Register for free to join our community of investors and share your ideas. You will also get access to streaming quotes, interactive charts, trades, portfolio, live options flow and more tools.
Register for free to join our community of investors and share your ideas. You will also get access to streaming quotes, interactive charts, trades, portfolio, live options flow and more tools.
won't comment on your questions but this presentation carries information which may explain, at least in part, why petrochina backed out. (Montney shale is one of the relevant plays).
http://www.encana.com/investors/presentations/investorday/pdfs/canadian-division-overview.pdf
the good news is that it's only 10%. the other good news is that it will almost certainly never be 100% unless the quality of education and living standard in Kazakhstan increases dramatically. while there is a lot of valuable stuff there, it is a complex reservoir that requires some technology and infrastructure to monetize.
snippets from 2003 AAPG Memoir 78, p. 237– 250
"Karachaganak was discovered in 1979, with the drilling of stratigraphic well P-10, and was placed on pilot production in October 1984. The hydrocarbons initially in place, consisting of 1.236 billion tons (9.7 billion bbl) of liquids and 1.371 trillion m3 (48.4 tcf) of gas, were formally reviewed and approved by the Republic of Kazakhstan in May 1999. Together, these give total in-place hydrocarbons of 17.78 billion BOE for Karachaganak."
"Fluid Composition and Model
The complex fluid system at Karachaganak field consists of a rich gas-condensate lying above volatile oil and is categorized as a retrograde gas-condensate. For the given depth interval of 3500–5150 m subsea (mss), reservoir temperatures are relatively cool, ranging from 70 to 90 C (158–194 F), and initial reservoir pressures range from 51.5 to 59.5 MPa (7469–8630 psi).
Karachaganak liquids belong to the methane-naphthene hydrocarbon group. The condensates contain high paraffin (1–5%), asphaltene (0.1–0.3%), resins (1.0–1.7%), and sulfur (0.6–2.2%), including mercaptans (0.1–0.25%). On average, the oils also contain high paraffin (3.6–5.1%), asphaltene-resins (2.0–4.4%), and sulfur (0.5–2.0%), including mercaptans (0.2%). The gas is sour, with H2S content averaging 3.5%, mercaptan content averaging 0.07%, and CO2 content averaging 5.5%."
"Karachaganak has a large number of development options and challenges because of remoteness of the location, size of the reservoir, and fluid composition (Hsu et al., 2000). The location of the field far from Western markets presents perhaps the largest challenge."
"Karachaganak is a giant retrograde gas-condensateoil reservoir with a 1650-m hydrocarbon column and in-place hydrocarbons of 17.78 billion BOE (9.7 billion bbl of liquids and 48.4 tcf gas)....
An ongoing workover program has restored previously declining production to historic maximum levels. Recent daily production averaged 230,571 BOE. The sanctioned optimization plan calls for a partial depletion and enhanced gravity-drainage strategy that involves partial pressure maintenance through gas recycling and development of the oil rim using horizontal wells. The current full-expansion development plan includes the workover of 81 wells and the drilling of 161 new wells from surface. These wells could allow maximum daily production to exceed 735,000 BOE."
i don't think there would be many complaints about the sulfur although i wouldn't be terribly surprised if the temperature in Qatar didn't cause some problems for an Alberta like pile.
My comment was an oblique reference to the mention of exports of H2SO4, gypsum or alkali sulfate. If sulfur starts accumulating in Qatar like it is in Alberta, then it will be an indication that their export expectations were a little optimistic. I'm guessing that the economics of the gas production and processing in Qatar are a bit dicey because of the high H2S content. If gas prices stay low, then any offset from sulfate/sulfur exports could be important. There is also a cost for processing and storing elemental sulfur (beyond oxidation of H2S to S). The cost for storage in Alberta is about $3/ton so it can become a significant sink.
I've seen some very stupid accounting in companies supposedly staffed by 'grown-ups' and some of that stupid accounting has involved ridiculous estimates for things like sulfur/sulfates and other 'by-products' of gas contaminants. Letting that kind of stupidity get as far as a full blown plant like Pearl would set a new standard so i doubt if the 'by-products' are critical to Pearl's viability.
note that sulfur was glossed over in those articles. It'll be interesting to see if huge yellow mountains start accumulating in Qatar and how critical sulfate exports are to the profitability of the operation. I think the latter question will only be answered by whether or not the plants are still operating in 10 yrs or so if gas prices stay roughly the same.
