Sanchez Acquires Additional Eagle Ford Acreage; $6,000/Acre (De-Risked/Producing); XTO To Acquire 26,000 Additional Acres In The Permian

It seems I've read this before, possibly even posted it earlier. Whatever. Rigzone is reporting:

Royal Dutch Shell plc will sell to Sanchez Energy Corp. its interest in Eagle Ford shale assets as the company refocuses its North American portfolio on acreage where it can reach the scale it needs to successfully execute projects.

Houston-based Sanchez will acquire Shell’s 100 percent working interest in approximately 106,000 net acres in Dimmit, LaSalle, and Webb counties in south Texas, which includes approximately 176 operated producing wells and associated field facilities and infrastructure.

The assets include 60 million barrels of oil equivalent of proved reserves. Net production from this acreage in first quarter 2014 was approximately 24,000 barrels of oil equivalent per day (boepd); around 60 percent of this production was crude and natural gas liquids. The acquisition will boost Sanchez’s position in the Eagle Ford to around 226,000 acres, with up to 3,000 potential drilling locations and average first quarter 2014 pro forma production of about 42,800 boepd, Sanchez said in a May 21 press statement.

The pro forma potential drilling locations of nearly 3,000 wells include 200 identified low-risk and high rate of return drilling locations and up to 800 additional potential locations.

I don't think the Rigzone article mentions the price (I may have missed it) but FuelFix says it was a $639 million deal for 106,000 de-risked/producing acres. BOTPE: $639 million / 106,000 acres = $6,000/acre.  

A bit more about Shell's re-focusing:

Shell has previously divested its acreage position in the Mississippi Lime play in Kansas, its position in Ohio’s Utica shale and part of its acreage in Colorado’s Sandwash Niobrara basins.

*********************************

Meanwhile, Rigzone is also reporting that in an exchange deal, XOM/XTO will add 26,000 acres to its North American portfolio:

Exxon Mobil Corporation announced Wednesday that it has executed an agreement to add nearly 26,000 acres to its U.S. oil and natural gas portfolio managed by subsidiary XTO Energy Inc., through a non-monetary exchange with LINN Energy, LLC. Virtually all of the acreage is located within the portion of the Midland Basin that is most prospective for horizontal Wolfcamp and Spraberry development. In exchange, LINN Energy will receive a portion of XTO’s interest in the Hugoton gas field in Kansas and Oklahoma.

Canadian Company To Try Nitrogen Flooding In Saskatchewan/Manitoba Bakken/Three Forks Wells

Every now and then a really good article comes across "my desk." Generally I do not know how good an article might be until weeks or months later. But something tells me this might be a very good article to bookmark for future reference.

A reader sent it to me. A huge thank you to the reader.

The article has to do with enhanced oil recovery (EOR) using nitrogen instead of CO2.

One should review primary, secondary, and tertiary oil production at wiki.

I'm getting out of my comfort zone and could be very, very wrong on this, but reading the wiki article as well as Schlumberger definitional resources, and then the new article (linked below), it looks like using nitrogen to help recover oil could fall into either secondary or tertiary production.

Again, outside of my comfort zone, it appears "secondary" production has to do with increasing reservoir pressure whereas "tertiary" production has to with decreasing viscosity. Depending on "how" one used a gas such as CO2 or N2 determines whether it is "secondary" or "tertiary" recovery. EOR is generally "synonymous" with tertiary recovery. (Further confusing matters, there is some suggestion that the operators consider this use of nitrogen to be part of primary production; see below.)

Again, this is all colloquial.

[Confusing matters further, nitrogen apparently can also be used for fracking, or at least has been tried. At the bottom of the blog, I have a "Fracking_Nitrogen" tag, for example.]

junewarren-nickle's energy group.com is reporting:

Tundra Oil and Gas Partnership is seeking regulatory approval for an immiscible nitrogen flood in the Middle Bakken/Three Forks tight oil formations in the Daly Sinclair field of southwest Manitoba.

