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While drilling gas levels - what are your limits, how are they managed?
29 March 2019
Seeking learning / experiences of how teams get ready to plan design, engineer, and prepare for the physical surface effects of drilling porous permeable GAS reservoirs at high ROP. e.g. 8 1/2" wellbores 20-25% porosity, ROP's > 100ft (30m/hr)

What do you expect to see via the mud loggers gas detectors, 
What are viewed as safe operable limits, best practices to be applied? 
What corrective actions are then needed?
What illustrative well DDR's can be provided to support if best or improper practices then resulted? 
How much of this is covered in current well control examinations, simulations?
FAIL (Failure Always Invites learning) events in this respect?


2 answer(s)
D&C Project Coordinator / Decommissioning
Society of Petroleum Engineers
Total Posts: 24
Join Date: 25/01/16
So many memories in the statement "While drilling gas levels - what are your limits, how are they managed?"  Always be drilling and reading ROP and hot wire gas by depth every foot / 1/3rd meter keeping a constant WOB and RPM.  Use crossflow on the nozzles. .  If the ROP increases for longer then 3 feet or 1 meter, stop drilling and pick up off bottom.  Check for flow.  Circulate bottoms up and determine hot wire gas readings from the drilled interval.  One an evaluation of porosity and fluid type is revealed for the brief drilling break, continue drilling.  If the drilling break continues for say 30 ft / 10 m, again check for flow.  If ROP's were increasing, circulate a 2nd bottoms up.  Reviewing mud log parameters of ROP Vs Depth, gas units and things like temperature changes of Delta T in and out can help understand the reservoir for completion purposes.  Note that the highest ppg EMW pore pressure will be at the top of the reservoir.  If there is a high porosity drilling break 500 to 1000 ft deeper (200 to 300 m) it will be at a lower ppg EMW.  So if on tripping and casing running there is a period of not filling the hole and the hydrostatic bleeds to the bottom ppg EMW, it underbalance the upper ppg EMW which often is a gas.  Once a little bubble gets into the well bore you end up with the Bladder Effect like on Macondo, Montara and the Lusi Mud Volcano.  Disastrous Decisions because of geological hazards masking well system behavior.
SPREAD Associates
Total Posts: 132
Join Date: 05/03/08
Hello Peter,

Is this for a development drilling program? Given your usual stamping grounds, I presume it’s Deepwater? Also, what are the expected formation depths & pressures? Are you sure it’s pure gas and there is no condensate in the reservoir?

If any of the above are applicable, then it can complicate the drilling process in several ways, however, my contribution and hopefully not teaching you to suck eggs in too many areas;

A) On highly deviated wells, large kicks can result in two phase flow, gas up the high side and mud down the low side.

Depending upon the hole configuration, kick volume and bottom hole pressure, the gas can expand to the extent that when it does reach the vertical section of the well, it has sufficient volume / momentum and does not stop, but instead continues upwards, pushing out all the mud ahead of it.

This can result in gas to surface much, much quicker than you expect – our record was gas to surface in less than 30 seconds from +/- 1,750m MD….

I have never seen the potential occurrence of two phase flow during a well kick in a deviated well taught in Well Control school – although I have made a point of bringing it up during ‘war stories’.

B) Expect high levels of drilled gas, even with no connection gas.
The Rig’s ability to handle drilled gas in the mud will be dependent on the capacity of the poor boy degasser, vacuum degasser, mud system retention time, mud pit ventilation and also mud system type.

The first two speak for themselves – depending upon the flow rates, mud properties and amount of drilled gas entrained in the system, the vacuum degasser in particular is important and could struggle (especially if you are using a riser booster pump).

Mud system retention time could also be a factor, in that if there is a small surface circulating system then there is less time for any remaining gas to break out of the mud before it gets pumped downhole again. In this respect, it is important that the mud pit ventilation & gas detection systems (presuming it’s a drillship) are up to scratch.

Mud system type (and properties) can come into play because some types are less likely to give entrained gas up – salt saturated systems in particular are notorious for this.

If the reservoir is at any reasonable depth or pressure, you may want to consider using an RCD to provide a little additional extra control, as mud in the bell nipple can overflow due to mud frothing with drilled gas.

The rig crews may also need to build confidence that nominally high gas levels during drilling does not mean that the Well is underbalanced – connection gas is what really matters in that respect.

These factors will all combine to give a drilled gas level that you are happy to continue with, while also reducing the amount of drilled gas that is entrained in the mud system and re-circulated to a minimum.

C) Educate the rig personnel on recognising that entrained gas is being recirculated.

This is not always easy to spot. Our normal practice was to circulate the cuttings clear of the BHA prior to making a connection – this mud should be gas free. If it’s not, you may be seeing entrained gas, especially if the heavier (C3+) gases are more prevalent as a % of total gas than experienced during drilling.

An unexpected drop in pump efficiency/SPP/GPM – or even the pumps actually jacking off – could also be signs of entrained gas.

If you are not sure, a belt and braces approach we used was to sprinkle some cement defoamer on top of a mud pit and see if there was any effect – in some instances it was dramatic how much gas broke out of the mud system at that point.

D) Swabbing & Kicks
The high poro/perm means it is much easier to swab in formation fluid. Calibrate your swab models with experiments in the field.

You may also find you need a greater static overbalance than would otherwise be thought normal.

Any kicks are likely to be larger than normal, unless you have an automatic kick detection system. Even then, consider using a higher than standard kick tolerance for this hole section during planning.

For any kick, ALWAYS calculate how much gas can be expected at surface when circulating it out – especially with higher downhole pressures and with a larger than normal kick, this can be a staggeringly large amount which could easily overwhelm the surface system if precautionary measures are not taken.

E) Becoming differentially stuck is much easier. Keep the pipe moving at all times – rotate the string in the slips during connections and only stop rotating for the final joint make up.

This requirement can affect the choice of which MWD/LWD system to use.

Minimise the DC’s in the BHA – we used HWDP to provide the weight in the 8 1/2” section. Depending upon the BHA configuration and how stable the formation is, you may want to consider running two Jars, one close to the bit and running in compression, the other in the ‘conventional’ position higher up.

Shoot anyone that wants to stop drilling and take real time formation pressure measurements.

Try and avoid any W/Line program, but if unavoidable, ensure the logging program takes the raised potential for differential sticking into account – this also includes the wireline itself, especially if it’s being pulled to the high side in a deviated hole.

F) Avoid faults when drilling the reservoir section – if losses are encountered then the hydrostatic head can easily drop and induce a large kick from higher up.

This kill / loss situation can result in very high surface pressures (reservoir pressure minus the gas gradient form the kick zone) AND/OR downhole pressures (reservoir pressure gas in a bubble at surface on top of a mud column) and may not have been considered as a possibility during the drilling phase in casing design models (as opposed to during production).

If the fault is sealing, obviously there may be virgin reservoir pressure on the other side (depending upon how much production has occurred prior to drilling) and a kick may also result.

If you can’t avoid drilling through a fault, control drill through it at slow ROP so you can see what is happening.

G) Use non-damaging drill in fluid if possible. (Well duh!) But be aware that high spurt losses will be incurred no matter how much fluid loss additive you have in the mud system. We used to run sized Calcium Carbonate in the mud system as a bridging agent while drilling the reservoir section. Make sure it’s top quality and doesn’t disintegrate or turn to paste.

I realise that the above doesn’t really provide the specifics that you were asking for, but hopefully gives you additional guidance on areas that need attention.

All the best

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