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API53S compliance
29 September 2018
If I have no return flow sensor on my trip tank line - am I compliant with above standard?
12 answer(s)
JDDrouin
Project Quality
SPREADAssociates
Total Posts: 99
Join Date: 06/05/09
Scott,

With respect, you need to re-read Wullie's post and the relevant sections of API Spec 53.  In his post, he asked "If I have no return flow sensor on my trip tank line ...".  The operative words refer to the absence of a flow sensor on the trip tank line and whether or not any such absence affected compliance with API Spec 53.

Again, API Spec 53, Section 6.4.8 specifically requires a trip tank flowe line sensor.  Further, API Spec 53 Section 6.4.6 addresses the general requirements of trip tanks, not flow rate sensors required on those trip tanks, which are addressed in 6.4.6.

Re the inspection companies deficiencies in NOT finding clear, unequivocal non-compliances, again, that's a matter of competence and / or training.  The requirements in API 53 in regards to flow rate sensors on trip tank lines are very clear and quite incontrovertible.

Re requirements being based on a project, and I'm not trying to be insulting, but that's nonsensical.  There is no, NO specification were that's even hinted at ... now a company may decide to waive any requirement for whatever reason it may deem appropriate, but the API Specs (or ISO, or ASTM, or, ASME, or, or, or) are in no way dependent of project scope or scale.

Further, I've worked for the majors for much of my career, and they are just as subject to human failings as every other company.  The majors typically, but not always, have superior controls in place to prevent those failings from escalating into catastrophes, but when someone high up the chain of command says 'make this happen', then happen it does.

James

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Scott_McNeil
Consultant
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Total Posts: 110
Join Date: 05/03/08
James,

You missed the point.

Wullie was specifically asking about the trip tank line, not the flow line.

So API 53 Section 6.4.6 is the appropriate standard, not 6.4.8.

As for your comment about the inspection companies, both are internationally recognised and regularly used by the lies of BP, Shell, ExxonMobile etc.

Yes, I've had rig inspections where we took over a Rig from another Operator after a short program, and the inspection company came up with a different list of failures - but the differences have nearly always been in the minor category, few in the major and never in the critical - unless something had changed in between times.

It also depends on the project you are looking at.

I'd commission a one level of survey if I was looking to take on a rig for a multi-year contract that had just worked for a less than reputable Operator. But a different one for a single shallow well if the Rig had just worked for BP / Shell for five years.

Best Regards

Scott
JDDrouin
Project Quality
SPREADAssociates
Total Posts: 99
Join Date: 06/05/09
Scott,

API Spec 53 lists the requirements for trip tanks in Section 6.4.6 and those for flow lines in Section 6.4.8, so "no", no confusion.

Re the land rigs and audits thereof, those are two separate issues; cost and competency.  Entire encyclopedias could be written on those.

However, of the two, I will (subjectively) rate the audit's failure to find a clear deficiency as the most serious.  Without delving into the nightmare scenario of what else may have been missed, that type of audit failure deprives the operator the opportunity to adequately risk assess each part of the rig and it's intended operation, AND institute work-arounds as may or may not be deemed necessary.

James
JDDrouin
Project Quality
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Total Posts: 99
Join Date: 06/05/09
Ray,

From API 53, pg. iii:

"The term “shall,” as used in this standard, denotes a minimum requirement in order to conform to the specification."

James
snas
Well Engineering Consultant and Instructor
Olango Consulting
Total Posts: 20
Join Date: 23/03/16

Wullie


Rather than going by the letter of API 53, back to basics this is all about monitoring the primary well control barrier which is the fluid column. What sensitivity does one have to ensure that the well is controlled by the primary barrier?


During drilling operation,  flow from the well is a primary indicator and the first indication that shows that an influx is occurring. A flow sensor (paddle, or some other flow meter) provides the first indication that flow from the well is increasing over and above of what is being pumped into the well.


Fluid level increase is a second indicator, but that is delayed simply because of the sensitivity of the circulation system. When drilling and circulating, the surface volume in use is relatively large and any increase needs to be a certain size before it can be seen.


When tripping operations are conducted the primary barrier must still be monitored. There is no circulation. Pumping across the top of the well with a small defined volume of fluid provides the indication that the well is static. When tripping out the correct volume is used to keep the well full, when tripping in the correct volume is returned when pipe is lowered into the well. A trip tank, small volume, is used to ensure that the volume can be measured accurately.


This is done the same way when stripping. Now the volume used and measured is even smaller and it allows monitoring of the primary barrier.


This is not about a well giving you a kick when drilling or tripping that flows at 2000 to 8000 bbls/day (60 to 230 gpm) but if the well was flowing at 10 gpm (14 bbl/hr) during a trip what flow meter or flow paddle would see this? A small tank of say 20 bbls would indicate that something is not right.


The basic question of API 53 really is: do we know if the primary barrier, the fluid column, has failed, so that we can activate the secondary barrier, the BOP.


