Troubled Kazakhstan Project Shows The Value Of U.S. Shale Oil

There’s nothing like seeing a big shot fall on hard times to make you appreciate what you have. That’s why American oilmen read news of Kazakstan’s Kashagan project with a strange mix of angst and glee.

Kashagan has been a nightmare for some of the biggest of Big Oil. Its polyglot mix of Kazakh (KazmunaiGaz), Italian (Eni), American (Exxon Mobil XOM -0.02%), Anglo-Dutch (Royal Dutch Shell ), Chinese (CNPC) and French (Total TOT +0.02%) partners have sunk more than $50 billion into the Caspian Sea field over the past 20 years — at least $30 billion more than they initially expected. First oil was supposed to start flowing back in 2005, back before America’s tight oil boom was even conceived. After delays on delays, final deadlines were pushed out to late last year. Then some gas pipelines sprung leaks. Maybe sustained oil flows will kick in by the end of this year. Maybe not.

Indeed, compared with the Kashagan nightmare, America’s burgeoning tight oil fields like the Bakken, Eagle Ford and Permian are a technicolor dream. Here drilling costs average less than $10 million per well. With oil flowing out of each new well at a rate of about 750 barrels per day in the first year, the drillers can pay back their development costs in less than 18 months. And the rest is gravy. These economics of American tight oil have spurred enough drilling to boost domestic petroleum production by 3 million barrels per day in five years.

Kashagan. AP Photo/North Caspian Operating Company, File

There’s been plenty of justified handwringing over the environmental impact of drilling and fracking. Oil spills and train derailments should not happen. But at least most of America’s tight oil is “light and sweet,” meaning that drillers won’t have to contend with Kashagan’s toxic reservoir gas contaminated with such high levels of hydrogen sulfide that it ate through steel pipelines almost immediately.

The Kazakh government has sued the consortium over this last set of delays, fined them $735 million, and may refuse to put up its share of cash for further construction. The government has done this before, and extracted a bigger share of equity in settling the disputes. There’s many more sordid details, so if you haven’t already, be sure to read the WSJ’s story yesterday on the Kashagan debacle.

The $50 billion spent on Kashagan so far is only for the first 400,000 bpd phase. At that rate (and at a price of $100 per barrel) it would take more than 5 years for the partners just to pay for construction, let alone generate royalties for Kazakhstan or a return on investment. Will the partners have the stomach to boost output to 1.5 million bpd?

Only if they aren’t sitting on better opportunities in the United States. Thanks to the increasing efficiency and precision of horizontal drilling, oil companies have decades of wells to drill in the United States. With good economics, solid property rights, a skilled workforce and far less geopolitical landmines to navigate, the U.S. has already been the destination for $200 billion a year in oil and gas investment in recent years, and will continue to be for many more to come.

Forbes

29 Comments on "Troubled Kazakhstan Project Shows The Value Of U.S. Shale Oil"

rockman on Fri, 4th Apr 2014 11:33 am 



Just MHO – First: “America’s burgeoning tight oil fields like the Bakken, Eagle Ford and Permian are a technicolor dream.” Unlike Kashagan the Bakken, EFS and Permian Basin are not fields…they are trends. So if one wishes to make a comparison those trend should be compared the ME oil trends and not just one of the fields in that trend.

Second, there is no comparison between those trends and Kashagan Field on any basis. I’m not sure where to start to highlight the absurdity of this comparison so I won’t. If anyone can’t see the obvious propaganda effort here there’s nothing I can say to change that view. Kashagan Field will be produce hundreds of million bbls of oil long after ever existing Bakken and EFS wells drilled to date and for the next 20 years falls to stripper status…less than 10 bopd.

Makati1 on Fri, 4th Apr 2014 12:33 pm 



Forbes … Capitalism’s cheer leader where facts never get in the way of hype.

I wonder what all of those Wall Street Casino dealers will do when their jobs become obsolete in the near future?

