I have read that Continental's multi unit test well Toms 1-21XH in Blaine County,OK produced over 1200 bbls of oil/ngl's and 1.9 MCF of gas on it first day. Is there any information available on what it has produce since? The well has just been completed a week or two.
Also, this well is a multi Unit well. I am wondering how that effects royalty payment. Are they figured like it would be 1280 acre spacing, (shared with royalty owers as in the 640 acre spacing) or is it figured on percentage by the horizontal length of the well bore, as I have been told, ie 46% to the well pad section and 54% to the addition section?
It is my understanding that the units will be shared as to your holdings within that unit. If you own 1 acre in a 640 acre unit, you own 1/640. One acre in a 1280 acre unit would be 1/1280. I could be wrong, so someone more knowledgable can correct me.
I thought that would be the case also, but I was told that due to the spacing in the area is 640 and that the well bore is longer in one unit than the other, it is asuumed that one unit is producing more than than the other. Let assume that the 640 spacing unit that the well is drilled on has a total of 4000 ft of horizontal bore because it takes 1250 feet to make the turn to horizontal, then the addition unit of 640 acre spacing has a total of 5200 ft of bore. They will then take the 4000 ft and the 5200 ft and figure the precentege of total hortizontal bore for each 640 acre spacing and split the production based on the precentages. So Unit one with the well site and 4000 ft of bore is 43.5 % and unit two, the addition unit has 5200 ft of bore is 56.5 %. The royalty payments to owners would be paid accordingly.
If this is the case, I feel that this new rule in OK on the Multi Unit wells are going to cause a lot of confussion and concern.
Richard the best way to check production, since Continental is slow in reporting except for their quarterly reports is to contact one of their Okla. field offices, look on their website for a number.The field offices have been nice to helpout Michael H and myself about our wells that were drilled.
The units are 640 acres, but a new law allows to drill across units. The combine them to MULTI UNIT wells. They are not 1280 acres units. They are drilling into to differnt sections, or units.
Richard, Watch out for the fine print. Continental reported 1268 bo(equivalent)pd. Actual 965 bopd, 1.9mmcft. Still a good well. I believe the equivalent value is calculated in BTUs so it's not a dollar for dollar comparison. I was looking at all those big numbers in N.D. then noticed the "e".
Don Underwood can you verify this is correct?
Yes, a company can state production as eqiivalent barrls of oil per day or equivalent cubic feet of gas per day. The formulas are somewhat tricky to do the conversion and competitors will disagree with each others calculations on the same well in the endless game of trying to beat each other out of the top dog position.
The daily production tells the story (losts of luck on finding that out in Oklahoma) as does the Royalty owners checks, if they can decipher them.
Mr. Hutchison, I don't worry much about gas in ND. I think a well that produces alot of gas for ND may produce enough in a year or two to make a good month for a good gas well in Tx or Oklahoma, although the gas in ND does seem to be rich, they just don't produce that much and I think that too much of it is flared. If I recall correctly, the operator gets to flare off the gas for the first year!
Michael Hutchison said:
Richard, Watch out for the fine print. Continental reported 1268 bo(equivalent)pd. Actual 965 bopd, 1.9mmcft. Still a good well. I believe the equivalent value is calculated in BTUs so it's not a dollar for dollar comparison. I was looking at all those big numbers in N.D. then noticed the "e".
Don Underwood can you verify this is correct?
Michael,
Thanks. I learn something new everyday. I was not aware of this. Now I have something new to watch out for when I discuss and work with oil and gas production information.
Michael Hutchison said:
Richard, Watch out for the fine print. Continental reported 1268 bo(equivalent)pd. Actual 965 bopd, 1.9mmcft. Still a good well. I believe the equivalent value is calculated in BTUs so it's not a dollar for dollar comparison. I was looking at all those big numbers in N.D. then noticed the "e".
Don Underwood can you verify this is correct?
Oklahoma statutes provide for a maximum spacing unit of 640 acres.
However, new legislation has allowed operators to combine multiple units for the purposes of horizontal drilling. So in your case it sounds as if 2 separate 640 acre spacing units have been combined. The operator has to make application to the Oklahoma Corporation Commission to approve the unit. In turn the Commission determines the formula for which costs are allocated and royalties are paid. The formula is finalized after the well is completed when the length of the lateral and the producing interval is known with certainty. Typically, the ownership is prorated based on the percentage of total perforated completion that underlies each spacing unit.
So for example, if the lateral is 2 full miles long, and equally perforated along its entire length, then each person in the 1280 acres would receive a 1/1280 share for each acre owned. Both 640 acre units share 50% / 50% in the production from the multi-unit well.
But let's assume that the lateral was only 1 1/2 miles long; 1 mile in one section and 1/2 mile in the other; again assuming perforated equally along its length. Now 2/3 of the production would be allocated to one section (with the 1 mile lateral) and 1/3 of the production would be allocated to the section with the shorter 1/2 mile lateral; because only 1/3 of the lateral is draining the second section. So the owners in the long section receive 67% share of production to proportionately share in their 640 acre unit, while owners in the short section receive 33% share of production to proportionately share in their 640 acre unit. The same pro rata sharing applies to costs attributable to anyone that elects to participate in the drilling of the well.
Is it a perfect system? No. But it could be far worse. The legislature has done the best it could to protect the correlative rights of everyone. Longer laterals reduce the cost per barrel of exploration, so some property will be developed that may not have otherwise been economic.