43-02-03-16.2. Revocation and limitation of drilling permits. 1. After notice and hearing, the commission may revoke a drilling,recompletion, or reentry permit or limit its duration. The commissionmay act upon its own motion or upon the application of an owner in thespacing or drilling unit. In deciding whether to revoke or limit a permit,the factors that the commission may consider include: a.The technical ability of the permitholder and other owners to drilland complete the well. b. The experience of the permitholder and other owners in drilling andcompleting similar wells. c.The number of wells in the area operated by the permitholder andother owners. d. Whether drainage of the spacing or drilling unit has occurred or islikely to occur in the immediate future and whether the permitholderhas committed to drill a well in a timely fashion. e.Contractual obligations such as an expiring lease. f. The amount of ownership the permitholder and other owners hold inthe spacing or drilling unit. If the permitholder is the majority ownerin the unit or if its interest when combined with that of its supportersis a majority of the ownership, it is presumed that the permitholdershould retain the permit. This presumption, even if not rebutted,does not prohibit the commission from limiting the duration of thepermit. However, if the amount of the interest owned by the ownerseeking revocation or limitation and its supporters are a majority ofthe ownership, the commission will presume that the permit shouldbe revoked. 2. The commission may suspend a permit that is the subject of arevocation or limitation proceeding. A permit will not be suspended orrevoked after operations have commenced. 3. If the commission revokes a permit upon the application of an ownerand issues a permit to that owner or to another owner who supportedrevocation, the commission may limit the duration of such permit. Thecommission may also, if the parties fail to agree, order the owneracquiring the permit to pay reasonable costs incurred by the formerpermitholder and the conditions under which payment is to be made.The costs for which reimbursement may be ordered may include thoseinvolving survey of the well site, title search of surface and mineral title,and preparation of an opinion of mineral ownership. 4. If the commission declines to revoke a permit or limit the time withinwhich it must be exercised, it may include a term in its order restrictingthe ability of the permitholder to renew the permit or to acquire anotherpermit within the same spacing or drilling unit.
On Oct 7, 8:17 pm, go-devil <[EMAIL PROTECTED]> wrote: > Anwser from someone in the know. > > Alger Field is spaced one horizontal well per 640 acre section with a > 500 foot setback while Alger Field zone II is spaced one horizontal > well > per 1280 acre spacing unit with a 500 foot setback. > > Ross Field is spaced one horizontal well per 640 acre section with a > 500 > foot setback while Ross Field zone II is spaced one horizontal well > per > 1280 acre spacing unit with a 500 foot setback, zone III is spaced one > well per 960 acre spacing unit with a 500 foot setback, and zone IV is > spaced one well per 1280 acre stand up spacing unit setback 1220 feet > from the east or west line and 500 feet from the north and south line. > > It will depend upon whose plan best protects correlative rights, that > is > includes all lands in a spacing or drilling unit that will provide the > best possible odds of an economic well being drilled. > > If the spacing and drilling units end up incompatible with one company > or the other's permit the permit(s) can be suspended and then > operator ship decided based upon 43-02-03-16.2 > > Guess we'll wait and see what happens. go devil > > On Oct 6, 1:25 am, elwood <[EMAIL PROTECTED]> wrote: > > > > > the ndic establishes spacing zones (i.e. zone I may be for 640's, zone > > II for 1280's,etc.) in each field area, usually according to what is > > asked for in the hearing application . sometimes the commission will > > combine applications and try to resolve the spacing for a whole area > > in a singal hearing. usually, the operators can work out how they > > want each area spaced, but if a dispute arises, the commission has to > > resolve the dispute. > > > On Sep 30, 12:17 