From the Hmm… Department: http://oilandglory.foreignpolicy.com/posts/2010/07/25/haywards_out_will_bps_new_guy_be_any_better
[QUOTE=dell;40449]From the Hmm… Department: http://oilandglory.foreignpolicy.com/posts/2010/07/25/haywards_out_will_bps_new_guy_be_any_better[/QUOTE] A rose by any other name…
[B]Bladder Effect.[/B]
I had never heard this terminology before.
I know it by a different name, “riser hydrostatic effect” or something similar, hence my confusion and query as to what it meant.
For anyone that may want to understand the term “Bladder Effect”, I believe this is what it relates to. Here’s an extract from a well control manual…
"When operating annular preventers subsea, [B]the hydrostatic pressure of the drilling fluid in the riser exerts an opening force on most annular preventers[/B] ([I][B]Bladder Effect[/B][/I]). To provide the same desired closing performance subsea, the required closing pressure is equal to the surface installation closing pressure plus a compensating pressure to account for the opening force exerted by the drilling fluid column.
The amount of closing pressure adjustment required for the riser hydrostatic effect depends on the annular BOP design, (the unbalanced feature of the opening and closing piston areas), the water depth, and the mud weight in the riser.
Closing pressure adjustments for annular preventers are included in the manufacturer’s catalogue and should posted on the rig floor for the particular annular preventer included in the BOP stack. For water depths less than 1500 feet, the closing pressure compensation for the Cameron and Shaffer annulars is small (100 to 200 psi) and the adjustments are not needed. The piston on the Hydril GX annular is balanced and does not require adjustment for hydrostatic pressure."
[QUOTE=New Orleans Lady;40442]I don’t know if the following factor will make a difference, in the outcome, but, what I would like to know, was this rig’s work enviroment, “toxic”, where by you felt intimidated, to speak up,and give your point of view, [/QUOTE]
The way it is being portrayed in the investigations seems to be as you suggest. [B]
dell[/B] is educating me on the “role playing” and “if the moon is made of blue cheese” antics of lawyers… so maybe those legal eagles in these investigations have a lot to do with what we “joe public” perceive?
However, I worked on a Transocean rig all last year (in a different part of the world to GOM), and it was nothing like what is being portrayed here in these investigations.
[QUOTE=ExCompanyMan;40444]Negative inflow tests are pretty routine but as Professor Smith stated no standard procedure seems to exist, or at least he could not find any. Maybe they should exist since [B]the cold fluid could potential have caused casing lengthening[/B] without the lock down assembly.[/QUOTE]
Cold fluids normally shrink/contract things don’t they? At least that’s what happens when I jump in the sea.
No disrespect, but is there something I’m not seeing here [B]ExCompanyMan[/B]?
[QUOTE=Alf;40452][B]Bladder Effect.[/B]
I had never heard this terminology before.
I know it by a different name, “riser hydrostatic effect” or something similar, hence my confusion and query as to what it meant.
For anyone that may want to understand the term “Bladder Effect”, I believe this is what it relates to. Here’s an extract from a well control manual…
"When operating annular preventers subsea, [B]the hydrostatic pressure of the drilling fluid in the riser exerts an opening force on most annular preventers[/B] ([I][B]Bladder Effect[/B][/I]). To provide the same desired closing performance subsea, the required closing pressure is equal to the surface installation closing pressure plus a compensating pressure to account for the opening force exerted by the drilling fluid column.
The amount of closing pressure adjustment required for the riser hydrostatic effect depends on the annular BOP design, (the unbalanced feature of the opening and closing piston areas), the water depth, and the mud weight in the riser.
Closing pressure adjustments for annular preventers are included in the manufacturer’s catalogue and should posted on the rig floor for the particular annular preventer included in the BOP stack. For water depths less than 1500 feet, the closing pressure compensation for the Cameron and Shaffer annulars is small (100 to 200 psi) and the adjustments are not needed. The piston on the Hydril GX annular is balanced and does not require adjustment for hydrostatic pressure."[/QUOTE]
Nice to know what it means, but of course it doesn’t explain the negative test result. A leaking annular preventer would have given the same pressure in the drill pipe and choke/kill lines.
