Ron, Take a minute to read the previous posts. They have been drilling the well for a week! Sounds like Steve is on top of things.
A well we are under started 12-28-11, still not producing. And then 6 months? Nov.?
I have recently received 2 more offers to buy my mineral rights. When I say offers, they do not include how much they want to pay but, do you want to sell your mineral rights from Cheryl DeLay and Cosmo Investments. I know they would expect to make money on their purchase, so why would anyone actually sell their mineral rights to them?
If a company is starting to drill on your minerals in a new play wouldn’t you want to keep those mineral rights forever? btw this is in MCClain county sec 9 town 6 north range 3 west
Steve, The only reason I can think of to sell is just if you are desperate for money. It looks like Newfield will be drilling that section soon, so I imagine you have already leased or been pooled. Our well was completed in Feb. but I’m still getting offers to buy. Let us know how your well turns out, we got a pretty good one in Stephens Co. 17-2N/4w
Steve, Did you know they have been drilling for about a week. Newfield spud the Danni 1H-9 on 3-31-12.
Thanks Don, well said.
yeah. I saw that Monday when OCC scanned it in, needless to say it piqued my interest. So how long until I get a royalty…cut to the chase…lol…I figure 4-6 weeks until completion and then division orders…but I don’t know how many months out until I could receive a royalty check.
Operators have 180 days from first production to pay royalty owners. After that, payments normally trail production by 60-90 days. The amount of time they have to pay is controlled by statute in Oklahoma. The law is called the Production Revenue Standards Act. If they don’t pay within the time allowed by the law, they owe 6-12% interest (depending on whether or not there are title issues that are preventing payment).
Michael I didn’t mean to said he wasn’t. But I started my response an was called away, by the time I got back to finish he already had a wealth of information. And I also type slow.
Thanks for sharing your experiences. I’ve learned a lot about the time frame from spudding until production. And I didn’t know about the fracking delay. I would like to think that the mid-continent newfield team would be timely in the fracking, because they have basically been pulling out of the gulf and eastern oklahoma natural gas plays and re-branding themselves as oil and liquid gas drillers. Because their stock has been murdered. management will be a key factor, they are saying on company news by summer and those kind of comments are pretty telling and forward. McClain seems to be the big secret that is coming out in this play because it’s not the traditional cana - woodford topographic. so if they are on to something and can land grab early like my lease last august, they can march in and start this new play without a bidding war. which is exactly what I think is going on…I just know these 3 oil formations are tight shale 120 feet or so each, which doesn’t mean anything to me because I’m not an engineer…(I feel like doc mccoy on star trek) Now I see why the oil business is crazy.
I think you will see more of this in McClain Co. Look at CD# 201105614. Some one good with words might tell everyone what is going on but I’m not and I type slow.
Larry-
I am not that familiar with the codes in Oklahoma. I do know that the gas can fall into different price ranges based on the btu in the gas. One of the codes is probably for condensate and even then, condensate can vary on it’s saturatiuon of oil and therefore there can be different codes for that. You could see this difference in consensate prices from well to well. The oil and dry gas are pretty straight forward in seeing what the production stream got for them. The fourth code will have to come from someone more familiar with it, I don’t know.
If you can, will you tell us what the rate of production was the sixth month after first production. My guess, based on a decline curve I have from Cimerex, is that it was down from 30 to 40% from first production. I would be pleased with a 20% drop and not surprised at a 50% drop.
To all concerned-These declining production rates are to be expected and those starting to collect royalties need to keep this in mind as far as finiancial planning is conserned.
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.