ND Regulators Approve Two Pipelines -- April 3, 2020

Link here.

Two pipelines:

• a CO2 pipeline supporting EOR projects: Denbury
• a NGL pipeline: ONEOK
• both approved unanimously

The NGL pipeline: ONEOK (earlier story here) -- The Tioga Lateral Pipeline

• $100 million project; to be completed by end of 2020 -- this year
• northwest corner of the state
• 75-mile steel pipeline: up to 30,000 b/d
• from three processing plants
• Hess Tioga
• XTO Nesson
• Flatiron Springbrook
• will end by connecting to the northern portion of ONEOK's existing Bakken NGL Pipeline
• ultimately connecting to markets further south, including the Gulf Coast
• ethane, propane, and butane

From an earlier post:

Data points for the Bakken NGL pipeline:

• $500 million
• 600-mile pipeline
• capacity to transport 60,000 bpd of unfractionated NGls from the Williston Basin to the Overland Pass Pipeline in northern Colorado
• first NGL pipeline to transport natural gas from the Williston Basin to facilities in the Mid-Continent and the Texas Gulf Coast
• further plans: another $100 million to install additional pump stations to increase capacity to 135,000 bpd from 60,000 bpd as noted in today's press release; this expansion will be completed in 3Q14

The  other pipeline:

• Denbury: from Montana into North Dakota, through Bowman, Slope counties
• 18-mile pipeline; nine miles inside ND
• ND portion: nine miles; $9.2 million (again, rule of thumb -- $1 million / mile)
• six months to build; several months of testing; dates unknown
• will carry CO2 for EOR
• CO2 will originate from XOM's Shute Creek Gas Plant and COP's Lost Cabin Gas Plant in Wyoming; via several pipelines to Fallon County in southeastern MT; from there via this new Denbury pipeline
• to boost oil production from depleted wells in the Cedar Creek Anticline Area
• second CO2 pipeline in ND; first was the 1998 Basin Electric's Great Plains Synfuels Plant near Beulah to oil fields in Saskatchewan

Pipelines, Pipelines, And More Pipelines -- December 22, 2019

Sent by an eagle-eyed reader. Thank you. 

Link here.

• PUC is considering to permit a pipeline
• CO2 pipeline
• 18 miles long; $9.2 million
• from Exxon Mobil's Shute Creek Gas Plant and COP's Lost Cabin Gas Plant in Wyoming
• via several pipelines to Fallon County in southeastern Montana
• from Fallon County through North Dakota through pipeline currently under consideration
• through Stark and Bowman counties
• Denbury Resources -- EOR project
• one other CO2 pipeline exists in the state
• authorized by the PSC in 1998
• CO2 from Basin Electric's Great Plains Synfuels Plant near Beulah to oil fields in Saskatchewan, Canada
• if approved, pipeline would be built in 2020; ready for injection in early 2021
• Cedar Creek Anticline Area: straddles North Dakota - Montana state line
• "secondary recovery" -- waterflooding
• "tertiary recovery" --  CO2

Also in the story:

The state Industrial Commission, which also regulates the oil industry, authorized a project in November that targets Bakken wells in Mountrail County. Hess is leading that effort, which involves injecting natural gas and a proprietary foam underground to build pressure and extract more oil.

One other enhanced oil recovery project secured approval from the Industrial Commission on Tuesday. XTO is proposing to inject natural gas into both the Bakken and Three Forks formations in Dunn County to boost oil production.

New Operator In North Dakota: An Ethanol Producer, Red Trail Energy, LLC, Has An Oil And Gas Permit -- December 2, 2019

Updates

December 11, 2019: what is Red Trail up to? From April 20, 2019, US News, a carbon capture project. Data points:

• this is being done to meet West Coast fuel standards
• the company recently completed a geophysical survey of eight square miles around the plant
• company's goal is to produce ethanol that will meet the low carbon fuel standards of California and/or the Pacific Northwest
• the company and the EERC are targeting the Broom Creek formation, about 6,400 feet below ground that area
• proposal: to inject about 160,000 metric tons of CO2 per year into the well
• leaks? can anyone say Aliso Canyon gas leak?

December 7, 2019: from a reader, regarding the Red Trail Energy permit, see first comment:

The permit Red Trail is requesting for drilling could likely be related to research for a carbon sequestration project. Ive heard they have interest in a potential CO2 capture project. There will likely be permits requested for a well or wells in Oliver County in the near future as well which are related to Project Tundra, another potential CO2 capture project.

Original Post

Active rigs:

455.98	12/2/2019	12/02/2018	12/02/2017	12/02/2016	12/02/2015
Active Rigs	56	66	53	39	64

One permit renewed:

• Bruin: an FB Leviathan permit in McKenzie County

Four new permits, #37229 - #37232, inclusive

• Operator: WPX (3); Red Trail Energy, LLC
• Fields: Spotted Horn (McKenzie County); Wildcat (RTE 10, Stark County)
• WPX has permits for a 3-well Patricia Kelly pad in section 3-150-94, Spotted Horn oil field;
• Red Trail Energy, LLC, has a permit for a wildcat in SENE 10-139-92;

Over at the NDIC well search site, this is the first and only permit (so far) for Red Trail Energy, LLC.  The website for Red Trail Energy greets visitors with huge "Ethanol" banner.
From the website:

Red Trail Energy, LLC (RTE) is a North Dakota-based investor group formed to finance, construct and operate a corn-based ethanol production facility located near Richardton, North Dakota. This vision became a reality when the $99 million, state-of-the-art plant began producing ethanol, in January of 2007. RTE now employs 47 personnel with an annual payroll of $2.9 million.

