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7" liner cementing with very narrow pressure margin
20 May 2010
** Updated this discussion with a supplementary question, to cover an actual situation that developed recently with one of our clients **  (Dave Taylor 6-Jun-2015) .. see Response Number 4

Gday,
I have only 1.2ppg drilling margin in my 8-1/2" hole section and will set the 7" liner across the section for DST.

My final MW will probably be 18ppg and the cementer has provided a design of minimum 18.5 ppg slurry. The problem is my offset frac gradient is at 18.6-18.7ppg!

Anyone has encountered such problem? .. what did you do about it, and what was the final outcome ?

Noor Nordin
Drilling Engineer
Petronas, Malaysia
9 answer(s)
Companyrep
Drilling Specialist/Well Engineer/Training Consultant
SPREADAssociates
Total Posts: 339
Join Date: 10/01/05

1. I would have investigated everything that went wrong to date to assure that I and the organisation have fully understood the physical, human and latent causes to why things went so wrong in the first place. I would have first considered what I did that was wrong and then what else in terms of the organisations involved.

Why? because this 'operational loss' was a significant and major accidental event i.e. a non injury one that by admission and fact that the companies involved HSE matrix and company policy documents clearly states!

i.e. A major accident/incident events that MUST be reported and investigated to understand why, what, when, how things went so wrong.

Where is the report for this events, where is the evidence and findings?

2. vs. What has been given and based on this evident view is that a well that had a 1.2ppg margin in an 8-1/2" hole is virtually un-drillable once you go the next hole and casing sizes. Particularly when one hazards and risks the high geological and formations factors still unknown. If I had engineered the numbers I believe I would have  evidently conclude this well was un drillable unless total pressure management was applied.

3. So in my simple reckoning, a MPD solution and controlled pressure management was likely needed throughout every step of the well. This is what should have been planned for. The risks assessed, where a safe solution was not likely feasible for every step of the operation. e.g Trying to trip conventionally. 

A different safer and lower risk solution should have been investigated. e.g. Sidetrack from higher up to assure well was testing in an 8-1/2" hole and 7" liner environment.

What is more disturbing is that such a series and sequence of failed events is not seen as safety because that's what it is?. The accident/incident dominoes lining up on this well simply for bigger things to go wrong as we are not seeing this as safety!

How many times are we going to place our ourselves and other people into these situations? 

3. We must therefore change.

We need to avoid prescribed solutions without proper diagnosis. Otherwise as in other businesses this is simply malpractice and non safe acts to have been performed. So in response to how to change?

I have attached the approach I would have taken. This method is the 'life changing' opportunity for all of us within well operations.

We start with ourselves and must first always see ourselves as part of the problem. Then with our organisation we try and truly learn from all the little and big things that go wrong.

We must work to conclude the evident truth to the physical, human and latent causes of things that go wrong, without pointing fingers or assigning blame. We learn so we can prevent failure next time. Please read the attachment.

Want to know more about LCA? Then get in touch with Dave at RP2 or myself as we are alliance partners, striving to assure and eliminate well failure through best practices.

Here LCA tops the bill and everyone in well operations at every level in the organisation is encouraged to pursue LCA training to learn from things that go wrong. You start by looking at one's self and asking how did I contribute to this event etc.

So I was part of this problem. I looked at myself and spent a full day making the summary LCA methodology attachment to share. 

So that we can all try and learn from things that go wrong, using an introspective approach that starts with one's self.  

regards,

Peter

MBourne
Well Integrity Specialist
National Offshore Petroleum Safety and Environmental Management Authority
Total Posts: 4
Join Date: 24/11/14
Hi Gents,

Thinking along similar lines to Graeme Gordon, another option would be the WAB packer from Welltec. I don't know if they are available in the size you need, but they would give you zonal isolation. My previous employer successfully trialled them recently in Qatar, although that was on a 7" liner in a nominally 8 1/2" horizontal hole.
rvasquez
Drilling Manager
SPREADAssociates
Total Posts: 4
Join Date: 06/11/14
Dave, Noor:
As operations already took place and you want to analize what happened if, my comments below:
  1. What would you have done before running the liner if you had known that losses were likely?

    Same as you, best way to continue was expand the hole to reduce the ECD during cement job, did you tried to do a stress caging?, maybe balanced a LCM pill at the bottom [or loss zone(s)] and applying pressure to it may have worked, before to RIH the liner.
  2. What changes would you have made to the liner running and cementing programme?

    As we don't have the original program, will be difficult to analyze the possible changes, but for sure the stress caging will be one, same as swell and/or inflatable packers to secure the isolation between intervals to be tested.
  3. Given that we had an RCD rigged up, would you have attempted a CBHP liner cementation?

    No, it will remove the possible mud cake protecting the losses, even not centralizers need to be run due same reason

  4. For those of you who have attempted solutions to (1) to (4) above, please share lessons learnt and best practices.
  5. Have you tried liner top squeezes and, if so, how successful have they been? Any lessons learnt?
  6. What else would you have tried? Including perforation of the liner and a "suicide squeeze".

