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Kick Tolerance Thresholds
01 August 2019

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:

  1. Where did this “25 bbls” figure originate from?
  2. What is an acceptable scientific basis for determining what a standard threshold K-tol should be for a particular hole size?
  3. What is your company position on K-Tol thresholds and how do you handle deviations?

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. 


19 answer(s)
D&C Project Coordinator / Decommissioning
Society of Petroleum Engineers
Total Posts: 32
Join Date: 25/01/16
Interesting discussion but I might suggest that there is too much complexity for decision making when terms of kick tolerance and calculations with decimal points are used.  Having been in the mud logging unit since 1974 to determine abnormal pressure indications it evolved that the only reliable way to manage pressure change is to keep the mud weight at a hydrostatic that balanced known permeable pore pressures at the casing shoe.  The monitor ROP with constant drilling parameters.  If the formation pressure in the barrier formation is increasing the drilling ROP will increase along with things like hot wire gas.  One then increases the mud weight to balance the drill off effect and then assesses what the shoe strength / kick tolerance is.  If getting close like an influx of 25 bbl of gas would cause a breakdown / underground blowout then set casing.  Note the power of SET technology opens the door for re-engineering well control to there being surety of two barriers.  Next step is to learn how to carry out SET operations.  So time to eliminate two decimal points and kick tolerance rules.  Take safety factor out of mud weight calculations and do the drill for kicks technology where folks on sight know what they are doing.
Drilling Support Superintendent
Maersk Drilling
Total Posts: 11
Join Date: 15/12/05

Thanks for all the points you have raised here.

The first 4 immediately bring to the fore, considerations for human performance factors in well control. From a Drilling Contractor perspective, this is critical to how we operate especially in these days of 30 - 40 day contracts for a 7th generation drillship and a quickly assembled crew that is expected to deliver the well on time and within budget with zero safety and well control incidents (topic for another discussion...).
In addition to mitigating the risks associated with the situation alluded to above by choosing to invest in warm stacking, we have also post-Macondo, implemented measures to support correct decision making under pressure. These include Driller's authority to shut in without recourse to a supervisor, Enhanced Team-Based WC Training, onboard WC simmulators, enhanced offshore engagement btw rig and client through pre-phase meetings in addition to the PJMs and TBTs, an onshore operations support team and things as basic as structured formats for procedures that remove ambiguity (e.g. simple one-line sentences and the use of 'action words' to start each line on a RAP/Drillers instructions). 

Best Regards,

Senior Wells Advisor
Redstone Drilling
Total Posts: 36
Join Date: 13/09/07
Scott McNeil makes some very valid points.

Indeed, there needs to be alignment within the team(s) how KT is calculated. I have performed well verification on an exploration well where the operator had outsourced the well engineering but retained a drilling manager on the project. It transpired that there was no alignment on how to calculate KT. This resulted in a status quo and there was no common KT value while drilling the well.

Rig contractors require to assess KT as part of their insurance policy requirements. Unfortunately, not many are adequately resourced to perform these calculations properly and rely on the operator to perform these in a systematic consistent method.
The discussions with rig contractors on KT will be more effective if there is a systematic consistent methodology to determine KT that includes a robust risk assessment adopted by the operator.

I would like to suggest to keep the section on KT in your well control manual as simple as possible and agree on one methodology but stress the issue of risk assessment and management of change procedures (MoC).
SPREAD Associates
Total Posts: 141
Join Date: 05/03/08
Hi Adebowale,

Lots of interesting responses here and it is fairly clear that there is no single 'correct' solution.

One thing that keeps coming through is that the approach to kick tolerance should be well specific, although guided by your Company policies.

A few additional things that I would take into consideration;

A) How confident are you in the Rig and crew? Is it a new build or newly reactivated Rig that the crew are not used to? Or a rig and crew that have been in use for a while, everything works and the crew are all fully trained up?

B) Same as A), but to a lesser degree, for the Mud Logging Unit.

C) Has the Rig come in from a different Country and local national content / employment laws mean that many crew have had to be changed out for locals, who may not have the same level of experience or familiarisation with the rig?