Based in Winnipeg, Tundra is a privately held light oil producer that operated the drilling of 168 wells in Canada last year -- 163 in Manitoba and five in Saskatchewan.

This isn’t the company’s first foray into gas flooding in a tight oil formation. Since August 2008 Tundra has been operating a miscible gas pilot injecting carbon dioxide in the southeast quarter of section 04-08-28W1 within Sinclair Unit No. 1. Last August this pilot was approved for conversion to a water-alternating-gas project.

Now the company is applying for an immiscible gas injection pilot using nitrogen. (In miscible gas floods, the injected gas forms a single homogeneous phase with the oil. The resulting fluid has lower viscosity, reduced interfacial tension and improved mobility. While immiscible gas doesn’t form a single phase with the oil, it still has the benefit of improved pressure maintenance and sweep efficiency within the reservoir.)

This is a long, long article and many, many data points.

First, of all, this is a Canadian story, with subject wells in Saskatchewan and Manitoba.  I talked about the Bakken in Manitoba in a recent post, but in that post, the Canadian Three Forks was referred to as the Torquay.

Second: in this new article, the difference between using CO2 and N2 is spelled out very nicely. The big difference is that using N2 is much less expensive than using CO2, is readily available, and doesn't get into the issue of global warming/greenhouse emissions.

A third data point has to do with the general recovery rate of crude oil from the Bakken/Three Forks in this area (Saskatchewan/Manitoba):

Total net original oil in place (OOIP) in the proposed project area is estimated at 2.78 million bbls for an average of 174,000 bbls per 40-acre legal subdivision.

According to Tundra’s application, oil production per well in the proposed project area peaked in 2009 at 268 bbls a day. As of last November, average oil production per well had fallen to 9.6 bbls a day. Production is forecast to continue declining at a rate of nearly 29 per cent a year.

By last Nov. 30 cumulative production from the four wells within the proposed Ewart Unit No. 5 project area was 206,500 bbls of oil and 292,800 bbls of water. The recovery factor was 7.4 per cent of the net original oil in place.

Estimated ultimate recovery of primary proved producing oil reserves in the proposed project area is estimated at 256,000 bbls with 49,500 bbls remaining as of last Nov. 30.
Under the current primary production method, ultimate oil recovery of the proposed Ewart Unit No. 5 is forecast to be 9.2 per cent of the original oil in place.

Note the "downspacing": 40 acres. (In one test, they plan to go to 20-acre spacing, also.)

Note the recovery rate:  7.4% of the net original oil in place (OOIP) prior to N2 flooding.

With N2 flooding, they propose a recovery rate of 9.2%.

Note the EUR of these Bakken/Three Forks wells: 256,000 bbls. Compare with EURs of Bakken/Three Forks in North Dakota -- suggested to range between 400,000 and one million bbls.

This is where it gets a little confusing. In bold in the above paragraph, it sounds like they consider N2 flooding part of primary production: "Under the current primary production method, ultimate oil recovery of the proposed Ewart Unit No. 5 is forecast to be 9.2 per cent of the original oil in place."

This seems accurate because almost immediately, the article talks about "secondary" / EOR production:

Tundra estimates ultimate recovery of proved oil reserves in the project area, using a secondary water-alternating-gas EOR scheme, would be 379,000 bbls of oil with 176,000 bbls remaining.

And here, the author writes "secondary" and "EOR."

Be that as it may. It's a long, long article, with many, many data points. As noted at the beginning, this may turn out to be an article we come back to again and again.

Oh, by the way, there is at least instance in which N2 injection was being considered by an operator in the North Dakota Bakken. In the August, 2012, NDIC hearing dockets, case 18402:

• 18402, Whiting, nitrogen injectivity test in the Sanish, Mountrail

Big disclaimer: I may have misinterpreted the linked article. I don't spend a lot of time sorting all these articles out the first time I go through them. If you are interested in this particular subject, I would ignore what I've written and go directly to the source.

