Sable Island Gas - the Ten Year Wonder
Posted by Paul Sears on November 7, 2006 - 11:42am in The Oil Drum: Canada
Sable Island lies about 150 km off the coast of Nova Scotia. In its
vicinity lie the natural gas fields of the Sable Offshore Energy
Project. Production from these fields began in 1999, and there was
initially considerable optimism about the potential of the area.
Since then, a number of dry holes have been drilled and exploration licences abandoned. There are some optimistic voices still to be heard, but the future of the area merits a closer look.
Canada's National Energy Board issues an annual report on the short-term outlook for natural gas in Canada. The most recent was issued this October: Short-term Canadian Natural Gas Deliverability 2006-2008. Canada has two areas from which gas is currently produced; the Western Canada Sedimentary Basin (WCSB) and the Nova Scotia off-shore area. The latter produces only a small fraction of Canada's total natural gas, but rates its own section in the report.
Gas production in the region consists of output from the Sable Offshore Energy Project (SOEP) since 1999 and a minor contribution from the onshore McCully field in New Brunswick since 2003. These sources currently account for roughly 9.9 million m3/d (350 MMcf/d) or about two percent of Canadian natural gas deliverability.
The Sable Island project has four reservoirs (Thebaud,Venture, South Venture and Alma) that are now producing and one that has been shut in (North Triumph).
The SOEP has benefited from the addition of three new wells since mid-2005 that are enhancing access to the Venture, South Venture and Alma reservoirs. Pressure declines in some other fields have required that wells be operated in a cycling mode (shut in briefly to rebuild pressure and then restarted) resulting in monthly deliverability from the project varying by almost 25 percent since late 2005. As a result of pressure decline, the North Triumph field has not been producing since November 2005.
Production from the project has never been very steady, is now well down from its 2001 peak of about 15 million cubic metres per day and is still declining. To counteract this decline, offshore compression of the gas will shortly be started.
To enhance deliverability, the SOEP is in the process of adding compression at the inlet of the pipeline that delivers the gas to shore. The offshore platform and compression unit was installed in mid-2006 and is expected to be hooked up and operational by December. The added compression will allow the existing wells to operate at lower pressures thereby significantly increasing overall project deliverability and potentially enabling the North Triumph field to resume production. Uncertainty exists regarding individual well performance at the new lower pressures, and cycling of some wells may continue.
The predicted effect of the compression on output is also shown in the report:
Click for full-size image
The curious thing about this diagram is the use of a new colour to show the effect of compression. No new field is involved, so all that compression should do is increase deliverablity, at the expense of more rapid depletion of the reservoirs. It cannot delay output decline indefinitely, and the diagram shows beginnings of decline in late 2008. One would expect that the total output (over all time) would scarcely be affected by compression, so a very rapid decline would be expected after 2008. It is difficult to see how a decline of the output to a very low level can be avoided by the end of the decade or shortly after. In spite of this, one report on Rolls Royce's involvement in the project implies that 25 years' further output is expected.
The Sable Tier ll project will develop six gas fields: Venture, South Venture, Thebaud, North Triumph, Glenelg and Alma. Combined, the fields contain nearly 85 billion cubic meters of recoverable gas reserves, one of the largest natural gas deposits remaining to be developed in North America. Sable is projected to produce a 25-year supply.
This view may have been encouraged by a 2005 report from the Canadian Association of Petroleum Producers, which contains the following:
Click for full-size image
In this diagram, the "85 billion cubic metres" is mentioned in point 3 as "recoverable gas reserves", but apparently is now only a 20 year supply. If one then considers point 4, some new things become apparent. The first is the use of different units, bcf (billion cubic feet) instead of billion cubic metres. This makes comparison with point 3 more difficult. Translated, it means that the Sable Offshore Energy Project had only 20 billion cubic metres of reserve base in 2003 - more like a six year supply, assuming a production rate of ten million cubic metres per day. This is consistent with the implications of the National Energy Board's production diagram above.
