.

Thursday, February 14, 2008

Petrobanks Bakken Oil

Petrobank had 58 (55.5 net) successful Bakken wells drilled in the first ten months of 2007, 52 (49.5 net) are currently on-stream. Nov 2007, Petrobank Bakken oil production was approximately 5,650 bopd.

Jan, 2008 Petrobank Closes a deal that bought Peerless Energy Petrobank's in Jan 2008 has over 12,200 boepd of high netback, Bakken production. Petrobank now has an inventory of 540 net Bakken locations based on a drilling density of only four wells per section, and we plan to drill 154 of these locations in 2008, which we expect will make Petrobank the most active operator in the play. If the 154 wells follow the average well that they currently have 16800 bopd of production should be added in 2008 for a total of 29000 bopd. The 390 other locations would be expected to add 44,000 bopd for 73,000 bopd by 2010. This from 0.1% of the total Bakken formation. Presumably this is one of the better spots, but if the rest averaged out to only 10% of the quality then that would still mean 100 times the production or 7.3 million bopd. Montana already produces over50,000 bopd from the Bakken Formation and the Parshall field part of the Bakken in North Dakota looks like it will produce over 100,000 bopd.

The majority of Petrobanks Bakken land base is expected to yield four horizontal wells per section. Petrobank's internal estimate is that each well will recover in excess of 150,000 barrels. Nov 2007, Petrobank estimate our drilling inventory at 532 (497 net) locations.

The Bakken formation is capable of high initial production rates of sweet, light, 41+ degree API gravity oil, and liquids-rich solution gas. This resource is significant with approximately 4.5 million barrels of original oil-in-place per section (square mile or 640 acres) of land within the defined play area.

The key to unlocking the potential in the Bakken has been recent advances in horizontal well techniques, particularly the application of new horizontal fracturing and completion technologies. Horizontal wells allow maximum exposure to the reservoir, and new completion techniques allow fracturing of the siltstone along the full extent of the wellbore to maximize production. Our horizontal drilling and fracture stimulation techniques allow us to avoid fracturing out of the Bakken zone, thereby minimizing associated high water production common in earlier horizontal wells, and consequently significantly improving oil productivity. Ultimately we expect this to lead to substantially improved recovery rates.

Petrobank drilled 28 (25.5 net) Bakken wells, bringing the total for the first three quarters of 2007 to 52 (47.3 net) wells. We now anticipate that by year-end we will have drilled approximately 62, 100% working interest, wells and an additional 12 (5.5 net) non-operated wells for a total of 74 (67.5 net) Bakken wells in 2007.

Wednesday, February 6, 2008

Bakken Oil formation could have 500 billion barrels of oil in place

The Bakken oil formation is possibly the largest conventional oil discovery in Canada since 1957.

That means that the Bakken oil is more than the Pembina's reserves, which were estimated to contain 7.8 billion barrels of oil, of which 1.6 billion were recoverable. To date, more than 1.2 billion barrels have been produced and it's still going strong. Big oil, say the engineering types, gets bigger.

If this oil formation plays out toward the higher end of size and recoverability then it will change the geopolitics of oil and the economies of the United States and Canada. If a lot of the oil proves difficult to recover now, new technologies could still drastically improve the percent recoverable. The motivation to pull out another 100 billion barrels would be $9 trillion at todays prices.

Estimates are anywhere from a conservative 25 billion barrels of oil in place, to a high estimate by the United States Geological Survey of 400 billion barrels of oil in the Bakken formation. Not only is the oil plentiful, but it's high quality too, 41 degree light sweet crude. The Bakken formation is a formation of black shale, siltstone, and sandstone. The formation lies beneath the Mississippian formation, Saskatchewan's current source of light sweet crude. The Bakken formation is situated beneath southeastern Saskatchewan, southwestern Manitoba, and North Dakota.

In 2007, EOG Resources out of Houston, Texas reported that a single well it had drilled into an oil-rich layer of shale below Parshall, North Dakota is anticipated to produce 700,000 barrels of oil.

The resources of the Bakken Formation are defined by the United States Geological Survey (USGS) as unconventional “continuous-type” oil resources. This means the hydrocarbons within the Bakken have not accumulated into discrete reservoirs of limited areal extent. With new horizontal drilling and completion technology taken into account, the technically recoverable resource base for the entire Bakken Formation is potentially much larger.

