thanks Michael, I’m just putting a sanity check out there. I’m trying to figure out how many barrels per day have been coming out of these horizontal wells. I’ve heard a lot of varying numbers and even tried to do some math on what companies have elluded to being on average 30-40 barrels per well per day…but, I’ve heard that some of these are 10 times more successful than that.
Steve, 30-40 bopd would be considered a poor well unless its making 10Mil.cft gas per day. Our well is producing about 250 bopd and 7mil.cftd. It is considered a good well but there are plenty of others producing in the same range. Even if yours comes in on the low side I would think at least 100bopd and 1mil.cftd. Newfield has almost $9,000,000 invested in that well, I’m sure they expect to make their money back.
Thanks Gabe, I didn’t know that rule. I guess we can be thankful for some state laws after all! What defines a well being completed? or is that when it starts pumping? Either way, if I’m dealing with an honest company, it looks like November or sooner…thanks for your comments it really clears up some questions!!!
Ron our well in 32-8N-6W was spudded on 10-26-2011 and show see production this week, waiting on water flow back, there are wells that are waiting 6 months just to get fracked. i hope tp see a check by Christmas, that would be a nice gift.
Also waiting on flow back. Had one over a Year from first production to check, but we got interest. That was with B.P., an honest Co.
A few of points about the “oil business”.
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It is and always has been highly competive and secretive, even though companies cooperate with each other readily.
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The delay in fracturing (and that is the correct term regardless of what cute little reporter conveyed it as fraking) is more of lining up the heavy duty equipment to do the job. The industry has overbuilt in the U.S. the heavy equipment and drilling rigs at least three times in my almost 60 years of working in it. The bust will come in some fashion. It always does no matter what the rosy predictions. The industry does not want to get caught with a pile of useless steel and parked trucks if they can help it. So, a delay because of equipment to drill a well or frac a well is going to happen.
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The Cana Woodford was a term used by the three for four companies that started in Canadian County. The extent of the Woodford shale is well known across the Anadarko Basin NW to SE. Many wells have been drilled through it to reach the conventional producing sands and limestones of the Anadarko Basin. So it’s whereabouts is no secret to the oil companies. The map at the top of this thread is very informative and shows the expected oil/gas window (green) and the dry gas area to the SW (red). Middle Grady is being developed and the play is extending SE into Stephens, Garvin and McClain. Over a long period of time the map will change slightly as various wells are drilled and produced. The final answer at to what is productive and what is not in the Woodford shale is years away. And what those successful individual wells will finally poroduce is decades away.
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For those with unleased acreage throughout the play my advice is to pay attention to this website and the particular county your acreage is in and ask about current lease prices. They will be all over the place in the early stages, settle down for a bit until the drilling starts and then increase rapidly as results become known on various wells. In my own experience I leased in Grady for $500 an acre last spring. I think the going rate now is $1500 an acre. But, there are five producing Woodford wells in the township and two more drilling and a multiunit planned. Each mineral owner has to make their own decision on what to do. Finiancial cirumstances have a large role here and it is each individual mineral owner’s decision on what is best to do. The leasing companies want to get the lease as cheap as possible. A long holdout to leasing may get thrown into the “forced pooling” pot and gain or lose in that situation.
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Selling outright a mineral interest is a hard decision. Many of these interests have been passed down over decades waiting on some activity to take place regarding them. A figure that will be thrown out first is three times the current lease rate. In the case of my minerals it would have been $1500 an acre. Offers of $2500 an acre are common in that part of Grady now. I have not heard of any buyouts at $4500 an acre which is three times the $1500 an acre that some leases are going for in that area. As usual, the buyer of the mineral interest is trying to get it as cheaply as possible. Everyone has to make their own decision to sell their mineral interest.
Long post but maybe it will help some of the individuals that are just now getting offers on their mineral interest.
A real rollercoaster of a ride over almost six decades for me. Glad I took it.
Don good info.
The well is complete when it is capable of producing. However, it is possible that a completed well may be shut-in awaiting connection to a gathering system or pipeline. First production would be when the gas/oil is first put into a pipeline or, in the case of liquids, possibly a tank at the well site.
Larry if you do not mind what is Contnental getting for price for oil and for gas, just wondering our well is just starting to produce.
Francis-That is a telling number. Playing the production out per unit to even six or four wells per unit says the price you sell your minerals for is undervalued. Remember though, that whoever is buying it has to make a profit long term on it. Otherwise, they would not be buying it.
Also, take into consideration that the multiple wells per unit will not happen just bang, bang, bang. With the history of production, gas wells length of productioj becoming more predictable. The operators do not have to drill additional well quickly in a unit. It will depend on prices primarily and the goals of the company .
