i'm sure OKC is great, but i don't wanna live near cat5 'naders
Houston..we have a problem....
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Last: 5 days ago by one MEEN Ag
What's oil got to do with dallass?one MEEN Ag said:
This thread is reserved for only dallas vs houston city slap fights. And even its only allowed during football season and 3 post max.
PeekingDuck said:What's oil got to do with dallass?one MEEN Ag said:
This thread is reserved for only dallas vs houston city slap fights. And even its only allowed during football season and 3 post max.
Ever heard of JR Ewing?
Gonna be interesting to see how well winterized operators are with the polar vortex incoming. We are seeing gas prices $8-9 thru the weekend and MLK day.
I hope someone with more knowledge than me can chime in with assurance that chemical plants on the coast insulated some damn pipes and figured out how to weather a cold snap.
I'd appreciate not having PVC skyrocket again
I'd appreciate not having PVC skyrocket again
Pahdz said:
I hope someone with more knowledge than me can chime in with assurance that chemical plants on the coast insulated some damn pipes and figured out how to weather a cold snap.
I'd appreciate not having PVC skyrocket again
I assure you they talked about it just long enough for the public whaling to blow itself out and then took it out of every forecast and budget as a "nice to have".
Sweet...force majeure here we come
Moved from Dallas to Norman for work 13 years ago. Less than 30 minute commute to downtown OKC. We love living here. Great place to raise a family.
Bonus: OU entering the SEC means I'll get to watch Sooners tears live.
Bonus: OU entering the SEC means I'll get to watch Sooners tears live.
I can verify that the RRC spent an enormous amount of effort on winterization and we spent an enormous amount of time wondering why they were completely focused in the wrong areas. There was even a secret map that we were driven by that operators weren't allowed to see. They made all of the decisions on their end with no direction from anyone that knew what made any sense. That said, I think we'll work it out collectively.
What are we talking about here? Are you talking about the Critical Infrastructure Designation?
Yes, and all the idiocy that came with it.
Yep, it was a mess and so far I haven't seen a benefit. Just more paperwork.
https://www.rigzone.com/news/talos_to_acquire_quarternorth_for_13b_add_gom_production-16-jan-2024-175389-article/?utm_source=newsletter&utm_medium=email&utm_campaign=daily&utm_content=articlethree
Quote:
Talos Energy Inc. is acquiring privately held U.S. Gulf of Mexico exploration and production company QuarterNorth Energy Inc. for $1.29 billion.
The acquisition will add production of approximately 30,000 barrels of oil equivalent per day (boepd) expected for full-year 2024, averaging about 75 percent oil from approximately 95 percent operated assets, inclusive of planned downtime, Talos said in a news release Monday. QuarterNorth's producing assets include six major fields. The acquisition will also add proved reserves of approximately 69 million barrels of oil equivalent with a PV-10 of $1.7 billion, according to the release.
bp confirmed it is Murry A for CEO. He is better than Looney but as long as Lunde is still around nothing changes.
https://bigbendsentinel.com/2024/01/10/railroad-commission-claims-gas-leak-to-hide-produced-water-destruction/
I'm a offshore O&G guy so I am not familiar with what goes on in west Texas. Is this "normal" or is this just election year posturing?
I'm a offshore O&G guy so I am not familiar with what goes on in west Texas. Is this "normal" or is this just election year posturing?
I would say it's neither. This isn't normal but it isn't just election year posturing. it is a major screw up that has been mishandled at every step.
Stogner sure has been getting her titties rustled over that lately
I would say an uncontained water flow like that is not normal, but it also happens on occasion.cajunaggie08 said:
https://bigbendsentinel.com/2024/01/10/railroad-commission-claims-gas-leak-to-hide-produced-water-destruction/
I'm a offshore O&G guy so I am not familiar with what goes on in west Texas. Is this "normal" or is this just election year posturing?
This paragraph caught my attention:
As the Pecos Enterprise previously reported, Burch believed that water produced by Permian Basin operations is only part of the problem because the Railroad Commission authorized Texas saltwater disposal operations to take water from New Mexico and Louisiana as well, since neither state will allow the water to be injected into their own ground.
The bold portion is false. Just like Texas, New Mexico and Louisiana have many salt water disposal wells.
For those who follow oil/gas on twitter this has been a big saga since the first time it produced water up to the surface in jan 2022.
Its a bunch of very old wells that have very bad plug and abandonments. Also, new production in the area is thought to have put pressure on the bottom side of the weak plugs.