There is some possibility that a pipeline built to transport Sable Island gas to the mainland will be used for the nearby Deep Panuke project as the Sable fields wind down. This is in contrast to the original plans, in which dedicated pipelines were to have been used because it was thought that the Sable pipeline would have no spare capacity.
Barring unexpected developments, it seems that the Sable Island gas
project will indeed prove to be a ten year wonder. Gas users in
Maritime Canada, who have watched the bulk of the Sable gas pass them
by on its way to the U.S., will then become dependent on imported LNG -
that is, if it is available.
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Why is this not getting any publicity? What can possibly reduce this problem to a manageable level? How can't this send teh region into total chaos?
i'm going to rock myself asleep in the fetal position until this all passes.
Sorry Markegg, you'll have to last at least two weeks.
King James Version (KJV)
Public Domain
So when they continued asking him, he lifted up himself, and said unto them, He that is without sin among you, let him first cast a stone at her.
Canadians are inherently smarter than Americans. You've observed us for far too long for this not to be true.
Bring Freddy Hutter into your ranks. The US has NO energy policy. Canada doesn't either, but at least you have a strain of independent European thought that helps in this regard.
TOD Canada is free and new. You can take chances. Please do.
Roel, take some chances, for chrissakes. Blame everything on me if it doesn't workout. But stop being a satellite.
Went to Canada twice beautiful country, and Grade "A" strip clubs.
As for having no energy policy if you choose to not decide you still have made a choice right?
Matt
We are. Not mentioned is the fact that this Canadian compression technology is being licensed to KSA where it will be used to maximize production from the inflated Ghawar reserves.
Appropriate use of Canadian compression will provide a viable future development path and forgo an expensive world outlay on Jim Beam and crack. Not yet certain of its application to females.
Blokey we are. Crude not normally.
Stoneleigh
As for the comments on Canada's natural beauty, I don't mind, but I also understand why Stoneleigh would like you to tone it down a tad.
Why not support us with some awesome graphs instead?
The curious thing about that graph is that it makes no sense whatsoever in that the more rapid extraction due to compression at the wellhead should be expressed as estimated increases in the various fields where it is being applied. What am I missing here? Is there a new field called Compression? No, there are no new fields. The existing fields are shown as still declining. This must mean that the declines shown would be the case if compression were not applied. I see, then, that they are making a point about the miracle of compressing natural gas by showing a cumulative estimate in a new category. This has the happy effect of bypassing field-by-field estimates. Declines will be wiped out in all the fields because the compression miracle makes total production in all the fields jump from about 9 million cubic metres/day to almost 14 in what looks to be a matter of a few weeks.
Alternatively, are they taking drugs at the CNEB? If so, what kind? Where can I get some?
has the data (I don't have the Adobe programme to extract it here).
It gives 2001 energy consumption by type for PEI, Nova Scotia and New Brunswick (but not Newfoundland).
The reality is this should be pretty small compared even to Quebec consumption.
Here are the numbers (from Statistics Canada) for 2000 to 2004 for the gross production of natural gas in (and off) Nova Scotia, and the direct sales of gas in Nova Scotia and New Brunswick. The gas numbers are thousands of cubic metres.
Year Production Sales
2000 3597200 0
2001 5375500 45004
2002 5474900 1007959
2003 4665800 630879
2004 4327900 668551
There appear to have been no utility sales of gas in those provinces, so the direct sales should be the total. This means that about 15% of the Nova Scotia gas is used in Canada, and the rest goes to the U.S..
Did the presenter make an error?
Did he do this deliberately?
Did he assume the audience would be sleepy after a big lunch?
Did anyone call him on it at the presentation?
Is anyone up for calling the presenter?
Which is why it surprises me a bit to see Sable Island as a gas location - the very last time I was in Nova Scotia, the hope was still for massive oil/coal deposits to be found/developed. In the mid-80s, the last coal mine in Glace Bay was shut down. (I spent some time with a few miners and their families camping in the early 1980s.)