    Can be done, risk is high. I did it 2 or 3 times with good and bad results.
  7. If you have tried solution (6), how successful have you been and what are your lessons-learnt/best-practices?
GraemeG
Drilling and Completions Supt
Hess Corporation
Total Posts: 2
Join Date: 18/05/15
Have you considered running swell packers instead of cementing? This would give you the isolation required for DST although never guaranteed (like cement).
PaulHowlett
CEO
Sudelac
Total Posts: 80
Join Date: 10/04/08

Dave, assuming there is already a 7" liner set and cemented inside the production casing and you are talking about under-reaming beneath it and you have open hole that could accept the 5" liner, even with hind-sight I may have considered doing what was done already, but instead of cementing conventionally I would have explored options and equipment to reverse cement from above the top of the liner down the annulus, not necessarily on the same trip as running and setting the liner. I may have elected to run the liner without an integral liner top packer and run a separate tie-back packer after the liner hanger was set and cemented.

admin
Managing Director (rp-squared.com)
Relentless Pursuit Of Perfection Ltd.
Total Posts: 376
Join Date: 10/01/05

Hi folks

I'd like to build on the question raised by Noor and the answers provided. Here's the scenario:

The well is an High Pressure, (borderline) High Temperature well. An RCD (Rotating Control Device) was used during this section, at the appropriate moments. The well-test at TD was planned for three separate intervals to be tested.

The 6â…›" hole reached TD. During a post-logging wiper-trip (the well had been open 4-1/2 days), total losses occurred and during the subsequent (and extended) efforts to pump LCM and (eventually) cement plugs, a well control incident ensued.  After securing the well (and an unplanned suspension), the cement plug was drilled out in preparation for under-reaming to 7"; the reason for under-reaming was to minimise ECD during cementation of the 5" liner, thus minimising the potential for losses.

During under-reaming, severe losses occurred, which took OEDP and large amounts of LCM to cure. Under-reaming operations then continued.

The 5" liner was run. The hydraulically set liner hanger has a weight-set integral tie-back packer.

Whilst at the previous shoe, circulation was established without any problems. When approx. 400m off bottom (and 470m into the open-hole) it was apparent that losses were starting, and when circulation was attempted there were no returns. 

It was decided to run the liner to bottom and continue with the job, but not to set the liner-top packer after the cement job, so as to allow the option of a liner-top squeeze if (as anticipated) severe losses/no-returns were encountered during the cement job.

The liner was run to bottom, hanger set and the cement job conducted with little or no returns throughout.

After pulling the running tools and cleaning out the liner, the CBL indicated little/no cement behind pipe.  A liner top squeeze was attempted, but injectivity could not be achieved.

The liner top packer was set (dedicated run) and DST conducted, but no longer on discrete zones (due to lack of zonal isolation).

Our questions are:

  1. What would you have done before running the liner if you had known that losses were likely?
  2. What changes would you have made to the liner running and cementing programme?
  3. Given that we had an RCD rigged up, would you have attempted a CBHP liner cementation?
  4. For those of you who have attempted solutions to (1) to (4) above, please share lessons learnt and best practices.
  5. Have you tried liner top squeezes and, if so, how successful have they been? Any lessons learnt?
  6. What else would you have tried? Including perforation of the liner and a "suicide squeeze" .
  7. If you have tried solution (6), how successful have you been and what are your lessons-learnt/best-practices?

We'd value your comments, please.

Many thanks

Dave

noornordin
Well Engineer (HPHT)
Shell
Total Posts: 10
Join Date: 13/04/10
Thank you so much for the info. We will have fiber as one of the additive in the slurry to minimize losses during displacement. Another thing is, we will rig up rotating head equipment with automated choke control manifold in order to drill this section. Its a MPD with constant bottom hole pressure. Do you reckon its best to leave the equipment standby during the cementation job just incase we have severe losses?

The MPD provider have done that in the past but i dnt want to go to that route. Prefer to rig down the rotating head once i have displaced the well to heavier MW prior to logging and run liner.
PMcNaughton
Fluids Coordinator
Halliburton
Total Posts: 13
Join Date: 27/04/06
High ECD resulting in losses when circulating & displacing cement are your biggest concerns. Consider sized marble & sintered graphite in the cement & in the drilling fluid to help minimise losses.

PMcN
Halliburton Moscow
MohammadP
Project Manager/Superintendent
Petrofac
Total Posts: 5
Join Date: 18/03/08
Hi,

There are few options available. My understanding is your main challenge would be ECD management while circulating mud and pumping cement/displacement. Here are the options:

Using UnderReamer to drill and UnderReam the section so you buy more annular clearance for better ECD management. Typically, 9 ¼” or 9 "” hole should give you enough clearance to maintain your ECD less than 1.0ppg in this hole size

All drilling fluid companies offering additives such as fiber, graphite, etc ”¦ which are basically inert additives which can be added into your mud system to bridge off pore and enhance fracture gradient while drilling. You just need to perform some sort of a research to make sure correct size distribution has been used based on your pore throat size distribution.

You may also have the option to pump some cement mix water/base oil based ahead of the cement slurry to reduce the ECD, ONLY if the pore and collapse gradient of the openhole section allow you to design this. This will have to be modeled to ensure during the job you always maintain your BHP more than your pore pressure. There have been a few well control incidents due to this technique being implemented inaccurately. So it could be very tricky!

I hope this helps.
Mohammad Pajouhesh
SPD (assigned to Enquest)
Aberdeen
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