I am currently updating the Kick Tolerance section of our well control manuals and I would like to know your thoughts on acceptable kick tolerance thresholds by hole size.
We have a minimum requirement of 25 bbls kick tolerance for 12¼” and 8½” holes. If the well design does not permit the circulating out of an influx of this size using the driller’s method (and its attendant pressures), a deviation/dispensation from our Well Control policies is triggered and additional measures/mitigations are required e.g. Installation of EKD, implementation of 'Level 2' alertness on the rig e.t.c.
We also differentiate between exploration and development wells - 25bbls to 50bbls ktol requires our attention for exploration wells but not for development wells. Our justification for this pertains to the fact that by their nature, exp wells have more uncertainties with respect to geology, formation pressure prognosis and well bore behaviour.
My questions are:
I heard about a "maximum 300 ft of influx height" rule of thumb and performed some rudimentary analysis with volumes and capacities. I could not find a discernible pattern with either pipe or no pipe in the hole for both hole sizes. at no point was 300ft = 25bbls
I don't like ‘rules of thumb’, so I'm hoping this forum can help me.
Looking forward to your responses.
I thank everybody for the contribution to this discussion. Within our company we have a permanent struggle how to properly appy KT in our well designs and to my understanding we are still running a far too conservative approach.
Using this discussion may help us on our way forward how to best apply it to our diverse type of wells.
Thank you all for your inputs – Steve Nas , Peter
Aird, Ryan Heng, Stephen Mann, Steve Devereux, Bill Abel and Mark Bourne –
The importance of early detection and appropriate reaction cannot be over emphasized. These can be brought about by the implementation of proper training, technology and a culture of operational and process safety, where "Doing it right the first time" is not just the fashionable buzz phrase of the week, but the modus operandi.
From all your inputs, it is clear that well-specific factors must be considered in determining what the KTol is in the design stage. But what exactly does that value mean to the Driller on the seat? He wants to know (clearly and simply) why a 20bbl KTol is good on well A but risky on well B. This is where case by case evaluation comes in. The days of the Rig Manager being seen as a ‘bus driver’ are over and we are progressing towards earlier engagement with the Operators to understand what the risks involved in upcoming wells are and what we can do as ‘partners’ to mitigate or possibly eliminate the risk identified during well planning.
From a mid-sized drilling contractor perspective, it is also efficient to have a generic set of ‘rules’ or thresholds which serve the purpose of a ‘trigger’, as things may change during the course of execution. We recently had a situation on one of our rigs where casing had to be set shallower than planned due to hole problems. The operator proposed to drill all the way to the next section TD without setting the contingency intermediate string, despite the reduced kick tolerance. The main reason given was the absence of any HC-bearing permeable formations within the interval. The rig leadership was immediately triggered and with our support sat with the client to explain why we could not in the specific case, deviate from our safety requirements simply to save cost. The Operator relented and set the contingency string. There are many similar situations where the programmed well prognosis is not “as drilled”. It could also be that the MW is high in order to combat wellbore instability but leaving a smaller margin to the shoe strength. All these require re-evaluation on a case by case basis to ensure that the right decisions are being made.
So to the question of setting thresholds, my approach, based on the inputs received from this forum and from our drilling guys internally, would be to modify our KTol volume requirements by:
· Distinguishing between operating environments: shallow vs deepwater (narrow margins)
· Exploration / Appraisal / Development wells (KI vs Swab)
· Providing explanations of the basis for the thresholds ranging from detection ability, reaction time, formation type, operating environment, MPD/no MPD.
· Displaying the thresholds in the form of a simple matrix
· Clarifying trigger points and appropriate actions
Once again, thanks for a very good and interesting discussion and let’s keep it going!
You might find it useful to review the Mathcad kick tolerance tutorial version worksheet on Drillers.com, see https://drillers.com/math-cad-worksheets/ .
Shell did a study decades ago at which they concluded that influx volume by the time the well was shut in ended up being about 3x the influx volume when the kick was detected. If your drill crew and equipment can detect an influx at 5 bbls and initiate closing in the well immediately, you need to be able to handle a 15 bbl influx volume under that assumption. Poorer equipment, less reactive crews = more kick volume.
You cannot sensibly define a kick tolerance as just a volume, you must also define the kick intensity. If it’s a swabbed kick then KI = 0 but you still must define that.
The frequently used kick intensity of 0.5 ppg equivalent comes from USA MMS regulations if memory serves me. I don’t know if they still use that value.