As one of the first coal-fired ethanol plants in the nation, RTE produces 50 million gallons of ethanol, using 18-20 million bushels of corn and ~100,000 tons of coal, annually. The plant will generate 2.8 gallons of ethanol from every bushel of corn. Coproducts produced by RTE include 125,000 tons of dried distillers grain and 80,000 tons of modified-wetcake annually.

The Richardton plant’s physical layout is composed of eleven structures, totaling 100,000 square feet of buildings, including administration, maintenance, processing, grain receiving, dried distillers grains storage, coal island, dryers and a pump house. The second-generation plant incorporates all the latest advances in ethanol processing, including equipment and technologies proven to boost efficiency and return on investment.

No mention of oil and gas operations.  The wildcat will be drilled on/near RTE property north of Richardton, ND. Richardton is east of Dickinson and about 100 miles west of Sterling, ND, where one turns south to Linton, ND. Linton is the county seat for Emmons County. Folks may remember Linton, ND: that's where the recent NDIC hearing on the DAPL expansion was held. Emmons County is the location of the fabled "Sleeping Giant" natural gas field.

From a reader, alerting me to RTE, which could end up being quite a story:

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

Hope Springs Eternal

Area under discussion:

Carbon Carbon; CO2-EOR; And, Re-Fracking -- Clearing Out The In-Box -- October 12, 2019

CO2-EOR, from Geoff Simon's top North Dakota energy stories this week (October 12, 2019):

Denbury Resources has submitted an application to the ND Public Service Commission seeking permission to build a pipeline that will bring carbon dioxide to Bowman County as part of an enhanced oil recover project.

The 12-inch diameter welded steel Denbury Green Pipeline would be just short of 18 miles in length, with about 8.5 miles in Fallon County, Montana, and the remaining 9.2 miles in Slope and Bowman Counties. The pipeline would enter the state nearly due west of Marmarth in southwestern Slope County, and terminate about six miles south of the community in Bowman County.

The CO2 will come from the Exxon Mobil Shute Creek Gas Plant in LaBarge, Wyoming, and the ConocoPhillips Lost Cabin Gas Plant in Lysite, Wyoming, and be transported to Denbury’s Bell Creek EOR Development in Powder River County, Montana.

The new pipeline will connect at a point 6.3 miles southeast of Baker, Montana. Denbury estimates the price tag for the North Dakota portion of the pipeline will be $9.2 million.

The project will provide for tertiary oil recovery from Denbury’s production wells through injection of CO2 into the oil reservoir which will result in increased extraction and utilization of crude oil resources.

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Re-Fracking: Next Big Trend In The Bakken?

From The Williston Herald. This should get one's attention: on average, re-fracking should result in 350,000 bbls of additional crude oil from these old wells. The figure was based on an analysis of 100 or so wells in the Killdeer area.

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Carbon Capture

Project Tundra, from The Bismarck Tribune, September 17, 2019:

• carbon capture
• source of carbon: a coal-fired power plan tin Oliver County
• project is described as "complex"
• cost of project if ever approved: $1 billion
• US DOE: awarded $10 million for a front-end engineering study
• recipient of the $10 million: Fluor
• seismic survey has begun near Center, North Dakota 

The Irony Of It All -- August 28, 2019

Note: we've been through this before -- see this note from July 30, 2019.

The best I can do right now with this; will try to get a better link later.

https://webcache.googleusercontent.com/search?q=cache:ovRT-wBM8jgJ:https://www.netl.doe.gov/sites/default/files/netl-file/J-Sorenson-Bakken.pdf+&cd=1&hl=en&ct=clnk&gl=us

From 2017:

Oil production grew significantly from 0.2 million barrels per day (bpd) to 1.1 million bpd in the Bakken petroleum system from 2009 to 2014. A large volume of associated gas (1.6 billion cubic feet per day) has also been produced with the oil. A substantial part (10%) of this produced gas is flared off because of the low natural gas price and limited infrastructure for gathering and transporting the gas from the well sites. Such a large scale of gas flaring not only wastes energy but also emits contaminants such as SOx, NOx, and CO2 to the atmosphere. Reduction of flaring and utilization of produced gas are important steps toward sustained development of the Bakken.

The potential for recycled gas enhanced oil recovery (EOR) is being investigated as a method of reducing flaring through utilization. However, large-scale gas flooding might be difficult for the Bakken because of the difference between the low-permeability matrix and the highly conductive hydraulic and natural fracture networks, which may lead to low sweep efficiency. Instead, this research by the Energy & Environmental Research Center (EERC) has aimed to investigate, through a series of laboratory experiments and numerical simulation activities, the potential to extract oil from the tight rocks by taking advantage of diffusion-based processes.

Oil and gas produced from Bakken wells were characterized, and the reservoir formation properties were analyzed based upon core samples. A series of oil extraction experiments with varying gas (solvent) compositions were conducted. The minimum miscibility pressure (MMP) of various produced gas components and oil was measured to determine the pressure required for effective extraction.

Based on the experimental results, a well-scale model was developed to simulate the performance of recycled gas EOR.

Results showed CO2 and produced Bakken gas to be miscible with the oil in reservoir conditions (5000 psi, 230°F).

The measured MMPs for pure CO2 and ethane with typical Bakken oil samples were 2528 and 1344 psi, respectively.

The presence of methane in the gas increased MMP, but miscibility was still achievable under reservoir conditions.

CO2 and ethane enabled extraction of most oil components from the rocks during a 24-hour experimental period, but methane exhibited strong molecular selectivity for light-end components.

Simulation results showed that a single-well CO2 and methane/ethane huff ‘n’ puff operation could increase cumulative oil production as much as 50% for the multistage fractured wells in the Bakken.

The results of this study clearly showed that produced Bakken gas could be effectively used for recycled gas EOR. Implementation of EOR may have potential to compensate for the production decline of Bakken wells while reducing the quantity of flared gas.