It also surprises me a bit in another way - listing such small gas production numbers means at this point, the future is looking pretty grim for new supplies, the same way that Nova Scotia's coal production in 1985 would have only been a footnote at best.
There was also a CANDU nuclear unit at Pt. Lepreau New Brunswick
http://nuclear.nbpower.com/en/pointlepreaurefurb/PLGS_History_factsheet_sept2005.pdf
680MW (about 1/3rd of New Brunswick demand), operating for 21 years.
Expat, I share your surprise about Sable Island gas. I worked in Nova Scotia during the years you were visiting there, and remember making a bet with my boss at the time that Sable Island gas would not come ashore before I retired. It was an outstandingly bad prediction - I'm still working.
This is a very important question. I don't know the answer, but I know a few wind experts who may be able to offer an opinion. If I can find out I'll post the information here.
there is significant undeveloped hydro in
Labrador that could be tapped.
The Danish example shows the importance of
the opportunity to combine variable sources
such as wind and tidal with more control-
lable resources like hydro and nuclear.
I think so. There is a bridge somewhere in northern canada that I saw a tv special on. It has to deal with mass deep ice flows seasonally. Basically the base is built like a inverted ice breaker nose causing the ice to crack and slide pass.
I so I think the towers could be built to withstand anything but a large berg. Now with global warming you get less ice but more bergs so ...
In one word no, see my reply to Peakearl below
But even onshore, the amount of icing could be very significant considering the amount of fog/drizzle/rain which is available, which is certainly higher than what is normal in my sketchy experience in Europe.
On the other hand, and not to place blind faith in technology, it is difficult for me to imagine that North Sea or British wind turbines don't face similar problems which haven't been solved - it seems like only the Finns sell a non-freezing rotor design, though - not just Canadians live with ice. This could also include the idea that insurance premiums are based on the idea of it happening anyways. Sort of like the Gulf of Mexico - since you can't realistically design for everything that could happen, you just gamble - even though the odds are carefully calculated, in the end, it comes down to probabilities. Thunderhorse or Mars looked like good bets, for example, but now, the odds have changed for any successors.
I will say seeing the twisted and mangled containers at the end of the South End Container Terminal in Halifax was eye opening - the Atlantic is a truly vicious environment, and likely worse than the North Sea in its extremes.
Sorry for my late reply, I don't think any aircraft anti icing systems would solve icing on wind turbine blades and any build up will cause out of balance problems and failure of the blade. When frontal weather systems move through or temperature changes suddenly with precipitation, clear ice can form rapidly.
It will never form uniformly and with such big blades on turbines these days, the out of balance load will destroy the blade as the weight of quickly forming ice causes enormous imbalances.
There are three types of anti icing systems on aircraft, one being pneumatic rubber boots on forward surfaces that act to break up the ice by flexing back and forth. Not possible for turbine blades. On jets hot air is taken off the later stages of the high compressor of the engine, again not applicable and finally the use of embedded electrical heaters in metal surfaces or glass.
This is unlikely to be available because of the power requirements and amount needed.These days I understand that many blades are now being made of fibre glass and composites because of fatigue and failure with metal, therefore this is a lot harder to put an element in especially to cover the whole blade.
Another risk which is destroying a lot of blades but not widely publicised is lightening which causes enormous damage. You couldn't pick a worse target than a high 350' structure on ridges, mostly made of metal for a lightening strike. At any given time around the earth there are approximately 50,000 active thunderstorms and icing, lightening and turbulence are always available to cause severe damage to anything in their path.
Do you have a more recent report, about the companies that drilled there after 2004, had dry holes and abandonned their concessions? Were they many? How many drills were made in the region? Has the hope faded among most companies?
Canadian Superior is the largest holder but I believe they haven't drilled anything there yet. Instead of drilling offshore Nova Scotia, they started to explore a new concession in Trinidad & Tobago.
about the new trust tax rules and has stated
that they will be taxing distributions both
in the hands of the trust and the receiver.
No info has come out as to how much the tax
will be.
