If two lateral wells are drilled on a section line. One traveling north and the other south. 1 well covers the north two sections and the other the south two sections are royalty payments made to owners in all 4 sections? Or is the pooling paid based on the section you hold the royalty?
EX. Sect. 1N and 2N hold 1280 acres, but i do not have and leased land on these. Will i receive payment from these wells since i DO hold leases on the Sect. 3S and 4S?
AD, if you give the full legal description I will look at it for you. I don't want to have to guess if you are in a vertically stacked [4 section] 2560 acre spacing.
I would guess the legal description would be we have a lease on the SE and NE 1/4 of the upper southern section. Continental has placed what appears to be a ECO-Pad with 4 wells on the section to the north of this. 2 wells dropped underneath the section we are in and continue to the next section south. The other two wells continue North through the norther two section. The pad is located in the north side of a road that divides the 1st north section and the 1st south section. You can view it on GIS. Wells Sibbern 1-27H and 2-27H are the southern. Payment received. To the north are Maruskie wells. No payment to date even though they were drilled at the same time. We just received first payments and division order was sent.
Sorry the division order was NOT SENT YET.
It's easier to search by Township range and section / file number/API number rather than by well name, operator, field. Township range and section should be on your lease.
These are a leased locations. Township 160 North, Range 94 West, Section 26: S1/2, Section 27: S1/2 NE 1/4, Section 35: NW1/4. I believe payments received to date are only for the leased section on 27. Well travel underneath this section and not 26 and 35. To the north lie sections T160N R94W Sections 22 and 15 which have two additional wells. Our check stubs only state the lower two wells to date. I am assuming we do not get royalty off the northern two, but i can get confirmation.
Correction in Section 27 we lease the S 1/2 NE 1/4 and N 1/2 SE 1/4.
AD said:
These are a leased locations. Township 160 North, Range 94 West, Section 26: S1/2, Section 27: S1/2 NE 1/4, Section 35: NW1/4. I believe payments received to date are only for the leased section on 27. Well travel underneath this section and not 26 and 35. To the north lie sections T160N R94W Sections 22 and 15 which have two additional wells. Our check stubs only state the lower two wells to date. I am assuming we do not get royalty off the northern two, but i can get confirmation.
AD, the way ND has regulated things, if you own mineral acres in a section that has been penetrated by a horizontal wellbore, you should receive royalty, whether you leased or not. The wells in your area look good, solid. They are not great but if you have more than a few acres, you don't need great, but it would be nice. Before all is said and done you will probably have a dozen wells or more.
Well you are correct about that. We have another half section to the east and there are two wells in "tight well" status currently. Would you say the payments we have received to date are only for the portion that resides on section 27? If so, that means we should really do well on the land to the east since we own over half a section as compared to 27 where we only have a few acres.
Ok, just to confirm you are saying if a well pad reside on my sections edge, but move horizontal into a section adjacent that i dont have interest on. We will not receive payment?
Thanks for all the help!
Yes, where the well head sits on a horizontal well has nothing to do with where the production comes from. It's the wellbore that does the producing. A half secrion vs a few acres, yes it will make a huge difference.
On last questions. Can you define what "Net" acres is? Are lease states a total acreage and then a net. Is the net where the the wellbore will be contacting? And does this normally define the payment method?
AD, as is common you probably own an undivided interest or a % of a much larger parcel. Meanig that you don't own all of any single acre but a % of all of them. If I had a 10% interest in the 640 gross acres of a section, I would have 64 net acres. If my section were pooled into a 1280 acre 2 section spacing where I had no ownership in the other section, I would still have 64 net acres but my decimal interest would be halved and my royalty would be halved compared to 640 spacing of equal production.
If all you care about is net from gross acres, you can stop here.
Really 640 acre spacings are too large for 4500 to 5,000 ft Bakken well. you could just as easily do it on 320 acres spacing. If someone says "Hey, that 2 section 10,000 ft lateral produces twice as much as a 5,000 ft lateral", you can ask them if it produces 4 times as much, because that is what it would have to do to give more royalty than a 4,500 to 5,000 ft lateral on 320 spacing.
