Martha,
Reading the article wouldn’t there need to be a coal plant in proximatey to the area to be drilled?
Linda
The bottom falling out of the royalties on the Devon wells… My guess is that many of the wells drilled this year and last will soon need new pumps. Frac sand is pretty hard on these submersibles, and since they produced them pretty hard initially, the production rates will fall off dramatically as the pump efficiency dies off. A neighbor of mine just got his pump replaced and he is back at his initial flow rate of 600 plus bbls per day after dying off to 70 bbls per day.
Robert,
Since they pumped then hard, do you think these wells will stand up? Or do you think they need to slow them down a little before they kill them?
H drilling is kind of new to me, but it seems they are trying to get their money back the first year and may be killing a good well.
Changing out pumps is going to be routine. Flowing the wells too hard does produce an excess of frac sand, removing it from the perfs, and closing the fractures , reducing the permeability of the well and reducing the production long term . Not to mention messing up the down hole pumps.
Fear not virginia, they will be re fracing, squeezing off unproductive zones, doing acid jobs , and enhancing production on these wells for years. They will also be drilling both the wood ford and the Mississippi on each section.
I had a question about the rate that Devon is paying on condensate. They list it in bbls under code 400, (all plant products ) . They are paying me. 35$ per bbl, when the selling price is 100 $ per bbl . What is up with that ?
did anyone receive D.O from section 15-19N-2w?
Linda, Sorry it took so long to reply. I just returned from North Central OK. Both coal and natural gas fired plants produce C02 and many coal plants are being converted to natural gas. Coal will continue to be used in areas where it is economical to mine and many new plants will use natural gas. Electricity generation from natural gas is expected to increase by over 40% of the total U.S. electricity generation by 2020. Not all of these power plants will be directly above designated C02 injection and storage areas, so pipelines will be used to transport large amounts hundreds of miles. Kinder Morgan just consolidated all its pipelines companies under one parent company, Kinder Morgan Incorporated, in the second largest energy merger in history since Exxon and Mobil and will be building C02 and natural gas pipelines. Their projects are massive.
M Barnes what are the discrepancy in royalty payments regarding Devon about? Just curious.
My understanding is that condensate that is stripped out at the well site is more likely to get closer to oil prices since it is simply a matter of pressure and temperature to split it out. It comes out as a liquid at the surface (it was a gaseous form at depth). Gets stored in the oil tanks and picked up by the tankers regularly. Goes right to market.
The liquids that are stripped out at the plant are different. They are the NGL’s- heavier and more complex components of the gas and need more processing at the plant, so they get a different price structure.
It also may have to do with the pipeline contracts that they have for those Plant Products. It could also have to do with the exact or loose definition of “condensate” that Devon uses.
Best thing to do is contact your revenue interest group at Devon and ask them why.
M Barnes, All the info I find claims that currently there is no fully defined definition of wet gas which can be anywhere from humid to multi flow and along with the reservoir temps etc it’s not being correctly measured and the measurement will continue to be guessed at until it’s universally defined and measurement rules and regs for metering are created. I have not been able to get a definitive answer from the OCC of it’s position on the companies not measuring the condensate and correctly paying the mineral owners? It just doesn’t seem possible that companies are not accurately measuring the liquids in the gas, because they legally report what each well is producing. Do you know if OCC is working on solving this problem? http://en.wikipedia.org/wiki/Wet_gas
Robert, It is an ‘endothermic’ process, so it requires energy for the gas to turn to liquid. The abnormal well pressures are a natural form of added energy. Gravitational loading or unloading due to deposition or erosion in sedimentary basins is one of the most common mechanisms responsible for abnormal fluid pressures. The basin fluid flow is caused by a vertical geological uplift (Nemaha Uplift) and is indicative of a area larger than one single basin. Thank you so much for helping me prove the multi basin theory. Now, we should be able to prove the metamorphic rocks in these gas driven basins are producing the gas thus the abnormal pressures are naturally produced and not created by adding man made pressures like injecting CO2 enhanced oil recovery mineral owners should be paid according to the amount of condensate which comes from this natural process and should be paid the going rate for condensate in the area which would be the 100 bbl without processing and transportation costs. However, the NGL’s do require man made energy to separate so a mineral owners lease might have to address this in order to be paid for the final product.