It is all up in the air, since there is a
minority government. I would expect an
election in early spring
I'll be doing a post on this next week - stay tuned.
Some Q's related to Canadian Nat Gas production, exports to the USA, ability to continue current export levels:
1 - Does Canada have pipeline infrastructure in place to move gas East/West and vice versa without moving it through the USA?
2 - If not (as I'm guessing is the case) how will central Canada (Ontario, Quebec) partake of Canadian gas when exports to the USA are severely cut/eliminated?
3 - Is anyone up to speed on NAFTA provisions for Natural Gas export once we exhaust all of our "spare" gas? Can we turn off the tap?
Thanks,
Paul
Yes, but not too much capacity.
2 - If not (as I'm guessing is the case) how will central Canada (Ontario, Quebec) partake of Canadian gas when exports to the USA are severely cut/eliminated?
That's a double question/double take. The gas that goes from Canada to the US at present doesn't go through the east, there's plenty pipelines from Alberta straight south. Most gas comes from the Western Canadian Sedimentary Basin.
It'll all soon be gone. Reserves are for 8 years max. Then it will be LNG imports, and perhaps the McKenzie Valley pipeline (which will take years, if it's ever built)
3 - Is anyone up to speed on NAFTA provisions for Natural Gas export once we exhaust all of our "spare" gas? Can we turn off the tap?
No, we can't, not without abandoning NAFTA. Because NAFTA covers much more than just energy, you will see Alberta separate before Canada leaving NAFTA. It was a well thought through, premeditated firesale.
NAFTA was by no means the first step, there was GATT and even earlier versions. The next will be Super-NAFTA, SPP and The North American Union.
Preventing this would take very drastic measures. 52nd state is what we are de facto. Harper's finishing the job that was started long ago.
Roel -whom I increasingly believe is NOT CANADIAN- seems to forget that PM Harper leads an unpopular minority government that already faces a crisis of confidence in the environmental bungling know to you as the 'Clean Air Act'.
Canada is most definitely not a 52nd state (de facto or otherwise) and if Roel actually pulled his head out of his ass and travelled the world he'd know this - the comments by Oil CEO above reflect but one example of how people around the world view Canada and it's citizens.
I would say that neither Canadian unity nor Canadian sovereignty over our natural resources can be taken for granted over the long term.
Harper's minority is better positioned than most minorities as the opposition is still in leaderless disarray. He can't do anything too extreme however, as he also has a minority in the senate and the senate can torpedo his initiatives.
The hit on Ontario, especially the Auto Industry, would be too great. Ontario is 40% of the population of the country. Quebec also has a lot vested in NAFTA eg in aerospace and biomed/ pharma.
You saw the disruptions after 9-11 when US Customs slowed down cross border deliveries at Windsor and Niagara Falls.
If there is a continent wide energy crisis, there is a continent wide energy crisis. We'll share in the pain.
I don't think Canada will become, politically the 52nd state, as long as Canada holds together as 1 political unit.
I mean, can you imagine Alberta and Ontario sharing the same Senator in the US Senate?
I'm not really sure, at this point, the US would have or want us. Canadians are relatively lower income, have a socialist(ish) state by American standards, are Godless, pro abortion, pro gun control, etc. etc.
Albertans and Central Canada don't see eye to eye at the best of times but you're mad if you think they won't support their countrymen in a time of need.
I concur with you Valuethinker in that as the energy crisis unfolds, Canadians will go out of their way to share with their southern neighbors to the upmost of what is domestically capable but not at sword point.
Canadians and Americans are neighbors and the former are defined as much by the latter; politically, socially and culturally.
For all intents and purposes it is one market.
On oil, the whole raison d'etre of the tar sands is the US hunger for oil. Although there was talk of building a pipeline to the Pacific Coast, to supply synthetic oil to China-- not sure how far that one got.
In the top figure, production is net of consumption by the upstream industry and imports include LNG from 2011 onwards. In the bottom figure, the gas exports shown are net of imports, which grow from 57 BCF in 2000 to 236 BCF in 2005, to 727 bcf in 2020.