Davy, Hermann, MO on Fri, 4th Apr 2014 12:38 pm 



Agreed Rock! These folk should just shut up. I am not exactly sure why we get so many articles with such a lack of substance. These articles are mainly lobbyist driven to influence opinion. What they end up doing is distorting the true picture and further distort investment decision by a market already promoting bad investments globally. The oil industry is not the only area we are seeing faulty marketing and lobby efforts.

rockman on Fri, 4th Apr 2014 12:48 pm 



Davy – I don’t have anything against industry lobbyists per se. Heck…I’m probably one of the biggest oil patch lobbyist on this site. But there no lack of honest and compelling points to make that I just don’t understand why so many have to resort to such BS. Sometimes I just want to shout at them: “For the love of Dog…please stop trying to help us”. LOL.

Davey on Fri, 4th Apr 2014 1:02 pm 



Agreed Rock, lobbyist market and that is part of capitalism. It is a pity there are so many truely worthless articles put out by lobby groups. It may be that standards are tanking due to a society wide tank in integrity and competence.

Arthur on Fri, 4th Apr 2014 1:33 pm 



the U.S. has already been the destination for $200 billion a year in oil and gas investment in recent years, and will continue to be for many more to come.

There are of course alternatives. In Holland we are bombarded with adds like these on a daily basis:

https://www.youtube.com/watch?v=w4m8HAuQyi8

You can roughly equate $1 million with 1 MW peak wind power (excluding installation and maintenance). $200 billion per year is 200 GW wind power per freakin year!

The US currently produces 1400 GW:

energyliteracy . com/wp-content/uploads/2009/09/electricityproductionhistorical.png

bobinget on Fri, 4th Apr 2014 2:12 pm 



While it’s not explicitly mentioned, North Dakota is
a great deal safer place to invest then Kazakistan.

OTOH, if ‘Big oil’ did not invest in the last ‘elephant fields’ they would have nothing to sell. As rockman points out, shale arithmetic doesn’t come close to meeting world petroleum requirements. (95 M B p/d)

Just one GOM offshore platform, Thunder Horse, is/was able to produce 200,000 B p/d. That’s one fifth of all shale total production. Between XOM and BP there are several such wells in the Gulf. Forbes is trying to deflect the fact that most of these elephant fields in the US and Mexico peaked years ago.

Everyone of the companies mentioned would have to pay the same amounts in taxes were they not building
this monster project.

In Canada a well producing 600 B p/d is cause for celebration. For ‘Big Oil’ 600 B won’t pay helicopter
and private jet expenses.

Boat on Fri, 4th Apr 2014 2:38 pm 



Maybe the author is trying to convey the fact the American worker is so much better and can deliver in a much worse environment. Quality of work, more adaptable, more innovative, and usually using the state of the art technology which they developed. If there were nothing but American companies and workers in Kashagan i expect the results would be much better.

Pops on Fri, 4th Apr 2014 2:54 pm 



Half the world’s oil rigs are working in 14 counties in the US.

Davy, Hermann, MO on Fri, 4th Apr 2014 3:14 pm 



Damn, Pops, that is amazing.

Pops on Fri, 4th Apr 2014 4:08 pm 



It puts the fracking miracle in perspective I think. I looked and the actual number for March was

1809 of 3,448 rotary rigs are in the US
1,487 targeting oil, 1,424 horizontal or directional

So not quite half but good enough for blog work, LOL

Northwest Resident on Fri, 4th Apr 2014 4:35 pm 



“Half the world’s oil rigs are working in 14 counties in the US.”

They are pumping fevereshly as if there were no tomorrow.

Davey on Fri, 4th Apr 2014 4:49 pm 



You have to admit when the Americans set their mind to something shit happins!!!

Pops on Fri, 4th Apr 2014 5:07 pm 



I think it’s more a case of they are drilling as if there were no tomorrow…
Because there really isn’t – they have no where else to go or they’d go there.

If they could drill one cheap vertical hole that would flow 5mbopd for 20 years instead of <1mbopd for 20 days (+/-I30 barrels per day Bakken average for all wells) I kinda think they’d do it.

Who said ‘It’s retirement party up there!’?

