Update On Harold Hamm's EOR Using Natural Gas -- Approved -- Buddy Domindgo Pad -- July 7, 2022

I assume this (see below) is related to this story, posted March 2, 2022:

CCS / Harold Hamm / Summit Carbon Solutions: The Williston Herald.

• CLR: $250 million buy-in over two years;
• help fund a project with Summit Carbon Solutions
• gather CO2 from ethanol plants in Midwest (Iowa, Nebraska, ND, SD)
• pipeline CO2 to ND for permanent storage
• comments: 
• if they were to do something with the CO2 (like EOR) it might make sense;
• to simply store it isvirtue signaling when China is building a new coal plant every week, or whatever they're doing
• and, of course, the pipeline is already being "fought" in Iowa

From The Bismarck Tribune today:

North Dakota's Public Service Commission has approved a pilot project for enhanced oil recovery in the Bakken. Enhanced oil recovery involves injecting a substance -- in this case natural gas -- down a well to try to boost oil production. Continental Resources plans to build a 3.1-mile pipeline to bring natural gas from a WBI Energy transmission line to Continental's Buddy Domingo (sic) oil well pad in Williams County. 

So, now we know the pad: the Buddy Domingo pad. I would post a screnshot of the map bu the NDIC GIS map is still not "up." 

From well search we can garner a bit of information.

Buddy Domingo pad is: NWNE 27-156-99

Wells with this location:

• 23180, 833, CLR, Buddy 1-27H, East Fork, t1/13; cum 299K 5/22; recent production --

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	5-2022	20	403	277	757	908	643	0
BAKKEN	4-2022	20	662	824	695	1990	1765	0
BAKKEN	3-2022	31	1287	1454	1254	3669	3258	0
BAKKEN	2-2022	28	1222	1100	1149	3377	3008	0
BAKKEN	1-2022	31	1408	1468	1307	3834	3433	0
BAKKEN	12-2021	31	1481	1412	1450	4458	4047	0
BAKKEN	11-2021	30	1553	1693	1500	4376	3985	0
BAKKEN	10-2021	31	1849	1839	1742	4981	4570	0
BAKKEN	9-2021	30	1906	1819	1665	4155	3758	0
BAKKEN	8-2021	29	1964	2088	1650	3866	3496	0

• 23181, 318, CLR, Domindgo (note spelling) 1-22H, East Fork, t1/13; cum 202K 5/22; recent production --
  

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	5-2022	27	873	1054	847	1672	1340	0
BAKKEN	4-2022	23	526	476	620	1392	1101	0
BAKKEN	3-2022	31	853	793	1011	2013	1602	0
BAKKEN	2-2022	28	813	799	899	1869	1498	0
BAKKEN	1-2022	31	944	1107	1034	1979	1568	0
BAKKEN	12-2021	31	967	787	1203	2028	1617	0
BAKKEN	11-2021	30	1102	1065	1168	2305	1907	0
BAKKEN	10-2021	31	1495	1570	1443	2516	2105	0
BAKKEN	9-2021	15	504	333	825	800	619	0

CLR: Enhanced Oil Recovery Project; Priimary Production Recovering Upwards Of 15% Of OOIP -- May 19, 2022

CLR: enhanced oil recovery project, link here. Or direct to The Williston Herald.

• Buddy Comindgo Pipeline Project
• transport natural gas from an existing transmission line to an existing oil well
• $3.55 million
• enhanced recovery
• think about that: spending $3.55 million to test enhanced recovery from an existing well
• at $100 at the well head:
• $3,550,000 / $100 = 35,500 bbls of oil
• 2,000 bbls / month = 18 months
• specifics:
• origin: East MonDak WBI Energy Transmission Line
• terminus: Continental's Buddy Domindgo Well Pad
• natural gas to be compressed and injected downhole into the existing well to test the feasibiliity of this method for prolonging thee well's production life;
• without enhanced recovery:
• the current technology will leave 80 to 85 percent of the oil tied up in shale rocks behind, North Dakota Director of Mineral Resources Lynn Helms has said in past monthly oil production reports — an enormous target, that makes even a 1 to 2 percent gain in oil recovery highly economic.
• Continental has already acquired all of the rights of way needed for the project, and expects to take two months completing the project once it is permitted.

