Magnum Hunter's Farley Well Blowout
Are there any experts out there who can talk about this event?
Wickipedia describes a blowout as;
A blowout is the uncontrolled release of crude oil and/or natural gas from an oil well or gas well after pressure control systems have failed
Gary Evans in public statements said it took four days to bring the well under control, and said:
"We’re seeing a geo-pressured regime here like we’ve never seen before. So our first well, the Farley well actually blew out on us in a natural fracture, we didn’t frac the well. So we’re pretty excited about what we’re seeing. We had totally changed our drilling techniques in this region using South Louisiana Gulf Coast technology with high pressure, well heads, 10,000 pounds well heads, double BOPs."
It sounds like a serious, rare event.
#1 question: What does this indicate about the prospects for the well?
(Does this event indicate a terrific amount of pressure and a massive amount of gas to be uncorked? Or, does it indicate a screwup on MH's part? Or, did the "challenging geology" contribute to the blowout as he alluded to in an earlier statement)?
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Replies to This Discussion
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Permalink Reply by Joseph-Ohio on
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The information and knowledge you fellows exhibit is very impressive and also way over my head.
Trying to understand the risk (of a blowout occurring) that confronts us as landowners.
It sounds like a very rare occurrence.
The last one I heard about prior to this was BP's in the Gulf caused by a faulty 'blowout preventer' installation.
Also it seems to me that risk of serious injuries / fatalities due to a 'blowout' occurrence would be in the nearer proximity of the vertical bore.
Is that a fair assessment ?
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Permalink Reply by Brian Powers on
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J-O
Land Rigs use "surface BOP's" connected to the well head flange. When the well is completed and the production tubing/hanger is installed, the BOP is removed and replaced by the tree. For the BP well in the Gulf, a "subsea BOP" was used that connected to a mud-line hanger on the sea bed in 5,100 ft of water depth.
The basic functionality of the BOP's are the same; they provide sealing devices that clamp around the pipe to contain pressure or flow, the have piping that allows flow or a pathway to pump fluid (choke/kill lines) and in extreme applications, the have a blind/shear ram that can cut through steel pipe and seal off the entire well bore.
The rams are hydraulically controlled, and the control system contains a spare reservoir of pressurized hydraulic fluid that enables the BOP rams to function after surface power is lost. In the event of damage by a fire or explosion, the rams are spring loaded and should "fail safe", or close automatically.
Your assumption that the greatest risk would be nearer the vertical bore is correct. The post mortem of the Deepwater Horizon BOP showed that it failed to seal and that the blind/shear ram failed to function. Had both functions worked properly, then BP would be developing a nice oilfield and 11 men would still be going home to their families.
In the only blowout that I was involved with in my 31 year career, our surface BOP had a blind ram without shear function, so all that could be done was to crimp the pipe. The uncontained flow came up the production tubing and enveloped the rig, and the rig team was able to shut off the motors before they left the rig floor. Three days later and after mobilizing a wild well control team from Houston to the middle east, the well was safely killed and completed.
Brian
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Permalink Reply by Bluflame on
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Brian,
With a vertical well, there is typically only one frack stage, while in horizontal wells, there can be 30 or more. It seems to me HZ wells therefore create considerable stress on casing pipe via the many high pressure abrasive events occurring during the multiple fracks. Can it therefore be assumed that this phenomonon may make HZ wells more susceptible to blowouts??
BluFlame
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Blu -
The only time I saw erosion of steel from frac fluid was some temporary surface piping that cut out about half way through a single stage vertical shallow well in Kansas. We were about two-thirds the way through the job, a 1.1 million pound proppant one, when the fluid began squirting through a pin hole in the elbow of the temporary pipe. We shut down, bled off the pressure and replaced the pipe section. We had a very forgiving formation coupled with a very efficient gelled fluid, this made it possible for the job to endure a 13 minute shut down and the job to be successfully finished.
I've seen much more erosion of casing or liner caused by steel on steel wear from the rotating drill pipe. Rig contractors often rent or purchase pipe with steel "hard banding" applied to the connections. This greatly extends the life of the drill pipe, but if the hard banding material is too aggressive it can cause rapid loss of casing thickness which often introduces a host of other problems, like stuck pipe, mud losses, and integrity issues throughout the life of a well.
I imagine that most multi-stage fracs are pumped through work strings (higher pressure rated pipe purpose designed for the job). I'm not aware of any of these fracs being pumped down the casing anymore, as cleanout of proppant becomes problematic and costly.
Brian
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Permalink Reply by The Hiker on
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Hey guys: This showed up on Magnum Hunters recent corporate presentation on the Farley well page (sounds like fallout from the blowout event): Can you comment?
Due to complications during the drilling of the 6,500’ lateral that resulted in poor integrity with the cement bond behind the 5 ½” casing, only ten stages (about 1/3rd) have been fracture stimulated
• Flowback and testing are currently ongoing
• A second horizontal well is planned on the pad in mid to late November
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TH-
Without seeing a wellbore schematic for this well, I can only speculate that a 5-1/2" liner was run though intermediate casing and into the open hole. They may have had trouble keeping the open hole stable and open to allow the liner to pass. Continued instability may have led to poor circulation prior to and during the liner cement job. The liner hanger that holds the pipe in place inside of the previous casing string may not have set or sealed properly.
I'd be curious to see what integrity tests were performed (or not) after the liner was run and cemented and what operational problems occurred during the frac operations.
In my experience, liner lap integrity problems were one of the more frustrating problems vexing D&C teams, as a leak that allows gas to pass from the formation to surface in the casing/tubing annulus may well result in a (well's) lifetime of problems.