D) How much offset information do you have? Is the information good quality and reliable, or do 'local influences' also have an effect. e.g. some NOC's historically have not been allowed to report that they have taken a kick. In other cases, the Driller would have to get permission to shut the well in, making a kick much larger than you would expect for the circumstances. In some instances, the offset Well may not exist at all, having been completely made up by the NOC, just to make a quota set by the central government.

E) If you have plenty of good offset information, what are the fluids? Should you really be using dry gas for your kick model, if all the offset wells encounter heavy oil or brine?

F) Is everybody in the organisation using the same kick tolerance model? It is surprising how often I've come across Companies where they have strict definitions of the criteria for kick tolerance, but everyone uses their own favourite method of actually doing the calculation, leading to inconsistency in results.

G) Is there a possibility of a loss zone deeper in the hole section, where losses may result in a reduced hydrostatic head and allow a zone higher up to flow?

H) Is the well deviated? A 25 bbls gas kick in a vertical well is much simpler to deal with than a 25 bbl kick in a 70 degree well, where the gas may very rapidly migrate up the high side and come to surface quicker than you would believe (my record, gas to surface in 30 seconds from 5,000ft, and yes, that was quicker than the BOP closure time..)

I) What could be the cause of a potential kick from a formation? A gradual build up of pore pressure in an impermeable formation which overlies a sand, but pore pressure monitoring gives you good warning indications that it is increasing? Or a sealing fault with trapped pressure below it, which gives little warning of increasing pore pressure?? Or an impermeable formation which contains fractures and you get no warning at all? (Those with Southern North Sea experience will know of the Platten Dolomite!).

J) Where could a potential kick come from? A low or high permeability sand? A fractured formation? A kick from a low permeability sand may take a considerable period of time to manifest itself, as a 1 - 2 bbl/hr influx can initially be easily lost in the 'noise' around mud volumes. On the other hand, a fractured formation kick can manifest itself instantly, but the extremely high effective permeability means a much larger kick can be taken even if the Driller acts instantly (see previous comment about the Platten Dolomite!).

I've wittered on enough, but I think you see where I am coming from - every well should be treated as an individual case when it comes to kick tolerance.

You mentioned about the Rig Contractor being involved. I suspect there are many cases where this work is being done and casing ordered long before it is known who the Rig Contractor will be.

If this is the case and your approach to kick tolerance in the well design could be construed as being out of the ordinary, then it is important to get a 3rd party to review your design.

Many of us know that this is standard practice in places like the North Sea, but it is by no means universal.

Having a 3rd party well examiner or peer review the well design to give a sense check will be invaluable in these cases when discussing the programme with the chosen Rig Contractor.

All the best!

Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 445
Join Date: 10/01/05
Following on from Haralds comments. 

The shoe is not always the weak point. We set claystone shale  etc for well integrity. 

Only Norwegian regulations address the obvious that engineers must design for the weakest point in the well.

eg a sand that exists 100ft (30m) below the shoe. 

How this is accounted for in terms of safe operating limits is what we shoul then be determining and evaluating.

Then we have wellbore strengthening where we try and increase safe well operating limits.

Some operators add LCA to system prior to taking a LOT to superficially increase kick tolerances.

Drilling Manager
Total Posts: 3
Join Date: 25/12/15

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.

Senior Wells Advisor
Redstone Drilling
Total Posts: 36
Join Date: 13/09/07
Great topic and some great responses.

One of the main input variables to calculate the kick tolerance is the strength of the formation at the shoe. This value has a large uncertainty during the planning stages of the well, and the magnitude of uncertainty does not really alter during the execution phase. A LOT or FIT value recorded would need to be interpreted differently to re-calculate the KT (btw how many of you do actually re-calculate the KT after a LOT or FIT?) and confirms if the adopted formation strength value to calculate the KT was correct or incorrect. To state the obvious, the strength of the formation could change within a 'few' feet of the shoe rendering the LOT / FIT meaningless.
The other problem with the KT calculations performed is that these assume a single bubble. This is incorrect and introduces a 'safety' factor in the calculation. Unless one use an advanced kick simulator such as the Rogaland RF simulator or Schlumberger Sidekick (if that is still around), the KT calculation will result in conservative outputs.
Having said all of that, KT guidelines are required in order to assess the risk of a well design. Steve Nas has provided KT values for the various hole sizes and I think one could agree that these are pretty much industry accepted values. Comparing the calculated KT values to these values should be subjected to a robust risk assessment - remember that risk assessment should also identify opportunities, and if the KT values are considered to be conservative for the well design under consideration, it may result in a better, more economical well design. One of the reasons why KT calculations should be included in a Basis of Design document.
I am a firm believer in reviewing KT values on a well by well basis and therefor support having simple guidelines such as provided by Steve Nas.
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 445
Join Date: 10/01/05

These topics surely come under ‘pressure management’ with all associated Well control Assurance matters to be addressed within wells life cycle integrity and safety management required.