Perhaps the most important takeaway from this article: rate of recovery before additional measures -- about 7%. My hunch is that newer, more aggressive technology in the North Dakota Bakken is resulting in a great percentage recovery. 

RBC Capital Suggests North Dakota Will Hit Million-BOPD Milestone Early Summer

The tea leaves suggest that North Dakota will have passed the million-bopd milestone as of last month (April, 2014). It was noted at this post. We will know in the next Director's Cut. It was with a small chuckle that I read this note from RBC Capital at SeekingAlpha:

• Oil and gas producers in the Bakken Shale saw a pickup in production in March and should see an even bigger increase as the weather turns warmer, according to a new report from RBC Capital.
• Bakken development activity rose to 200 well completions in March vs. 70 in February, and well backlog remains high at ~635 wells, RBC says, expecting operators to work through the backlog since North Dakota has experienced a relatively warm spring.
• "As completion activity catches up in the early summer and drilling activity remains strong, oil production should top 1M bbl/day around mid-year, the report says.

"... according to a new report from RBC Capital." -- It would be nice if the real source of this information would have been cited: the Director's Cut, North Dakota Industrial Commission. 

Summer: June, July, August, I believe. Early summer: June.

For Investors Only -- May 21, 2014; CLR Trades At 52-Week High

Updates

Later, 7:42 p.m. central time: this really isn't an update, just a comment. Mineral owners should be happy with oil at $104 today. For investors in the oil and gas industry, and for investors in the stock market in general, $104-oil is not good. I would prefer that oil remain in its historical trading range. It scares me when speculators start driving the price of oil up. Regular readers know my feelings about "speculators."

Original Post

Trading at new 52-week highs: BP, BRK-B, CLR, NFX, TRGP, WMB.

Oil trades up almost 2% -- hits $104.

47% of unemployed have 'completely given up' looking for a job -- The Weekly Standard. The same percent of the population that would never vote for Mitt Romney.

10 million US citizens on disability. New record. First time in history.

CO2 400 parts per million. New record. First time in history.

385 days. Number of days since Phoeniz, AZ, whistleblower in VA scandal was transferred from her place of duty. I guess yesterday, her boss, the commander-in-chief, as he referred to himself several times today, became aware of that.

At least 8. Number of years the president has been working on the VA problem. He said he started working the problem when he was running for the US Senate. 

1. The number of deaths due to a 1967 Oldsmobile being driven off a Chappaquiddick bridge.

0. Number of deaths in US due to CBR trains derailing. 

Disclaimer: this is not an investment site. Do not make any investment decisions based on anything you read here or think you may have read here.

Quite a Day on Wall Street

Oil will close near $104/bbl.

Majors (CVX, COP, XOM): all in the green, though COP barely moved. The other two up about 1.5%.

Service companies (SLB, HAL, BHI): all in the green; about 1%.

ENB, WMB: ENB up about 1%; WMB trading at a new 52-week high.

Bakken: 

• OAS: goes over $50 first time in a long time; up over 5% today.
• KOG: up 4%.
• WLL: up 2%
• CLR: up over 3%; traded at 52-week high.

Other shale:

• EOG: up 2%
• SD: up almost 3%
• CHK: flat (slightly up)
• HK: flat (slightly up)

Railroads:

• BRK-B: flat, up sightly
• UNP: trading near its 52-week high; up 3/4th of a percent

Rawson Oil Field

Permits
2014
28424, loc, Whiting, Good Shepherd 41-15H-2H,
28423, loc, Whiting, Good Shepherd 41-15H,
28226, loc, Triangle Petroleum, Paulson 150-101-23-14-4H,
28225, loc, Triangle Petroleum, Paulson 150-101-23-14-3H,
28224, loc, Triangle Petroleum, Paulson 150-101-23-14-2H,
28223, loc, Triangle Petroleum, Paulson 150-101-23-14-1H,
27566, 622, Triangle Petroleum, McCabe 150-101-24-13-4H,
27565, drl, Triangle Petroleum, McCabe 150-101-24-13-3H,