Briefing on the Final Report of the MIT Study on the Future of Natural Gas
On Thursday, June 9, the MIT Energy Initiative will present a briefing on the final report of the MIT study on the Future of Natural Gas. The briefing will be led by the study co-chairs – Professor Henry Jacoby (Sloan Management School), Mr. Tony Meggs (MIT Visiting Engineer), and Professor Ernest J. Moniz (Director of the MIT Energy Initiative) – as well as other members of the study group. The report will be released on June 9 and participants will be able to request hard copies at the briefing and at the following website: http://web.mit.edu/mitei/research/studies/index.shtml . The audience for the report is principally US government, industry, and academic leaders, although the study is carried out in an international context.
Please join the MIT gas study group principals for the briefing on this important and timely topic. A luncheon will be held at the Cambridge Marriott from 12:00 noon – 1:00 pm with the presentations and discussion following from 1:00 – 3:00 pm. Space is limited at this event, so please click the link here and follow the instructions to register: http://www.regonline.com/future_of_natural_gas
For those unable to join us in Cambridge, the presentation will be webcast from 1:00 – 3:00 p.m. If you are interested in viewing the webcast, please select the "Viewing Webcast Only" option when registering. We will send you a link before the day of the event.
nah, the drilling isn't a problem. Firstly, the concerns of folks overlying the Marcellus are that additives in the frack fluids are entering their drinking water aquifers. Methane is just for sensationalist demonstrations (as in Gasland). There are many additives and they vary in identity and usage; however, they may include biocides, surfactants, pH buffers, viscosity modifiers, etc.
http://geology.com/energy/hydraulic-fracturing-fluids/
I suspect the biggest concern involves biocides. You could drink a lot of water saturated with methane and you'd probably die of water intoxication before suffering any ill effects from the methane.
There are 2 scenarios where human activities could conceivably cause or allow methane or fracturing fluids to enter an aquifer above a gas reservoir: 1. a bad or compromised cement job which allows stimulation fluids or produced fluids to migrate up the well between the outside of the cement and the wellbore; and 2. the fracking operation penetrates a cap rock or opens pre-existing fractures through a cap rock and thus provides a conduit for stimulation or produced fluids (natural gas, oil, or brine) from the reservoir to migrate upward to an aquifer.
The 1st scenario is acknowledged by the PNAS paper's authors as being a possible culprit for the methane in their samples. Of course, that methane might also be from other reservoirs above the Marcellus and might have nothing to with drilling. In any case, bad cement jobs do happen so it should not be automatically discounted as a possible contributor to groundwater contamination.
The 2nd scenario is also possible - nobody has definitively shown that it is not be possible. However, The fracturing fluids do not flow upward unless they are either more buoyant (less dense) than the overlying fluids or there is a pressure gradient which forces the fluids upwards even if they are more dense. Even if either of those occurred, there is usually flow in the overlying aquifers and several thousand feet of rock over the reservoirs. That means any leakage will be diluted and swept 'downstream'. So anybody who claims that their well water is contaminated by a nearby gas well is probably almost certainly wrong unless the gas well has a bad cement job or there are some really long and open fractures that will almost certainly be very obvious. Since the latter are not observed, then the choices are either folks should look 'upstream', or look at the cement jobs, or look for a different source for the methane.
I believe that Halliburton and Schlumberger have both released the identities of the chemicals used in their fracturing fluids. If you google: fracturing fluid chemicals site:halliburton.com or slb.com you'll come up with much more specific information.
some companies are starting to take preemptive actions, presumably to protect themselves, against claims of groundwater contamination in reservoirs being hydro-fracked. For example, these companies are doing baseline groundwater measurements prior to doing stimulations. I know of one case where the company didn't log the well or take core or fluid samples in the reservoir rock, however, they took water samples from an aquifer several thousand feet above the reservoir and several thousand feet below the surface (that doesn't mean they won't do logs or reservoir sampling later). Of course, these measurements are only really meaningful in relatively virgin areas of a reservoir (e.g. a couple of miles away from existing wells; however, that distance will depend on things like when neighboring wells were drilled and flow rates).
One of the most severe criticisms of the PNAS paper that insinuated fracking operations had contaminated groundwater in PA was that it had not used or carried out any baseline groundwater measurements.