A helping steer can be resourced in Chapter 3 of recently published “Deepwater drilling” book. Where Pressure management has been specifically addressed in more depth and detail via a 40page specialist assisted summary. Principles as outlined that in the main can be used and applied for all other wells types etc.

Pressure management and integrated well control assurance is then further entwined within several other well planning, design and operational chapters in this book as these subject areas are evidently essential and  core to assure safe effective and efficient well's result.

Chapters raise, discuss and outline all the key issues, aspects and complexities to be addressed within such subject matters, particularly wrt complex narrower operating margin wells that challenge us today.

e.g. illustrated in fig 3.3 in the book it can be concluded how variant pressure management well's regimes can evidently exist within certain wells types, that within Deepwater alone range from simple (deep transitional normally pressured wells) to extremely complex (ricochet or narrow margin) pressure regimes throughout.  Wells in this particular domain that are generally far from being pressured the same. 

To highlight all key and central problems to be assured and addressed within standards, rules, regulations etc required.

We wish NOPSEMA success in producing a set of usable, practical ALARP guidelines in regards to safe operating pressure management of wells as currently planned, designed, and operated today. 

Drilling Support Superintendent
Maersk Drilling
Total Posts: 11
Join Date: 15/12/05

Hello All,

Thank you all for your inputs – Steve Nas , Peter Aird, Ryan Heng, Stephen Mann, Steve Devereux, Bill Abel and Mark Bourne – highly appreciated.

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!

Best Regards


D&C Project Coordinator / Decommissioning
Society of Petroleum Engineers
Total Posts: 32
Join Date: 25/01/16
Good discussion.  I might add that everyone here can benefit by doing your IWCF / IADC well control certification and dealing with all the issues discussed.  The simulation for understanding gives a grounding for well control using instinct. 

So many combinations that can evolve as seen in Montara and Macondo blowouts where the geological hazards are not understood in doing the casing and cement designs.  I had the experience of being on site for detecting abnormal pressure and determining required casing shoes and design during the '70's and 80's and being able to realize what your kick tolerance is as you drilled.  So valuable in planning the future drilling / casing strategies for two barrier well integrity knowing the earth system. 

 Time to get drilling engineers back into the mud logging unit as the Bladder Effect of missing well control integrity process hazards is catastrophic.   Simple things like knowing at what point of the well there is the highest ppgEMW pore pressure.    Some times the kick tolerance is because of the lower ppgEMW pore pressure dictating the maximum hydrostatic pressure that can be carried so the kick comes from the top gas formation when fluid column drops to the lower hyrostatic pore pressure and gas comes in from the top while the pumps are off and the hole isn't kept full. 
Well Integrity Specialist
NOPSEMA (National Offshore Petroleum Safety & Environmental Mgt Authority)
Total Posts: 5
Join Date: 24/11/14
Hi Folks,

Kick tolerance is an area that NOPSEMA are currently looking into, along with PP/FG prediction and monitoring. As a non prescriptive regime we are interested in international standards and guidelines that we can reference, and it seems there is not a lot on these specific subjects. I recently went through all the well integrity standards and guidelines in IOGP Report 485 (June 2019) looking for useful information on PP/FG prediction and monitoring and kick tolerance calculations and procedures. There was very little there. I found the most useful information was located in 2 documents, the pithily named Energy Institute Model Code of Safe Practice Part 17 Volume 1 High pressure and high temperature well planning, and the IADC Deepwater Well Control Guidelines, which actually has a reasonable amount of detail on both subjects. Another document I came across, which is not on the Report 485 list, is NOGEPA Standard 50 -Kick Tolerances for Well Design and Drilling Operations. We are currently working out where to go next with this topic, probably via the IRF. Any suggestions would be great.