[QUOTE=dell;40418]BTW, y’all have noticed those words “negotiated exit” next to Hayward’s name in all the stories, right?
[/QUOTE]
[B]Negotiated Exit?[/B] if the boy is off to Russia and is still working for bp why does he deserve a penny? He’s been demoted.
Dudley, who previously worked for Hayward will now likely be his boss (if you trust news reports?).
Yes I know [B]dell[/B]… it’s all about contracts and not much to do with reality.
[QUOTE=berzx;40456]… but of course it doesn’t explain the negative test result… [/QUOTE]
I never said it did… the info was supplied for clarity and understanding of “Bladder Effect”.
[B]Jobs for the boys…[/B]
"I just want my life back…"
[QUOTE=Alf;40455]Cold fluids normally shrink/contract things don’t they? At least that’s what happens when I jump in the sea.
No disrespect, but is there something I’m not seeing here [B]ExCompanyMan[/B]?[/QUOTE]
Tend to agree but still would like to get it confirmed with a simulation. Look, the BOP did not close in the well, and failed it main purpose, either because there was a leak and it did not receive the signal (unlikely) or because the casing moved up and prevented the rams from closing around the DP. Also remember that if there was a leak going up the annulus then hot reservoir fluids would be traveling up; so you would have cold sea fluid in the casing and hot reservoir fluid behind it; god knows the effect on the steel with that.
Just brain storming…
[QUOTE=ExCompanyMan;40462]Tend to agree but still would like to get it confirmed with a simulation. Look, the BOP did not close in the well, and failed it main purpose, either because there was a leak and it did not receive the signal (unlikely) or because the casing moved up and prevented the rams from closing around the DP. Also remember that if there was a leak going up the annulus then hot reservoir fluids would be traveling up; so you would have cold sea fluid in the casing and hot reservoir fluid behind it; god knows the effect on the steel with that.
Just brain storming…[/QUOTE]
Metal expands when heated. Steel behaves rather predictably in response to thermal gradients and such. We don’t have to pray for the answers, or even run simulations, just look them up in the Handbook.
Now with regard to the BOP, there are two pieces of DP in it, as I already said in a post to you on Page 202. There may also be a casing in the bottom half. One more thing about the BOP. They didn’t try to activate it (the shear rams, EDS) until after loss of (hydraulic) power on the rig. That left only what was stored in the accumulator. It obviously wasn’t enough.
[QUOTE=Alf;40416][B]dell…[/B]
I ask you, as an Expert Witness…
‘Isn’t it true… that “a Bladder Effect” is BS?’
and… ‘in your experience, as “an Expert Witness”…’
‘Isn’t it true that “a Bladder Effect” only occurs after 3 pints of real beer?’[/QUOTE]
I’m going to take a wild stab here and assume that what has been referred to as “Bladder Effect” is more commonly known as “Ballooning”. Below is from the SPE Bulletin Board. I offer it “as Is” with no commentaries. Hope it doesn’t add too much to the confusion.
