The Briefing Room
General Category => Science, Technology and Knowledge => Energy => Topic started by: thackney on November 28, 2017, 01:40:32 pm
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Natural gas production in Bakken region increases at a faster rate than oil production
https://www.eia.gov/todayinenergy/detail.php?id=33892 (https://www.eia.gov/todayinenergy/detail.php?id=33892)
NOVEMBER 28, 2017
(https://www.eia.gov/todayinenergy/images/2017.11.28/main.png)
In North Dakota’s Bakken region, the ratio of natural gas production relative to crude oil, known as the gas-oil ratio, has been gradually increasing since 2008 and has increased at a faster rate since 2014. More than 90% of North Dakota’s crude oil and natural gas production comes from the Bakken region, which includes the Bakken and Three Forks formations.
Total North Dakota crude oil production peaked at more than 1.2 million barrels per day (b/d) in December 2014, but production has since dropped to 1.07 million b/d (as of August 2017), based on data in EIA’s Monthly Crude Oil and Natural Gas Production Report. The record crude oil production in late 2014 was the result of increasing crude oil production from the Bakken and Three Forks formations. Despite production declines in 2016, North Dakota remained the second-largest oil-producing state, accounting for 11% of total U.S. crude oil production.
(https://www.eia.gov/todayinenergy/images/2017.11.28/chart2.png)
While oil production has slowed in North Dakota, natural gas production has continued to grow, reaching a record high of 1.94 billion cubic feet per day (Bcf/d) in August 2017, or the energy equivalent of about 334,000 b/d of crude oil. Despite the increasing gas-oil ratio, North Dakota still produces more than three times as much energy from crude oil as from natural gas.
(https://www.eia.gov/todayinenergy/images/2017.11.28/chart3.png)
In tight oil formations like the Bakken and Three Forks—which have low permeability—the gas-oil ratio tends to increase only gradually over an extended period of time before reaching a certain point at which it then increases significantly. As producers extract hydrocarbons from a rock formation, the pressure in the formation eventually falls below the point at which natural gas naturally separates from the gas-saturated crude oil—a threshold known as the bubble point. More oil relative to natural gas tends to be produced during the initial phases of production, after which natural gas production can increase once pressure in the formation reaches the bubble point.
(https://www.eia.gov/todayinenergy/images/2017.11.28/chart4.png)
In previous years, insufficient infrastructure to collect, gather, and transport North Dakota’s increasing natural gas production meant more than 35% of the state's gross withdrawals of natural gas was flared rather than marketed. In an effort to reduce the amount of flared gas, North Dakota's Industrial Commission established new targets in 2014 to limit flaring to 10% by October 1, 2020. Based on data from North Dakota's Industrial Commission, the volume of flared natural gas has declined from more than 0.35 Bcf/d in 2014 to about 0.20 Bcf/d in 2017—about a 40% decline.
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In North Dakota’s Bakken region, the ratio of natural gas production relative to crude oil, known as the gas-oil ratio, has been gradually increasing since 2008 and has increased at a faster rate since 2014.
This is not a good thing at all! At first blush and without having access to all the data, it indicates that producers are over producing wells in that region.
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This is not a good thing at all! At first blush and without having access to all the data, it indicates that producers are over producing wells in that region.
It may also mean now that there is more Natural Gas Infrastructure in place, producers are willing to go after fields that have a higher gas ratio than they would before.
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It may also mean now that there is more Natural Gas Infrastructure in place, producers are willing to go after fields that have a higher gas ratio than they would before.
This is true but for the long term health of the Bakken in general I do not think that is necessarily a good thing.
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This is true but for the long term health of the Bakken in general I do not think that is necessarily a good thing.
Is the gas/oil ratio in this discussion include what was flared? Or is it only the amount brought to market?
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Is the gas/oil ratio in this discussion include what was flared? Or is it only the amount brought to market?
@Bigun
Sorry, as soon as I hit enter I realized I should be able to answer my own question at the EIA site.
It does include flared gas.
https://www.eia.gov/petroleum/production/#ng-tab (https://www.eia.gov/petroleum/production/#ng-tab)
Natural gas production represents monthly natural gas gross withdrawals estimated from data collected on the EIA-914 survey.
Monthly Oil and Natural Gas Production Report, Form EIA-914
https://www.reginfo.gov/public/do/DownloadDocument?objectID=49922501 (https://www.reginfo.gov/public/do/DownloadDocument?objectID=49922501)
See flow chart at above link for clarity of numbers reported:
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Is the gas/oil ratio in this discussion include what was flared? Or is it only the amount brought to market?