Abel Engineering
Total Posts: 11
Join Date: 18/11/11
Here are my thoughts in KTOL:

I am old enough to remember that before kick tolerance we assumed the kick was due to being underbalanced 0.5 ppg (mud in hole was light and pore pressure kicked when penetrated) and the max anticipated kick was that size that created the max wellbore stress. This "design" was not kick size but casing shoe design that a full column of gas could be tolerated. This is NOT possible in all cases (one runs out of holes size and budget to drill the well). Thus kick tolerance came into vogue where one alerts the crew to the size of kick that can be handled without breaking down the openhole section. Thus it is NOT a kick size that works for ALL holes sizes, it is what stress is created when a kick is shut in that is below the frac gradient of the exposed formation and further can it be dynamically circulated out. Therefore I would caution having a size that fits all holes geometries. Whether you feel intensity or size rules the prudent engineer should calculate the load line for the kick for shut-in and circ. out. In ANY case the smaller the kick the better the chance of handling the kick within the "tolerance" or strenght of a particular design. 

SOLUTION: Run load line for kicks in a hole size and casing setting depth in relation to the frac gradient, THEN determine what kick size the well at hand can tolerate based on the well specific parameters. Lastly, the program for drilling should alert the crew to the size of kick that the well can tolerate and the detection / handing procedures matched to the well. Example, in some wells the key will be early kick detection or going to an MPD set up which would introduce more sensitive methods (I have seen kicks detected at 0.5 bbls in MPD and also screw ups in MPD where the kick exceeded 200 bbls). The crew and equipment and training are the keys to success.
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 445
Join Date: 10/01/05
Tips for calcs

when you have c1.......c5 gas readings from well you can calculate the physical characteristics of gas being drilled to surmise gas density. 

In deeper sections this will not likely be 0.1psi/ft as used in most KTOL determinations.

the bp toolkit is useful because one can input min max pp/fg values and output will show dynamic Masp based on a surface or subsea well choice to see if well can be physically killed or not at kill rates input. There is also a smaller app to evaluate choke line friction losses at low pump rates likely require d for subsea wells. The graphs generated provide a better understanding to where limits may be. Pvt effects are also accounted for. Downside is i believe only a fad gradient of 0.1psi/ff ( methane only) is used throughout. 
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 445
Join Date: 10/01/05
To sum up several point made. 

on one wildcat exploration well I remember a gas ( methane) kick being taken on a connection. 

Fortunately we had put
in place  several
measures to reduce the risk abc uncertainty.

we were drilling a pilot hole from below the 20in shoe. 

We we were making connections via the trip tank and finger printing these. 

We we had a lwd in the bha to try and detect formation changes indications of porosity permeability etc.

no warning sign was evident and on a connection. Well started to flow ( quickly) 

Time top drive was engaged a fairly large kick was taken. Time well stabilised this volume as stated was much larger. 

Masp was exceeded but due to smaller hole size and distance from shoe kick was inside shoe.

after circulating out kick it was later assessed we had drilled through a shallow overpressure one metre highly porous permeable sand/silt zone likely sealed with claystone above. 

The message in all of this was that even big Ktol numbers can give you a false set of security. 

The essence of operational safety is to be doing the right things and getting things right first time. If these were not implemented in this 1m interval case a underground shallow gas blowout could have easily resulted. 


Drilling Consultant
SPREAD Associates
Total Posts: 40
Join Date: 11/02/09

Hello Adebowale

You might find it useful to review the Mathcad kick tolerance tutorial version worksheet on, see .

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.

Regards, Steve

Drilling Engineer
Norwell Engineering
Total Posts: 6
Join Date: 27/09/09
Hi Adebowale,

I'd like to add formation deliverability as an additional consideration as it is often ignored when discussing kick tolerance. 

I acknowledge that we need to put a line in the sand someplace and put a hole size limit in place however, I believe this approach can actually give a false picture of the risk. 

Being able to identify and shut in an xxbbl kick in one area doesn't necessarily mean that a similar volume would be shut in by the exact same crew/equipment/reaction time if they drilled into the same pressure regime with greater permeability.

A less generic approach to KT and a fuller understanding of well specific risks would allow us to push deeper on some occasions and where necessary show increased vigilance. I fully understand this isn't easily put into a global standard and as engineers we don't like the vague!