Northwest Resident on Fri, 4th Apr 2014 5:16 pm 



“I think it’s more a case of they are drilling as if there were no tomorrow…”

Yeah — great point! They WISH they were pumping feverishly. But instead, they are drilling feverishly. Big, huge difference.

shortonoil on Fri, 4th Apr 2014 5:33 pm 



“With oil flowing out of each new well at a rate of about 750 barrels per day in the first year”

Apparently Forbes journalists don’t read the same production reports that everyone else does. According to IHS data, the average Bakken well produces 470/d barrels for the first month, which then falls to 46 b/d within five years. But why let a few little facts get in the way of a good article?

But Kazakhstan is a nightmare in waiting. It is on a lake that is frozen over six months out of the year, and it is the dirtiest muddle hole on the planet; the H2S ratio is 15%. The sulfur content is so high that drilling crews wear Hazmat suits. The sulfur content is so extreme that direct exposure to the gas can cause death instantly. The folks in ND thought things were tough this winter, freezing to death is nothing compared to having your lungs burnt out in 10 seconds.

Ten years ago I was predicting that Kazakhstan would never come to full production, while the media was hyping that it was the next great field that was going to save the world! Of course, things always look better from a 16th story New York high rise than they do in the field. But it is interesting that they would use their last prophetic miracle to show how great the next one is going to be. If the shale industry thinks it is necessary to put out the bucks to buy Forbes, things might not be too great in “miracle shale land”.

Bob Kraus on Fri, 4th Apr 2014 5:58 pm 



The Forbes piece is awful. But at least they referenced the very fine recent Kazakhstan article in the WSJ. Whatever you think of WSJ’s editorial views, they turn out some great jounalism–and very important oil stories. A few years ago they did an amazing feature on the truly horrific challenges facing the workers, engineers and oil companies in the Kashagan project. It was grim, gritty and prophetic.

Boat on Fri, 4th Apr 2014 5:58 pm 



Davey
You have to admit when the Americans set their mind to something shit happins!!!

I think your right. This is a little off topic but I think Mexico will be next. Lots of Eagle Ford close to the Houston area refineries. Pipeline to connect will be much easier politically than tar sands from Canada. And awesome wind potential running right through the backbone of Mexico. Does Mexico have sun potential? I think so.
Because of the close proximity of Mexico to US technology and infrastructure I would bet that within 20 years we will be amazed that Mexico is doing so much better. It will all start with their decision to open up capitalism in their oil fields.
Mexico get nat gas at the same cheap price the US and Canada does. As long as this holds its a win win for the continent.

Nony on Fri, 4th Apr 2014 6:53 pm 



What could go wrong with 5 partners, central Asians, and Italian management? Oh…not to mention H2S and freezing lacustrian extraction?

Shell (damned two-headed cyborg) would have been better off just shutting up, investing their money, and letting Exxon run the whole thing.

I am reading through Yergin’s The Quest (quite good by the way). Interstingly, he covers that ‘stans towards the beginning. Kashagan called at as a big CF. For all that you people* hate him, he really gives an awesome overview…he writes on large topics and has command of sources primary and secondary. Most of the book is not about shale or peak or any of that…and a lot of it is outside the US (makes sense, that’s where the bulk of the oil is).

Can someone direct me to online (or offline) definition of “field” as opposed to “trend”. I do sometimes hear different parts of the Bakken referred to as “fields”. But then the resource is actually continuous and USGS just refers to it as a continuous accumulation area.

*said with a Ross Perot tone 😉

Nony on Fri, 4th Apr 2014 7:00 pm 



Rock:

Conoco Phillips was sure happy to sell their equity in the project…

Oh…and maybe the reason the 100s of millions of barrels will come out later from Kashagan is because they are so behind on getting the project done. 😉

rockman on Fri, 4th Apr 2014 8:52 pm 



Nony – the general definition of a trend is a collection of different reservoirs (“fields”) producing from similar rocks with a similar hydrocarbon origin and migration history. And this is where it gets complicated because of the way different regulatory agencies define “fields”. I can have the same 4 way structural closure that might have 3 different intervals of different rocks layered on top of that structure. In Texas each layer (reservoir) might be labeled with a different field name. Yes: there can be a different “field” that may share some of the same surface area as an Eagle Ford “field” that has a different “field” name then the EFS “field”. It can get even more confusing: I might drill a nice Eagle Ford hz well on my lease and submit it to the state as the Rockman Field. You drill a well just on the other side of the lease and you register in with the state as the Nony Field. The two wells may be draining the same fractures. Or draining two different set of fractures that are completely isolated from each other. So in this case the field designation isn’t even based on reservoir continuity. Last time I looked there were about 15+ different “fields” (as designated by the Texas rail Road Commission) producing from the Eagle Ford Shale formation…and all falling within what someone circles on a map and labels the Eagle Ford Shale trend.