It is ALL of the gas produced from the field regardless of where it ends up. Most of it is gas that comes out of solution as the liquids rise upward in the production tubing and that amount must be produced if you want the liquids. Problems occur when liquids around the well bore are produced fast enough to allow free gases to reach the well bore and become entrained. That phenomena is referred to as "Coning" in the business.
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@Bigun
Sorry, as soon as I hit enter I realized I should be able to answer my own question at the EIA site.
It does include flared gas.
https://www.eia.gov/petroleum/production/#ng-tab (https://www.eia.gov/petroleum/production/#ng-tab)
Natural gas production represents monthly natural gas gross withdrawals estimated from data collected on the EIA-914 survey.
Monthly Oil and Natural Gas Production Report, Form EIA-914
https://www.reginfo.gov/public/do/DownloadDocument?objectID=49922501 (https://www.reginfo.gov/public/do/DownloadDocument?objectID=49922501)
See flow chart at above link for clarity of numbers reported:
@thackney
LOL! I was writing when you posted this.
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@thackney
LOL! I was writing when you posted this.
At least we had the same answer!
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At least we had the same answer!
Indeed! :beer:
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It is ALL of the gas produced from the field regardless of where it ends up. Most of it is gas that comes out of solution as the liquids rise upward in the production tubing and that amount must be produced if you want the liquids. Problems occur when liquids around the well bore are produced fast enough to allow free gases to reach the well bore and become entrained. That phenomena is referred to as "Coning" in the business.
Coning is a natural phenomena in oil and gas fields but does not apply to tite reservoirs like we are dealing with here. Coning is caused by the pressure drawdown in the vicinity of a well where significant vertical permeability is present. This decidedly is not the case here and I seriously doubt any familiar with the phenomena would disagree.
There are several possibilities which might be the answer on why higher gors are occuring.
One, a review of individual wells could be made to determine whether a single well is progressing toward higher gors. If not, then what was said before that higher gor wells being targeted would be the case made.
Now about higher gor wells. The gors are all pretty low, as <2,000 scf/b is a darn low gor. I am not worried at all about damaging the reservoir performance at such a low gor. if it were 10X as high, perhaps.
The natural, in situ oil resides in the Bakken at somewhere between 200 scf/b up to 1,800 scf/b.
Every barrel produced will contain that amount of gas when reservoir conditions remain above the bubble point.
There is a complexity in these tite reservoirs as one travels away from the wellbore such that nearer to the wellbore one is below the BP and gradually gets above the BP away from the wellbore. In other words, the oil/gas in the formation exists not as a single phase but at different pressures, hence different phase regimes.
The bottom line is this: increasing GORs is reflective that a larger portion of the reservoir is being produced below the BP. This is as expected.
It is not a bad thing right now as gas being released from oil drives the oil to the pressure sink of the well, so one can produce more.
When it gets bad for the reservoir, as @Bigun correctly states, is when gas is accumulated enough it no longer pushes the oil but reaches a saturation high enough to flow to the well independently of the oil. This means the energy of the reservoir is depleting without the benefit of producing oil.
No one has ever witnessed an oil reservoir this tite through its life cycle to know what happens when this occurs, so we are all up in the air to see if a sudden drop in oil happens and when. I do suspect a gradual event will occur rather than catastrophic.
Sorry about the dissertation, my engineering side is showing up.
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Coning is a natural phenomena in oil and gas fields but does not apply to tite reservoirs like we are dealing with here. Coning is caused by the pressure drawdown in the vicinity of a well where significant vertical permeability is present. This decidedly is not the case here and I seriously doubt any familiar with the phenomena would disagree.
There are several possibilities which might be the answer on why higher gors are occuring.
One, a review of individual wells could be made to determine whether a single well is progressing toward higher gors. If not, then what was said before that higher gor wells being targeted would be the case made.
Now about higher gor wells. The gors are all pretty low, as <2,000 scf/b is a darn low gor. I am not worried at all about damaging the reservoir performance at such a low gor. if it were 10X as high, perhaps.
The natural, in situ oil resides in the Bakken at somewhere between 200 scf/b up to 1,800 scf/b.
Every barrel produced will contain that amount of gas when reservoir conditions remain above the bubble point.
There is a complexity in these tite reservoirs as one travels away from the wellbore such that nearer to the wellbore one is below the BP and gradually gets above the BP away from the wellbore. In other words, the oil/gas in the formation exists not as a single phase but at different pressures, hence different phase regimes.
The bottom line is this: increasing GORs is reflective that a larger portion of the reservoir is being produced below the BP. This is as expected.
It is not a bad thing right now as gas being released from oil drives the oil to the pressure sink of the well, so one can produce more.
When it gets bad for the reservoir, as @Bigun correctly states, is when gas is accumulated enough it no longer pushes the oil but reaches a saturation high enough to flow to the well independently of the oil. This means the energy of the reservoir is depleting without the benefit of producing oil.
