[ROCKMAN]

Shorty - Your numbers seem to confirm my suspicions. I haven't seen anything about pressure maintenance via reinjecting the NG. Recycling NG production was proven decades ago to be the best way to max URR from such reservoirs. Maybe with so much capex sunk they got cheap. But as you say the proven models would have told them this was the way to go when they tested the discovery wells all those years ago. This is shaping up as one of the worst reservoir engineering f-ups I've ever seen. And I've seen my share. LOL.

[rockdoc123]

seems to be some jumping to conclusions here that aren't warranted from the little bit of information available out there. Karachaganak is gas condensate but it is much more likely that Kashagan is volatile oil based on it's API (around 40) and the fact they have been saying oil rather than condensate in all reports from the companies involved. Volatile oil and Gas condensate behave completely different under reservoir depletion. Pressure maintenance is suggested in both but the end result of lowered pressure is different simply because of the different location of dew point on the solidus curve.

Also I noted from digging around a bit that it isn't corrosion per say that is causing the problem with the pipelines but rather stress corrosion cracking, which is completely different. Stress corrosion cracking is often related to the presence of water and the strength of the steel. Simple corrosion is easy to plan for, stress corrosion cracking less so. You can have stress corrosion cracking occurring in pipe that seems to be completely free of any normal corrosion.

[shortonoil]

Rockman said:
"This is shaping up as one of the worst reservoir engineering f-ups I've ever seen. And I've seen my share. LOL."

Now, don't be too hard on them. When this field was first investigated condensate reservoir modelling was still in its infancy compared to today. I see it like swimming in a vortex, once you get $10 - $20 billion in it, you can't get out!

rockman123 said:
Also I noted from digging around a bit that it isn't corrosion per say that is causing the problem with the pipelines but rather stress corrosion cracking,

Could be, but the problem with that appraisal is that it seems too simple. Stress cracking is usually associated with martensite production, and any mechanical engineer worth $0.15 per day would see that immediately. Solving that problem is just a matter of changing the material specs for the steel used in the pipe. Considering how much they've got invested in this mud hole they could have lain pipe all the way to the moon - and back, by now. I think Rock has the better take on the problem. With this kind of money at stake, above ground problems are going to get fixed. Below ground, not so easy, especially if you f--k'd up with initial reservoir modeling design.

http://www.thehillsgroup.org

[ROCKMAN]

shorty - “When this field was first investigated condensate reservoir modeling was still in its infancy compared to today." I don't know: when I was working for Amerada Hess about 35 years ago I worked on such a big reservoir in La state waters and they were doing a fine job of re-injecting the NG. Might not have had a good model back then but they knew how so seperate out the liquids and inject the NG.

But doc is right: without the details we're just guessing what’s going on. But given the monies and manpower involved such problems should not have developed IMHO. It’s not as though it were a marginal property and they couldn’t justify hiring the best in the world.

[shortonoil]

Rockman said

I don't know: when I was working for Amerada Hess about 35 years ago I worked on such a big reservoir in La state waters and they were doing a fine jobjob of re-injecting the NG.

Rock you're talking about the stone age of reservoir simulation. The ECLIPSE 300 reservoir simulator can tell you how many hairs can grow on a barrel of field condensate! The stuff that Schlumberger has put together in the last few years makes ECLIPSE look like ancient history. This technology has come a long, long way in the last 10 years.

If Karachaganak turns out to be a 500,000 b/d field, from an expected 2 mb/d field we are never going to get the details; especially if it can be linked back to something like initially poor reservoir simulation. Kashagan has invested too much political capital into projecting the image that they were to be the next Saudi Arabia. You of anybody should know that in extractive resources you don't count your chickens before they hatch. Those baby chicks are as just as likely to turn out to be Goonie Birds, as chickens. I've seen a lot of outfits over the years spend a lot of money to find out that there was nothing there~

http://www.thehillsgroup.org
.

[rockdoc123]

Just to clarify a few things.

As to what the problem is/might be the latest press information is still speaking of the problem being related to pipelines and not downhole casing corrosion/formation damage/phase changes etc.

http://www.reuters.com/article/2014/04/02/oil-kashagan-idUSL5N0MP4G820140402

Some snippets worth noting:

Oil company investigators have yet to announce conclusions about what went wrong at Kashagan in October, when onshore pipes carrying corrosive gases sprang leaks and brought offshore production in the Caspian Sea to a halt a month after start-up.

It has now emerged that sulphur-laden sour gas burped out from the oil field during production last year may have weakened long stretches of processing pipelines, two sources said.
"The problem goes on for kilometre after kilometre, it's a systemic problem," an industry source briefed by Kashagan engineers told Reuters.
That defective stretch of pipeline runs mainly through hard-to-reach swampy terrain, making intervention costly and difficult.