In essence a field is the extent of a reservoir from which hydrocarbons can be produced. Field A drills wells to the lateral limit at which point there are no hydrocarbons present in the reservoir rock. But then you drill a well about 2,000’ away and find that same rock with hydrocarbons in it and know you’ve found B Field. But now you see the problem with defining fields in a fractured shale reservoir. You might drill 20 wells in a straight line and produce hydrocarbons from every one of them. And some of the are draining the same fractures as an offset well and others aren’t. Even worse it’s unlikely you’ll know the difference until you’ve produced the wells for many months. But it’s too late then because you had to designate a field name before you began producing.

And the naming is not a trivial matter. In Texas well spacing, unit sizes and production rates are determined by, guess what, the FIELD RULES. If your wells are classified as being in Field A yuo have to adhere to those field rules. But the next field over, Field B, is producing from the same reservoir rock and you have to comply with the Field B field rules.

And don’t even try to understand how it works in La. They don’t really have “fields” from a regulatory stand point. They have “producing units”. My well may be labeled in the Napoleonville Field but according to the great state of La. it is the CR IIIV RA SUA, Smith Well No. 1. Rolls right off the tongue, eh? LOL. But that is a deadly serious designation upon which the distribution of tens or perhaps hundreds of $millions will be determined. The spatial extent of such “fields” is determined by state committees dealing with many lawyers, engineers and geologists representing all the companies and mineral owners involved. And it has an extremely detailed legal description of the extent of the unit. there are consulting companies in Baton Rouge that specialize in this area and that’s all they do. And are very well paid for it.

And that just how it’s done in these two states. Each state has its own set of rules as to how a “field” is defined.

Nony on Fri, 4th Apr 2014 11:20 pm 



(I realize this is off topic, but I have nowhere else to ask it.) Also, I’m sure the answer is “it depends” as well as “varies by state”. But I’m looking more for the stereotypical general pattern.

1. When a oil company landsman buys the acreage rights, does he just acquire oil/gas rights or all minerals (diamonds, gold, coal, etc?)

1.5. If the answer is “all minerals”, how often do they find other valuable things (do they look at the rocks as they go down?) Or are valuable ores only worth getting if very close to surface? And if they find diamonds or gold on the way down, do they extract that or just sell it off?

2. Does he buy all the oil by depth? E.g. in the Permian, all the different layers of the wedding cake?

3. How do they deal with a section or unit or whatever having multiple owners? Let’s say the state wants to permit by square mile. But there’s like 10 different 64 acre owners (or even 2560 different 1/4 acre owners)? Can one guy hold out and screw the development up or are they compelled to sell…and how does that work?

4. Let’s say I buy a whole square mile of rights. How does the pad space and access work? Do I have a separate transaction to pay for that or does that just get thrown in because the seller wants the thing developed anyway? And is there some negotiation on location (not screwing up my best deer blind or the like)?

Stilgar Wilcox on Fri, 4th Apr 2014 11:22 pm 



Hey guys, I know this is off topic but you’ve got to see this linked video of Bison running down a road away from Yellowstone. There was a 4.8 earthquake, the largest in 20 years. Was it the earthquake or is it the caldera? You make the call.

https://www.youtube.com/watch?v=RiexHmbJlp4

rockman on Sat, 5th Apr 2014 12:52 am 



Nony – First let’s make the distinction between “buying” minerals rights and “leasing” mineral rights. When buy you own them until you sell them. Very expensive compared to leasing. Like real estate depends on the local demand. Can sell for 10X to 30X what a lease will cost.