After the initial flush production, many of the 10,000 foot laterals don't compare well on a foot by foot basis with the shorter laterals when the pressure is gone and production depends on a pump. I have found information where it is estimated that 70% of production comes from the first 3/4 mile of lateral wellbore, thats 3960 feet. No wonder so many wellbores in Texas are in the 4500 foot range. (Sarcasm alert) We all know that those Texas operators know very little about producing oil and just haven't yet figured out that the 10,000 foot lateral wellbore is so superior that you wouldn't want to drill anything else.
Operators continue to drill 10,000 foot laterals in areas where the field pressure is nonexistant for practical purposes after only 3 months, and that last mile of lateral does very little considering the cost to drill it and the expensive fracking/completion that was only of use for a very short time. If one looks around for one of the uncommon 3 section, 1920 acre spacings where they drilled from the center 7500 feet each way, their production is as likely to be greater than a 10,000 foot lateral in the same area as it is to be less.
I know you didn'r ask about anything but net acres, but you seemed interested in the behind the scenes of the Bakken play and the overlarge spacings and the inefficient wells of the land grab are the 800 pound gorilla in the room that is seldom talked about.
Is it going to change? No. Is there anything one can do about it? If you aren't held by production or leased, you could refuse to lease and that would make them grind their teeth. They are doing all of this as much to have unproductive acres under lease which is better than owning them. If you won't lease, they are drilling these horribly inefficient and expensive wells to little purpose and they have to pay you a royalty anyway that is not great and not poor, whether you leased or not, and one day you may be part owner in the well. Your mineral acres remain your mineral acres and continue to appreciate. Even leased your mineral acres would appreciate but they are then the lessees appreciating asset and not your appreciating asset.
Thanks again for the info. i have been at this for a year trying to find information just like this.
It does appear odd that the producers would want to drill 10,000 foot laterals with less production over using half the distance to maximize production out of a single rig. My only thought would be the expensive of setting up a new rig and drilling another hole out weighs the loss in production over the long lateral. And possibly the environmental impacts(surface) and permit costs.
It is obvious to me that Mineral/Land owners DO NOT have any say in how things will go for the forseeable future. Maybe in another 20 years when the owners have money in hand we will be able to pay the lobbyist to put are interests first. Of course by then we are all on electric cars and solar! ;)
I see Continental resources is using ECO-PAD's to maximize drilling over a small surface area and maximizing production in a section(s). I hope Oasis and others follow suit with this type of technology.
Regarding the drilling maps on GIS. I see most wells in my area are off center of the section and drilled north to south or south to north. Would you say these sites are off center of the sections to allow room for further expansion?
AD, the verticle part is the cheap part of the well. The verticle part of the well can be drilled in a week but the horizontal takes 3 weeks or more and rig time alone would make it much more expensive. Then you add in completion costs, which could be anywhere between $75,000 and $200,000 per frack stage. I have an operator telling me that each frack stage on one of my wells cost $191,000 each, for 24 stages. $4,584,000. The savings on mostly wasted frack stages that are useless after the first year would easily pay for a second verticle, in my opinion, but you can't hold 2 square miles with a 4,500 to 5,000 foot lateral. The ECO PAD (TM) could be used on short laterals just as well.