A reader sent a note some time ago mentioning "small molecules." Note the abstract above. "Small molecules.

CO2: a small molecule. 232 pm.

CH4: a small molecule.  200 pm.

H2O: 275 pm.

N2: 370 pm.

Kinetic diameters here.

There's some irony here -- something I alluded to earlier.

The analogy: volatile Bakken crude oil shipped by CBR. What did North Dakota do? Skimmed off the propane, put it in "approved" rail tank cars, and shipped the propane in unit trains to Mexico.

Now, use that flared methane to pump even more crude oil.

Faux environmentalists must be going nuts. 

CO2 EOR Resulting In 60% Recovery -- Huge Story -- May 11, 2019

Updates

May 12, 2019: see first comment -- The CO2 project that Denbury is doing in far sw ND and se Montana is showing the same promise. Wells that were pretty much dead, only producing a few barrels a day, are now producing 100 barrels+ per day with CO2 injection.

Original Post 

Peak oil? What peak oil? CO2 EOR re-vitalizes a dying field. 

This is a huge story. I completely missed it. Geoff Simon caught it and posted it in his top ND energy stories. Data points:

• CO2 EOR
• source: from the Dakota Gasification Company, Beulah, ND
• operators recovering 60% of oil in the formation near Weyburn, Saskatchewan
• most interesting: why CO2 injection works -- it's not what we think
• CO2 EOR added 25 years of life to the field
• I don't know for sure, but this sounds like what we call the Madison in North Dakota (Midale-Nesson)

Wiki: the world's largest CCAS project;

• current production consists primarily of medium-gravity crude oil with a low gas-to-oil ratio

From Geoff Simon this week: Recovery Rates Near 60% at Weyburn

Canadian oil producers using carbon dioxide piped from the Dakota Gasification Company's plant near Beulah say they are recovering up to 60 percent of oil in the formation near Weyburn, Saskatchewan.

Joel Armstrong, VP of Production and Operations for Whitecap Resources, said oil production in the Weyburn field began in 1954 and peaked at around 45,000 barrels per day in the 1960s, before dropping to under 10,000 bbl/day in the 1980s. Armstrong said horizontal drilling help revitalize the field in the 1990s, but he said it really took off after DGC completed the CO2 pipeline in 2000.

Click here to listen to Armstrong's comments.

Armstrong said the injection of CO2 into the formation helps build pressure to move oil to the wellbore, but it primarily works by mixing with the oil to make it flow more easily.

Click here to listen to Armstrong's comments.

Armstrong said DGC is still the primary source of CO2 for the project, but it now has a secondary supply coming from the CO2-capture project at the Boundary Dam coal plant near Estevan, SK. He said since its establishment, the field has stored more than 30 million tons of carbon dioxide.

Click here to read more about the Weyburn-Midale CO2 project. Click here to read a paper on CO2 enhanced oil recovery from the National Energy Technology Laboratory.

The Weyburn CO2 project:

The project was launched in 2000 by the Government of Canada, the Government of Saskatchewan, Cenovus Energy and the Petroleum Technology Research Centre (PTRC) in Regina, Saskatchewan.

The eight-year project, part of the IEA Greenhouse Gas R&D Programme, was extended to 11 years at a cost of $85 million. It is the largest full-scale CCS field study ever conducted and results include studying mile-deep seals that securely contain the CO2 reservoir, CO2 plume movement, and the monitoring of permanent storage.

The project has attracted 16 sponsors from government and industry that include IEA, Alberta Innovates, Saskatchewan Ministry of Energy and Resources, Japan’s Research Institute of Innovative Technology for the Earth, and 10 industry sponsors from Canada, the US, the Middle East, and Europe.

In July 2010, the US Department of Energy (DoE) and Natural Resources Canada committed $5.2 million to enable the project to conclude in 2011. The DoE provided $3 million and the Government of Canada provided $2.2 million.

Peak Oil? What Peak Oil? EOR Is Already Here -- November 19, 2018

Link here. Why US oil production won't peak anytime soon.

The U.S. shale oil revolution continues to defy the skeptics, and the country is now producing a record 11 million barrels per day (MMbpd) of crude..... production has been up 18 percent since the start of this year alone. Output has exploded 120 percent over the past decade to heights not dreamed about. Production was long thought to have peaked at 9.6 MMbpd back in 1970.

Texas and North Dakota have been at the forefront, with the former now yielding more oil than Iraq, the world’s fourth largest producer.

Looking forward, given that the United States has accounted for 60 percent of new global oil supply since 2008, ....  how long can the United States continue to produce increasing amounts of oil?

It’s surely a difficult question to answer. The shale bonanza itself has proven that predicting future energy production is a fickle business. Back in 2007, for instance, no forecasting body was projecting how quickly a U.S. shale oil (and natural gas) surge would not just change the U.S. outlook but also transform energy markets around the world. Despite using the most advanced forecasting techniques possible, both the Energy Information Agency’sNational Energy Modeling System and the International Energy Agency’s World Energy Model were completely blindsided. 

[I think Harold Hamm used a hand-held calculator and maybe an iPad, first version.]

We do know, however, that false pessimistic predictions regarding the future ability of U.S. companies to produce more petroleum have been around since the inception of the industry,.... the record is known: “peak oil” theorists have been proven wrong every time.

[Insert here: "Shale is not a revolution, it's a retirement party." -- Art Berman, who gets big bucks for his prognostications.]

Indeed, too many fail to appreciate oil as an economic commodity powered by market changes, namely the constant advance of extraction technologies. The obsession with reserves (what’s currently available) instead of resources (what’s potentially available with price changes and better technologies) has made most Americans completely unaware of how much oil we have at our disposal. [This, by the way, was a most confusing issue when I first started blogging about the Bakken.]