There's a pretty heavy editorial slant here and the truth is somewhere in the middle.
-The oldest wells are weak and susceptible to P&A failure in that field. They are old Gulf wells I think from the 1930s to the 1950s, Chevron bought them but they didn't drill these ones that are causing problems.
-Fracing activity nearby is probably a contributing factor to degrading P&A
-It is a big problem and Chevron is surely realizing that their P&A obligations for this field are way greater than they had thought.
-Chevron hired a law firm to manage the P&A activity back in Jan 2022 and it wound up doing wacky things like never writing anything down for fear that the surface lease holder would photograph it.
-Burch is lying by saying that the only thing you can do is stop fracing in the area. Thats not true, you can also (and more reliably) reenter the well and do a better P&A job.
-Burch is wrong to think that hauling the produced water off is dumb and building these pools is laughable. You've got a problem right there, this is how you mitigate it. The salt water disposal injection wells are usually a few layers deeper than where you're getting oil/gas from. Salt water injection is mostly associated with lubricating fault lines and causing minor earthquakes. The back pressure on the underside of the P&A is most likely related to fracing oil/gas production zones nearby, not way deeper SWD.
Its a bunch of very old wells that have very bad plug and abandonments. Also, new production in the area is thought to have put pressure on the bottom side of the weak plugs.
There's a pretty heavy editorial slant here and the truth is somewhere in the middle.
-The oldest wells are weak and susceptible to P&A failure in that field. They are old Gulf wells I think from the 1930s to the 1950s, Chevron bought them but they didn't drill these ones that are causing problems.
-Fracing activity nearby is probably a contributing factor to degrading P&A
-It is a big problem and Chevron is surely realizing that their P&A obligations for this field are way greater than they had thought.
-Chevron hired a law firm to manage the P&A activity back in Jan 2022 and it wound up doing wacky things like never writing anything down for fear that the surface lease holder would photograph it.
-Burch is lying by saying that the only thing you can do is stop fracing in the area. Thats not true, you can also (and more reliably) reenter the well and do a better P&A job.
-Burch is wrong to think that hauling the produced water off is dumb and building these pools is laughable. You've got a problem right there, this is how you mitigate it. The salt water disposal injection wells are usually a few layers deeper than where you're getting oil/gas from. Salt water injection is mostly associated with lubricating fault lines and causing minor earthquakes. The back pressure on the underside of the P&A is most likely related to fracing oil/gas production zones nearby, not way deeper SWD.
jetch17 said:
Stogner sure has been getting her titties rustled over that lately
Get ready for some more pump jack titties to hit the internet soon…
I believe half of the Strategic Petroleum Reserve is salt dome injections in southern louisiana.TxAg20 said:I would say an uncontained water flow like that is not normal, but it also happens on occasion.cajunaggie08 said:
https://bigbendsentinel.com/2024/01/10/railroad-commission-claims-gas-leak-to-hide-produced-water-destruction/
I'm a offshore O&G guy so I am not familiar with what goes on in west Texas. Is this "normal" or is this just election year posturing?
This paragraph caught my attention:
As the Pecos Enterprise previously reported, Burch believed that water produced by Permian Basin operations is only part of the problem because the Railroad Commission authorized Texas saltwater disposal operations to take water from New Mexico and Louisiana as well, since neither state will allow the water to be injected into their own ground.
The bold portion is false. Just like Texas, New Mexico and Louisiana have many salt water disposal wells.
The area where the original well turned into a geyser and now water is leaking to the surface through a fault is in the Central Basin Platform between the Delaware and Midland basins. This is not an area of active hydraulic fracturing.
This is an area of old oil fields where current operators are injecting produced water into disposal wells. There are a few disposal wells near the geyser well. It is likely that one of these wells is causing the problem either due to bad casing/tubing allowing the water to inject into a shallower zone or by water migrating up a fault into the shallower zone of the geyser well.
I would hope the Railroad Commission had disposal in nearby wells halted when the geyser appeared. Looking through the RRC website at the nearby disposal wells, I can't find reports of injection volumes by month. Makes me wonder how well these mom and pop operators were reporting their activity and how much oversite the RRC was giving to this area.
This is an area of old oil fields where current operators are injecting produced water into disposal wells. There are a few disposal wells near the geyser well. It is likely that one of these wells is causing the problem either due to bad casing/tubing allowing the water to inject into a shallower zone or by water migrating up a fault into the shallower zone of the geyser well.