Too bad the NDIC map is not available to locate the origin and terminus.

But look at that: primary production in the Bakken recovering upwards of 15% of OOIP, link here:

• 500 billion bbls OOIP
• 15% of 500 billion = 75 billion bbls
• at 1 million bbls / day x 365 = 365 million bbls / year
• 75 billion / 365 million bbls = 205 years.
• others have said 250 billion bbls OOIP
• 15% of 250 billion = 37.5 billion bbls
• = 102 years

Note: I am inappropriately exuberant with regard to the Bakken and often make simple arithmetic errors.  

Early Evening -- Brent Jumps Another $4 -- Absolutely Ludicrous -- Wednesday, March 2, 2022

Oil:

• Brent: up 7.58%; up $7.96; trading at $112.90; Later, 7:40 p.m. CT: $116.40. Now, 7:57 p.m. CT: $116.90.
• WTI: up 1.56%; up $1.72; trading at $110.90. Later, 7:35 p.m. CT: $113.10. Now, 7:59 p.m. CT: $113.50. Later, 8;46 p.m. CT: someone has a screen shot of WTI at $114.58.
  

So many story lines:

The price of oil is not the price of the first bbls being sold, but the price of the last barrel.

Amazon: shutting down brick-and-mortar; link here.

• shutting down all its Amazon Books physical bookstores, as well as its Amazon 4-star and Amazon Pop Up shops, which sold a variety of electronics and other hot items.

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EOR - NG

Updates

July 7, 2022: approved. The Buddy Domindgo pad in Williams County.

Original Pad

CCS / Harold Hamm / Summit Carbon Solutions: The Williston Herald.

• CLR: $250 million buy-in over two years;
• help fund a project with Summit Carbon Solutions
• gather CO2 from ethanol plants in Midwest (Iowa, Nebraska, ND, SD)
• pipeline CO2 to ND for permanent storage
• comments: 
• if they were to do something with the CO2 (like EOR) it might make sense;
• to simply store it isvirtue signaling when China is building a new coal plant every week, or whatever they're doing
• and, of course, the pipeline is already being "fought" in Iowa
  

EOR -- Natural Gas Injection -- NDIC Approves Pilot Study -- November 26, 2019

Link here. Hess is proposing the project to target newer Bakken wells near Ross in Mountrail County. From the link:

• foam and natural gas
• in place of CO2 which is already used in some parts of the state
• if it works, the idea would spread quickly
• "would immediately end the flaring problem"

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XTO: EOR Pilot Operation -- Injection Wells

Case 28131, (not a permit) from November 21, 2019:

• XTO
• Cedar Coulee- Bakken
• section 33-148-96 and section 4-147-96
• to use existing wells in these sections as injection wells for an EOR pilot operation 
• wells: #25332, #25333, #25334, $25335, #16914 (these area all big wells; worth taking another look)

Case 28132, (not a permit) from November 21, 2019:

• XTO
• Bear Creek
• sections 27/34-148-96
• use existing wells as injection wells for an EOR pilot operation
• wells: #32502, #32501, #32500, #32499, #32481, #32480, #32479, #32367, #32366, #29673, #29672, #29871 (these are huge wells; worth taking another look)

Area of interest:

Wow, Wow, Wow -- EOR Using Natural Gas; Seeing A 30% To 70% Improvement In Production In Older Wells -- June 10, 2019

From Bloomberg via Rigzone:

At least five producers, led by EOG Resources Inc., are experimenting with shooting highly-pressurized natural gas into past-their-prime wells that have seen their output slip. The wells are then capped to build up pressure inside with the aim of dislodging any oil still hiding in the rock.

Note: there are three others posts regarding EOR using natural gas.

Other notes from the linked story:

The methodology’s been used in conventional wells elsewhere with both natural gas and carbon dioxide for years, but it’s just now emerging in America’s fracked shale fields.