Isopach map of the Bakken formation in Saskatchewan, Canada (Map of the areal extent and thickness variation of a stratigraphic unit; used in geological exploration for oil and for underground structural analysis)

The Williston Basin covers approximately 300,000 square miles over parts of North Dakota, South Dakota, and Montana and parts of the adjacent Canadian provinces of Saskatchewan and Manitoba. The Bakken formation can be encountered throughout the Williston Basin.

Application of new drilling and completion technology has begun to unlock new potential in this legacy basin. There is speculation that the total resource in the play could be in the billions of barrels.

Hydrocarbon Potential of the Bakken and Torquay Formations,
Southeastern Saskatchewan by L.K. Kreis and A. Costa

Much of the oil reservoired within the Bakken shale likely resides in a network of enhanced porosity and permeability related to microfractures.

• Upper and Lower Bakken shales showing anomalously high resistivity values in southeastern Saskatchewan suggest that they are saturated with oil that has either been generated in place or has migrated into these locations.

• Basement structures, such as those associated with the Brockton-Froid lineament, and compactional features in regions of Middle Devonian salt dissolution may control fractures that serve as primary migration pathways for Bakken-sourced oils into possible plays in the Bakken and Torquay formations.

• The relatively low permeability of Bakken and Torquay reservoirs are likely best exploited through horizontal wells.

• A large untested and poorly evaluated rock volume remains in the Bakken and Torquay formations of southeastern Saskatchewan, within which there may be significant potential for finding new oil.

Porosities in the Bakken average about 5%, and permeabilities are very low, averaging 0.04 millidarcies—much lower than typical oil reservoirs. However, the presence of horizontal fractures makes the Bakken an excellent candidate for horizontal drilling techniques in which a well drills along the extent of the rock layer, rather than punching a hole vertically through it. In this way, many thousands of feet of oil reservoir rock can be penetrated in a unit that reaches a maximum thickness of only about 140 feet. Production is also enhanced by artificially fracturing the rock.

Oils with an API gravity of 40 to 45 have the highest market price and those with values outside this range sell for less. Above an API gravity of 45, the molecular chains become shorter and are less valuable to a refinery. Crude oil classified as light, medium or heavy, on the following basis:
Light crude oil has an API gravity of above 31.1 °.
Medium oil has an API gravity in the range 22.3 ° and 31.1 °.
Heavy oil has an API gravity less than 22.3.

In 1992, Energy and Mines estimated there was roughly 100 billion barrels of oil in the Bakken formation throughout the entire Williston Basin.

Dancsok, who co-authored the 1991 study, said the prevailing view in the geoscience community at the time was "the potential of the Bakken was immense, but the price of oil in 1991 was not such that people wanted to risk (exploration and development dollars)."

Dancsok estimated roughly 25 per cent of the Williston Basin, which covers some 200,000 square miles (518,000 square kilometres) is located in Saskatchewan. Based on that simple arithmetic, the estimate of Bakken oil in the province could range anywhere from 25 billion barrels to 100 billion barrels of oil in place.

Of course, geology isn't that simple.

"Whether the Bakken is evenly distributed throughout the basin is one question," Dancsok said. "It is deeper in North Dakota. But is the distribution of Bakken oil equal in Saskatchewan to North Dakota or Montana? That's a big question mark."

Research documents for purchase from the Saskatchewan government

North Dakotas Bakken Reserve estimates

New estimates of the amount of hydrocarbons generated by the Bakken were
presented by Meissner and Banks (2000) and by Flannery and Kraus (2006). The first of
these papers tested a newly developed computer model with existing Bakken data. Data
used was not as extensive as some of the other studies mentioned in this discussion
therefore estimates of generated oil presented were 32 BBbls. The second paper by
Flannery and Kraus used a more sophisticated computer program with extensive data
input supplied by the ND Geological Survey and Oil and Gas Division. Early numbers
generated from this information placed the value at 200 BBbls (pers. comm. Jack
Flannery, 2005). Estimates had been revised to 300 BBbls when the paper was presented
in 2006. Even if the lower value of 32 BBbls is correct, the amount that may be
potentially recovered from the Bakken is significant.

How much of the oil that has been generated is technically recoverable is still to
be determined. Price places the value as high as 50% recoverable reserves. A primary
recovery factor of 18% was recently presented by Headington Oil Company for their
Richland County, Montana wells. Values presented in ND Industrial Commission Oil
and Gas Hearings have ranged from 3 to 10%. The Bakken play in the North Dakota side
of the basin is still in the learning curve. North Dakota wells are still undergoing
adjustments and modifications to the drilling and completion practices used for this
formation. It is apparent that technology and the price of oil will dictate what is
potentially recoverable from this formation.