A successful well in a unit probably means at least a ten year production period for that well. That lease that the well was drilled under will establish what is called HBP (Held By Production), meaning that well will hold that lease for probably ten years as long as it is producing something, and that something may not be very much eight to ten years out. So a company does not need to be in a rush to add the three to seven other wells a unit might hold.
There are mineral interest owners that will experience some sad experiences as all this plays out. Even though they have a successful well in their unit, the next unit has more wells in it in a short period of time. Probably different companies with different goals. And no, the multiple wells in the next unit are not “draining” the unit with only one well in it. Very tight shale gas production drains from a relativity small radius around the horizontal lateral fracture zone. If there was the ability to drain a 640 with one well why are companies planning on drilling as many as eight?
Also, companies may sell their producing units from time to time. They are making the same calculation that an individual mineral owner makes in selling their interest, only much more complicated and for many more $$. By the same token, whoever buys producing units from an operator believes they can make a profit out of the purchase. Otherwise, no sale.
I have been watching all the posts so will jump in. Our well is in section 1, 16N 14W Dewey county. Drilling was finished end of April 2011. Fracturing finished by end May, 2011. First gas sold JUNE 2011 and first oil sold in jULY of 2011. Our first check came late Feb. this year but no interest paid on that check or the March check so intend to contact them. The well came in at 105 bopd and gas at 2.1 Million cfpd. Don maybe you can help me understand the product codes on our remittance from Continental Resourses.They list 4 product codes at top of the remiitance. 1xx for Oil, 2xx for Gas in mcf, 3xx for condensate and 4xx for plant products. We are getting paid on codes 200, 203, and 300. Payment for 200 is very small, Payment for 203 and 300 are much better and pretty close to the same $ amount. We are not getting paid on Code 1xx. I called them and they said the 300 was for the oil. Would the code 203 be for galls liquids? If you or anyone is familiar with CR payment codes I would appreciate your explanation. Well dropped off pretty fast first 6 months but seems to be leveling out now.
Larry i am going to take a guess and say the code 200 is for 1000 mcf gas and since it has a higher btu level because of the oil you get a higher then market price. i would think the code 203 would be the bi products they are getting off the gas, i am not sure, someone can correct me. IT looks like Continental is getting some decent prices for their product, Thanks for the information.
Also keep in mind that those gas prices are hedged contract prices. As soon as those contracts are expired, the 5.80 per mmcf will settle to 2.00 per mmcf and drilling season will be over. The bust may come sooner than later unfortunately. Prices must be at least 3.50 per mmcf for drilling to be profitable. Those with good oil production will continue in the boom which looks to be most of Grady and half of Canadian.
Don. After 6 months production was down 35% to 40%.
Thanks Larry, right on the decline curve.
The only bogus thing is that the company uses MY farmland in MY section to drill a well under SOMEONE ELSES land. I understand how directional drilling works, but the royalty for that well wont be paid to me, I just get to loose some useable top soil. BTW this is an open general thread not a payment thread. I guess if you were loosing some land without compensation you might think differently? Funny you complain about my complaint. LOL I think I have a valid one. Yours not so much.
To anyone: Do the horizontal wells have a set direction like north to south or south to north etc? A well head in sec 2 drilled into sec 35 and a well head in 35 drilled into sec 2. Could well heads in any other sections come into 35 besides from section 2? I don’t know sections are laid out. Thanks
Last check showed code 300 (oil) at a little over $100 for Feb. Code 200 was 3.72 and code 203 was 4.17 for December and Jan respectivley. Those codes have me confused.
On selling your rights… We have a good well, deffinitely not the best well but a good one. We are getting between 100.00 - 150.00 per acre after a year+ of production. If you had 10 acres and sold those rights for 4500.00 each you would recieve 45,000.00 right? That would be less than 3 years production from one well. They are planning to drill 8 wells in many of those sections. When you multiply those production numbers to 8x. Then they are paying you less than four months worth of production. I wouldnt sell for 10,000.00 per acre.
Francis, You are assuming that oil prices will remain the same. They will change over the next 10 years but who know which way. 3 years ago it was around $40 a barrel, 4 years ago $135. From the late 80s to early 2000s it was $20-$30. You really never know. I also have records on a few wells the were decent producers for about 2-4 years and then produced almost nothing for the next 4-5 before they were plugged. In some cases the well lost money for the investors.
On the other hand I’m seeing new interest in sections with plugged wells, dry holes, (or wells with very low production.) In many cases it has been 30-60 years since there has been any activity.