Proved reserves can grow over time and estimates of the recoverable resource change as new information is acquired—through drilling, production, and technological and managerial development. For example, BP reports that the United States now has 50 billion barrels of proven crude oil reserves, a 66 percent boom over the past decade. [This alone is a very interesting statistic; some think the Bakken alone holds that much.]

The U.S. oil resource is measured in the hundreds of billions of barrels, maybe more. And it is obviously impossible to accurately predict “how much oil we have,” as some 95 percent of the immense, resource-rich U.S. Outer Continental Shelf is off-limits to oil and gas activity. [Peak oil, anyone?]

In fact, without drilling a single new well or making a new discovery, U.S. oil supplies could drastically be expanded. At least two-thirds of the total petroleum in a well is typically left behind after primary and secondary operations because it is too difficult or expensive to extract. [Remember all that talk about the "Red Queen" by the "oil peakers"?]

Now a tertiary technique that produces 0.5 MMbpd in the United States, CO2-based enhanced oil recovery (EOR) will grant us even more access to this hard-to-reach oil, while storing CO2 safely underground.

Like shale has been, large-scale CO2-EOR recovery is the logical next step in turning the “unconventional” into the “conventional” when it comes to crude oil extraction.

From twitter:

From the EIA, these are the weekly projections, not the actual production that will be reported some time later. Note: the EIA continues to estimate that US production is below 12 million bopd when the data certainly suggests to some that US production is now solidly above 12 million bopd:

Keeping North Dakota Great -- June 19, 2018 -- Denbury, EOR, Southwest North Dakota

From a press release:

PLANO, Texas, June 18, 2018 -- Denbury Resources Inc. announced that the Company has sanctioned a CO2 enhanced oil recovery project at Cedar Creek Anticline. 

CCA is a massive geological feature stretching approximately 125 miles in length across parts of Montana, North Dakota and South Dakota.

Denbury's portion of CCA covers approximately 175,000 acres and is estimated to hold up to five billion barrels of original oil in place.

KEY PROJECT HIGHLIGHTS:

• targets EOR potential greater than 400 million barrels, with initial tertiary production expected by late 2021 or early 2022
• modest capital to first tertiary production of approximately $250 million (including CO2 pipeline) can be funded with cash flow
• first two project phases are estimated to generate $3 billion of cumulative net free cash flow at $60 oil

If one gets 50% of that OOIP from primary production and EOR, we are talking about 2.5 billion bbls of oil.

One of the more pleasing observations from that press release: it's out of Plano, TX -- just up the road from us. Plano is home to many Fortune 500 companies, including Toyota, after it moved out of California a couple of years ago. Toyota has completely transformed Plano.

Denbury "needs" $60-oil long-term to make this project viable (after 2024 or thereabouts).

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Outlet Mall

Near Seaside, Oregon -- Along The Coast

Tesla Charging Station

 Can you imagine if every car in Oregon was an EV? Wow!

After Hess Pulls Out, OXY Is Now Dominant US Producer Of Oil Via Carbon Injection -- Reuters -- June 21, 2017

Data points:

• Hess will sell its stake in EOR projects in the Permian Basin of West Texas and New Mexico to Occidental Petroleum for $600 million in cash
• the deal cements OXY's status as the dominant US producer of oil via carbon injection
• carbon injection: favored by faux environmentalists and oil producers alike
• carbon injection: could grow if Congress expands tax credits this summer
• OXY also gets complete control of naturally occurring sources of underground CO2
• this naturally occurring source: boosts OXY's bottom line 
• cost of carbon is generally the largest expense in EOR projects

Hey, This Is Texas! Of Course This Facility Is The Largest Of Its Kind In The Universe -- January 10, 2017

This could be the biggest non-Bakken story of the year to date.

Updates

October 31, 2017: EIA update on Petra Nova. 

The Petra Nova facility, a coal-fired power plant located near Houston, Texas, is one of only two operating power plants with carbon capture and storage (CCS) in the world, and it is the only such facility in the United States.

The 110 megawatt (MW) Boundary Dam plant in Saskatchewan, Canada, near the border with North Dakota, is the other electric utility facility using a CCS system.

Petra Nova’s carbon-capture system is designed to capture about 90% of the carbon dioxide (CO2) emitted from the flue gas slipstream, or about 33% of the total emissions from Unit 8. The post-combustion process is energy intensive and requires a dedicated natural gas unit to accommodate the energy requirements of the carbon-capture process.

 The carbon dioxide captured by Petra Nova’s system is then used in enhanced oil recovery at nearby oil fields. Enhanced oil recovery involves injecting water, chemicals, or gases (such as carbon dioxide) into oil reservoirs to increase the ability of oil to flow to a well.

By comparison, Kemper had been designed to capture about 65% of the plant’s CO2 using a pre-combustion system. The capital costs associated with the Kemper project were initially estimated at $2.4 billion, or about $4,100 per kilowatt (kW), but cost overruns led to construction costs in excess of $7.5 billion (nearly $13,000/kW). Petra Nova CCS retrofit costs were reported to be $1 billion, or $4,200/kW, and the project was completed on budget and on time.