Hi Martha,
Do you have your own agreement or “paragraphs” that you include when companies wish to lease? Is there room to negotiate or will they simply file a pooling order and have the court decide if they can’t come to an agreement with you?
Shelly
Here is the deal on the natural gas condensate, and NGLs. I started up a gas plant here the last two years taking gas from Range and Sandridge wells. We make condensate, and NGLs. Devon has a small gas plant on county road 65 about 3 miles from me. The purpose of this plant is to reduce the pressure on the oil wells. By doing this they take 50 to 80 psi well head pressure and take the pressure down to about 20 psi. This allows the wells to make more oil. Remember the downhole pump is at the bottom of the vertical. The vertical tubing has to be full of liquid so the pump wont cavitate. The more oil in the vertical the faster they can pump the well. The gas is what drives the oil level down.
They compress the gas to whatever discharge pressure DPC has on their pipeline and send it to the plant south of crescent. They have a slugcatcher and a dehy unit on location. The slugcatcher makes condensate, as well as the suction scrubbers on the compressors. The dehy removes the water. Condensate is in liquid form at 14.7 psia. Think of it as the light ends of the oil. But the main point is that it is liquid at atmospheric pressure. Devon sells the condensate from their location out of atmospheric tanks. NGLs are what the plant in crescent is making. They take the wet gas from Devon, strip the water in a dehy, and cool the gas using an expander/JT unit. This cools it down to -170F or so, and they separate the propane from the methane and ethane. They sell the propane, and send the methane to a pipeline that buys natural gas. That is what you use to heat your homes in the city. We sell condensate out of atmospheric tanks every day for about 100 per bbl. from our plant. That is why I was wondering where Devon got their price of 35 dollars per bbl. Sounds like someone is getting screwed again. If anyone can contact Devon and get a straight answer out of them let me know what they say. I dont know if we get a percentage of the NGL at the DPC plant. We should, but I would have to know what their contract is.
Robert,
“…the Nemaha fault zone in central Oklahoma form the discharge locus where pressure reaches near atmospheric.”
http://pubs.er.usgs.gov/publication/ofr20111245
https://gsa.confex.com/gsa/2010AM/finalprogram/abstract_180146.htm
US plans to export ethane NGL. Enterprise Products Partners (EPD) is going to build out a refrigerated ethane export facility in Houston in last part of 2016 to fully refrigerate ethane at approximately 10,000 barrels per hour, so it will be the largest in the world. http://www.wallstreetdaily.com/2014/09/04/u-s-ethane-exports/
Does anyone have current lease for pricing comparison on bonus in se/4 of 16,18n,4w ? Or status of activity in that area? Fielding an offer- just want to be knowledgeable in dealings! Thanks
s 23 $550 3/16, $500 1/5, $0 for 22% This was for 640 acre spacing. The prices are based upon whether it is for a horizontal well at 640 or a shallow vertical well at smaller spacing.
Logan: Stephens Production Co.; Jane No. 4-21-16H Well; SE/4 NE/4 NW/4 NW/4 (BHL) of 16-16N-04W; 156 barrels oil per day, 251,000 cu-ft gas per day; TD 11,021.
Stephens Production Co.; Norris No. 1-23H Well; NE/4 NW/4 NE/4 NE/4 (SL) of 23-18N-04W; 73 barrels oil per day, 28,000 cu-ft gas per day; TD 10,975.
I heard that Gastar is going to drill 44 new wells in the Wehlu Unit this next year. Any forecasts from anyone on this?