Leasing: details can be as simple or complex as you like. Lease bonus: paid up front. A few hundred $ per acre or $thousands. Royalty: your share of any production: 1/8 to 1/4 is common. Off the top…no deduction for expenses. But you pay your own production taxes. Term: 1 year to 5 years typical. Lease expires at term unless producing commercial value of oil/NG at that time. Then lease is perpetual as long as producing. Some times on anniversary you’re paid a rental of $X per acre if no well drilled by then.

There’s no such thing as a standard lease. You can lease oil, NG, coal, water, iron ore, etc. You lease what you agree to lease in the lease form. It’s a contract like any other contract: you decide what to include or not include.

Same with depth rights: you can lease from 1,000′ to 1,200′ or from the surface to the center of the earth. That’s between you and the company.

You can require a fixed surface damage fee if the well is drilled on your lease. Or you can restrict access to X’ away from your house or no drilling on your property at all. Your lease could be put into a larger drilling unit where the well is drilled on someone else’s property. But let’s say your acreage makes up only 10% of that drilling unit you only get 10% of your royalty: you have 25% royalty: 25% x 10% = you get 2.5% of the wells production.

Deer hunting: big business in Texas. Can sell you deer hunting rights on your land for tens of $thousands per year. And you can try negotiating a no access clause for drilling ops during hunting season.

There is only one rule regarding leasing you oil/NG rights: there are no rules. Everything is negotiable. But I have seen landowners negotiate themselves out of hundreds of $thousands to $millions: companies will work with you so long before they close the door and walk away.

Arthur on Sat, 5th Apr 2014 7:55 am 



“Half the world’s oil rigs are working in 14 counties in the US.”

Must be bobinget’s 600 B/day field-lets.

shortonoil on Sat, 5th Apr 2014 3:39 pm 



Rock this varies by state, and sometimes by county. In West Virginia you can own the mineral rights, or the surface rights, or both. I’ve got 152 acres in Barbara County. Consol bought all the mineral rights except for 7 acres back in the 20’s for $2/ acres. We own the surface rights on 145 acres, and the mineral, and surface rights on the seven acres. We get an offer from them every year to sell the mineral rights on the seven acres. It’s the best bottom land on the whole parcel so we don’t sell.

In Vermont, I’ve got leases, mineral rights, and surface rights. The difference is in Vermont you are better off with leases than mineral rights because you don’t have to pay property taxes on leases, and the owner of the land can not prevent you from working those leases, or sub-leasing them. Leases in Vermont are also perpetual, they never expire (unless explicitly stated in the lease). Once you have bought a lease its yours forever, and can be passed down through inheritance.

California – that’s another whole kettle of fish. The owner of the surface rights has more rights than the owner of the mineral rights, and the state owns all the water. Moral of the story: if mineral rights, or leases on those rights is an issue hire a good lawyer, and don’t even trust them to get it right. Almost none of them understand who gets the depletion allowance, which can make or break a deal.

rockman on Sat, 5th Apr 2014 7:23 pm 



Shorty – Exactly. I didn’t try to detail any more about just Texas. And in La. it’s stranger: you can buy the mineral rights from a surface owner. But “buy” is a loose term: even of you buy the minerals rights you have 10 years to establish commercial production or the rights automatically revert to the surface owner. The only way to perpetually own mineral rights in La is to also own the surface. In Texas it’s a simple matter to permanently separate the surface from the minerals. And in such cases the surface owner can’t prevent the mineral from being developed. Some folks don’t want to pay for the minerals, build a nice house and the 10 years find themselves in the middle of developing oil/NG. Basically you get what you pay for…and don’t get what you don’t pay for.

That’s why I said there is no one set of rules or lease contracts. I’ve always advised folks the same: get a lawyer that specializes in this area. Such advice was ignored by folks up in the Marcellus play and they came to regret that decision greatly.

Kenz300 on Sun, 6th Apr 2014 3:02 am 



Forbes — a cheer leader for the top 1%……..and the Republicon party infomercial

Nony on Sun, 6th Apr 2014 12:47 pm 



I still think if they had let Exxon (best oil company) run the whole thing, it would be done and pumping a long time ago. This kind of project is not a good one for such a complicated governance structure. Reminds me of ITER or the International Space Station. Too many chiefs.