The consortium said only that toxic gas lay behind the problem. "Sulphur stress cracking was identified as the root cause of the pipeline issues," the spokesman said. "This process occurs if steel of high hardness is exposed to high concentrations of H2S (hydrogen sulphide) under high pressure in the presence of water," the spokesman said.
"This mechanism is not at all related to normal corrosion (formation of rust) but solely to the hardness of the steel".

And as to the issue of potential “retrograde condensate” dropout in the field, as I mentioned this is not a gas/condensate pool but rather an undersaturated very light /volatile oil and gas field. There are a number of papers that have alluded to this :

Ybray, D., Galiyeva, G., & Ibragimov, F. (2011, January 1). Raw Gas Injection Principles And Challenges In Kashagan Fields. Offshore Mediterranean Conference.

The reservoir fluid is a 43 °API light oil, with a GOR of about 2,850 scf/stb, mostly stored in the first medium. Notably, high sour gas content (16% H2S, 4% CO2) imply relevant HSE challenges for field management.

Albertini, C., Greta, L., Calabrese, M., Bado, L., Francesconi, A., & Tarantini, V. (2013, June 10). Kashagan Field Approaching Production Start-Up: Insight Into Reservoir Characteristics. Society of Petroleum Engineers. doi:10.2118/164831-MS

The Kashagan field is a deep, over pressured (initial reservoir pressure: 783 bar), isolated, carbonate build-up with a high-permeability, karstified and fractured rim and relatively low- permeability, stratified, platform interior. The field contains a 43-degree API light oil, with 15% H2S and 5% CO2, and contains more than 100 Tcf of associated gas.
One of the biggest challenges of the Kashagan field development is the management of huge volumes of highly sour associated gas. The consortium had essentially two options to address this challenge:
• A commercially unattractive, but technically not challenging, conventional choice of evacuating the sour gas to shore for treatment (H2S and CO2 removal) and sales; or
• A technically very challenging, but potentially economically beneficial, alternative of injecting the raw sour gas back into the reservoir.
This injection alternative, with its high discharge pressures and sour service, would extend the current capabilities of existing gas compression technologies. Nonetheless, it had the potential to significantly enhance oil recovery, as the Kashagan oil and injected gas are first contact miscible at pressures well below the initial reservoir pressure.

Akhmedzhanov, T.K., 2012. Chemical properties of reservoirs, oil and gas of Kashagan field, souther part of Pre-Caspian depression, Kazakhstan. Int. J. Chem. Sci.,10(1).. pp 568-578

The initial reservoir pressure (Р res init) exceeds the saturation pressure (Рs) by 50 МPа which ensures long-lasting stable production of the field

So the immediate issue is the pipeline leaks that are possibly a result of extreme temperature conditions coupled with coatings having deteriorated and perhaps some corners being cut in terms of steel specs.

Fluid phase changes either in the well bore or in the reservoir do not seem to be of concern based on the description of the oil. In fact with a volatile oil that is miscible reinjecting the gas ends up as a gas recycling/liquid stripping exercise that can increase overall oil recovery. The main issue at a reservoir level has to do with the variable reservoir properties. Kashagan is a huge ancient atoll reef where the rim is kharsted and fractured and the interior has reasonable vuggy porosity (good storage capacity) but limited permeability. This will impact overall recovery and demands some attention paid to dealing with the tighter reservoir compartments. When you are trying to direct gas injection this is always challenging as gas bypassing tends to be common.

[shortonoil]

And as to the issue of potential “retrograde condensate” dropout in the field, as I mentioned this is not a gas/condensate pool but rather an undersaturated very light /volatile oil and gas field. There are a number of papers that have alluded to this :


I think you are confusing Kazakhstan's two major fields, Karachaganak and Kashagan. In Eni's presentation they specifically refer to Karachaganak as a Super Giant Oil & Gas Condensate Field: page 10,

https://www.eni.com/en_IT/attachments/i ... AVANNA.pdf

Karachaganak is the larger of the two fields, and is off shore field; Kashagan is onshore. On page 33 they have a comparsion of the two fields. Karachaganak has over three times the sulfur content of Kashagan

Your reference by Albertini, C., Greta, L., Calabrese, M., Bado, L., Francesconi, A., & Tarantini, V where they state:


This injection alternative, with its high discharge pressures and sour service, would extend the current capabilities of existing gas compression technologies.

is flatly wrong. Eni has been using re-injection since day one on the project (page 13). 783 bar is 11,663 psi. and both Garder Denver, and HiP have been building 20,000+ psi compressor units for almost five decades. I was using 100,000+ psi water injection systems in the 80's for stone fabrication.