April 13, 2017: press release, no link -- "Secretary Perry celebrates successful completion of Petra Nova carbon capture project." Data points, same as those previously posted, but these new ones or important enough to be reposted:

• joint venture: NRG Energy (US) and Nippon Oil (Japan)
• funded in part by US DOE; originally conceived as a 60-MW electric capture project
• expanded to a 240 MWe Houston-area power plant; quadrupling the size of the capture project without additional federal investment 
• 5,000 tons of CO2 captured daily; EOR at the West Ranch Oil Field
• to boost production from 500 bopd to 15,000 bopd
• estimate: 60 million bbls of recoverable oil from EOR operations

January 10, 2017: also in Financial Times.  Additional data points:

• the project is called Petra Nova
• $1 billion project
• capturing CO2 from the equivalent of 240 megawatts of power generation
• covering costs by using gas for oil production

Original Post

At Reuters via Rigzone:

• operations have begun
• NRG Energy and JX Nippon Oil & Gas Exploration
• $10.4 billion carbon capture facilty
• Texas coal-fired power plant
• emissions are being used to extract crude from nearby oilfield
• 80-mile pipeline (yes, at least one state can still build pipelines) to the West Ranch Oil Field
• West Ranch Oil Field opened in 1930; produces 300 bopd
• with EOR, production should jump to 15,000 bopd within three years
• unlike wind and solar projects, this project will NOT result in higher utility costs for consumers
• CO2 extraction = EOR (enhanced oil recovery) -- several readers have spent several years waiting for this news -- time to break out the champagne
• largest of its kind in the world
• US DOE funded $190 million for the project's construction
• Japan: $250 million in loans
• NRG / JX Nippon: split the remaining $600 million
• Mitsubishi: engineered the plant
• at its peak: 1.6 million tons of CO2/year (4,000 tons/day) -- 90% of NRG's nearby power plant, the largest in Texas
• since opening December 29, 2016: 111,000 tons of CO2 (111,000 / 12 days = 9, 250 tons/day (I may have done the math wrong, but the first ten days, the average collected more than doubled expectations
• the other science project, the incredibly expensive Kemper, MS, plant is yet to come on-line
• cost $7 billion (so far) 
• the Texas plant: $1.04 billion
• uses a different process to capture CO2

Update On Future Of US EOR -- April 5, 2016

On March 31, 2016 -- just a few days ago -- we had a nice update on Occidental's enhanced oil recovery experience in the Permian. Today, Rigzone is reporting that an analyst sees oil, gas companies adopting novel EOR technologies.

Tertiary methods such as thermal enhanced oil recovery (EOR), steam-assisted gravity drainage (SAGD), gas injection and chemical injection can help boost the North American thermal EOR market.

California’s heavy oil production and exploration frontiers such as Canada’s oil sands have created an expansive market for thermal EOR in North America. Frost & Sullivan reports that oil production from thermal EOR in North America was 2.53 million barrels per day in 2013, and expects to reach 4.64 million barrels per day in 2020. SAGD is expected to be the highest revenue contributor, followed by steam injection. Other thermal EOR methods are still nascent.

Thermal EOR in particular will find application in areas where oil is viscous and heavy; it currently accounts for 55 percent of the total EOR market in North America. Nearly 80 percent of oil sands can only be extracted through the SAGD method, which is more expensive versus other thermal EOR methods.

Bakken Economy -- March 7, 2016

Catching up. Some of these articles are a bit dated; I am just now getting caught up on some of these.

From The Bismarck Tribune, a week or so ago:

BNSF Railway Co. will continue to invest in North Dakota in 2016, though at a reduced rate.

The company released a statement saying it plans to spend more than $100 million in North Dakota this year. About $326 million was spent on rail capacity improvement projects in 2015, and $506 million was spent on infrastructure in 2014.

BNSF invested more than $1.1 billion in North Dakota from 2012 to 2014.

Spending this year will be focused on maintenance projects rather than the additional capacity built to meet customer demand in prior years, according to a company statement. This will include replacing and upgrading rail, rail ties and ballast, as well as continued installation of centralized traffic control signaling projects near Dickinson and Jamestown.

Maintenance will be performed on more than 740 miles of track, including the replacement of about 55 miles of rail and 240,000 ties and signal upgrades.

From The Williston Wire, last week:

RDO Equipment Co. will celebrate a Customer Appreciation Open House at its new Williston location on Wednesday, March 16 from 10 a.m. until 2 p.m. RDO Equipment opened its first store in Williston in 2009. In early 2016, construction was completed on the new location at 14057 49th St. NW. The new site offers more than 36,000 square feet, 12 service bays and a drive-through wash bay. The original location is now home to RDO Truck Center.

Set in the heart of downtown Williston, Renaissance on Main (ROM), located on the corner of 2nd and Main Street, is opening the door to the new city center. ROM offers elegant office space along with retail and residential space. Williston Economic Development Executive Director, Shawn Wenko states, "Not only is it a top quality commercial and residential complex; it's going to be a showcase piece for our downtown." The public is invited to get its first peek at this exciting new development, during an Open House on Thursday, March 17th from 2-5 p.m. 

Local restaurateur Jason Esperum has opened his second restaurant in Williston. Esperum's newest eatery is Quinn's Bar and Burgers located in the former Blaine's Auto Body Shop at 2406 2nd Ave. W. Quinn's features hand ground burgers in a 21 and over bar setting. In addition to Quinn's, Esperum owns Lucy Lu's Restaurant and Bar in Downtown Williston.

I am really going to miss this one; this should be fun: The Williston Area Chamber of Commerce and Murphy Motors are gearing up for the annual ShamRockin' the Bakken / Taste of Williston on Thursday, March 17 from 5:30-10 p.m. at the Grand Williston Hotel and Conference Center. The St. Patrick's Day Celebration will feature some of the area's tastiest food and beverages; live music from Whiskey Rebellion; plus much  more. Admission is $20 per person.

From Reuters, by-line, Grand Forks, ND:

In a basement lab of a North Dakota research center, Beth Kurz and an assistant are peering through a scanning electron microscope, studying samples from the state's vast Bakken shale oil formation. Kurz, a hydrogeologist, is part of a team, which looks at using carbon dioxide to coax more oil out of wells that have already been hydraulically fractured, or fracked, in the process of extracting oil from shale rocks.

"No one is sure just yet how this process can work in the Bakken," said Kurz. "We're hoping to crack that riddle."