[I]This question was asked in August on the SPE Drilling General Discussion discussion board, if you are an SPE member, you should be able to subscribe to this board with the following link.[/I]
[I]http://communities.spe.org/metadot/index.pl?iid=2494[/I]
[I]The answers were posted on the 20 and 24 August. I have attached them below. I like the comment in the last item.[/I]
[I]_____________________________________________________________________________________[/I]
[I]Date: Fri, 20 Aug 2004 10:15:47 +0000 (%z) [/I]
[I]Discussion: Drilling General Discussion[/I]
[I]2) Wellbore Ballooning [/I]
[I]3) Re: Wellbore Ballooning [/I]
[I]4) Re: Wellbore Ballooning [/I]
[I]Message 2: Wellbore Ballooning [/I]
[I]Date: 2004-08-19 18:57:58 [/I]
[I]------------------------------------------------------------------------ [/I]
[I]The fluid losses and gains associated with wellbore ballooning are most[/I]
[I]frequently caused by an active drilling induced hydraulic fracture. The [/I]
[I]hydraulic fracture is created and extended when the wellbore pressure [/I]
[I]exceeds the fracture pressure, and fluid forces the fracture creation [/I]
[I]and extension. Ballooning results when the circulating pressure is [/I]
[I]greater than fracture extension pressure, and the static well bore [/I]
[I]pressure is less than the fracture closure pressure. Therefore, when [/I]
[I]circulating, fluid extends the fracture and losses are observed, and [/I]
[I]when circulation is stopped the fracture closes and drilling fluid is [/I]
[I]returned to the annulus. [/I]
[I]The numbers here can be big or small; I have personally seen balloon [/I]
[I]losses and gains of several hundred barrels taking over an hour to flow [/I]
[I]back in the annulus. This can be an uneasy observation at the well [/I]
[I]location, but understanding the mechanism can prevent further wellbore [/I]
[I]damage created by hasty reaction to what is perceived as a well influx.[/I]
[I]In my experiences this condition can rarely be cured with anything [/I]
[I]except casing; however, it can be managed with good practices and [/I]
[I]certain lost circulation products. [/I]
[I]My recommendation is to do everything possible to avoid the scenario [/I]
[I]entirely with good wellbore pressure management planning and [/I]
[I]surveillance; however, if you find yourself in a reactive position I [/I]
[I]would quickly read SPE Papers, 74518, 67780, 78205 and 67742-4.[/I]
[I]Message 3: Re: Wellbore Ballooning [/I]
[I]Date: 2004-08-19 18:57:25 [/I]
[I]------------------------------------------------------------------------ [/I]
[I]HPHT ‘best practices’ evolved by one operator were as follows;[/I]
[I]Purpose: Determine whether flow during connections/flow checks is due to flow-back of mud lost when the pumps were on (ballooning), or a kick, and take appropriate measures.[/I]
[I]Procedure; [/I]
[I]If losses did not occur while drilling: [/I]
[I]- Flow is not lost mud flowback. [/I]
[I]- Treat as a kick, using standard well control procedures.[/I]
[I]If losses did occur while drilling: [/I]
[I]- Monitor rate of gain on trip tank. [/I]
[I]Worst case I have expereinced 60bbls lost per stand and 45-50bbl gain on connections.[/I]
[I]- Norm; If flow stops before a safe and manageable allowable volume of mud is bled (e.g., for Central North Sea HPHT wells, experience has shown recommended 5-10 bbl) [/I]
[I]- Flow is probably lost mud flowback. [/I]
[I]- Continue with normal operations.[/I]
[I]If flow does not stop after the allowable volume of mud is bled: [/I]
[I]- Shut-in well. [/I]
[I]- Measure initial SIDPP, SICP. [/I]
[I]- Open choke, and bleed fluid.[/I]
[I]If flow stops before the allowable volume of mud is bled: [/I]
[I]- make connection and continue drilling.[/I]
[I]The above flowbacks are best conducted on the trip tank or a small active system volume.[/I]
[I]it is prudent to get the mud logger to plot a volume gain versus time graph for each connection.[/I]
[I]This is termed a “connection footprint”. [/I]
[I]From this ‘best pratice’ drillers can thereby identify a normal balooning connection or a deteriorating loss or a immeidate gain thereby preventing an escalating well control situation occuring.[/I]
[I]Bottom line in ballooning (since you already most likely in a very limited pressure window) is to recognise, analyse and identify ‘losses and/or gains’ through accurate and continuous measurement so that abnormal losses and/or gains are detected and reacted to immediately.[/I]
[I]Message 4: Re: Wellbore Ballooning [/I]
[I]Date: 2004-08-19 18:56:59 [/I]
[I]------------------------------------------------------------------------ [/I]
[I]Herewith SPE paper considering wellbore balloning: SPE67781, SPE67780, SPE51182, SPE71368, SPE74517, SPE62770.[/I]