The win-win goal: The trapped gas is put to work, and there’s a 30%-to-70% gain in oil output from older wells, according to EOG.

In late 2018, Permian flaring -- the burning off of associated gas -- more than doubled from a year earlier to 500 million cubic feet a day, and that’s likely to rise.

Generally, the use of injected gas is known as enhanced oil recovery, or EOR. Initially, EOG was the main company using natural gas to boost shale oil output, Krishnamoorti said by telephone. "But the fact is that now we have seen four other producers do it," he said. “And with remarkable results.”

EOG has been experimenting with EOR for at least three years in the Eagle Ford basin. Gas injection can potentially extend crude production volumes in older wells by 18 to 24 months, Krishnamoorti said. What’s still to be determined is how well EOR works in different types of rock formations.

For the most part, producers have disclosed little specific information about how well the new method performs, even in the Eagle Ford, where it is increasingly being adopted. 

Much, much more at the link.

20 - 70 Years Of Drilling Left In The Bakken -- January 21, 2019

From NDIC's annual update to the North Dakota state legislature, slide #13 of 42.

From same source, slide #21 of 42:

Bakken EOR Test Using Injected Hydrocarbon; Ross Oil Field; Hess -- March 7, 2017

Bottom line:

• Hess to test enhanced oil recovery using injected hydrocarbon gas. Two vertical wells in Ross oil field have been drilled for this test
• apparently EOG has been doing similar testing in the Eagle Ford for the past two or three years (see end of post)

Graphic:

The wells:

• 32937, IA/drl, Hess, RS-Nelson Farms-156-92-24V-1, Ross, a Birdbear well, no production data, PGI for the Bakken well; noted to be IA (posted January 24, 2018)
• 32938, SI/NC, RE-Nelson Farms-156-92-24V-2, Ross, drilled to Birdbear, below the Three Forks; still SI/NC, posted January 24, 2018;

FracFocus: as of March 7, 2017 -- no data at FracFocus regarding these two wells.

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32937 (V1)

32937 (V1), API: 33-061-03974; geologic summary --

• spud: September 9, 2016
• cease drilling: September 14, 2016
• TD: 9,974.90' TVD
• drilled as part of a projected Hess's Enhanced Oil Recovery (EOR) group, RS-Nelson Farms 156-92-24V-1... vertical hole targeting the Middle Bakken and Three Forks Formation where a 210' core was taken
• the 210-foot core was taken from 9,587 feet MD, an estimated 10 feet below the False Bakken, to 9,797 feet MD in Three Forks Formation
• The False Bakken, the upper Bakken shale, the middle Bakken, the lower Bakken shale, and all four benches of the Three Forks are described in the file report, as well as the Birdbear

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

32938 (V2)

32938 (V2), API: 33-061-03975; geologic summary --

"As part of a project by Hess's Enhanced Oil Recovery (EOR) group, RS-Nelson Farms-156-92-24V-2 was drilled as a vertical hole to monitor the RS-Nelson Farms-156-92-24V-1. The surface location ..... located in Mountrail County in the Ross Field.

"RS-Nelson Farms-156-92-24V-2 spud on September 21, 2016, and reached a total measured depth of 9,983' on September 24, 2016, at 5:00 a.m. CDT. This (#32938) was the second of two verticals drilled on this well pad.

"Thirty foot samples were caught from 7,470 feet through the end of the vertical section at 9,983 feet in the Birdbear Formation."

The False Bakken, the upper Bakken shale, the middle Bakken, the lower Bakken shale, and all four benches of the Three Forks are described in the file report, as well as the Birdbear. 

Disclaimer: in a long note like this there will be factual and typographical errors. I am doing this to help me better understand what is going on in the Bakken. Do not quote me on any of this. If this is important to you, go to the source.