2013
27230, drl, Triangle Petroleum, Rowe 150-101-1-12-6H,
27229, drl, Triangle Petroleum, Rowe 150-101-1-12-5H,
26232, 414, Triangle Petroleum, Dwyer 150-101-35-26-4H, t2/14; cum 32K 3/14;
26231, drl, Triangle Petroleum, Dwyer 150-101-35-26-3H, producing,
26230, 348, Triangle Petroleum, Dwyer 150-101-35-26-2H, t2/14; cum 31K 3/14;
25718, 633, Triangle Petroleum, McCabe 150-101-24-13-2H, t11/13; cum 66K 3/14;
25717, 622, Triangle Petroleum, McCabe 150-101-24-13-1H, t11/13; cum 70K 3/14;

2012
24546, 485, Triangle Petroleum, Dwyer 150-101-35-26-1H, t5/13; cum 65K 3/14;
24279, 478, Triangle Petroleum, Triangle 150-101-36-25-5H, t8/13; cum 74K 3/14;
24278, 436, Triangle Petroleum, Triangle 150-101-36-25-6H, t8/13; cum 83K 3/14;
24277, loc, Triangle Petroleum, Triangle 150-101-36-25-7H,
24276, loc, Triangle Petroleum, Triangle 150-101-36-25-8H,
23620, loc, Triangle Petroleum, Rowe 150-101-1-12-4H,
23619, 355, Triangle Petroleum, Rowe 150-101-1-12-3H, t6/13; cum 101K 3/14;
23618, loc, Triangle Petroleum, Rowe 150-101-1-12-2H,
23617, 634, Triangle Petroleum, Rowe 150-101-1-12-1H, t6/13; cum 87K 3/14;
23523, 1,510, Murex Petroleum, Rose Marie 3-10H, t12/12; cum 85K 3/14;
23426, loc, Triangle Petroleum, Sanders 150-101-3-10-1H,
23416, 895, Murex Petroleum, Jade Brenna 2-11H,
23414, PNC, Zenergy, Jacobson Family 26-36H,
22892, 1.552, Oasis Petroleum, Dwyer 27-34H, t9/12; cum 87K 3/14;,

2011
21828, loc, Triangle Petroleum, Gullickson Trust 150-101-36-25-4H,
21827, 1,173, Triangle Petroleum, Gullickson Trust 150-101-36-25-3H,
21826, loc, Triangle Petroleum, Gullickson Trust 150-101-36-25-2H,
21825, 984, Triangle Petroleum, Gullickson Trust 150-101-36-25-1H, t6/12; cum 104K 3/14;
21515, 853, Whiting, Good Shepherd Home 150-101-15B-22-1H, t10/12; cum 76K 3/14;

2010
No permits
  
Some selected wells permitted prior to 2010
9328, AB/29, Triangle, Berge-FLB 1-24, Rawson, t4/82; cum 212K 9/12; 
8706, Red River/Madison, 153/64; Triangle, Berge C 1, t1981/1990; cum 40K/cum 133K 9/12;
7845, Duperow/Madison, 70/142, Triangle, Nygaard State 1, t7/18/t9/85; cum 37K 134K 3/14;
  Original Post
Rawson oil field is a 3-section x 6-section field; a rectangular, 18-section field. It is one of the sweet spots in the Bakken, located in north-central McKenzie County, just west of Watford City and west of some of the sweetest spots int the Bakken. US Highway 85, running east-west through Rawson oil field, cuts the field exactly in half,with 9 sections to the north and 9 sections to the south. The field lies almost exactly midway between Alexander, North Dakota, and Arnegard, North Dakota. Watford City is about 12 miles to the east. On the date of the original post, most permits in Rawson were Triangle Petroleum permits. The largest truck wash facility in the United States is located just to the west of this field.