Among the most intimidating aspects of working on oilsands, or any energy question, is unit conversions. It seems that the hidden objective of most any publication is to express all results in the most inaccessible manner possible.
One of the biggest surprises for me in writing this blog has been the degree to which I use it as a reference. I will often look back at old posts for a link or a calculation, so I thought I’d build on that and write out some calculations I am working on this evening and try to break down some of that inaccessibility in the process.
Tonight’s math lesson involves working from a steam:oil ratio for an in situ oil sands project to get the total GHGs from natural gas combustion and electricity consumption associated with the production of the bitumen.
The steam:oil ratio tells you how many barrels of steam are injected, on average, per barrel of oil produced. You will generally see two calculations – the cumulative (i.e. average over the life of the project) and the recent (usually a trailing 3-month average) steam:oil ratio provided by producers.
In order to get steam, you have to boil water using a fuel source (usually natural gas, with the exception of the Nexen Long Lake project which uses gasified asphaltines), and the simplest process through which to do this is using a once-through steam generator.Using efficiency benchmarks for a OTSG, you can determine how much natural gas it takes to produce a barrel of bitumen – CERI provides this handy table in their Green Bitumen report (page 4):
Natural Gas Requirements – 30,000 bbl / d Thermal In Situ Projects
|
Wet Steam-Oil Ratio(barrels per barrel) |
Dry Steam-oil ratio (barrels per barrel) |
Million cubic feet of natural gas per day (MMcf/d) | Thousand cubic feet of natural gas per barrel(Mcf per barrel) |
|
2.5 |
2.0 |
24.7 | 0.82 |
|
3.0 |
2.4 |
29.4 | 0.98 |
|
3.5 |
2.8 |
34.1 | 1.14 |
|
4.0 |
3.2 |
38.8 | 1.29 |
|
4.5 |
3.6 |
43.5 | 1.45 |
|
5.0 |
4.0 |
48.2 | 1.61 |
|
5.5 |
4.4 |
52.9 | 1.76 |
|
6.0 |
4.8 |
57.6 |
1.92 |
The next question you might ask is: what’s a typical steam:oil ratio is for a SAGD facility? Well, some excellent data exist for this as well. You could look to the Brandt (2011) paper, which provides the following (now slightly dated) summary table:
Table 1: Steam oil ratios (SORs) for in situ bitumen production (2009). A sample of large in situ projects is included, along with the average for all thermal in situ production [13].
| Operator – Project | Bitumen production103 m3/d | Water injection103 m3/d | SORm3 water/m3 oil |
| Imperial – Cold lake | 22.4 | 78.5 | 3.50 |
| CNRL – Primrose | 9.8 | 58.9 | 5.99 |
| EnCana – Foster creek | 12.0 | 30.1 | 2.49 |
| Suncor – Firebag | 7.8 | 24.3 | 3.13 |
| Total thermal in situa | 81.4 | 256.3 | 3.1 |
If you want to know the steam:oil ratio for an individual project, the best places to look are either their investor presentations (like this one from Cenovus) or the ERCB Performance Presentations which each operator must make (see one here for Suncor Firebag).
Taking the cumulative average steam:oil ratio of 3.3 for Firebag (I’ve assumed this is wet steam), we can infer that natural gas usage has been approximately 1.08 mcf/bbl over the life of the project.
With natural gas consumption in hand, we can then quickly derive the GHG impact from this phase of production. Assuming the companies are burning pipeline-grade gas (an optimistic assumption since many will burn produced gas at a higher GHG/volume), we can rely on Environment Canada emissions factors for Alberta of 1918g CO2e/m3 which, if we use the conversions of 0.028m3/cu ft and 10^6g/t, yields 0.0543t CO2e/Mcf of gas. Applying the ratio of 1.08 mcf/bbl, we get the value of 0.0586t/bbl, with a steam:oil ratio of 3.3. If the unit were burning produced gas, according to Environment Canada benchmarks, we’d expect 0.0674t/bbl with the same steam:oil ratio.
We’re not quite done from a GHG perspective, since there are also electricity requirements for SAGD. Again using CERI data, the electricity demand for a 30,000 bbl/d SAGD project would be 300 MWh, or .01 MWh/bbl. If we again use Environment Canada data for average emissions intensity of electricity in Alberta of 0.88t/MWh, this adds .0088t/bbl in electricity emissions. If we assume gas power is used, at an emissions intensity of 0.4t/MWh, the additional impact is .004t/bbl.