I was once responsible for drilling an exploration well overseas (from the company head office). We did an open hole LOT and I calculated we couldn’t take more than a 5 bbl influx. We were hoping to drill into a high pressure gas reservoir. Back at HQ, someone told me we could take a 165 bbl influx. I asked him to send his calculations. Not only was he assuming a swabbed kick but he assumed BHP was less than mud hydrostatic, on the grounds that his assumed pore pressure was below hydrostatic. This, like Star Trek and Harry Potter, defies the known laws of physics. BHP cannot be less than mud hydrostatic, no matter what the pore pressure.
Years ago there was a BP kick tolerance spreadsheet doing the rounds. Under some data entries, it was apparently possible to drill with mud hydrostatic exceeding formation strength. The spreadsheet was protected so I couldn’t see inside the box, which I don’t like. The basic KT calcs are simple as you can see from the Mathcad worksheet.
Huge big subject this one, where do we start. General points to consider (knlowldeg experiences) I have tried to capture below.
The key issues wrt to well control wrt KTOL values are early detection, quick corrective action to be taken (confidence competency level in this) and can we safely get the kick out of the well. The what/ifs and what is then plan B!
e.g. does the well design afford a contingent string to be run as this is by far the best well control assurance we have in such a limited threshold operational situation/scenario. Don't ever forget or misplace this evident fact!
Where too many wells have failed to afford this well control contingent assurance options and why many never reached required TD it was not becuase we ran out of kick tolerance.
The 25bbls value? in my understanding was a general ball park figure derived for early HPHT exploration wells based on the rig types and surface gas handling equipment capabilities present. If a bigger kick was taken on bottom the decision tree mandated to try and bullhead to reduce the kick volume before circulating to surface for rig safety and operating reasons.
Scientifics reasons basis?
We should surely consider all on a well by well section by section basis looking at each section akin to a traffic like process. i.e. Green amber red operational hazard/risk and uncertainty.
Key point is that standard kick tol, calcs are extremely conservative, in narrow margin wells we have to up our game in this respect and perform much more in depth and detailed sensitivity analyses.
When we identify and enter into a amber or red zone interval and get backed into a operational corner wrt kick / operating tolerances/limits we need to then ask what can we live with, and what do we intend to do to reduce all hazards/risks and uncertainties that we could be confronted with.
What we generally do from a design and operating standpoint is as follows.
1. We engage a specialist to do a sensitivity analysis to all inputs outputs outcomes benefits and value that could result. We would run these by the drilling contractor as they have to approve and signoff on what we (the operators) intends to do to safely meet the wells goals and objective i.e. get to required TD in a big enough hole size safely, effectively and efficiently.
2. We clearly state what we have then derived from our evaluations and determinations and sensitivity analysis conducted within the well's specific basis of design and well control bridging document produced for each well on a section per section basis to what the operator and drilling contractor have assessed is ALARP! (Because standard contractor and operating documents do not cater for such events). So don't over complicate these manuals, simply state the obvious.
3. The bottom line is that when we run out of an accepted kick tolerance for each particular section what ever this may concluded and determined to be (as it can be a big to a very small number). How will this compromise the well's purpose and objectives. Consider the what/ifs and have a contingent plan B or C in place and then enforced as needed. (when we know we are at the end of the road to safely drill and operate a section)
e.g. in the late 80's early 90's on early HPHT explorations wells when Ktol reached <25bbls in an 8 1/2" wellbore. It was simply deemed not safe to proceed (we were typically in a loss/gain scenario at this time anyway) . We then filled the well with concrete and had to come back with an alternative well design and operational plan at a later date. Early well design and operational failures with key lessons (often yet) to be learned!
Drilling Deepwater wells where no hydrocarbons are present we have drilled tens if not hundreds of wells with kick tolerance's less than 15bbls in an 8 1/2" wellbore. Taken water (brine) kicks. Concluded these were very difficult to kill (ie wells normally fractured at weak point during well killing circulation) we had associated downhole problems /issues to deal with but no risk was placed to rig at surface. vs a Gas kick in a similar underground flow situation! So we should always be thinking what if in such situations.
In mature areas such as the central North sea we regularly drill through massive claystone intervals where there have been no hydrocarbons present and where normal pressure exists at significantly reduced Ktol vs standard norms. This allows us deliver a more slender well at significant operating time cost benefits. We learned that some drilling contractors did not have an issue with this and others did. So it was made quite evident what contractor we preferred to use for thess types of wells. So be careful what you prescribe in your manuals wrt. We suggest it is better to offer a method that will diagnoses what is deemed to be safe ALARP!
4. A key point is that the well assurance, integrity and safe ALARP barrier plan and basis of design affords and permits another string of casing/liner pipe to be run when operating threshold limits presented clearly state it is not safe or practicable to continue. Running a string of pipe (or an expandable liner) to isolate the problem will always remain as the best well control assurance we have.
There is lots more on this so let not treat this lightly.
Thanks for raising this post.