I would hope the Railroad Commission had disposal in nearby wells halted when the geyser appeared. Looking through the RRC website at the nearby disposal wells, I can't find reports of injection volumes by month. Makes me wonder how well these mom and pop operators were reporting their activity and how much oversite the RRC was giving to this area.
Did a quick drilling info pull, and there are 12 injection wells still reporting injection within 5 miles of the SWD geyser. the thing that concerns me the most is that looking at those 12 wells, the last report shows a cumulative ~6100 BBL/Day injection, which is not much. and one of the wells (42-103-05734) reported injection pressures of 1185 psi for the last few months with only 300-400 BBL/Day injection. it seems like that injection interval is charged up at this point, and I would guess that all of those old wells in the area are just sitting there corroding, creating pathways for that saltwater to escape the injection zone and either come to surface or crossflow downhole.
early in my career I was part of a response team for a well in East Texas that had a saltwater well control incident. It was a slightly older well, that was cased across a long time injection zone. Well that injection zone slowly corroded the pipe and when we got on it the casing and tubing were basically like swiss cheese. The flow test to surface showed upwards of 40k bbl/day flow potential and when the surface was shut in there was a screaming cross flow. made the well a nightmare to try to cement because you couldn't get the well to static conditions to let your cement set up. If memory serves we had a standalone snubbing unit on that well for >90 days before we finally got it controlled and plugged.
This has been my fear in W. Texas since I took over as an SWD engineer back in 2016. With all of this injection going on out there and much of it at or above the producing intervals, I think we could have quite the problem on our hands as an industry in the next 20 or so years (our intermediate cement jobs on an industry level don't give me lot of warm fuzzy feelings). Because despite what the disposal operators tell the RRC, no reservoir is truly infinite acting.
early in my career I was part of a response team for a well in East Texas that had a saltwater well control incident. It was a slightly older well, that was cased across a long time injection zone. Well that injection zone slowly corroded the pipe and when we got on it the casing and tubing were basically like swiss cheese. The flow test to surface showed upwards of 40k bbl/day flow potential and when the surface was shut in there was a screaming cross flow. made the well a nightmare to try to cement because you couldn't get the well to static conditions to let your cement set up. If memory serves we had a standalone snubbing unit on that well for >90 days before we finally got it controlled and plugged.
This has been my fear in W. Texas since I took over as an SWD engineer back in 2016. With all of this injection going on out there and much of it at or above the producing intervals, I think we could have quite the problem on our hands as an industry in the next 20 or so years (our intermediate cement jobs on an industry level don't give me lot of warm fuzzy feelings). Because despite what the disposal operators tell the RRC, no reservoir is truly infinite acting.
As an intern and entry level engineer, I did a study on a legacy vertical asset involving casing leaks. I don't remember exact numbers but over 90% of them were the result of corrosion in an injection interval that sat above the producing zones. Cementing to and above the primary injection intervals can be very challenging due to overpressure, existing natural fractures and low fracture gradient in those zones. My suspicion is that a significant portion of vertical wells in the Midland Basin do not have good cement across the injection interval, exposing the casing to fairly corrosive produced water. Fixing it correctly is rarely a high priority or high ROI workover, so the net result is that a lot of decent vertical wells end up plugged, or the problem is ignored as long as its not overpressuring producing intervals and watering out the well altogether.BlackGoldAg2011 said:
Did a quick drilling info pull, and there are 12 injection wells still reporting injection within 5 miles of the SWD geyser. the thing that concerns me the most is that looking at those 12 wells, the last report shows a cumulative ~6100 BBL/Day injection, which is not much. and one of the wells (42-103-05734) reported injection pressures of 1185 psi for the last few months with only 300-400 BBL/Day injection. it seems like that injection interval is charged up at this point, and I would guess that all of those old wells in the area are just sitting there corroding, creating pathways for that saltwater to escape the injection zone and either come to surface or crossflow downhole.
early in my career I was part of a response team for a well in East Texas that had a saltwater well control incident. It was a slightly older well, that was cased across a long time injection zone. Well that injection zone slowly corroded the pipe and when we got on it the casing and tubing were basically like swiss cheese. The flow test to surface showed upwards of 40k bbl/day flow potential and when the surface was shut in there was a screaming cross flow. made the well a nightmare to try to cement because you couldn't get the well to static conditions to let your cement set up. If memory serves we had a standalone snubbing unit on that well for >90 days before we finally got it controlled and plugged.