If cogeneration is used to generate both steam and electricity, then the electricity generated would offset other electricity emissions. CERI estimated that a SAGD plant for which all the steam was generated by CoGen facilities would have a net electricity surplus of 3,530 MWh/day. If we apply the grid average emissions factor, this implies a displacement of 0.1035t/bbl. If we apply the more reasonable assumption that gas power is displaced, the factor is 0.0471t/bbl. This is offset by the fact that cogeneration would use approximately 60% more gas according to CERI data.
Combined (and assuming gas electricity as the marginal source), these ratios lead to a figure of 0.0583t/bbl from natural gas combustion and electricity generation for a SAGD oilsands facility operating at a steam:oil ratio of 3.3 at 30,000 barrels per day, with all the other assumptions listed in the CERI model facility. If we assume the facility burns produced gas, this increases to 0.0714t/bbl. If the facility were operating on CoGen, the net GHG impact would be between 0.04-0.06t/bbl depending on whether produced or pipeline gas is burned.
Hopefully you (and I) now know how a little bit more about how to calculate the emissions per barrel of bitumen produced from a SAGD facility, similar to figures you see in Figure 22 (page 54) here. I would welcome any corrections to these calculations and hope you find this useful.
This is useful.
Andrew,
Your recent article with Nelderini was a fine addition to on-going Peak Oil Literature, so I took a gander here.
This is pretty much Greek to me and probably to most of the folks who comprehend the demands of diminishing energy resources and climate change, but don’t have the technical knowledge or desire to go this deeply into the technology. I’m sure it’s very valuable to dozens of folks who need to explain reality in more detail. Don’t stop, but…
Unfortunately it does little to counter the fossil fuel industry propaganda that millions of ordinary folks see, often daily, on the TV or online. One feel-good spot by ExxonMobil has really gotten my goat lately. I’ve seen it all over, even on PBS. I’d like to see a blog by someone of your stature deconstructing the spot for distortion, or even downright lies. Then someone with less tech savvy could point to your work as something most anyone could understand.
The thing about the spot that most gets me livid is the claim that at their project in Canada, “We’ll be able to produce these oil sands with the same emissions as many other oils.” Note how they don’t say “conventional oil,” but rather “many other oils,” leaving themselves the out that they weren’t referring to conventional oil, when that is exactly what they are implying.
Here’s the 30 second spot:
http://www.youtube.com/watch?v=5XQOJipRlJ8&feature=related
BTW, I couldn’t help wondering as I read this blog what the average actual mining of this crud using diesel adds to the energy inputs of NG and electricity that make it ready for pipelining or trucking out? Even just having an idea of added percentages would have been valuable to me.
Andrew,
Oops, I got you mixed up with Gregor Macdonald. Sorry about that first line. The rest applies.
Thanks for this Andrew, very informative.
Any thoughts on how or why this doesn’t really line up with reality for Suncor Firebag?
In 2009, according to S.46 (mandatory federal GHG reporting, which is public and includes no indirect emissions from grid power or anything else) Suncor Firebag emitted 1,414,084 tonnes of CO2 eq and produced 17,803,605 bbl of bitumen (ERCB ST 53), this gives a 2009 EI for Firebag of ~0.079 t/bbl. Also note firebag uses ~100% pipeline NG, so you would expect them to be around 0.0586 t/bbl. Also note that the avg SOR for 2009 that they reported to ERCB was 3.13 (which is lower than the 3.3 cumulative value you used so you would think their 2009 actual would be lower than 0.0586 t/bbl.
Any insights would be greatly appreciated.
Thanks for reading. A couple of things that I expect are causing this discrepancy. First, Firebag is using produced gas (see Slide 52 here http://www.ercb.ca/docs/products/osprogressreports/2006/2006AthabascaSuncorFirebagSAGD8870.pdf). Second, and I expect more importantly, cogeneration leads to higher on-site emissions per barrel, because the cogeneration offsets would not be counted against the facility level reported GHGs, but would be counted against their SGER compliance requirements in Alberta.
Andrew
thanks Andrew.
Cogen may be the culprit.
Firebag’s 2010 ERCB progress report has good info on electricity consumed (roughly 20 MWhr /month) and exported (roughly 30 MWhr/month) from which I guess you could back calculate the emissions that are created by this exported electricity gen and subtract it form their reported EI to see where their bitumen extraction EI actually is.
this progress report also shows that in 2009-2010 Firebag uses almost an insignificant amount of produced gas (<1%).
Thanks. Need to look at this more closely. Not sure why they have the level of attention to sulphur that they do if they are not producing significant quantities of gas. 1% is obviously not large enough to make a difference on the ghgs, but I would expect that the extra gas burned for cogen would do it.
Andrew