Replies to This Discussion

Permalink Reply by Ben Elmore on March 1, 2011 at 3:56

There is no real regulation by the RRC of an operator's decision to shut-in a well.  You are correct that shutting in a well should be temporary.  How long a well is shut-in depends on the situation and reason for shutting it in.  In the Haynesville, for example, some wells get shut in because the gathering line infrastructure does not exist to connect the well to.  So the well is shut in until the infrastructure is built.  Aside from the particular lease language (I would always require some time limit as to the total months or years the lessee is permitted to shut in a well), the implied covenant to market the oil or gas provides some protection against a lessee shutting in a well for long periods of time.  Essentially, the lessee has the duty to market the oil or gas as would a reasonably prudent operator under the same or similar circumstances.  If that means building the necessary pipeline infrastructure to get the oil or gasl to market, that is what the lessee must do. 

Permalink Reply by jffree1 on March 1, 2011 at 4:44

Ben, here is what is in the rules under 3.14 (b)(2):

Plugging operations on each dry or inactive well shall be commenced within a period of one year after drilling or operations cease and shall proceed with due diligence until completed unless the Commission or its delegate approves a plugging extension under §3.15 of this title (relating to Surface Equipment Removal Requirements and Inactive Wells).

It looks like they expect an operator to either produce a well or plug it.  Does an interest owner in the well or the surface owner, if they are different, have any say in whether an inactive wells gets plugged in a timely manner?

 



Permalink Reply by Jan Childress on March 1, 2011 at 5:16

After reading your comment Ben I was curious about the definition of an "inactive well". According to HP 2259 (9/2010) it is an unplugged well that has been spudded or has been equipped with cemented casings and that has had no reported production, disposal, injection or other permitted activity for a period greater than 12 months. 

It's funny...RRC rule says plugging an inactive well shall commence within one year...the law says a well isn't defined as inactive until a period greater than 12 months...what a difference a day could make in the legal world. :)

Permalink Reply by Ben Elmore on March 1, 2011 at 9:59

It is highly unlikely that the RRC would order a shut-in well be plugged, especially a shut-in well that is capable of producing in paying quantities but for access to a market.  If a surface owner or interest owner wants a well to be plugged, they need to file an applicationw ith the RRC, as they are the ones with jurisdiction under the rule you cite.

Permalink Reply by king john on March 1, 2011 at 15:31

are wells shut in because of mechanical failure?

 let's say the well is failing and just before zero production can an operator shut it in to preserve the lease? 

would there be an obligation for them to fix the well in a timely manner?

kj

Permalink Reply by Eric Camp on March 2, 2011 at 1:49

Such an analysis always begins with the language of the oil & gas lease - as shut-in provisions come in all different forms. Generally and historically, wells can be shut-in for any number of reasons - including mechanical failures. But even with an operator-friendly shut-in clause, generally the operator's duties with respect to each well are still subject to the implied covenants of marketing (that Ben mentioned above) and reasonable development. So, yes, there may be an obligation for the operator to fix such a well in a timely manner - if a reasonably prudent operator would do so.

Permalink Reply by king john on March 2, 2011 at 3:07

thanks eric. haven't seen you around lately. thanks for the reply.

kj

Permalink Reply by Ben Elmore on March 2, 2011 at 3:44

In addition to what Eric said, the scenario you raise King John tends to suggest the well was not capable of producing in paying quantities at the time it was shut-in.  Obviously, if the well is shut-in during the priamry term it does not matter.  If you are in the secondary term, and your lease "habendum clause" states the lease will remain in effect for the primary term and "so long thereafter as oil or gas is produced in paying quantities," then it must be determined whether the well satisfies that standard (see the article I sent you previously on lease preservatyion).  Some leases contain the unfortunate habendum clause ending "whether or not in paying quantities."  That would preclude you from asserting the shut-in was improper.  Assuming a well is properly shut-in due to mechanical failures, the lessee must repair the well and turn it back on within a reasonable time, which varies depending on the circumstances. 

Permalink Reply by king john on March 3, 2011 at 1:00

ben, thanks for the additional comments.

in this case the lease is being held by production only. in the beginning of the lease there is the "the implied covenant to market the oil or gas" however, towards the end of the lease it uses the" whether or not in paying quantities" phrase. 

i have looked at 2 other nearby wells that feed the same gathering line and it appears they have opened these other wells up, i suppose to keep the pipeline pressurized. it stands to reason to me, if the pressure on the gathering line is greater than the pressure of the well it would be impossible to produce from said well. would this not make the well incapable of producing?

as i understand, a shut in is designed to "buy" some time for the operator.  either to complete, place pipeline, or repair,aka operations, but no where in my research did i find anything about shut ins being permanent, or indefinite.  it seems to me, i have heard of a couple of wells being shut in for twenty or so years. me, i would be calling my attorney before that.

kj

Permalink Reply by king john on March 3, 2011 at 1:05

btw-

Habendum clause

In an oil and gas lease, this clause fixes the duration of the lessee's interest in both a primary and secondary term. It is also refereed to as a term clause.

 

is this a good, basic explanation of the habendum clause? also, does the secondary term mean an extension of the original lease as in 2 year option, and does this also include HBP ?

kj

kj

Permalink Reply by Ben Elmore on March 3, 2011 at 3:40

Yes that is a good explanation of a habendum clause.  The secondary term is not the same as an option to extend.  The option to extend applies to the priamry term.  So if you have a 3 year lease with a 2 year option, and the lessee exercises the option, he has converted the lease from a 3 year primary term to a five year primary term.  That's why I tell my clients who I negotiate leases for that if they are going to accept an option, they should just consider the elase to be a 5 year lease going in (unless you can negotiate a higher bonus per acre for them to exercise the option). 

 

As to your question on the pipeline issue, I probably could have been clearer in my post above.  The covenant to market applies regardless of the "whether or not in paying quantities language."    It applies to any shut-in well.  So if you  have a well shut-in for years, someone needs to address the implied covenant to market issue.

Permalink Reply by Bill R on March 13, 2011 at 10:48

I originally posted this in Shelby County, but upon a suggestion from Jffree, I will now ask the same question here....

How long can a well be held in the 'shut-in' status? I have a couple that I get my $1 per year that are approaching the three year mark and one that just passed the five year mark. Be nice to know what is going to happen with them since they tie up some decent acreage next to some of our producing properties. The signing  lease contract does not list any time frame in the language of the document.

None of these leases have been extended beyond the initial lease and all of those have long since expired.

Appreciate any and all input on this one!

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