DFRAI,
perhaps you can show where i said any of the things you claim.
2 of the 3 links you posted contain 3rd party 'interpretations' of other people's comments. Some of those interpretations are actually misrepresentations - a tactic of which you are quite familiar and fond.
you would do yourself a favor by posting less and reading more without trying to 'read in' your ill-informed biases.
cso
Dew,
because i'm prohibited from investing in any oil/gas company securities i haven't looked at SEC filings for any O&G companies for quite a while. I only looked at the Petrobras 20F to see where the hell westeffer might be getting his numbers.
Since the document is 368 pgs long i obviously didn't read the entire thing. I scanned for "reserves", "field", and "salt" - partially to confirm to myself that they didn't report field reserves that way westeffer implied.
the bit about the "assignment agreement" was interesting. i'd just search that term and read the sections fore and aft where it crops up. Seems a bit dicey, i.e. an agreement with very few fixed parts (e.g. the word 'revision' occurs in abundance) and i'm not clear what happens in 2050 or when PBR produces 5 billion barrels from the pre-salt reservoirss (whichever comes first).
The bit about the "new state run non-operating company" that "will participate in operational committees... and will manage and control costs..." was good for humor value.
regards,
Charlie
my comments as they were before. you are clueless. if your reservoir friends are not fictional characters and your representations of their comments are even remotely accurate and in context, then they are clueless.
you apparently missed the part where i pointed out that i work in this business.
westeffer,
your comments are nonsensical.
1.Cantrell is an example of reservoir mismanagement. Its production problems have nothing to do with recovery techniques eroding "the reserve base to [sic] quickly".
2. Your claim that "all major fields were discovered at least 40 to 50 years ago" is laughable
3. and in the 'are you serious?' category: "People get excited about the huge deep salt deposits potential off Brazil and yet the oil industry doesn't even have the drilling bits that can drill through the salt."
4. 'refinery challenges' have nothing to do with challenges involved in increasing production from Canadian oil sands.
Congratulations, you are a winner of getting absolutely nothing correct.
never hurts to have an inside man ;^)
http://www.cheniere.com/corporate/directors.shtml
re: Duke fracking paper
i had to review the paper as part of my job so i can't pass on detailed comments from that exercise; however, here are a couple of sites that address most of the pertinent problems:
http://www.energyindepth.org/tag/report/
http://johnhanger.blogspot.com/2011/05/comments-on-duke-university-study.html
the PNAS authors have also starting writing op-ed pieces in newspapers which seem to further expose their lack of objectivity:
http://articles.philly.com/2011-05-10/news/29528421_1_water-wells-safe-drinking-natural-gas
The PNAS paper is an embarrassingly bad piece of 'science' unfortunately, i suspect that the authors' funding position will benefit. Mine will probably as well; however, i'm not the guy prostituting himself.
enjoy,
Charlie
i've seen a bunch of buses in our 'beloved' Cambridge that run on NG and Obama bought nice new NG fueled taxis for the local cab companies; however, i have seen zero NG fueled garbage trucks - anywhere.
the original article is here:
http://www.pnas.org/content/early/2011/05/02/1100682108.full.pdf+html
i'll comment more later when i've thought it over a bit.
he also was an SLB director and has many more shares than me.
DOE frack panel
i suspect obama will get something quite different than what he expects. From a superficial perspective the panel is composed of a mix of quasi-industry, environmental, and academic 'experts'. I know most of the people on the panel are very liberal and i suspect all are of that persuasion, however, that doesn't matter much beyond that they'll give obama something they think he wants. What is more important and is a shared goal of the panel members is that they all want higher natural gas prices - whether they want that explicitly or not. The large multinational production and service companies that have been expanding or trying to expand their operations in shale gas will also be quite happy with the higher price goal. So the stars are aligned for everyone but those whose are crimped by higher natural gas prices.
cheers,
Charlie
ob,
yup, i'm actually very environmentally conscientious. my cynicism about many environmentalists (of the 'activist' variety) is that they have no idea that their actions are contradictory to their cause. For example, the idea that battery driven cars are 'green' is just plain dumb (i'm not referring to hybrids).
cheers,
charlie
ob,
for an article addressed to the lay person it's not too bad. the only thing i found particularly heinous is:
while i agree with the author's opinion, i'm familiar with his own work some of which is also not particularly good science.
xrymd,
i can't answer your question regarding O&G companies. I'm a research guy in the business so I don't know much about operations of specific companies but even if i did it would be an ethics breach for me to comment.
sorry,
charlie
don't know much about CBM but this will give some perspective (keep in mind pricing is different now)
http://pubs.usgs.gov/of/1996/of96-735/figure5-7.htm#Figure7
i'm kind of curious if that 4-5 BSCF is total recoverable or per year or ....? Just saying it's per sqr mile doesnt tell you much.