With information like this, the government's advisors probably don't see any urgent need to discuss turning off the tap on exports, though turning it down is certainly in the cards.
Sorry to comment late.
The main line in red, owned by TransCanada Pipelines Ltd, delivers about 40% of Canada's total gas production. However, the line that leaves Canada near Emerson, Manitoba re-emerges in southwestern Ontario at Courtwright, where Canada essentially re-imports some 10% of its annual consumption. This figure has been climbing recently.
Syntec and I posted earlier on the impact of NAFTA on gas exports to the USA here. The bottom line is that the tap can be turned off but not without political fallout. Your question is partly about the extent to which the government of the day could stand the heat. Partly it's also about the degree to which the Canadian gas market is integrated into the North American market, and how increasingly tight supply might affect use and demand.
WHEN we have to cut exports to maintain national minimum consumption levels (keeping some heat and lights on) A) Will we actually have the "Canada only" pipeline capacity to fully supply central Canada? B) In this scenario why would the USA ever allow gas to "flow through"- Western Canada - US - back into Central Canada? I wouldn't!
New issue: We would, in this scenario, then have a single point of failure in our gas distribution infrastructure. I wonder how many terrorists in training are working on this eventuality?
P
As for the new issue...
I don't think terrorists are at all that versed on NatGas supply issues between Canada and the US, however, the scenario is indeed plausible - that is of course if one can imagine a group of jihadists running around in the rural, pre-dominately white/native hinterland and no one noticing them.
From the Trans Canada web page - "TransCanada's 100 per cent owned 14,898 km natural gas transmission system in Canada"
I'm happy the corporation is 100% "owned" - does anyone know who the majority (controlling) shareholders are? Canadian? From the corporate web page it's clear there are Board members from the USA. Hmmmm.
P
The owners are whoever happens to be the shareholders at that moment. Which could include US institutions,individuals and mutual funds.
I mean you could blow up a section, stop it for a few weeks.
But actually really disrupting it would require an attack on a pumping station or network junction point, I think.
My own view is terrorists (of the jihadist kind) are likely to aim for things which make a big splash, and hopefully kill lots of people/ contaminate areas. Think nuclear waste repositories, chemical plants, public transport (they just gave a guy 40 years for planning to blow up London Tube trains whilst they were under the Thames, thus flooding the Tube and potentially killing thousands).
Just inconveniencing people and causing economic loss wouldn't be enough.
Blowing up an LNG terminal would be spectacular, though.
Pump stations or pigging stations are few enough in number to be defensible by military means, and block valves can be buried and armored against hit and run attacks.
Units: nothing happening here, move along. The two axes are identical, just different units. This is so you can read the flowrates in oilfield units (left hand side) or metric units (right hand side).
Compression: healthy, normal, nothing to be ashamed of. You need enough pressure at the export flange (Lovely word. Try repeating it under your breath like a mantra. Flange. Flange. Flange. North Sea proddies (production operators) use it to mean "sexual activity", as in Can't wait to get back to the beach - I'm dying for a spot of Flange) - errrm, enough pressure at the export flange to dewater the sealine, push a pig, and arrive at the shore terminal without going supersonic.
At field startup the reservoir pressure, and hence the wellhead pressure, is enough to do this, but once reservoir pressure falls you need to put more energy into the export stream. This is what a compressor does. It therefore allows you to produce at lower wellhead pressures. The export flowrate really does jump like that - the compressor is either there or it isn't, modulo a few commissioning hiccups.
Obviously the compressor doesn't change the size of the reservoir, but yes it does add reserves. If you can't produce to market without the compressor, the SEC doesn't let you book the gas as reserves until you've committed to compression (i.e. until you've signed the relevant procurement and gas sales contracts). This is irrespective of whatever you've got you've got in the reservoir; if the SEC doesn't accept it, it isn't reserves.
