Posted on 04/03/2015 4:58:22 AM PDT by thackney
he State Oil and Gas Division has taken action against five oil companies that are flaring more gas than is allowed under the state’s new gas flaring order and policies.
Starting this month, the companies were ordered to choke down production to 100 barrels per day on certain wells or face potential daily penalties.
Division spokeswoman Alison Ritter said this is the highest number of companies and the most wells to be placed under restriction since a flaring order went into effect, calling for companies to capture 77 percent of produced gas by start of January this year.
The companies are Emerald Oil with 10 wells restricted, OXY with nine wells restricted, QEP with six wells restricted, Abraxas Petroleum with three wells restricted, and Enerplus with two wells restricted.
Ritter said the restriction orders are effective for a month and will be continued or dropped depending upon the company’s following month production reports.
The division also restricted production for some companies in January, February and March, though Emerald Oil is the only company to face restrictions in every month this year. Enerplus was restricted for two wells in February and Whiting Petroleum for three wells the same month.
An enforcement policy adopted by the State Industrial Commission says the 100-barrel restriction applies to companies that are not capturing at least 60 percent of the gas from the well.
Ritter said penalties would kick in only if the companies don’t restrict wells as ordered.
I’ve often wondered (coming from an oil producing area) why the gas produced by pumping oil is not collected rather than burned off. Anyone know?
Cost, always cost.
If they can make money piping the gas to a gathering system it is done quickly.
If the gas produced is too little for cost of installing the gathering piping, it is delayed as long as possible.
This becomes a function of the amount of gas produced, amount of existing gas gathering infrastructure in the area, as well as gas prices.
Many states require the gas to be eventually tied into production, but the amount of time and amount of gas flared varies by area.
I like the Alaska rules, producers pay royalties on gas not compressed back into the reservoir. If the gas is used or flared, the royalties are paid to the state the same as if it was sent down the a pipeline. Either return the gas to the field to help maintain pressure or pay for the gas.
Some can, but sometimes it’s just junk. Also, it’s a safety thing. If a site goes into ESD (emergency shutdown), valves will shut in, and the flare stack one will open allowing any excess gas in the lines to depressive and be burnt off. Better than having a big boom.
We use those gases for power all the time. You’d have a lot of logistics though to get power out of the backwoods to some grid in a lot of cases. They’re normally used to power on site devices.
Thanks for the info.
Why does RRC allow flaring?
http://www.rrc.state.tx.us/about-us/resource-center/faqs/oil-gas-faqs/faq-flaring-regulation/
The Commission’s Statewide Rule 32 allows an operator to flare gas while drilling a well and for up to 10 days after a well’s completion for operators to conduct well potential testing. The majority of flaring permit requests received by the Commission are for flaring cashinghead gas from oil wells. Permits to flare from gas wells are not typically issued as natural gas is the main product of a gas well.
Flaring of casinghead gas for extended periods of time may be necessary if the well is drilled in areas new to exploration. In new areas of exploration, pipeline connections are not typically constructed until after a well is completed and a determination is made about the well’s productive capability. Other reasons for flaring include: gas plant shutdowns; repairing a compressor or gas line or well; or other maintenance. In existing production areas, flaring also may be necessary because existing pipelines may have no more capacity. Commission staff issue flare permits for 45 days at a time, for a maximum limit of 180 days.
See specifics on Statewide Rule 32 at the following link under §3.32 (Gas Well Gas and Casinghead Gas Shall Be Utilized for Legal Purposes):
http://texreg.sos.state.tx.us/public/readtac$ext.ViewTAC?tac_view=4&ti=16&pt=1&ch=3&rl=Y
The gas typically needs to be cleaned up at a nat gas processing plant.
Some have tried to make an economic means of using it directly but I have not seen a commercial success yet.
Keep in mind, if it was a significant amount of clean gas, it would already be piped in for economic recovery.
You should also note that the oil wells this production cut has affected is 30 out of the over 12 thousand in the state, 9 thousand in the Bakken – Three Forks plays.
https://www.dmr.nd.gov/oilgas/directorscut/directorscut-2015-03-12.pdf
Camel’s nose.
“Why can’t that gas be recovered and used?”
Also, the amount of hydrocarbons contained in the natural gas on a typical well in North Dakota is very small - maybe only 7% of all hydrocarbons including the oil produced. An as far as value, it may be 2% as gas is cheap compared to oil.
My brother used to work in Saudi Arabia years ago and they were flaring over 1,000,000,000,000 standard cubic feet of gas per day from a single field. A typical ND oil well that the Commission is placing restrictions on is not in the best part of the basin which means the producer struggles to recover its cost to drill and produce already, and is likely to average no more than 150,000 standard cubic feet per day.
There are cogeneration plants associated with landfills. I’m sure that flare gas can be simply filtered enough to run in a generator.
Keep in mind that electricity is needed at the well site, and is either generated on site or power lines are brought in. Shipping out a limited amount of electricity is cheaper than piping out a limited amount of natural gas.
Actually, North Dakota was many years (decades) behind most oil producing states in this. It is a normal part of the business in other areas.
You can pretend it is a recent liberal agenda, but that is not reality.
Yes, I've been part of the design team for the clean-up and compressing plants for those facilites. You are also talking about a larger production of Nat Gas concentrated in a smaller area, along with government requirements to also not just flare the gas. Sometimes it is so difficult (exensive) to clean up landfill gas to meet the pipeline quality requirements, it is cheaper to burn it there and deal with the impurities by modifications to the turbine/gen set.
Also, landfills are usually sourced to a nearby city and not dozens of miles to the nearest power line, as is the case in some of these remote wells.
Keep in mind that electricity is needed at the well site
Your assumption is false.
Bring back the Poppin Johnnys.
Nothing like going to sleep to the sound of money being made.
They (or their modern equivalent) are still used in some remote locations.
Shipping out a limited amount of electricity is cheaper than piping out a limited amount of natural gas.
Another false assumption in most cases.
The current version of the old “poppin johnny” is made right here in Tulsa OK.
http://arrowengine.com/en/products/2012-01-23-22-58-10/engines
A friend of mine worked with a guy that gets his electricity from a generator run by one of those running off the gas from a septic system.
He got the plans from him how to do it and apparently there is nothing to it.
I don’t know if he runs it all the time or just sometime to charge up batteries but apparently it’s common in New Zealand, where the guy lived, and Australia.
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