BMY,
$45 in afterhours - what the hey? somebody care to clue me in?
tia,
Charlie
OT XOM US taxes
from http://www.manufacturing.net/News/Feeds/2011/04/mnet-mnet-industry-focus-facilities-and-operations-on-earnings-profits-and-taxes-exxonmobil-lays-it/ story dated yesterday
Finally, Cohen closes by refuting the political attacks against oil companies, the demands for higher taxes, and the claims that oil companies escape paying their fair share of federal taxes.
Let me state it unequivocally. Last year, our total taxes and duties to the U.S. government were $9.8 billion, which includes an income tax expense of $1.6 billion. Over the past five years, we incurred a total U.S. tax expense of almost $59 billion, which is $18 billion more than we earned in the United States during the same period.
And during the first quarter of this year, we incurred tax expenses in the United States of more than $3.1 billion on U.S. earnings of $2.6 billion.
if a producer wants to pipeline a very viscous crude, then the easiest, cheapest thing to do is to dilute it with a much lighter crude or a refined, lighter hydrocarbon. trucking or heating pipelines is more expensive and burns product. Diluting just delays the refining of the diluent.
AVEO
anyone know why the big jump today? 13+% on 10x volume
thx,
Charlie
Dew,
if you're referring to the price premium vs WTI, i suspect that it's because Bakken's API is 40+ vs WTI which is just under 40. Another possible reason is that the oil-sands folks in Canada need diluent.
those are just WAGs so i'd ask HES's IR experts anyway.
cheers
Charlie
what isn't so obvious from that article is: which oil are the cited taxes referenced to? I believe most Venezuelan oil is much heavier than WTI or Brent and sells at a substantial discount to those oils.
it's loony either way but it would be truly impressive if he's referencing the tax to a non-Venezuelan crude.
John,
i'm the wrong guy to ask for that sort of information. I should know more about it than i do but I'm not a flow guy so take that into consideration.
I don't think 200 mD is necessarily bad. The Macondo reservoir was supposedly only ~300 mD. The Eagle Ford shale is supposedly ~1 mD. Fracturing/stimulation is not limited to gas shales. If a rock contains sufficient quantity and quality of oil and the porosity is as you say, then I'd think they would create the permeability. Of course, if the pores are 80% full of water, then that might be another problem.
I would also think that temperature and pressure would have to be known in order to determine permeability (e.g. they affect viscosity which is also part of the viscosity calculation) so that sounds a bit off.
Bottom line is that you shouldn't read too much into an out of context permeability number.
regards,
Charlie
re: current fracking methods are wasteful.
yeah, a lot of unproductive shale gas wells are drilled and fracked because it's generally considered to be cheaper to do that than to use the more careful, deliberate methods that are used in oil and conventional gas exploration, field development, and well completion. The vast majority of shale gas wells are not logged at all. Consequently, a good bit of the learning process never happens and field development and well completions become a hodge-podge of hit-and-miss well placements and remedial completion practices.
The environmental crowd may actually help the larger exploration and service companies on this front. Developing shale gas reservoirs in a systematic way is expensive. Doing it in a sloppy way has proven to be effective and cheap. The big exploration and service companies can't compete on pricing as long as the sloppy approach remains the status quo. If the more deliberative approach becomes a legislative/regulatory requirement in order to avoid environmental problems, then the big boys win. One of those rare circumstances where a certain 400 B market cap company is cheering on the tree huggers.
‘le fracking’
this exemplifies why shale gas is not likely to be as big in Europe and other locales where ownership of subsurface assets belong to the state rather than individuals. Because the "owners" are politicians, any decision on whether extraction (or injection) proceeds inherently depends on 'popular support'. The corollary result of the community screwing a surface owner by literally under-mining them also exists.
Note this also applies to things like CO2 sequestration, however, in that case liability fears are likely to force folks in the US to act more like Europeans.