This item crops up on numerous well designs, how to mitigate the risk of abnormal pressure lenses particularly in the intermediate/production sections to maintain an optimal well design.
The scene: One offset in the area encountered an abnormal pressure lens, took a kick and the same zone may or may not be present on your location- but can´t be discounted. 9 times out of 10 you don't see anything when you drill them.
Planning: when designing the well do you push on and drill through to next section TD accepting the potential performance risks, high overbalance, low ROP, losses, unable to reach TD or do you deal with potential abnormal pressure lens and isolate it requiring extra string, cost and time.
I would like to know if there is a more pragmatic approach and understand the merits of particular strategies used by
members in the group.
Some of the risks:
1) high overbalance - subsequently performance risks drilling ahead
2) hole size (17-1/2”)- ability to dynamically kill abnormal pressured lens
3) kick tolerance (surface casing)
1) Accept high overbalance and drill ahead (high risk of low ROP), set decision tree options Drill ahead, set liner/ casing could be planned based on depth, ROP and time.
2) Plan to drill through and case off with extra string/liner, lower MW
3) Plan to drill through take pressure points confirm yes/no pressured and adjust MW
4) Push surface casing as deep as possible or extra string for kick tolerance
5) Drill different hole size (slim) to dynamically kill it- dedicated pilot hole
6) Is there any lookahead tools on the market that can provided added value in the assessment of the lens being abnormally pressured?
I would consider drilling through potential abnormal lenses. In the event of hitting abnormal pressure lenses, I would increase BHP immediately to stop the influx and then kill the well dynamically. I would then continue with the new higher bottom hole ECD to TD. However, I would equip myself with sort of an Early Kick Detection (EKD) system.
You may now ask as to how you could increase BHP immediately in response to a kick without closing the BOP? This would be possible by establishing a closed-loop circulation system. The technique is referred to as Managed Pressure Drilling (MPD) in the drilling industry. To implement MPD, we can installed a Rotating Control Device (RCD) on the top of the annular preventer. The return is then diverted to a designated choke manifold. The choke(s) on this manifold can be manipulated to implement adequate pressure to the annulus of the well from surface whenever is required. We normally refer to this pressure as Surface Back Pressure (SBP). Paper SPE-170684 will be beneficial, I think, if you can have a read through. This paper explains dynamic well control with MPD equipment. By reading the paper you will also get a good idea what factors we need to take into consideration during planning for this type of operation.
Regarding EKD, MPD packages could come with sort of EKD system. A good kick detection algorithm together with a robust control system, flow rate measurement, and pressure measurement will be a great help in detecting the influxes at very early stages. There have been cases that influxes as small as 2-3 bbls, or even smaller, were detected. Some companies even went one step further and designed control systems by which the choke(s) will react automatically to a detected kick and stop it by increasing SBP and circulate it out automatically. Please refer to paper SPE-168948 for a case study.
I've been around in circles once before weighing up pilot hole options vs setting an extra casing string for a scenario with some similarities to this.
An approach that helped in making a final decision was to assign probabilities and costs to all options and outcomes (a weighted decision tree sort of thing that can be a few levels deep).
We were initially trying to minimise the cost in the most likely case - which we thought would lead us to a quick dedicated pilot hole to confirm lack of pressure rather than most likely having to set an extra string if we didn't drill a pilot hole. In our case however, when we put numbers to it all, the weighted average costs of the two options (dedicated pilot hole or not) were very similar, but the worst case costs were much higher with the dedicated pilot hole.
It's not high science (probability modelling could no give full probability distributions), but in our case it helped to have a probabilistic cost option tree drawn out with the likely weighted costs, best and worst case numbers - the decision became much clearer.
Let´s go back several steps in the well planning process as
this is where this discussion must start. Best practiced ”˜Front end loading´ is
where these problem are often best resolved via a project´s multi-disciplinary
team, i.e. We spend numerous hours with
the G&G and other bods discussing pore pressure and wellbore stability
Hazards, risks within each section to try and do the right things and get it
right first time and/or have the plan ”˜a´ or ”˜b´ or even a plan ”˜c´ in worst
When geological risk and uncertainty risk results higher, on a well or section by section basis (note: G&G should be driving this, we should be asking the right questions). We may still further employ and outsource to specialized geo-mechanic bods to conduct studies to further verify, validate pressure risks to assure the right mud weight strategy. (note; Too high an overbalance often the greatest risk and from where most wells fail and significant cost overruns then result.)
