Replies to This Discussion

Permalink Reply by tc on October 9, 2013 at 2:57

Bad well results for Foster well.  The well result were good for the actual completed length, but that is small consolation after spending $13m.

Goodrich Petroleum Corporation (GDP) today announced the completion of its CMR-Foster Creek 20-7H-1 (99% WI) well in Wilkinson County, Mississippi. The well was successfully drilled with a 6,200 foot lateral and fracture stimulated with 23 stages but encountered completion issues while drilling out the frac plugs with coiled tubing resulting in the loss of a bottom hole assembly and fishing tools in the well. The Company replaced the coiled tubing unit with a workover rig in an attempt to remove the downhole tools but fishing operations were un-successful. The well was subsequently placed on production from the approximately 2,100 feet of usable and unobstructed lateral.

The well has reached a 24-hour peak production rate of 527 barrels of oil equivalent ("BOE") per day, comprised of 500 barrels of oil and 174 Mcf of gas on a 16/64 inch choke from the 2,100 feet of lateral.

The Company is currently drilling the lateral of the Huff 18-7H-1 (97% WI) well in Amite County, Mississippi, with plans to go to two rigs later this month.

The Company currently has in excess of 300,000 net acres in the Tuscaloosa Marine Shale

Permalink Reply by Big Little Oil on October 9, 2013 at 3:25

Does anyone know how many frack stages' plugs were succesffully drilled out to contirbute?

Permalink Reply by Bernell McGehee on October 9, 2013 at 4:05

In the past they have had frack stages of around 275 feet, so this would be 7-8 stages.

It was posted earlier that 6 stages were brought in, so I don't know if these stages were wider or the earlier info was off 1 or 2.

Permalink Reply by Steve on October 9, 2013 at 9:17

6 plugs 7 stages I believe. You can tell by the 2100 ft. completed - stages run 250-300 ft.

Permalink Reply by Bernell McGehee on October 9, 2013 at 4:06

Is it possible that the coiled tubing is the issue.

Would not the use of regular tubing potentially solve this problem?

Permalink Reply by Steve on October 9, 2013 at 9:45

Coil tubing rigs are not robust enough for these wells IMO. I think this is one of those lessons they should have learned after several previous wells with short lateral completions due to undrillable plugs. This problem goes way back. We have seen lots of wells with long sections of their laterals not completed. Weren't they using the need for 8k-10k ft. laterals as the excuse for forming these long legged units. The units are huge and the completed laterals are getting shorter.  Maybe the MSOGB should revisit the facts on the ground vs. the proposals before permitting 2000 acre units. Operators will not go back and capture the oil under that 4000 ft. of uncompleted lateral so that's lots of wasted resources for the landowners.   IMO

Permalink Reply by Skip Peel - Mineral Consultant on October 9, 2013 at 10:20

Steve~

Re:  Operators will not go back and capture the oil under that 4000 ft. of uncompleted lateral so that's lots of wasted resources for the landowners.

Not necessarily the case especially if it is good rock.  The state has set the precedent of approving Cross Unit Laterals.  As much as this may be of concern for those who fear large units it does have some advantages one of which would be drilling a lateral from an adjoining unit that picks up that 4000'.

Permalink Reply by Steve on October 9, 2013 at 12:00

I hope Ms. will allow cross unit laterals like La. does. Do they?

I agree it can be done but at the cost of wells at this point and the short laterals so far, it seems to me that the State of Ms. would be taking a hard look at what is actually happening before they permit many more 2000 acre units. Just my opinion but it seems that landowners are being put at risk with the operator's gusto to hold more land with a single well at this point.

Permalink Reply by Steve on October 9, 2013 at 9:25

Bad result for Goodrich but not bad for the play so much. It looks like they could have matched the Crosby's production if they had been able to complete the full lateral. Also, they could be drilling +8000 ft. instead of 6k ft. laterals with the size of the units they are being authorized by the State to permit. When and if they finally get their act together on drilling plugs on 8000 ft. laterals, we could easily have + 1500 bbls 24hr. IP wells routinely. IMO.

Permalink Reply by Charles Bell on October 9, 2013 at 10:23

:) Hope so...

Permalink Reply by Skip Peel - Mineral Consultant on October 9, 2013 at 12:38

I think that state O&G regulators work under similar dynamics regardless of the jurisdiction.  Departments of Conservation have mandates to prevent waste and to provide a user friendly atmosphere for E&P companies to explore and produce.  The state wants/needs the revenue. The state and the mineral owner are unable to explore/produce on their own. 

The other dynamic is one of economics.  Operators are as adverse to waste as mineral owners.  As I prefaced in my earlier reply, if the rock is good; the operator will likely make an attempt to produce it.  And if they make a reasonable application, the state usually approves variations like CUL's. 

What gets lost in many of our discussions is the tremendous cost and risk that E&P companies accept.  Any non-industry GHS member who has been around for a few years should by now understand that the industry does not bat 1000.  Not even 500.   The conviction that "company X wouldn't spend this tremendous amount of money over this long a period of time if they didn't have a sure thing" has been proven inaccurate time and again.  A successful E&P company bats 300 or better.  Some of their hits are singles and some are extra base.  It is impossible to know which base they end up on for some years.  As much as the Eagle Ford has been held out as the prime oily shale play, it now becomes known that 40% of production is not oil but condensate.  And that the "sweet spot" is smaller than originally thought.  That's what drilling thousands of wells over five years will do.  I for one would like to see how much that cost.  And how many companies made quite large investments in the Eagle Ford and ended up outside of the sweet spot(s).

Permalink Reply by Rusty McClendon on October 9, 2013 at 15:20

I read that in Louisiana the operator's cost has to be fully recouped before any royalties are paid. Anyone know what the situation is in Miss.

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