New cheap computer modeling could allow access to about 218 billion barrels of oil that is still in the ground in the USA in old wells and less economical fields.

Microwave oil recovery could make it cheaper to extract a lot more oil from oil shale (up to 800 billion barrels in the USA extractable) and from the oil sands. (Up to 2 trillion barrels in Canada's oilsands.

Al Fin also has a feature on the Toe to Heel Air Injection (THAI) technology for extracting oil from tar sands deposits.

A posting and msg board related to the EOG Resources well

EOG resources website

In the United States EOG’s total crude oil and condensate production increased 23 percent compared to the same quarter a year ago, driven by continued drilling success in North Dakota and the Mid Continent.

EOG announced 2008 total company production growth targets, ranging from 13 to 17 percent, depending on drilling economics and North American natural gas prices. Production growth in 2008 will be driven by United States operations, particularly the Fort Worth Basin Barnett Shale natural gas and the North Dakota Bakken crude oil plays, both very high rate of return programs

2007 EOG Resources SEC filings

In the United States, EOG's total crude oil and condensate production increased 23 percent compared to the same quarter a year ago, driven by continued drilling success in North Dakota and the Mid Continent.

In Mountrail County, North Dakota, EOG has reported successful drilling from the Bakken Formation. The Wenco #1-30H, in which EOG has a 52 percent working interest, was completed to sales at the end of September at an initial production rate of 1,930 barrels of oil per day (Bopd), gross. Also in Mountrail County, the Austin #1-02H was completed to sales in October at an initial production rate of 2,000 Bopd. EOG has a 100 percent working interest in the well, which is located nine miles north of existing production. This is the northernmost location that EOG has drilled to date. To further confirm the northern extension of the field, following completion of the Austin #1-02H, EOG drilled an offset well, the Austin #2-03H that will be completed in November. Based on shows during drilling, EOG expects the well to produce at a rate similar to that of the Austin #1-02H. EOG has an 81 percent working interest in the Austin #2-03H. In the North Dakota Bakken Play, where it has accumulated over 175,000 net acres, EOG plans to increase drilling activity from six to eight rigs in early 2008.

"The results from the two Austin wells have given us the confidence to increase estimated reserves in the Bakken Play from the previously announced 60 million barrels of oil to approximately 80 million barrels, net to EOG. By extending the perimeter of the field, we have also increased our inventory of firm drilling locations. Therefore, we expect this area to have a significant impact on EOG's oil production in 2008 and beyond. The Bakken is currently the highest rate of return play in our drilling program," said Mark G. Papa, Chairman and Chief Executive Officer

North Dakota Bakken

Zacher 1-24H - EOG has a 75 percent working interest in the Zacher 1-24H that was completed in June with a peak production rate of 1,774 barrels of oil per day (Bopd), gross.
Hoff 1-10H - EOG has a 75 percent working interest in the Hoff 1-10H, which began flowing to sales in June at a peak rate of 2,034 Bopd, gross.
N&D 1 - 05H - EOG holds a 67 percent working interest in the N&D 1-05H, which was completed in July at an initial peak production rate of 1,610 Bopd, gross.

Rocky Mountain Oil Journal: EOG Confirmed to Have Significant Producer North of Parshall Field

EOG Resources (EOG) has confirmed that its wildcat 10 miles north of Parshall Field is a large volume, horizontal Bakken producer. According to EOG’s 2007 Third Quarter results, the Austin #1-02H, a single-lateral test in the sw-se 2-154n-90w, Mountrail County, has been producing at an initial rate of 2,000 bopd. EOG has a 100 percent working interest in the #1-02H. Parshall Field is the largest Bakken oil pool discovered in North Dakota with a monthly production exceeding 200,000 bo. The company believes that this well is connected to Parshall Field, and if geological data supports this, Parshall Field could be a Class A oil field (100 mmbo +). Not only did EOG confirm the huge rates on the Austin #1-02H, the company also said that its first stepout to this well, the Austin #2-03H sw-se 3-154n-90w, will also produce at similar rates based on shows encountered during the drilling of this well. The #2-03H scales about one mile west of the of the 1-02H.

drillers added fracture technology to horizontal drilling. In fracture technology, mud is forced into the drilled hole under immense pressures to "frack" or break up the shale further. The deeper cracks allow more oil to flow to the pipe