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The Proposed Hydrocarbon Injection Test

32937, brief description of proposed injection program, pages 27 - 28 of the 126-page file report. Data points:

• "The objective of the proposed enhanced oil recovery (EOR) test is to demonstrate enhanced oil recovery through injection of a hydrocarbon fluid into the Middle Member of the Bakken Formation (Middle Bakken). The EOR test is planned in two phases:
• 1) cyclic production / injection test
• 2) injector-producer pair test

Cyclic production / injection test (CP/IT)

• two vertical wells
• 32937 (V1): a cyclic production / injection well 
• 32938 (V2): a monitoring well in the first part of the EOR test
• 32937 (V1): middle Bakken; stimulated with a hydraulic, propped fracture to achieve sufficient well injectivity for the test; the test will begin with an initial production period in V1 well to establish a primary production baseline  
• 32937 (V1): after initial production, the V1 well will be converted to an injection well
• 32937 (V1): a hydrocarbon fluid will be injected into the V1 well at rates up to 285 MSCFPD and surface pressures up to 4,500 psig. The injection pressures will not exceed the fracture pressure of the Middle Bakken.
• after the injection cycle is complete, the V1 well will be shut-in for a soak period; then, the well will be converted back to production and produced
• production after the injection/soak period will be compared with the primary production baseline to determine enchaned oil recovery
• 32938 (V2): will be completed in the Middle Bakken; a bottom-hole pressure temperature gauge will be installed in the well for monitoring during the production, injection, and soak cycles of V1;
• 32938 (V2) will not be produced during hte CP/IT

Injector-Producer Pair Test (IPPT)

• the same two wells will be utilized
• V1 will be converted to an injection well
• V2 will be stimulated with a hydraulic, propped fracture prior to conversion to production
  
• a hydrocarbon fluid will be injected into the V1 well at rates up to 285 MSCFPD and surface pressures up to 4,500 psig. The injection pressures will not exceed the fracture pressure of the Middle Bakken. Production response to the hydrocarbon fluid injection will be monitored in the V2 well

The injection facility

• to be onsite, trucked in
• injection fluid will be purchased from the Tioga Gas Plant

Duration of study

• multiple injection, soak, and production cycles, would continue for a sufficient duration to study the impact of hydrocarbon fluid injection on oil recovery
• anticipated duration of the test is 1.5 - 2 years with total gas volume of 90 mmscf (million standard cubic feet)

Impact on other wells

• another Hess-operated well, Nelson Farms 1-24H is located about 1,000 feet from V1
• "due to localized reservoir depletion, a response in the Nelson Farms 1-24H could be expected during the EOR test. The Nelson Farms 1-24H will be monitored daily to detect changes in production. No detrimental impact to production in his well is anticipated because the injection fluid is a hdrocarbon.
• other Hess-operated wells outside the 640-acre RS-Nelson Farms DSU will be monitored for any effect:
• RS-Feldman 156-92-1423H-1 (#17696; middle Bakken)
• RS-State 156-92-3625H-1 (#16800; middle Bakken)
• RS-Lois Enander 156-91-3130H-1 (#17962; Three Forks)
• additionally, produced gas from the RS-Feldman 156-92-1423H-1 (#17696) will be analyzed to ensure that a response in this well could be detected. Due to the much great distance between these wells and the injector (2,800 - 4,000 feet) than the injector and the Nelson 1-24H, it is not anticipated thtat a response in any of these wells would occur. If a response does occur, the NDIC would be notified. Not detrimental impact to production in these wells would be anticipated in the unlikely outcome that a response occurred.

Additional comments:

• test to use 90 million standard cubic feet of natural gas; compare:
• #16800, drilled in 2008, Ross oil field; production through 1/17: 64 million cubic feet of gas
• #24193, drilled in early 2013, Ross oil field, production through 1/17; 69 million cubic feet of gas
• #31000, Robinson Lake oil field, drilled in mid-2015; production through 1/17: 111 million cubic feet of gas

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Other Sources

Additional sources:

• EOG enhancing Eagle Ford oil recovery using novel natural gas injection system; Natural Gas Intel.com, May 10, 2016; archived.
• public access review of Natural Gas Intel story linked above; May 10, 2016; a must-read

 
"Huff and Puff, ResearchGate.com, 2014, 2015.