The use of CO2 in fracking, for example, could cut production costs in North Dakota's largest oil-producing county by about 10 percent. That, according to Reuters calculations, would bring costs to around $24.30 per barrel, below current market prices.
So far, the process has worked in laboratory conditions, but not yet in field trials, so it is unclear how quickly it could be commercially deployed.

Hess Corp, North Dakota's third-largest oil producer, is studying how it can lengthen the horizontal wells and use cheaper materials in fracking.

Services giant Schlumberger NV, licensed a new process last fall that slashes the number of pumps needed to frack a well.

With regard to that last story, this from an article from the North Dakota Geological Survey:

Enhanced oil recovery (EOR) projects in North Dakota have met with varying degrees of success. Some failed to produce any incremental oil while others successfully increased recovery. Most of the unsuccessful EOR projects were attempts to waterflood Madison reservoirs in north-central North Dakota.

The failure of these waterfloods is inexplicable because waterfloods in the same strata in Canada have been successful. One explanation is that project operations were conducted differently while another explanation is that reservoir properties in North Dakota differ from similar reservoirs in Canada. Carbonate reservoirs are often inhomogeneous and only a thorough understanding of the reservoir characteristics and careful planning can compensate for these inhomogeneities.

The EOR projects attempted in North Dakota are listed in Table II [the table is missing from the article]. Each of the listed EOR projects has a unique identifying abbreviation that corresponds to those in figure 28, a location map of all the active units in North Dakota [Figure 28 is also missing from the article].

In 1983, Chevron Oil Co. attempted to unitize Little Knife Field to institute a CO₂ flood for pressure maintenance. A successful pilot study involving five wells had shown that the program would probably be successful (Desch et al., 1984), but the unitization attempt failed because the 80% of the royalty interest owners necessary to ratify a unitization agreement in North Dakota was not attained.

Recent CO₂ enhanced recovery programs in Canada have apparently been successful. These successful programs, coupled with the apparent success of the Chevron pilot program at Little Knife Field, might point to a future need for CO₂. There are two sources of CO₂ presently available to operators in the Williston Basin. The first source is the Wyoming Thrust Belt, where CO₂ is produced together with other natural gasses. The second source is the coal gasification project at Beulah, North Dakota where CO₂ is a byproduct of the process. A pipeline is being built to transport CO₂ to the Weyburn Field in Saskatchewan and startup of a CO₂ flood may begin during 1999. The pipeline's route takes it past many other fields that are suitable for CO₂ programs and perhaps some other fields will be CO₂-flooded soon.

From The Bakken, July 31, 2013:

The EERC team is also working to establish the best possible approach to enhanced oil recovery (EOR). For the past year, the team has been analyzing and working to test the use of CO2 injected into an oil well as a vehicle to mobilize previously trapped oil droplets, allowing for the recovery of more oil. Currently, oil recovered in the resource is roughly 3 to 5 percent. “If we can change 3 to 5 percent to 4 to 6 percent,” he says, that is very meaningful. “The denominator on this research is so huge that single type percent increases in recovery are extremely meaningful. A 1 percent increase of recoverable oil translates to roughly $150 billion of value.”

To find that value, EERC has started to analyze two unsuccessful Bakken EOR pilot projects: one in the Elm Coulee field of Montana and the other in Mountrail County of North Dakota. The team has arranged a data-sharing agreement that will help them better understand the efforts. According to Harju, the EERC team has developed some exciting tests that could help prove Bakken EOR by 2014. 

Other links:

• Basin Oriented Strategies for CO2 Enhanced Oil Recovery, Williston Basin, 2006 -- excellent
• EOR, at energy.gov. 
• Wyoming State Office Reservoir Management Group, undated, probably about 2008.
• Saudi Aramco, 2010.

Update On Next US Oil Revolution -- July 14, 2015

Update on then next revolution in US oil production: CO2 EOR. OilPrice is reporting:

What OPEC countries fear most is a follow-up technological revolution that will lead to a second oil boom in the U.S., and that fear is now being realized.

A technological revolution spurred the U.S. oil boom that resulted in the greatest increase in domestic oil production in a century, and while that has stuttered in the face of a major oil price slump and an OPEC campaign to maintain a grip on market share, the American response could be another technological revolution that demonstrates that the first one was merely an impressive embryonic experiment.

It’s not only about shale now—it’s about reviving mature oil fields through advancements in enhanced oil recovery, potentially opening up not only new shale fields, but older fields that have been forgotten.

There are myriad gloom-and-doom stories about what is often alluded to as a short-lived oil boom in the U.S. But what many fail to understand is that revolutions of this nature are phased, with the advent of new technology typically followed by a temporary halt in progress while we study the results and come up with something even better.

What we’re looking at here are advancements in EOR for greater production and cost efficiency that can weather oil price slumps and awaken America’s sleeping giant oil fields. Soon we are likely to see some new players in the field buying up oil assets and putting more advanced EOR technologies to work to re-ignite the revolution.

The shale revolution was stunning, indeed. But there have been setbacks—even beyond the oil price slump that has rendered fracking expensive. Fracking uses a lot of water.

According to a recent U.S. Geological Survey study, the process uses up to 9.6 million gallons of water per well and is putting farming and drinking sources at risk in arid states, and especially in major drought-ridden shale-boom venues like Texas.

Phase two of the U.S. oil boom hits at the heart of the inadequacies of the first phase, in a natural progression.

There are two very interesting EOR advancements that have caught our attention in recent months: CO2 EOR and Plasma Pulse Technology (PPT).

Go to the link for the rest of the story.  

By the way, one of my pet peeves is this boiler plate: "...fracking uses a lot of water." So do golf courses.

Coal Gasification Project In Odessa, Texas, Set To Break Ground Later This Year; Whiting To Use CO2 For Permian Basin EOR -- April 1, 2015

FuelFix is reporting:

A new power plant in West Texas that could transform coal into cleaner-burning natural gas is poised to break ground later this year, an executive in charge of the project said at a conference in Houston Wednesday.