Note that one of the fields (N. Triumph) died in 2005. They probably depleted it faster than the others so it lost pressure and its wells could not flow into the export manifold (could not compete with the other wells). When the compressor goes in, that field will miraculously revive as its wells start flowing again against lower wellhead pressure (and immediately start declining like the others).
Looks like they sized and timed the compressor to fill the receiving terminal - the profile doesn't exceed the previous peak. Any more would be wasteful, and the sales contract probably doesn't ask for it anyway.
Reserves: Anyone care to guess the cumulative production to date and remaining reserves? Taking the start of that nice decline curve as the break point, I get the following:
- Cumulative produced to date (to mid 2006) = 400 MMcfd average for 6.5 years = 949 bcf
- Base profile = 350 MMcfd initial at 35% annual decline = 365 bcf
- Early compression profile = say 250 MMcfd average for 2 years = 182 bcf
- Late compression profile from end 2008 = 250 MMcfd initial at 35% decline = 260 bcf
Total reserves that I can see in that profile is therefore 949+365+182+260 = 1747 bcf = 1.75 tcfOne terminology quibble - in the context of a gas sales contract, "deliverability" may or may not mean "actual production rate". Alternatively it may mean "maximum theoretical gas production rate under the sales contract for any given day". Impossible to tell which from the material available, so I'm assuming it's the former - the real production rate.
The decline curve looks a bit funny by the way - the blips in the field profiles cancel each other out. The sort of profile an engineer produces to keep the mouth-breathers in the corner office happy so he can go back to playing with the reservoir simulator. The same engineer could probably guesstimate pretty good incremental profiles for each field, but he can't be bothered just now.
The quoted lifetime reserves of 85 bcm comes almost exactly to 3.000 tcf (1 cubic metre = 35.3 cubic feet), which is suspiciously round. I don't know what that 700 bcf number refers to (initial reserves? Remaining? For which subset of fields?); without more context, it's meaningless. However 3 tcf feels like a huuuuge stretch unless they've got some reservoirs they haven't told us about, like that onshore field that comes in in 2007.
Obviously, once the field is depleted, the landfall would be a great place to build an LNG import terminal - remote, on the coast, established gas processing facility, land ownership and easements already in place, no-one lives there (no-one important anyway ;-) and already connected to the national gas grid.
Next question?
To digress to a previous comment on ice and wind turbines. I am sitting in line of sight of 65MW of wind turbines and another 100MW to add once the natives are convinced. Ice flying off and killing people was/is a red herring argument against these units. However, we suffer an extreem ice event (1 cm +) of accumulation about every 8 to 10 years. (GW may make this more frequent and severe .. or not). This causes a lot of tree damage and usually electrical line damage. We dodged the bullet in 1998 when the big ice storm hit east of us but Quebec may have had operating turbines in the zone at that time. I don't remember any comment on damage to them but it could have been lost in the general disaster. Perhaps someone has more direct info on this. Only the various manufacturers (GE in our case) can say how much ice loading they have allowed for in design and operating rules. It is also note worthy that Prince Edward Island plans to be the Canadian leader in wind energy. Hopefully they have accounted for this as they suffer more extreem weather than N.S.
Lots of good stuff on here .. thanks to everyone!
That combination of wet weather and the occasional cold air mass can leave some fearsome ice storms.
It's a very real concern. I don't know if anyone has tried yet to run a wind farm in an area with that kind of ice condition.
NS has mild winters. NB does not, from memory. Some quite brutal ones in fact, a la Maine.
I think a lot of people in New Brunswick heat with bottled gas (propane). Or wood.
UK is in the same position, only worse. Headed for 70% gas fired power by 2020, by which time UK gas will be less than 20% of our consumption (might be less than 10%).
http://www.ieso.ca/imoweb/marketdata/marketToday.asp
does not even have a seprate catagory for NG generators. Today at 1800 hours we were using about 21.5 GW of which 10% was in the "Other" classification, most of which is co-gen of one sort or another. According to the generator reports we were generating a bit of a surplus at 1800 hrs. Base load in Ontario is mainly produced by the nukes with a little from coal, wind and any non-switchable co-gen and some hydro. The switched generation is coal and hydro with imports being called upon when we exceed our peak available capacity. To date our imported power is mostly from coal in the USA. The IESO does not report stations with less than 25MW name plate capacity so there will be a few MWs available but not reported.