So the immediate issue is the pipeline leaks that are possibly a result of extreme temperature conditions coupled with coatings having deteriorated and perhaps some corners being cut in terms of steel specs.

The effects of sulfur on steel are certainly well documented:

http://www.metallurgvanadium.com/sulfurpage.html

Other considerations are also important, however. High sulfur contents are known to increase corrosion rates in certain environments. They promote stress corrosion cracking and hydrogen induced cracking, possibly, through electrochemical or "poisoning" effects


Airplane manufactures use ultra low sulfur alloys explicitly because sulfur increases the brittleness of steels. Steel's absorption of sulfur in high hydrogen, carbon dioxide environments is a well known phenomena. It would be expected that in an environment, such as Kazakhstan presents, that this would be closely monitored. Sulfur content is usually measured through high frequency infrared absorption. This was obviously a failure on the part of the project's engineering staff. It is not, however, the primary reason why the project after seven years is $20 billion over budget, and almost 1 mb/d behind schedule!

A look at a PVT curve using Karachaganak's temperature, pressure characteristics supports the determination that it is a rich gas condensate field. It is undoubtedly one of the largest in the world. Although its smaller onshore neighbor, Kashagan, has had some pipeline problems recently they are only marginally related to the projects overall under performance. If Kazakhstan is to become a world class producer it will have to overcome some major problems; those problems can be found in the production of its princpal field, Karachaganak. We strongly believe that those problems lie in the morphology of the field.


http://www.thehillsgroup.org/

[rockdoc123]

I think you are confusing Kazakhstan's two major fields, Karachaganak and Kashagan. I

no someone else was. My point is that Kashagan (the title of the thread) is not going to have problems with liquid dropout in the reservoir as was suggested by another poster.

Airplane manufactures use ultra low sulfur alloys explicitly because sulfur increases the brittleness of steels. Steel's absorption of sulfur in high hydrogen, carbon dioxide environments is a well known phenomena. It would be expected that in an environment, such as Kazakhstan presents, that this would be closely monitored. Sulfur content is usually measured through high frequency infrared absorption. This was obviously a failure on the part of the project's engineering staff. It is not, however, the primary reason why the project after seven years is $20 billion over budget, and almost 1 mb/d behind schedule!

the point made by the operator is that it is stress corrosion cracking that is causing the problem not simple H2S corrosion. The two processes are different. The operator no doubt designed the pipe specs to deal with high H2S ......anticipating stress corrosion is another thing altogether.

[ROCKMAN]

Paris...we have a problem

Reuters - French major Total said no oil production was to be expected from the troubled Kashagan project in Kazakhstan this year and it was not likely to yield much next year either. "What is clear is that no production can be expected in 2014, and in 2015 ... it will be probably little," head of exploration and production told a conference on Tuesday. Production at the offshore deposit, the world's biggest oil find in 35 years, started in September but was halted in early October after the detection of gas leaks in the $50 billion project's pipeline network.

[sparky]

.
Kashagan problems are not technical , it's an administrative cluster f..k
the consortium include some big majors including Eni , Royal Dutch Shell , ConocoPhillips and Exxon Mobil Corp.
the government was in the North Caspian Operating ,
the oil was to be exported to China , as per signed agreement

It was decided to get the Italians ENI to be project head, AGIP is an adviser partner for the Kazakhstan gov
17 years later with a bill between 50 and 100 Billions !!!! stil no oil

ENI actually did a pretty good job in a complex and politically difficult project
they claim not to understand how the pipes came to crack

the Hydrogen sulfide create stress corrosion ,in particular , pipe welds must be passivated by heating
any stress in the steel is going to corrode , mild steel grades are much better ,
high grade steel corrode like candy ,
the accepted standards are the NACE MR 0175 ,
I was working with the previous edition when building gas separators ,
the whole industry know about H2S , it's the normal to have some often a lot of it
the gas is a bastard , it stinks , crack pipe half an inch thick , is explosive , is poisonous in small dose
and burn your nose sensors so that if you do not smell it , there is a good chance there is a lot of it
and you are in danger

for a long time it was burned at the stack , making a beautiful blue flame ,
but it was hell on the environment downwind

[ROCKMAN]

Sparky - That's a point I was trying to make before. You apparently know about H2S. I know enough to not suck it in. But the industry knew all it needed about dealing with it for decades. Billions of bbls of sour oil/NG have been produced all around the world. Given the massive budget of this project they could put the 50 most H2S experienced engineers on the planet on retainer for the entire term of the project. IMHO it has to go well beyond incompetence. I can only explain it by massive/widespread corruption. If it ever gets reported I suspect we'll hear about bodies dropping soon...if they haven't already. Too many folks probably know where the graft went given the scale of the thievery.