The project, located on a 600-acre site in Odessa, uses coal as a feedstock for a 400 megawatt power plant. But instead of burning it, the plant uses a chemical process to first strip it of carbon, sulfur and mercury.

The result, project leaders say, is a hydrocarbon that can fuel the power plan but burns even cleaner than natural gas — even though it was derived from coal. The extra carbon dioxide that gets stripped away is sold to production company Whiting Petroleum, which can pump in underground through a process known as enhanced oil recovery that helps coax more hydrocarbons from the earth.

“We’re not actually burning coal; we’re unlocking hydrocarbons,” said Jason Crew, CEO of Summit Power, the Seattle-based company behind the undertaking dubbed the Texas Clean Energy Project.

The U.S. Department of Energy has awarded the project $450 million in federal grants. Even though the U.S. is moving to phase-out coal in favor of natural gas-fired plants and alternative energy sources, coal is still poised to be a vital source of energy for the U.S. and other countries for years to come, said  Jason Lewis, federal project manager at the U.S. Department of Energy’s National Energy Technology Laboratory.

• Background: Texas Clean Energy Project. 
• Background: Integrated gasification combined cycle.

The Odessa project is one of three carbon-capture projects in Texas.

• The Petra Nova project, a joint venture involving NRG Energy Inc., is under construction in Fort Bend County. Technology added to an existing power plant is designed to capture carbon before it’s emitted into the atmosphere.
• Air Products and Chemicals is capturing carbon from a hydrogen production facility in Port Arthur. All three projects have received federal support.

CO2 Solutions And UND-EERC Partnering In CO2 Capturing Studies -- November 28, 2014

Links

Basin Oriented Strategies for CO2 Enhanced Oil Recovery, Williston Basin, 2006 -- excellent
EOR, at energy.gov

Updates

March 9, 2016: this page will be the "start point" for EOR-CO2. 
 

Original Post

 

A reader sent me this as a short note. I'm posting it here for easy googling, and waiting to see if anything comes of this:

CO2 Solutions from Canada is partnering with UND's EERC to test their just-patented CO2 capturing process. This has the potential to economically provide large volumes of carbon dioxide.

Remember, Ms Neset suggests 20 to 40 percent of  original oil in place is generally recovered from oil fields. CO2 EOR may be one way to do it.

Link here.

Under the program, CO₂ Solutions will test its technology at EERC's existing testing facility using natural gas and coal flue gas in December, 2014. The program's goal is to evaluate several CO₂ capture technologies that are among the most advanced systems under development for application to power and steam generation plants.

"We also expect that the program will benefit our U.S. market entry, particularly for commercial applications such as Enhanced Oil Recovery, through the exposure of our technology to the program's prominent industry participants. 

The testing program is supported financially in part by the U.S. Department of Energy (DOE).

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Call It What You Want

Global Warming

Extreme Weather

Ice Age Now

Early Winter

We spent a lot of time in the Boston area the past four years. I loved it but my wife and son-in-law did not like all the snow. Most of it fell in January/February. I see tonight, more than 16,000 are still without power due to 15 inches of snow. And it's not even winter yet.

From the Farmers Almanac (date unknown):

The Old Farmer's Almanac's long-range weather predictions for 2014–2015 are available—and another teeth-chatteringly cold winter is on its way across the United States!

"Colder is just almost too familiar a term," Editor Janice Stillman said. "Think of it as a refriger-nation."

With its traditionally 80 percent–accurate weather forecasts, The Old Farmer’s Almanac predicts that this winter will be another arctic blast with above-normal snowfall throughout much of the nation.

Great Article Over At Rigzone On Enhanced Oil Recovery -- Propsects For CO2-Based EOG -- October 29, 2014

Updates

October 31, 2014: 3rd in the series -- the prospects for thermal enhanced oil recovery (EOR), highlighting the opportunities for using heat to improve oil recovery in regions that have not traditionally used the technique

Within the Canadian oil sands, thermal EOR techniques are used when reserves are too deep to mine.

Thermal processes overtook mining as the dominant production method in 2012, and with around 80 percent of the remaining oil sands reserves in Alberta more than 200 meters (650 feet) below the surface and thus deemed too deep to mine, EOR techniques will play an increasingly dominant role in the oil sands market over next ten years.

Steam assisted gravity drainage (SAGD) is the leading technology, used at 75 percent of currently operational projects, with cyclic steam stimulation (CSS) used at most other locations. The thermal oil sands market is about to experience a period of rapid expansion as a wave of new projects come online in 2015 and 2016. However, the increased production that this creates may lead to transportation and refinery bottlenecks. Moreover, slowing Chinese investment, at the behest of the Canadian federal government, along with the potential for lower oil prices could also restrain the market, with projects likely to be delayed or cancelled.

Nonetheless, with more than 160 projects under construction, approved or announced, the thermal oil sands market will see fairly substantial production growth even if just a fraction of these projects are completed.

October 30, 2014: 2nd in the series -- can chemical EOR take off?

In terms of current spending and production figures, chemical EOR will remain the smallest segment of the EOR market for the immediate future. Yet the potential for chemical EOR development is vast in terms of both size and regional scope. Chemical EOR already surpasses both thermal and gas EOR methods in terms of the number of countries with active projects (14), while double-digit spending growth is anticipated over the next five years as pilot projects are set up and expanded. As such, chemical EOR is set to emerge from the shadow of its rival EOR methods to become an important technology on the global scale.

Original Post

 

This is a fairly long article for Rigzone, providing background and prospects for CO2-based EOR. I wold love to place this as a permanent link on the sidebar at the right, but my hunch is that this article will require a subscription or password in the not-too-distant future.