Another interesting consideration is where mud weight is increased for reasons other than increasing pore pressure, e.g. hole stability and the knock on effect that this can have on kick tolerance if considering volume. It starts to look like you've "out-drilled" the shoe when you have actually increased the overbalance. So should you set casing or has the risk actually reduced?

Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 445
Join Date: 10/01/05

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. 





Drilling Advisor
SPREAD Associates
Total Posts: 5
Join Date: 19/02/13
Hi Ade,

I was in a similar situation of writing a well control manual a few years ago and was also trying to go back to "first principals" approach. This was the logic I applied to set the KT thresholds - so hopefully it may help.

For me, there are 2 main kicks scenarios:
1) Underbalanced kick - when the pore pressure is greater than the mud hydrostatic. The volume of this kick is a function of well deliverablility (e.g. Productivity index), rig response time and kick intensity.
2) Swab Kick - when an influx is induced into the wellbore during tripping. The volume of this is a function of how soon the driller detects the incorrect hole fill and is related to the open hole volume below the drill bit (in the worse case of high volume swab).

The table below shows that hole size (ie 26" hole vs 6" hole) has a minor effect on well productivity index and hence underbalance kick volume. ie a 26" hole has "only" 80% more productivity than a 6" hole.

In comparison, a high-volume swab kick is very sensitive to hole size - using open hole volume of a 90 ft stand (ie 3bbl for 6" hole vs 59 bbls for 26" hole - 1800% larger). So for me the key driver of selecting KT based on hole size was the swab kick.

I thought it would be appropriate that the openhole volume of at least 2 stands (2 x 90ft) be swabbed in prior to exceeding the KT threshold. The driller should be able to pick this up after 1 stand, but I thought 2 stands would provide a safety margin.

In summary, I ended up making it 30bbl KT for 12-1/4" hole and below (2 stands of 12-1/4" hole are ~26 bbl), and 50 bbl for above.

A couple of items of note:
- Kick tolerance volumes are only appropriate if the crew and rig are able to detect and shut-in before the limit is reached (e.g. KT for a floater rig may be more, though this analysis suggests it's still the swab kick that is the driver)
- The swab kick in this instance is based on a high-volume swab (plunger effect due to balled stabs). However in practice, the low volume swab (not replacing the drillpipe volume with mud) is often more prevalent. Though this depends on parameters like tripping speed and mud parameters - which are a bit harder to make general assumptions about.

Hope that helps,
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Well Engineering Consultant and Instructor
Olango Consulting
Total Posts: 36
Join Date: 23/03/16

Kick tolerance has two aspects, influx volume and intensity. The intensity of an influx is the difference in pressure between the formation pressure and the mud weight in use, that is given by the shut in drillpipe pressure. 

Some companies do not use kick intensity, which basically means that they are only considering swab kicks. 

The volume requirements are normally a function of the kick detection system on the rig being used and the hole size. Often this is bigger for larger hole sizes and then the volume reduces with the hole sizes.

This is sometimes defined as 3 x minimum detection limit of the rig others define the volume as 300 ft (100m of open hole) as a limit. No hard rules here, lots of differences.

The challenge with kick tolerance is always the assumptions that are being made and these have to be clearly stated. 

The most common rule is kick intensity of 0.5 ppg and volumes based on hole size and they vary greatly. Not sure that there are any rules of thumb as such. Some operators state intensity of 1.0 ppg for exploration wells, 0.5 ppg for appraisal wells and swab kicks for development wells in known fields. The intensity should all be about the pore pressure uncertainty.

As for volume the rule needs to be the bigger the influx, the harder it will be to control and circulate out but common volume numbers are
17-1/2" hole or bigger sizes kick tolerance 75 bbl
12-1/4" hole kick tolerance 50 bbl
8-1/2" kick tolerance 25 bbl

it is all about the detection and shut in process. remember observing a 5 bbl gain and stopping drilling, conducting a flow check and closing the BOP may give you a 10 to 15 bbl influx. 

If you are using an MPD system a lot of companies will allow a significantly increased detection threshold and there we have seen kick tolerance numbers as low as 5 bbl.

Not an easy topic and much discussed on many operations.

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