The drillsites are usually off center these days because the selection of drillsite is not driven by geology as it used to be but to keep things neat for the future wells to be drilled in these spacings that are mini-fields. If I were only going to get one well in 20 years, I would want it to be placed according to geology, to make the most of it. You may or may not get another well in your lifetime if you only get one well to start and you will be sharing your royalty with non-producing acres for those 20 years. Might not be so bad if you were sharing your royalty with people in the section near the head of the well where most of the production occours, possibly getting 1/4 of your royalty but if you add a largely unproductive section in, your royalty is so diluted, well, the landowners won't have any money untill they are all drilled out and there won't be anything to lobby for because nobody is going to undo it. They will just say yes it was wrong, but you have your wells now and and all's well that ends well. I hope you get at least two wells drilled in rapid succession because you may not get any more for a very long time. I am in 5 spacings in the better part of McKenzie county that have a single well. On a scale of 1 to 10 I would call them an 8 with just the one well for going on 6 years now. I see a few new wells being drilled in the area with modern completion techniques that produce twice what my wells have done. My operator there does not seem interested in drilling my spacings even if the wells will have 2,000 barrel IP's. I can only assume that the operator does not want production, merely wants to keep the acres in reserve. I hope you have alot better luck than I have had.
Well (no pun intended) we have interest on 5 sections and on those 5, 2 wells are up and running on 1 section. 2 sections are bare and the last two have a pad established and are in tight well.
I am afraid that my Mother and Aunt signed to long of a lease on the bare sections and this may be what is keeping them from drilling. Especially since i do not see a reason not too. No environmental issues such as lakes or rivers here. I think eventually they will get here, but maybe years down the road.
Your operator must be waiting until lease end or are you in a pugh clause with the other spacings? Just remembered I think we have a pugh clause on the bare land. This is probably why there is no activity.
AD, it's not just your lease, unless you have 100% of the rights to the spacing or at least the great majority. You have to consider everyone elses lease in the spacing and if they signed a shorter lease than you did, the length of your lease may be less important in determining when drilling occours.
AD, my soacings are already drilled in Mckenzie county, each with one well, a couple producing over 5 years, a couple almost 5 years and a johny come lately that has only been producing for 3 years and the only way the operators lease will expire would be for the wells to stop producing and that isn't going to happen for a very long time, decades. 1 well is not going to drain those spacings. Those wells drilled early by Continental Resources with 10 frack stages and literally fracked with beach sand which serves to clog the fractures about as much as it props them open are amazingly crude compared to todays completion techniques. One of the wells was reported to be the best well drilled to date in McKenzie county, a little over 5 years ago. New wells to either side of this well have IP's of 2,000 barrels per day.
Fast forward to Dunn county late 2011. The area I'm in there I consider a 9, on a scale of 1 to 10. I did get 2 wells drilled at once, one had a little mishap but the other did fine with an IP of 2698 for 1 day and payed out in about 10 months. The other well needing some work just trickled for a year producing under 13k bbl oil but produced 14,800 bbl oil in 15 days after it was repaired and finally fracked. Although there is a second multipad in my section, nothing has ever been drilled from it. The operators only in a few rare cases fully explore and get a spacing into production as they should. When they do drill 6 wells in the Bakken in one spacing, they are just testing to see what they would get if they actually did what they are supposed to do and they do it in a good to great area. If it were just mine that was not being developed, I wouldn't be happy but big whooptie, the thing is that it's most of the western half of North Dakota that is not being properly developed and that changes the perspective. If your wells are relatively recent, wait until they are depleted to their stable but low production and no more are drilled for a decade which I can easily see happening, it may become a matter of great interest to you. I hope you don't get put on the shelf and that your minerals are fully exploited, I hope that for everyone.
Ok, so what is your opinion on the current numbers. Since September 2012 (Well start) 2 wells have produced 89311 Barrels total. I assume these numbers are low in comparison to what you wells seem to do. There have been dramatic fluctuations in porduction from month to month as well. Is this common to produce 24,000 one month and then down to 4000 bls the next?
I have no idea how to forecast and would assume trying is not feasible considering there are a lot of factors to account for. These are our first and i am not sure if this is common when they first start to produce or do they increase with time? I have heard they do dwindle over time, but i assume there is a normal and somewhat consistent peak period?
r w kennedy said:
AD, it's not just your lease, unless you have 100% of the rights to the spacing or at least the great majority. You have to consider everyone elses lease in the spacing and if they signed a shorter lease than you did, the length of your lease may be less important in determining when drilling occours.