pm, David <[EMAIL PROTECTED]> wrote: > > > > OK I had a hunch about this but did find a reference that was > > > consistent with my hunch > > > > The reference > > > ishttp://en.allexperts.com/q/Oil-Gas-3147/2008/8/lay-spacing-units.htm > > > > Apparently if the two sections are one atop the other NS, that is a > > > standing up spacing unit, whereas if the two sections are beside each > > > other > > > EW that is a laying down spacing unit. > > > > It must be kept in mind that these spacing units are tenatively > > > approved before the drill bit hits the ground. It may turn out that > > > unforseen things happen during drilling--commonly perhaps a lateral > > > that cannot be drilled as long as planned. As a consequence, a driller > > > might decide on the spot that it would be better to convert a single > > > 1280 acre spacing to twin 640 acre spacings. Generally a driller can > > > do these things if there is an obvious reason to change the plan...The > > > spacing on any well is not truly official until after the official > > > post drilling pooling hearing in Bismarck. I think that is the main > > > reason for the legal term "other relief as appropriate"...basically > > > the driller in the initial approval has the option to change what he > > > does w/o having to go back for another hearing assuming that the > > > change is reasonable given the new circumstances only apparent after > > > drilling commenced. Otherwise the driller would have to immediately > > > stop drilling and wait weeks to schedule a new hearing. Think of an > > > airplane that puts in a flight plan. A storm builds and the pilot must > > > decide in the air on the spot to change the route. He doesnt go back > > > to the airport and file a new flight plan, but surely he calls the > > > tower to tell them what the amended route will be. > > > > I don't really know anything about the zone thing except to say that > > > oil exists at different vertical depths and a dry well at one depth > > > may be a productive well at another. Once the driller has the lease he > > > is free to check out whatever possibilities might be thought to be > > > economically productive. That apparently was part of what was going on > > > when EOG was drilling to over 13,000 ft in the Winnepeg formation, but > > > it looks to me as if the experiment failed or some production would be > > > forthcoming. > > > On Sep 30, 12:39 pm, go-devil <[EMAIL PROTECTED]> wrote: > > > > > David, > > > > Brighams asking for Stand Up Spacing Units in Alger-Bakken Pool. What > > > > is a Stand Up? > > > > In a different case, same hearing a company is asking for 1280 spacing > > > > in Alger Bakken Pool Zone II. It also states: > > > > For which spacing has been established on the basis of one horizontal > > > > well per 1280 acres and such other relief as is appropriate. > > > > Are these the same Fields and different Zones? > > > > Is it one well per 1280 unless relief is needed, meaning another well? > > > > Thanks > > > > > On Sep 30, 8:25 am, David <[EMAIL PROTECTED]> wrote: > > > > > > I honestly don't see any issue with this. If companies want to do two > > > > > mile laterals and believe that such an approach is working, which this > > > > > spacing permits, so be it. It looks to me like the plan is to > > > > > ultimately drill at least two wells per 1280 acre spacing, so in the > > > > > end they have well counts similar to one well per section spacings, > > > > > but with the longer laterals. Granted that the royalty payments get > > > > > divided up among mineral owners on both sections, and there may be > > > > > year long time lag before the second well is drilled, but this should > > > > > tend to smooth out royalties over time for every mineral owner. > > > > > > On Sep 30, 10:51 am, go-devil <[EMAIL PROTECTED]> wrote: > > > > > > > David, Larry, Teegue, > > > > > > I see in a Hearing reports for Oct. 08 that Brigham is pushing for > > > > > > 22 > > > > > > various 1280 Spacings, > > > > > > I know Hess permitted a 1280 combining Section 32 and 29 of 156/92. > > > > > > In Brighams request it asks for 1280 spacing on Section 32 of 156/92 > > > > > > with Section 5 of 155/92. > > > > > > Any ideas as to the outcome here? > > > > > > > On Sep 30, 4:47 am, David <[EMAIL PROTECTED]> wrote: > > > > > > > > Yesterday's 9/28/08 daily activity report was especially > > > > > > > interesting > > > > > > > because it includes initial production information (ip) for a > > > > > > > large > > > > > > > number of wells by many different drillers in the state including > > > > > > > several EOG wells just off confidential. > > > > > > > Linkhttps://www.dmr.nd.gov/oilgas/dailyindex.asp > > > > > > > > Of the wells listed the first place goes to EOG drilled Austin 26 > > > > > > > in > > > > > > > SE Austin with an official ip of 3070 bopd. > > > > > > > > The silver medallian goes to EOG's School 16 on the south side of > > > > > > > Parshall TWP bringing in an official ip of 1721 bopd. > > > > > > > > On the other end we now know for sure that, sadly, Behm's Edwards > > > > > > > 1 > > > > > > > was not a producer. > > > > > > > > We have producing wells coming in as low as 17 and 30 bopd. I > > > > > > > wonder > > > > > > > how many of the wells coming in at 100 bopd or less will still be > > > > > > > in > > > > > > > production a year from now..It takes 3-4 bopd I think just to > > > > > > > cover > > > > > > > the costs of pump operation already in place. > > > > > > > > Can anyone tell me exactly what is going on with 17058 Shell Creek > > > > > > > State 1 01 drlled as a second well in 1 152 90 (Parshall TWP up > > > > > > > by the > > > > > > > primary already producing "Long" well in that section). I know it > > > > > > > was > > > > > > > scheduled to be a test well of some sort.The report says they > > > > > > > drilled > > > > > > > to 13,459 ft into the Winnepeg formation, but apparently has not > > > > > > > been > > > > > > > put into production. > > > > > > > > For those of you with EOG holes drilled awaiting the pooling > > > > > > > hearing > > > > > > > for your section, a bunch of these are scheduled to take place on > > > > > > > October 23rd in Bismarck. Check the Oct 23rd hearing dockets page > > > > > > > on > > > > > > > the dmr site, as this was just posted yesterday > > > > > > > . > > > > > > > Figure a minimum of 2-3 months from the hearing date to when a > > > > > > > royalty > > > > > > > check shows up in your mailbox. :-) > > > > > > > > Those of you with a pooling hearing scheduled October 23rd should > > > > > > > receive legal papers within a few days I would think telling you > > > > > > > the > > > > > > > official hearing has been scheduled and you can show up if in > > > > > > > Bismarck > > > > > > > you are unhappy with the pooling scheme (not that it would do any > > > > > > > good, LOL).You can also listen in on the hearing live via the Web > > > > > > > starting at 9 AM on the scheduled hearing day. Most of this is > > > > > > > routine > > > > > > > and if no owners are present to complain about something, the > > > > > > > hearing > > > > > > > goes smoothly and very quickly. But occasionally someone wanders > > > > > > > in to > > > > > > > raise an interesting issue. > > > > > > > After the hearing, the last step is for the title owners to do one > > > > > > > final check on who owns the mineral interest in each section, to > > > > > > > make > > > > > > > absolutely certain there are no errors when the checks are cut. > > > > > > > The > > > > > > > companies take extraordinary steps to assure the accuracy when > > > > > > > they > > > > > > > get nearly to the check cutting stage, and that is why this seems > > > > > > > to > > > > > > > take a little longer than it otherwise might. By the time you get > > > > > > > your > > > > > > > first check,your well will likely have been producing for sale for > > > > > > > nearly 6 months. > > > > > > > The first check usually includes royalty payments for the first > > > > > > > 2-3 > > > > > > > months of production combined.- Hide quoted text - > > > > > > > - Show quoted text -- Hide quoted text - > > > > > > - Show quoted text -- Hide quoted text - > > > > > - Show quoted text -- Hide quoted text - > > > > - Show quoted text -- Hide quoted text - > > > - Show quoted text -- Hide quoted text - > > - Show quoted text - --~--~---------~--~----~------------~-------~--~----~ You received this message because you are subscribed to the Google Groups "Bakken Shale Discussion" group. 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