Brian
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Permalink Reply by The Hiker on
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MH's Gary Evans today admitted this was a "management mistake".... and was "against everything you learn about well control"....."the kick lasted over an hour (and seemed to say that the folks just sat and watched and didn't alert the guys up the food chain)"....."if it had happened on the gulf coast, it would have been a tragedy"....."all crews on the Farley and the Stalder are being retrained"....and a bunch of other stuff that went too fast and was too technical for me to understand..."lost circulation, etc..."
He did say however that they were pleased with the flow after 10/26 stages, and were moving in another rig to drill the next well (?). No explanation for the rig change that I caught.
They really like the Stalder prospects. "Could be a company changer".
Interesting presentation even though the slides they spoke to didn't match the deck that was provided....and the presentation was cut off just as Jim Denny was going to talk in detail about Washington, Noble and Monroe counties...and before the Q/A really got going. I'm hoping for a reprint or historical broadcast to fill in the missing details.
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TH-
An hour long kick must have seemed like an eternity for those on site.
Management failure online partially describes the problem to me. Site leadership failure is more likely. A well trained and drilled crew only notifies town after the well is secured and enough data obtained to plan the well kill. When the event is underway, alarms are blaring, chaos is everywhere and this is the last time that one should phone for help.
An hour long event in an overpressured naturally fractured zone would have unloaded the mud from the well and likely spewed gas everywhere; they are lucky that a fire/explosion did not occur. The flow may also have damaged the BOP equipment. There is a reason that this equipment is frequently inspected and function tested to ensure it works when needed.
The crew should also have known the capacities of the drill pipe from surface to the bit, the annular capacity of the hole from bit depth to surface, the strokes per barrel and efficiency of the mud pumps and other data used to complete the "kill sheet" to circulate the kick out fully and safely kill the well.
The kill sheets involve simple math. The common well control methods that I'm familiar with all involve keeping the bottom hole pressure constant throughout the entire circulation process to prevent another influx. This involves great communication and coordination between the man controlling the mud pump rate and the one controlling the manual choke. All of this is more than adequately covered during well control classes and while on the simulator. It's very frustrating to be on the simulator thinking that you are about to complete the well kill problem and then incurring another influx of gas into the well. These events can begin the well control problem all over again.
Its also too bad that the presenter spoke too quickly and did not have a Q&A opportunity.
Brian
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Permalink Reply by Kangoo on -
An issue with well control in shale plays these days is that many (especially smaller) companies don't design their wells for full reservoir pressures anymore.
The way I read the Magnum Hunter story is that it's not the pressure that was unexpected, but the natural fractures. It is very common in shale plays to drill production holes with a mud weight lighter than reservoir pressure. Reason is that in nano darcy shale (e.g. Point Pleasant) rock the un-stimulated reservoir rock is not capable of flowing sufficient gas to give you a kick. Many companies will drill a 15 ppg equivalent mud weight reservoir (for example the Point Pleasant) with a 10-12 ppg mud. If doing this one hits natural fractures you'll get a sudden influx of gas/hydrocarbons. If at this point the crew does not thoroughly monitor returns/does flowchecks, etc.... they can take a kick without noticing it. This (natural fractures) is how one gets blowouts in shale reservoirs (since the pore pressures are usually very well known)...... It's usually a lack of engineering combined with bad supervision.
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Permalink Reply by Kangoo on
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Brian, regarding your frac string comment. Actually in most shale plays with high rate slickwater fracs (Utica/Marcellus/Eagle Ford/Haynesville/Barnett, etc....) multi stage fracs are pumped down 5 1/2" production casing.
I am only aware of one blowout event due to errosion close to the wellhead during a high rate slickwater frac in Canada a few years ago. It's very rare. The heavy and high yield casing required to withstand the high frac pressures (in the deeper Utica one is looking at 5 1/2" 26lbs/ft P110 or 5 1/2" 23# Q125) is very erosion resistant.
Also the natural sand used these days on most wells (compared to ceramic or bauxite proppant) reduces erosion potential (especially when compared to bauxite)
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Permalink Reply by Al Cramblett on
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TO ALL,
Mine is a unique position when responding to this threat. First, I am a landowner with producing wells. Second, I'm a qualified investor in MH drilling partnerships. Third, I shall reluctantly admit that I am an engineer because engineers have distinct ways in which they go about solving problems. My perspective is that in today's advanced technological society, engineers can come up with a viable solution to most engineering challenges. Catastrophic results sometimes occur when management directs changes to engineering design due to the desire to reduce project cost. The Deepwater Horizon incident has already been mentioned earlier in this thread, and I believe that to be a prime example of almost everybody involved, to include regulators, not doing their job properly.
I have been posting and have hosted the Harrison County, Ohio webpage since mid-2010. This is the first thread that I have read which is principally devoid of name-calling and finger-pointing. Brian and Steve are to be commended for providing GMS readers a thorough, candid, and insightful explanation of what is involved with drilling a horizontal well within various shale plays. No reader would have been willing to pay for the technical info provided. Thank you Brian and Steve and GOD BLESS you for that!
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Permalink Reply by Joseph-Ohio on
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Obviously very knowledgable posters here.
Problem I have is that most is presented as highly technical industry jargon and because it is, it's meaning many times is hidden from me in particular (as I suspect it is for others who have not spent their working career in the Oil & Gas fields).
I've spent my working life as a technician also, but, in another field.
l find great value in reading these posts and attempt to ask the right questions to satisfy concerns I may have about the subject being discussed.
This has been an important and informative discussion for me.
Thanking the poster and all who replied.
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