Our imports will be an issue if the USA reliance on NG generation is threatened and they need the coal power. We probably have enough switchable hydro to compensate for any domestic NG shutdowns at present levels. Even though there are suggestions for new hydro generators in Ontario (see other articles on TOD) GW precipitation declines probably make that less sure, even if the transmission/location issues were to be overcome. Flow rates on Ontario river systems can vary by 95% from spring run off to low flow in August. As an example, the Spanish R. flowing into Lake Huron, one of the most damned rivers in Ontario has four electric generating sites with a max. potential of about 100MW. In a typical August the river run only has enough for a quarter to one third of this. The only major project at present is OPG spending a billion $CDN to increase capacity at Sir Adam Beck in Niagara by less that 200MW.
The NG crisis will always be more significant in Ontario for process heat, feed stock, space heating and other domestic use. We can only hope the powers that be do not try to up the percentage of gas fired electrical generators in any significant way.
As far as the UK goes, you had better start pumping out those closed coal mines.
As I understand it, Ontario is planning to increase dependency on natural gas for power generation by converting existing coal plants into gas plants. Whether this could happen, however, before gas supply becomes tight enough to cause significant price volatility is questionable.
A prime conern of mine regarding gas in Ontario is that high gas prices for heating might induce people to plug in electric heaters in large numbers instead. This in turn could cause significant problems for the power system.
I agree with you. My own view is that we will see the economy falling into recession shortly. I think we are looking at a deflationary credit crunch correcting the irrationally exuberant excesses of recent years. That would add a whole new dynamic to the peak oil and gas scenario.
The problem with coal is global warming. Peak Gas will exacerbate GW like no one's business.
I am not sure, geologically, whether the UK could reopen its coal resources. That is a very dangerous and tricky operation, much more so than a greenfield site. I suspect we will simply import more.
$5,000/kW ? Pretty expensive. Can this be right?
http://www.opg.com/power/hydro/new_projects/ntp/index.asp
Still cheaper at $5 per watt than wind if you take the generator efficiency and reliability into account. However take a look at the cost of the "upgrades" to Sir Adam Beck #2. I think these need to be added to the cost of that 197 MW. Ontario Power Generation knows how to spend money.
Big Becky drills on and limits be damned. Beck's vision continues.
Actually I don't quite get what is being said about compression. What I assume is that by pumping gas in (Nitrogen or CO2??), you can raise the pressure coming out as so get it out quicker.
But I think what you said is that you will also raise the reserves by essentially get more gas out. Is that correct? If so how exactly or what sort of percentage increase would we expect. I assume you inject the input gas at the base and sweep out gas that would otherwise hang around. If that is the case, I would suspect you increase reserves on the order of 10% to 15% at most.
So my questions are: 1) What gas is pumped in. 2) How much can the reserves be raised by.
This leads onto a 3rd question. What is the typical recoverable fraction of a gas field? Would I be correct in assuming in depends to some degree on size and initial pressure, but for some fields may go as high as 85% or 90%???
In theory you could increase gas recovery by injecting inert gas, but at the cost of marketability once the injected gas starts breaking through in producers. That sort of thing tends to be reserved for single-buyer gas projects, i.e. gas to power.
Recovery factor for a gas field is purely a function if initial and abandonment pressure (theres something called z-factor, but it doesn't make a lot of difference abandonment). The lower the abandonment pressure, the better. Size isn't an issue in itself (recovery factor is a dimensionless number). For a gas reservoir at moderate depth, 75-80% might be typical, 90% would be excellent.
Units
The peculiar change in units that I was talking about is in the second figure I used, not the first. The change is between the third and fourth points in the list, and makes it more difficult to compare the numbers.