It does not matter how we check the primary barrier, providing that we know the well is static we comply. Now in deep, hot and narrow margin wells with ballooning and breathing and thermal effects this all gets very complex. But remember no one will ask how we did this or what we did when the well gets to TD and reaches its objectives.


If a bolt on a string from the handrails worked, we are heroes. But if a well blows out…a million questions by a thousand experts are asked even if we had all the flow meters and level sensors we could install.


It is not about how or what can we measure, it about what do we see, how do we interpret what we see and what actions are taken.


If you can monitor the primary barrier you are fully compliant. If the secondary barrier closes, stops the flow and holds the pressure you are 100% compliant with API 53. 





learning.lifewayne@g
D&C Project Coordinator / Decommissioning
Society of Petroleum Engineers
Total Posts: 16
Join Date: 25/01/16
At worst a trip tank has a measuring bar mounted on the tank and one can see what the level of fluid is in the tank and then take readings by time and know flow rate etc.  Interesting that those investigating the Oklahoma explosion seem to have no background of the drilling management system and the guy doing the drilling had no knowledge of how a well system worked.  Need to get a law where blowouts can't be tax deducted.  The moneyland ideology must be paradigm shifted.  https://www.theguardian.com/books/2018/sep/09/moneyland-oliver-bullough-review-wealth-corruption-oli...  Complexity of it all is well documented at   https://www.scribd.com/document/249130988/Macondo#
Scott_McNeil
Consultant
SPREADAssociates
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Join Date: 05/03/08
James,

Are you not confusing trip tank line with flowline?

Although most of my recent work has been on old Land Rigs, I have yet to see one that has a separate flow meter on the trip tank line.

This has never been raised by the inspection company (in pre-hire inspections) as being non-compliant with API 53S.

In that respect, I agree with Dicks line of reasoning.

Best Regards

Scott
RayKoehn
Senior Drilling Supv
Hess Corporation
Total Posts: 3
Join Date: 29/05/12
Sorry James. Shall in legal terms is not a mandatory, if it reads “must” then it is definitely a requirement.
JDDrouin
Project Quality
SPREADAssociates
Total Posts: 99
Join Date: 06/05/09
Wulie,

I don't want to get into an argument with the other posters, but the answer to your question is a very unequivocal "NO, your trip tank line is NOT compliant with API 53".

The standard very specifically states that "A flow rate sensor mounted in the flow line shall be installed ...", with the remainder of that requirement being a descriptor of the sensor's function.  "Shall" is not, NOT, an option, it is a requirement.

James
dickheenan
Drilling Consultant - Frontier Operations
SPREADAssociates
Total Posts: 15
Join Date: 07/03/11
I would say yes you are compliant with the intent - reading the requirements from David and considering the actual tripping operations.

6.4.8.1 "...early detection of formation fluid entering the wellbore or a loss of returns."
Clearly this is as important when tripping as drilling (statistically more so) . Despite this, I think the the use of flowrate from the well would logically only apply during drilling and circulating.  

When tripping there are two options re the trip tank
(A) circulate continuously across the trip tank while pulling pipe and periodically confirm that the hole is taking the right amount of fluid.  (System needs to be stable - drillpipe stopped and not draining into the hole)
(B) periodically fill the hole and verify that the correct amount of fluid is being taken as the steel is removed.  Again, in a stable situation.

In case (A) the flow rate into the trip tank at any time will be a function of gain (or loss) in the hole, but will be very influenced by pipe movement so I don't believe flow rate in this case is useful as a primary kick indicator, unless some sophisticated software was used to determine when the pipe was stationary, not draining back into the hole, etc.  I'm not aware of such a system.

In case (B) it is clearly not useful.

I see the trip tank system as a volumetric check (essentially a "PVT for tripping").  Since the surface mud volume is very low compared to an active system it should be very sensitive for this application.
As far as API 53S is concerned, I believe that the authors intended this to apply to drilling/circulating operations and not tripping.  Unfortunately I don't have enough context from the document to confirm or disprove this.
Similarly, I don't see how 6.4.8.2 could be appropriately applied to a tripping operations.

Comments from others?  
Do you have a flow sensor on your trip tank line?
If so how do you use it and what advantage does it have over the traditional "volumetric" approach?
dstrickland
Drilling Superintendent
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Join Date: 24/06/16
Typically the return flow sensor is on the flowline upstream of the line that would lead to the trip tank.   In this layout the one flow return meter can cover both the conventional circulation path and the line that goes to the trip tank.   It should be possible to relocate the return flow meter (or install another one) on the return line upstream of his point.
JDDrouin
Project Quality
SPREADAssociates
Total Posts: 99
Join Date: 06/05/09
Wullie,

Looking at the 4th Ed, it specifically states:

=====

6.4.8 Flow Rate Sensor
6.4.8.1 A flow rate sensor mounted in the flow line shall be installed for early detection of formation fluid entering the wellbore or a loss of returns.
6.4.8.2 Audible and visual alarms shall be active during well operations.

======

James
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Wullie Mair

ARM

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