AD, my soacings are already drilled in Mckenzie county, each with one well, a couple producing over 5 years, a couple almost 5 years and a johny come lately that has only been producing for 3 years and the only way the operators lease will expire would be for the wells to stop producing and that isn't going to happen for a very long time, decades. 1 well is not going to drain those spacings. Those wells drilled early by Continental Resources with 10 frack stages and literally fracked with beach sand which serves to clog the fractures about as much as it props them open are amazingly crude compared to todays completion techniques. One of the wells was reported to be the best well drilled to date in McKenzie county, a little over 5 years ago. New wells to either side of this well have IP's of 2,000 barrels per day.
Fast forward to Dunn county late 2011. The area I'm in there I consider a 9, on a scale of 1 to 10. I did get 2 wells drilled at once, one had a little mishap but the other did fine with an IP of 2698 for 1 day and payed out in about 10 months. The other well needing some work just trickled for a year producing under 13k bbl oil but produced 14,800 bbl oil in 15 days after it was repaired and finally fracked. Although there is a second multipad in my section, nothing has ever been drilled from it. The operators only in a few rare cases fully explore and get a spacing into production as they should. When they do drill 6 wells in the Bakken in one spacing, they are just testing to see what they would get if they actually did what they are supposed to do and they do it in a good to great area. If it were just mine that was not being developed, I wouldn't be happy but big whooptie, the thing is that it's most of the western half of North Dakota that is not being properly developed and that changes the perspective. If your wells are relatively recent, wait until they are depleted to their stable but low production and no more are drilled for a decade which I can easily see happening, it may become a matter of great interest to you. I hope you don't get put on the shelf and that your minerals are fully exploited, I hope that for everyone.
AD, production can be erratic on a new well. I think they need to let them run hard at first to clean them out, this can sometimes have unexpected consequences. My friend Brian got two wells drilled at once, more importantly completed at the same time and they produced over 40k bbl oil...in ND...in December....with no pipeline yet, I would call this the textbook definition of take away constrained, so they of course choked the wells back. I always try to keep track of the number of days per month a well produced, did that well decline? or did it just produce for 2 weeks that month? Production is likely to be shut in in surrounding wells when a new well is being fracked because you probably don't want to help someone else frack into your well. Some operators install a pump on their wells at the earliest opportunity, even if it isn't necessary for some time and this will require some downtime.
An unregulated Bakken well can decline at 30% a month. My newer wells were choked back pretty hard after the first month. With the production reduced by 50% the production remained very stable with a decline rate of 5% to 8% a month. On a new well, production can be all over the scale because every well is different and regulating the well is as much art as science.
AD, I just looked at your wells again and I can tell that the number of days production has been somewhat erratic and just because a well that produced 9k barrels produced 5k in the next month, the odds are good it could have produced 9k again but the operator adjusted the choke. You are 6 months in and I believe that your operator will find his happy medium and your well will have a slow steady decline rate in a few more months. You do have some surprises ahead of you because neither of your wells have pumps yet and when the operator decides to install them you will have no warning, just short months and short checks. Never count on a royalty check, have a plan for what to do with it if it comes but don't depend on it unless you have several widely spaced wells where at least some are down at any one time.
AD, I would guess one could say that my wells are in a better area but your new wells are at least as good as my older ones. You have benefitted greatly from the advance in completion techniques over the last 5 years. You may have had a longer wait to get your wells but the wait was worth it. I hope your other spacing/s get at least two wells at a time also. 5 years ago you might have wound up with one well in that spacing that might have only produced 100k bbl oil or less in the 5 years.
If you don't get some new wells before these decline to 50 to 100 bbl a day, the money may seem disappointing. It's not unusual that someone is surprised how little they actually receive from leasing their minerals under even some good oil wells.
Well luckily the money would be just a bonus and I don't need to depend on it, plus my share wouldn't be enough to live off of. Just a nice retirement bonus.