If there is higher risk and uncertainty? (or we still don't know what we don't know as Geological is fraught with risks!). The team must assure more and better robust contingent plans exist. E.g. engineers may require an expandable liner or two in the well design toolbox options. Or a simple to more complex MPD solution ready to go.
This pressure management process is always therefore a compromise between well safety, integrity, risk, optimisation and other factors, it's never easy. But as good wells drilled show it these surprises can be safely managed and dealt with.
In an exploration/appraisal well you need as the engineer to assure contingency strings to assure you can get to TD in worst cases in a required wellbore size (generally circa 8"” for offshore wells). Recent example;
Exploration well (14xxm water dept) (fraught with geological risk and uncertainties from seabed to TD) base case was however a slim hole design. Worst case a more conventional design with 4 further contingent strings (note:two of these were expandable's) planned for subsequent section risks. A pilot hole was decided to be drilled from the seabed to surface casing depth to provided data needed to make better (conductor/ surface string decisions). You cannot generally dynamically kill shallow 17"" ”˜kicking´ wellbores as wellbore mofdelling will show.
Pilot hole confirmed a slim hole design was feasible i.e. so a 133/8" casing was as the surface string). So this was bold strategy for a rank exploration well in the middle of nowhere, with 2500m more to drill below the surface string depth, a major nearby fault and lots of pressure uncertainties still to be dealt with.
However despite all these unknowns in the subsequent sections, the pressure risks and uncertainties existed, contingencies can be built into the slim-hole design. E.g. Unocal pioneered this in deepwater in the 90´s!
So although this was exploration an optimal design was feasible (if low case pressure cases resulted). In higher case events (e.g. pressured zones, and there was two further major risk identified in this well) on these sections, liner and expandable options were afforded the ability to isolate any over pressurised zone if encountered. When you start to struggle in a well the safest option is being abel to set a string of pipe across the zone.
Versu a development well, (worst pressure case comes in through a pressure lenses etc) once in every xx? well´s. Again you now need to run a contingent string, and yes optimal productivity size may be compromised due to added section required. But again with expandable and use of under-reamers available today this risk can be reduced somewhat and you have a fairly optimal well to produce. vs weeks of lost time and AFE cost overruns!
So that's the pressure prediction part and practical well design.
The flip side is the pressure detection part. Where explicit focus must again be planned, engineered and then executed by the rig site team. i.e. The best laid plans can easily become undone through poor rig-site leadership and management. So focus here is just as important.
However experienced rig site people (e.g. a decent driller who understands downhole) can feel when the well is talking!. With LWD/PWD etc etc today, it is far easier than before to pick up on the pressure ”˜warning signs´ present. So time spent on these aspects are just as important. Thus having a good set of best practices in place to assure people do the right things and get it right first time is central to delivery success.
Lets not overcomplicate this. When formations change, bit parameters change, so learning to pick up on these features is where experience and knowledge kicks in. If you take an obvious kick or a major loss zone. You have to deal with this safely, effectively and efficiently. i.e. Drillers knowing immediately what to do in each scenario! Too low a mud weight or too high a mud weight makes this much more difficult to deal with. So mud weight management and a well trained team, is central to success.
To minimize risk in this respect you plan for the zone, you slow down, control your drilling rates, parameters, you watch for the signs, when variations are observed, you take the time needed to investigate this before drilling ahead (note: look ahead and pressure point tools often are a waste of time in these cases in my view) Simply because these are generally discrete geological features that are not recognised until you simply drill through them. You run these tools, then dick around at increased risk, and often are none the wiser!
So the process to drill through as safe as practicable
again the key driver to success here. A too low or too high mud weight is not
the answer. It about ascertaining the correct and safest mud weight to best meet
all cases is what the team must assure. As previously mentioned this is
where the FEL benefits now result.
If kick tolerance is assessed as too low you MUST run a string or have a MPD contingent option in place. Or sign off on a management of change. If losses are too high or you take a kick and have to increase MW where operating margins are now considered non-conventional.
You options are drill a safe rat-hole distance, run and cement contingent pipe and/or have a reactive or proactive MPD system ready to safely meet the challenges now faced.There´s also additionally lots of well written documents on pore pressure prediction, detection etc. All the service providers have this quite well outlined in their supporting technical and training documents.