This has been my fear in W. Texas since I took over as an SWD engineer back in 2016. With all of this injection going on out there and much of it at or above the producing intervals, I think we could have quite the problem on our hands as an industry in the next 20 or so years (our intermediate cement jobs on an industry level don't give me lot of warm fuzzy feelings). Because despite what the disposal operators tell the RRC, no reservoir is truly infinite acting.
I'm not well versed in the O&G insurance world, but my understanding is that there are many operators who buy some form of bond or insurance for the plugging responsibility of their wells at the end of life. Whoever is on the other side of that transaction is probably in for a very rough time if this ever gets investigated/addressed, unless there is recourse to the operators.
Yea, my old company got into the Delaware out in reeves county, and about a year or so after starting up our drilling program, we started to have minor problems drilling through the Delaware mountain group sands, taking increased kicks and having trouble maintaining balanced conditions. Our theory was it was due to all the increased injection and so we started aggressively pushing offset SWDs to shut in while we drilled intermediate. I also spent a decent chunk of time writing up/modeling technical arguments to protest commercial SWDs on our acreage at the RRC.GarlandAg2012 said:As an intern and entry level engineer, I did a study on a legacy vertical asset involving casing leaks. I don't remember exact numbers but over 90% of them were the result of corrosion in an injection interval that sat above the producing zones. Cementing to and above the primary injection intervals can be very challenging due to overpressure, existing natural fractures and low fracture gradient in those zones. My suspicion is that a significant portion of vertical wells in the Midland Basin do not have good cement across the injection interval, exposing the casing to fairly corrosive produced water. Fixing it correctly is rarely a high priority or high ROI workover, so the net result is that a lot of decent vertical wells end up plugged, or the problem is ignored as long as its not overpressuring producing intervals and watering out the well altogether.BlackGoldAg2011 said:
Did a quick drilling info pull, and there are 12 injection wells still reporting injection within 5 miles of the SWD geyser. the thing that concerns me the most is that looking at those 12 wells, the last report shows a cumulative ~6100 BBL/Day injection, which is not much. and one of the wells (42-103-05734) reported injection pressures of 1185 psi for the last few months with only 300-400 BBL/Day injection. it seems like that injection interval is charged up at this point, and I would guess that all of those old wells in the area are just sitting there corroding, creating pathways for that saltwater to escape the injection zone and either come to surface or crossflow downhole.
early in my career I was part of a response team for a well in East Texas that had a saltwater well control incident. It was a slightly older well, that was cased across a long time injection zone. Well that injection zone slowly corroded the pipe and when we got on it the casing and tubing were basically like swiss cheese. The flow test to surface showed upwards of 40k bbl/day flow potential and when the surface was shut in there was a screaming cross flow. made the well a nightmare to try to cement because you couldn't get the well to static conditions to let your cement set up. If memory serves we had a standalone snubbing unit on that well for >90 days before we finally got it controlled and plugged.
This has been my fear in W. Texas since I took over as an SWD engineer back in 2016. With all of this injection going on out there and much of it at or above the producing intervals, I think we could have quite the problem on our hands as an industry in the next 20 or so years (our intermediate cement jobs on an industry level don't give me lot of warm fuzzy feelings). Because despite what the disposal operators tell the RRC, no reservoir is truly infinite acting.
I'm not well versed in the O&G insurance world, but my understanding is that there are many operators who buy some form of bond or insurance for the plugging responsibility of their wells at the end of life. Whoever is on the other side of that transaction is probably in for a very rough time if this ever gets investigated/addressed, unless there is recourse to the operators.
Operationally we started doing some 2 stage cement jobs to ensure we got our intermediate cement cleanly across the DMG and up into the surface casing shoe for exactly this reason. But part of my job was reviewing old wellbores to look for SWD conversion candidates, and the ones that we had bond logs on... i'm not thrilled about the state of any of the wells out there drilled before about 2017.
Gotta love them DV tools.
Hey Bullfrog1 shoot me a PM I have a question I wanted to ask you.bullfrog1 said:
The problem is that the prices r getting close to where they will start dropping Frac crews to compensate.
I think most the natty boys should be dropping.
so are Marathon, Endeavor, and Diamondback safe from being acquired?
No- I would put Marathon and Endeavor as the to be acquired. Thinking Devon and Marathon tie up sooner or later.
If the article that came out a month or so ago is to be believed, you should probably see some movement on Endeavor in Q1. My bet is on Exxon picking them up with all that cash on hand once the Pioneer deal gets done.
I dunno about cash on hand, it will be some form of stock.
When is the PXD to XOM deal going to be done? I heard it was going to take a very long time. Like after the election. Could be wrong.
Hearing May 1 internally.
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