[I]______________________________________________________________________[/I]
[I]Date: Tue, 24 Aug 2004 10:11:58 +0000 (%z) [/I]
[I]Discussion: Drilling General Discussion[/I]
[I]1) Re: Wellbore Ballooning [/I]
[I]3) Wellbore Ballooning [/I]
[I]4) Re: Wellbore Ballooning[/I]
[I]Message 1: Re: Wellbore Ballooning [/I]
[I]Date: 2004-08-23 23:03:54 [/I]
[I]------------------------------------------------------------------------ [/I]
[I]One of the conditions of occurence of ballooning is alternate bands of shale and coal. Actually, at optimum circulating pressure the seam of the coal and shale opens-up and mud goes in. In static condition the mud comes back. [/I]
[I]Another related case may be alternate swelling shale and coal bands. In this case, mud will go to the slits between coal and shale. The mud can come back by shutting of the slit as well as by swelling of the shale (delayed vomiting). [/I]
[I]Thus stratigraphy can provide prognostics about ballooning behaviour. [/I]
[I]Message 3: Wellbore Ballooning [/I]
[I]Date: 2004-08-23 23:05:40 [/I]
[I]------------------------------------------------------------------------ [/I]
[I]I would also add SPE papers 78288 and 54592 to the recommended reading [/I]
[I]list. The experience of using pressure while drilling (PWD) tools [/I]
[I]downhole is described. [/I]
[I]Each wellbore has a certain elasticity and the effect of surge on the [/I]
[I]hole can be determined. The character of the pressure signature changes [/I]
[I]when the magnitude of the pressure surge exceeds the fracture gradient [/I]
[I]somewhere in the hole. The pressure signature when a wellbore is [/I]
[I]breathing resembles a “shark fin” with a sharp pressure rise and then a [/I]
[I]fall-off. The experience at Milne Point and elsewhere on the North [/I]
[I]Slope was that once a wellbore entered the breathing phase, it usually [/I]
[I]was not possible to exit it. In order to stay below the critical ECD, [/I]
[I]procedures were developed to take measurements of the ECD when the mud [/I]
[I]was “clean” and then monitor the changes as drilling proceeded. Great [/I]
[I]attention was paid to keeping the hole as clean as possible. Strict [/I]
[I]attention was also paid tripping and reaming. It was realized that it [/I]
[I]was most important to decrease the pump rate while reaming down due to [/I]
[I]the effective increase in flowrate and surge caused by pouring pipe into [/I]
[I]the hole. The use of effective drilling practices cannot be [/I]
[I]overemphasized. This includes circulating bottoms up at a reduced [/I]
[I]circulating rate after making a trip to remove dehydrated, heavier mud [/I]
[I]from the wellbore. At times completely new mud volumes needed to be [/I]
[I]circulated into the hole keep the ECDs within limits. Once the wellbore [/I]
[I]section is drilled, the same care with regard to mud “cleanliness” and [/I]
[I]minimizing surge needs to be employed when the casing is run. [/I]
[I]Engineered surge calculations were used to determine a safe running [/I]
[I]speed in order to remain below the critical ECD. In one particular well [/I]
[I]the recommended casing running speed at TD of over 19,000’ md with 7" [/I]
[I]casing in 8-1/2" hole was 4 minutes PER JOINT!!! If you have the [/I]
[I]option, hole sizes may be increased to give greater flow area as your [/I]
[I]hole sections get longer. In these cases, some wells were upsized to [/I]
[I]allow 9-7/8" production hole to be drilled with 7" casing still being set. [/I]
[I]Message 4: Re: Wellbore Ballooning [/I]
[I]Date: 2004-08-23 23:04:52 [/I]
[I]------------------------------------------------------------------------ [/I]
[I]Other contributors to your request have provided some excellent comments and guidance. [/I]
[I]Please exercise caution when diagnosing a ballooning problem. I see blowouts much too frequently resulting from large kicks initially diagnosed as a ballooning problem.[/I]
[I]Here is a good guideline. If you don’t initially lose mud as the first step in a ballooning scenario, then any gains thereafter are probably kicks.[/I]
[I]To All,[/I]
[I]Looking for some information on Ballooning Effect of Formation, our client is looking for some info. If somebody has information would appreciate the knowledge.[/I]
[I]Rgds[/I]
[QUOTE=27182;40448][I]Just have the rig crew fiddle with it until it comes out the way I want…Right?[/I]
Or with Guide’s boss, who was [B]on the rig himself.[/B]
…
I’m not holding my breath for either of those two (to testify), or Kaluza without someone starts passing out get-out-of-jail-free cards.[/QUOTE]
Kaluza has taken the “fifth” however he did say in his interview with the cost guard after the incident that his experience was mostly on land rigs and he was there to learn deep water drilling.