No one has ever witnessed an oil reservoir this tite through its life cycle to know what happens when this occurs, so we are all up in the air to see if a sudden drop in oil happens and when. I do suspect a gradual event will occur rather than catastrophic.
Sorry about the dissertation, my engineering side is showing up.
@IsailedawayfromFR
The dissertation is much appreciated by this poster at least!
I freely admit to having no real knowledge of, or experience in, the Bakken at all and thus thank you for taking the time to somewhat educate me about it.
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Sorry about the dissertation, my engineering side is showing up.
Thanks for the info.
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Sorry about the dissertation, my engineering side is showing up.
The rest of us engineer types appreciate it.........
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Coning is a natural phenomena in oil and gas fields but does not apply to tite reservoirs like we are dealing with here. Coning is caused by the pressure drawdown in the vicinity of a well where significant vertical permeability is present. This decidedly is not the case here and I seriously doubt any familiar with the phenomena would disagree.
There are several possibilities which might be the answer on why higher gors are occuring.
One, a review of individual wells could be made to determine whether a single well is progressing toward higher gors. If not, then what was said before that higher gor wells being targeted would be the case made.
Now about higher gor wells. The gors are all pretty low, as <2,000 scf/b is a darn low gor. I am not worried at all about damaging the reservoir performance at such a low gor. if it were 10X as high, perhaps.
The natural, in situ oil resides in the Bakken at somewhere between 200 scf/b up to 1,800 scf/b.
Every barrel produced will contain that amount of gas when reservoir conditions remain above the bubble point.
There is a complexity in these tite reservoirs as one travels away from the wellbore such that nearer to the wellbore one is below the BP and gradually gets above the BP away from the wellbore. In other words, the oil/gas in the formation exists not as a single phase but at different pressures, hence different phase regimes.
The bottom line is this: increasing GORs is reflective that a larger portion of the reservoir is being produced below the BP. This is as expected.
It is not a bad thing right now as gas being released from oil drives the oil to the pressure sink of the well, so one can produce more.
When it gets bad for the reservoir, as @Bigun correctly states, is when gas is accumulated enough it no longer pushes the oil but reaches a saturation high enough to flow to the well independently of the oil. This means the energy of the reservoir is depleting without the benefit of producing oil.
No one has ever witnessed an oil reservoir this tite through its life cycle to know what happens when this occurs, so we are all up in the air to see if a sudden drop in oil happens and when. I do suspect a gradual event will occur rather than catastrophic.
Sorry about the dissertation, my engineering side is showing up.
That is the big question, one of how much oil will remain 'left behind' when the reservoir passes BP.
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That is the big question, one of how much oil will remain 'left behind' when the reservoir passes BP.
And raises, in my mind at least, the question of is there a method to enhance recovery of the oil remaining at that point.
Water flood?
Gas injection?
I have no idea what might work in that situation.
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And raises, in my mind at least, the question of is there a method to enhance recovery of the oil remaining at that point.
Water flood?
Gas injection?
I have no idea what might work in that situation.
Intermediary laterals perhaps. The trick will be to release the oil from the tight rock back from the current frac. Re-fracs are possible, too, and may enhance production by raising formation pressure (taking it back above bubble point). The current maximum number of wells per pad per formation on a 1280 spacing is four, and with the general layout from later in development having those ordinarily running roughly parallel, there may be the ability to CO2 flood the reservoir (Dakota Gassification (https://en.wikipedia.org/wiki/Great_Plains_Synfuels) would be a possible Co2 Source. There is a distinct possibility that permeability fairways might defeat such a strategy, though.
Either the re-frack or the CO2 flood would raise pressure in the reservoir, and keep it above bubble point, allowing oil to flow again.
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Intermediary laterals perhaps. The trick will be to release the oil from the tight rock back from the current frac. Re-fracs are possible, too, and may enhance production by raising formation pressure (taking it back above bubble point). The current maximum number of wells per pad per formation on a 1280 spacing is four, and with the general layout from later in development having those ordinarily running roughly parallel, there may be the ability to CO2 flood the reservoir (Dakota Gassification (https://en.wikipedia.org/wiki/Great_Plains_Synfuels) would be a possible Co2 Source. There is a distinct possibility that permeability fairways might defeat such a strategy, though.
Either the re-frack or the CO2 flood would raise pressure in the reservoir, and keep it above bubble point, allowing oil to flow again.
@Smokin Joe
It's a start! Thanks!
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And raises, in my mind at least, the question of is there a method to enhance recovery of the oil remaining at that point.
Water flood?
Gas injection?
I have no idea what might work in that situation.
highly doubtful any injection would be cost effective as flood conformance is improbable with formation fractures . Increase in well/frac density best hope