The most interesting takeaway: the shale (tight) oil revolution is an under-discussed threat to CO2 EOR prospects.

The table at the linked article shows the 15 largest CO2 EOR producers in North America ranked alongside the 15 largest spenders in the shale oil market in 2014; the table shows there is significant overlap with companies involved in both endeavors.
Shale oil development has lower start-up costs and quicker returns than CO2 EOR projects. Consequently, investors and company executives are likely to prioritize their shale oil asset development at this present time. Occidental – by far the largest CO2 EOR company in terms of production with 30 percent of the U.S. total – plans to keep CO2 EOR production in the Permian Basin flat through 2016 while increasing production from its shale oil assets in the region, according to the company's most recent presentation.

The second most interesting takeaway: "growth prospects for US CO2 EOR are overstated."

Although a CO2 EOR pure play company such as Denbury Resources could achieve 10-percent per year production growth (in a best case scenario), the market as a whole is unlikely to grow at this rate in the medium term. The optimistic forecasts for CO2 EOR production have tended to focus on the availability of new CO2 sources and pipelines, without paying enough attention to the plans of CO2 EOR producers and outside factors influencing the market. 

The other major points:

•  prospects for CO2 EOR are more favorable in China, Brazil, and the Middle East
• CO2 EOR not economical in the North Sea (at least in the near term and at current oil prices)

Long postings -- especially those done in the midnight hour while watching "Lost In Translation" -- may contain factual and/or typographical errors. If this information is important to you, go to the linked article. 

CO2-EOR; CO2 As A Commodity

Links

EIA: carbon dioxide emission factors for coal. 

Updates

October 4, 2014: be sure to see first comment below about UND-EERC; and, GE and Statoil partnering on CO2-EOR studies.

Original Post

 

I got a couple of articles sent to me today regarding CO2-EOR and carbon capture and storage (CCS). Time to have a page devoted to CO2-EOR updates.

October 4, 2014: CBC is reporting --

Saskatchewan made history this week by launching the world's first commercial-scale carbon-capture and storage operation at a coal-fired power plant.

With the $1.4-billion mega project, Saskatchewan has leapfrogged past Alberta to take the lead in the race to capture carbon in Canada.The facility in Estevan will take a million tonnes of CO2 a year from a SaskPower station, convert it to liquid and bury it deep underground.

SaskPower says the captured emissions are equivalent to taking a quarter of a million cars off the road.

Alberta’s plans sounded even more ambitious six years ago when the government announced it would invest $2 billion in four major carbon capture and storage (CCS) projects to slash emissions.

But since then two projects have been scrapped and new Premier Jim Prentice now seems lukewarm on CCS.

CCS simply for environmental reasons is costly; may not make economic sense. However, treating CO2 as a commodity for CO2-EOR is a completely different story.

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This is simply some housekeeping:

January 18, 2014: Barron's on DNR.

The first 20% of an oil well's production gushes out, thanks to natural pressure. That eventually drops, and you can push out another 20% by flooding the well with water. When that's finished, you can do carbon-dioxide flooding, a highly effective technique that is Denbury's specialty. Carbon dioxide is an unusual gas. It loves oil. Denbury injects highly pressurized CO2 into a well. It finds the oil, bonds to it, and pushes it out. 

The biggest user of this oil-recovery procedure is Occidental Petroleum. The next largest, and the purest play, is Denbury, which produces 72,000 barrels of oil equivalent a day.

This quarter, the Plano, Texas-based company will pay its first-ever dividend, of 25 cents. Next year, that dividend will grow to between 50 cents and 60 cents a share, giving the stock a yield of about 3%. At a recent $16.46 a share, the stock trades at 4.5 times free cash flow, well below the industry average of 6.8. Closing the gap could push the shares up at least 20%, to $20, not including the dividend.

January 3, 2014: The Dickinson Press, for some reason, ran a story today suggesting that DNR will begin waterflooding in southwestern North Dakota around 2020, but needs to lay a CO2 pipeline first. Not sure why the story was printed at this time. Don updates DNR's plans for southwestern North Dakota:

One year ago this field was supposed to have CO2 in 2018. DNR is currently laying the pipeline for CO2 from Belle Creek, MT, to Baker, MT. I believe the injection in the Baker, Montana, field is to start in 2015. There are also fields northwest and southeast of Baker. 

DNR's plans were delayed somewhat because the company decided in late 2013 to transition to a "dividend company" rather than a growth company. In 2014 DRN will start paying dividends and are slowing down the growth pace. This meant that the field in North Dakota got pushed back two years (to 2020).

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Timing Is Everything

This article "found" just after I was putting together this CO2-EOR page.

For the warmists who love graphs, this is a good one.

PowerLine is reporting:

One fundamental question in the global warming debate is, what is the Earth’s equilibrium climate sensitivity? That is, how much will the Earth’s average surface temperature rise, ceteris paribus, on account of a doubling of the concentration of carbon dioxide in the atmosphere? Global warming hysteria is predicated on the belief that average temperature will rise by up to 6 degrees C as a result of doubling atmospheric CO2. All of the scare headlines you see about polar bears, droughts, flooded cities, etc., rely on that assumption.

The problem for alarmists is that contemporary research doesn’t support any such scenario. The most recent nail in the alarmists’ coffin is a paper by Nic Lewis and Judith Curry titled “The implications for climate sensitivity of AR5 forcing and heat uptake estimates,” which concluded that the best estimate of equilibrium climate sensitivity is 1.64 degrees. C. Lewis describes the paper’s methodology at the link at the PowerLine article.

Why is 1.64 degrees so important? Because it's the range of normal variability. Furthermore, it is like the 1.64 degrees is "too high," anyway.

Yes, the science is settled. Has been for quite some time.

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