[sparky]

.
I don't know what happened
a wild guess , a cheap contract on the pipe laying with poor quality control
the local temperature variance is huge , it goes from 40Dg C to minus 30 easily
could it be an issue , I don't know , just a guess

[rockdoc123]

the local temperature variance is huge , it goes from 40Dg C to minus 30 easily
could it be an issue , I don't know , just a guess

up thread I reported that the operator is saying it is stress corrosion cracking which is only marginally related to high H2S. I suspect the pipeline specs are right where they need to be with respect to H2S grade. The environment you speak of is significant. Stress corrosion cracking is known to be exacerbated in areas where the pipeline is subject to loading and unloading. The microfailure is in tension which fits perfectly with the idea of frost heaving in the subsurface.

[ROCKMAN]

They know the proper specs for metal used in the space shuttle, submarines, North Slope production equipment and nuclear plants. They knew exactly what specs were required at Kashagan. And they didn't use the proper material. Why? I don't know. But the requirements would be well understood by any competent engineer.

[rockdoc123]

They know the proper specs for metal used in the space shuttle, submarines, North Slope production equipment and nuclear plants. They knew exactly what specs were required at Kashagan. And they didn't use the proper material. Why? I don't know. But the requirements would be well understood by any competent engineer.

I think you are confusing H2S grade specs (which undoubtedly were met) with stress corrosion cracking which can occur in the presence or without high H2S. The hydrogen helps but you need tensile stress in the system. My understanding is it is very hard to anticipate this issue whereas with regular high H2S corrosion it is somewhat predictable. Solutions to avoid stress corrosion cracking are special coatings for the pipe or using very high tensile strength steel as far as I am aware.

My experience is the tendency these days in big projects is to not over engineer facilities (i.e. zero risk of failure) but get to that point where it is still low risk but more cost beneficial. In the good old days it was more common to engineer to avoid any chance whatsoever of failure. Unfortunately this made many projects uneconomic and the industry gradually seemed to move to accepting a bit more risk (with the exception of potential high impacts).

[Graeme]

Further blow for $50bn Kashagan oil project

The $50bn Kashagan oil project in Kazakhstan is likely to be delayed by two more years while 200km of pipeline is replaced, in a further blow for the companies developing the largest oilfield outside the Middle East.

Erbolat Dossayev, Kazakhstan’s minister for economy and budget planning, told the FT that he expected production to start at the end of next year at the earliest – but that it could be delayed until 2016.

FT

[sparky]

.
up in the blue yonder of speculation ,
the pipes and specs might be right
but if they used the wrong electrodes for welding they would be up the creek
sharp end engineering doesn't take prisoners ,
it's the law of the smallest stuff up with the largest cost
on the North sea Frigg field , there is a platform footing two hundred feet tall
build in Nantes in a shipyard at great costs , towed for five hundred miles and sunk two miles from it's proper position
because someone miscalculated the crushing pressure of temporary flotation tanks
it is now a resting place for seagulls and a hazard to navigation !

in the oil industry , the jackpot can be huge ,the stuff up totally breathtaking

[ROCKMAN]

Doc - No...not confusing specs. The required specs (regardless of their nature) weren't unknown. Not like this is the first time such a field has been developed in a harsh environment. As you say some companies take risks by under engineering a project to save money. In my experience more money is lost net then saved by that approach. And that's not monetizing injuries and deaths. Me and my engineer always over engineer our projects. And even that doesn't guarantee no failures. Just consider the loss in net present value of a two year delay let alone the interest on any borrowed caped.

[rockdoc123]

the issue with over engineering is really only pertinent to very large projects. Here I am talking about billions of dollars of investment not millions.
spending 10% more to insure no possibility of failure on a $25 MM pipeline project is a lot different than the same extra 10% spent on a billion dollar pipeline project. The first case the extra 10% is worth the comfort whereas in the second case most would look at risk reward analysis.

[dolanbaker]

My experience is the tendency these days in big projects is to not over engineer facilities (i.e. zero risk of failure) but get to that point where it is still low risk but more cost beneficial. In the good old days it was more common to engineer to avoid any chance whatsoever of failure. Unfortunately this made many projects uneconomic and the industry gradually seemed to move to accepting a bit more risk (with the exception of potential high impacts).

The Isambard Kingdom Brunel school of engineering, over engineer it to the point that it would need demolishing when it's finished with!