[QUOTE=Alf;40454] … dell is educating me on the “role playing” and “if the moon is made of blue cheese” antics of lawyers… so maybe those legal eagles in these investigations have a lot to do with what we “joe public” perceive?[/QUOTE]
Alf,
That’s just what they’re [B][I]all[/I][/B] trying to do at this point: ‘prepare the battlefield’, create a favorable climate for their particular story, get it in the public’s mind, perception, ‘conventional wisdom’ etc. That effort, at this point, is pretty frantic. Remember, you do [I][U]not[/U][/I] want an unbiased trier of fact (judge, jury, arbitrator, administrative law judge, whatever); you want one biased, or, at the very least, one predisposed in your favor.
[QUOTE=DDdon;40465]I’m going to take a wild stab here and assume that what has been referred to as “Bladder Effect” is more commonly known as “Ballooning”. Below is from the SPE Bulletin Board. I offer it “as Is” with no commentaries. Hope it doesn’t add too much to the confusion.
[I]2) Wellbore Ballooning [/I]
[/QUOTE]
Thanks for your input, but Wellbore Ballooning is something different to Bladder Effect , and relates to drilling in open hole sections.
Bladder Effect is mud hydrostatic from the riser affecting the annular/rams in the BOP from above.
[QUOTE=ExCompanyMan;40462]Tend to agree but still would like to get it confirmed with a simulation. Look, the BOP did not close in the well, and failed it main purpose, either because there was a leak and it did not receive the signal (unlikely) or because the casing moved up and prevented the rams from closing around the DP. Also remember that if there was a leak going up the annulus then hot reservoir fluids would be traveling up; so you would have cold sea fluid in the casing and hot reservoir fluid behind it; god knows the effect on the steel with that.
Just brain storming…[/QUOTE]
Remember also that at one point they dropped the drillpipe pressure to zero (not easy to interpret from the chart data we have. They could have also isolated the DP string readings!).
That would drop the hydrostatic below that DP by approx 2350psi ie +/-950psi more than they had “planned” for.
[QUOTE=Alf;40472]Thanks for your input, but Wellbore Ballooning is something different to Bladder Effect , and relates to drilling in open hole sections.
Bladder Effect is mud hydrostatic from the riser affecting the annular BOP.[/QUOTE]
I stand corrected… Thanks, Alf
BP did plan to test with 2350 psi differential. Because the test had 1400 on the drillpipe it was never a good test. If the drillpipe pressure came from the formation it was a failed test, and if it came from the leaking preventer it was not a 2350 psi test.
[QUOTE=berzx;40481]BP did plan to test with 2350 psi differential. Because the test had 1400 on the drillpipe it was never a good test. If the drillpipe pressure came from the formation it was a failed test, and if it came from the leaking preventer it was not a 2350 psi test.[/QUOTE]
You’re right about the 2350psi. My mistake. I forgot to look back and read.
[QUOTE=27182;40464]
Now [B][I]with regard to the BOP, there are two pieces of DP in it[/I][/B], as I already said in a post to you on Page 202. [I][B]There may also be a casing in the bottom half[/B][/I]. One more thing about the BOP. They didn’t try to activate it (the shear rams, EDS) until after loss of (hydraulic) power on the rig. [I][B]That left only what was stored in the accumulator[/B][/I]. It obviously wasn’t enough.[/QUOTE]
They hot-stabbed it with the ROV, but I (we?) don’t know if that ROV really had the capability of supplying enough flowrate and pressure at that time. (They are usually low flowrate)
… and as you point out there could be a lot of junk in the BOP bore.