You mentioned pumps being installed. How does this affect production and how did you find this information?
The pumps when installed i assume stop production, but after i assume production will return to same volume or atleast capable of same volume?
r w kennedy said:
AD, production can be erratic on a new well. I think they need to let them run hard at first to clean them out, this can sometimes have unexpected consequences. My friend Brian got two wells drilled at once, more importantly completed at the same time and they produced over 40k bbl oil...in ND...in December....with no pipeline yet, I would call this the textbook definition of take away constrained, so they of course choked the wells back. I always try to keep track of the number of days per month a well produced, did that well decline? or did it just produce for 2 weeks that month? Production is likely to be shut in in surrounding wells when a new well is being fracked because you probably don't want to help someone else frack into your well. Some operators install a pump on their wells at the earliest opportunity, even if it isn't necessary for some time and this will require some downtime.
An unregulated Bakken well can decline at 30% a month. My newer wells were choked back pretty hard after the first month. With the production reduced by 50% the production remained very stable with a decline rate of 5% to 8% a month. On a new well, production can be all over the scale because every well is different and regulating the well is as much art as science.
AD, I just looked at your wells again and I can tell that the number of days production has been somewhat erratic and just because a well that produced 9k barrels produced 5k in the next month, the odds are good it could have produced 9k again but the operator adjusted the choke. You are 6 months in and I believe that your operator will find his happy medium and your well will have a slow steady decline rate in a few more months. You do have some surprises ahead of you because neither of your wells have pumps yet and when the operator decides to install them you will have no warning, just short months and short checks. Never count on a royalty check, have a plan for what to do with it if it comes but don't depend on it unless you have several widely spaced wells where at least some are down at any one time.
AD, I would guess one could say that my wells are in a better area but your new wells are at least as good as my older ones. You have benefitted greatly from the advance in completion techniques over the last 5 years. You may have had a longer wait to get your wells but the wait was worth it. I hope your other spacing/s get at least two wells at a time also. 5 years ago you might have wound up with one well in that spacing that might have only produced 100k bbl oil or less in the 5 years.
If you don't get some new wells before these decline to 50 to 100 bbl a day, the money may seem disappointing. It's not unusual that someone is surprised how little they actually receive from leasing their minerals under even some good oil wells.
AD, I have been studying for a few years now, just about every aspect that I could find any information on and from everything I could find, the horsehead or pumpjack could take up to a month to install. Submersible pumps seem like they can be installed in days. In my study of literally thousands of wells, not just mine, this holds true.
The good news is that you may notice a slight production increase before the well starts to decline again, this is frequently called a pump-bump, catchy name.
The bad news is that production is going to decline again. Many people moan about well decline but I think they are short sighted. Wells decline and that is it, small or large, they decline. The important thing to you as a royalty owners is where the long relatively stable plateau is going to be. Those first dozen or so big checks are nice but the next 100 checks are just as important. The true measure of a well is how much wealth it produces before it's plugged and abandoned. If your well IP'd at 368 bbl oil and someone elses well IP'd at 3,000, that does not mean that there is not an equal amount of oil under each property. It may take twice as long to get the same amount of oil out. These Bakken wells are a fairly new development, nobody knows what the average well is going to do long term because they have not been around long enough. They could conceivably become really run down after a decade and dribble 200 bbl of oil per month for 40 years, if I am wrong, someone can dig me up and tell me because I doubt I will be alive to see it.
There are alot of marginal wells being drilled today that I doubt are costing even 7 million dollars and at that price point it's still going to take that well 10 to 20 years to pay out. The operator does gain something by controlling the unproductive acres long term, freezing royalty where it is and escaping the lease cycle for the unproductive acres, if you take the long view those things give alot of added value, and some day someone will figure out how to increase the ultimate recovery. AD, you have benefitted from improved completion techniques developed over a period of five to six years. Will it improve in the next 5 years? I doubt it but it's possible. Will it improve in the next 20 years? I would say it's extremely likely.