A visual demonstration of channeling

In the Saturday posts on oil reservoirs and why drawing down the oil too quickly can cause problems, I talked about channeling.  There is a visual example of how this comes about in the failure of the repaired levee in New Orleans.   When the levee was repaired they filled the hole with a combination of fine and coarse rock which was dumped at the site and raised into a wall that filled the opening and stopped the water flowing into the city.  However the pressure of the water in the canal was sufficient for it to percolate through some of the passage ways that were left through the rock in that berm and so, by Thursday evening there were pictures on some news channels,  from the site, of water flowing out through bottom of the wall, and this before the greater surge and failure that came later.  (This is the residual permeability that was talked about in the posts back then).
At this time it was a fairly general flow through different parts of the levee, much as in drawing oil from rock, it initially comes from all parts of the rock.  But as the flow continued and the smaller rock particles began to be washed out of some of the channels the flow in those areas began to open larger channels, which made it easier to move larger rocks, which caused the overlying rock pebbles to fall into the opening, and a channel all the way to the surface developed and water now began to run down that channel from the surface.

But if you look at the site now you will see that almost all the water is now (around 11 am Saturday) flowing though just two paths out into the town, and no longer percolating through the rest.  The opening of those channels makes it easier for the water to divert, rather than going through the main body of the levee.  Thus it is with the oil-bearing rock.  If channels get developed in this way by accelerating the flow of oil out of the rock, then then oil in the volumes outside those channels does not move as readily to the well.  Further if a water flood is being used to push the oil, it now has an easy passage to the well, producing a water cut to the oil being produced, that can even further lower the total volume of oil that is recovered from that reservoir.

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water cut at saudi arabia's ghawar, the biggest oilfield in the world.
Does anyone have knowledge of CO2 recovery? Useful tool? Too-high expectations?

One of the companies I follow closely - EnCana, has had a test going on for some years now in Saskatchewan; I've been to the plant but know precious little as to how useful using CO2 to aid recovery will be, other than it has obvious appeal to countries who are trying to meet Kyoto obligations (Canada is one).

Have been meaning to float the question for a while, was reminded by this piece on the G7/G8 meeting:

(incidentally, the original G7 came together thanks to the OPEC oil crisis 30 years ago... perhaps Pres. Ford invited Canada into the group for a reason -- prior to the USSR/Russia joining the G7 officially or unofficially, Canada would have been the only country able to be a net oil exporter. Today, only Russia and Canada are.)

http://www.dose.ca/ottawa/news/story.html?s_id=QycEAjLDJ64TssMmWOFYqgHLobPAe9IdC9xb1vy4p6vn%2bXpWqzv y8Q%3d%3d

Canada Tackles Oil
WASHINGTON (Reuters) - Innovations that extend oil field lifespans by decades and extract more from oil sands are Canada's contribution to boosting world crude supply, Finance Minister Ralph Goodale said on Saturday.

Goodale told Reuters that he touched on these issues in a presentation to Group of Seven counterparts at a formal meeting on Friday and, with high oil prices plaguing economies around the world, his colleagues paid close attention.

"This positions Canada very strategically on energy supply issues," Goodale said in an interview.

There has been some discussion here about CO2 injection in the past.  I believe that one of our industrial advisors and I have some disagreement about this, that will probably show up in a debate some months from now as we reach that point in the technical talks that come out on Saturdays.  It is quite a lot more technically challenging than it might appear, and costs are a major part of this.  A lot of what has been done in the past has used geological sources for the CO2, but to make it work we have to change to using the output from power stations and the like.  It can be done, it won't be simple, but it has a very large potential.
In Alberta they seem to be getting closer and closer to an agreement that would build a CO2 pipeline and system to deliver the stuff. My guess is that it is EnCana driving a lot of this - they invested in the technology early on and have something of a track record of leadership in unconventional techniques. Their CEO, Gwyn Morgan, also walks to the beat of a slightly different drummer - he's the sort of person who I can see driving the building of such a consortium through.

Alberta is a rather perfect test case for this - you've got the considerable CO2 emissions from the oil sands projects, which are only going to get bigger and are created in a relatively small area proximity wise, so collection seems practical, it must be the 'twinning' of pipelines back to the well head which will be costly and time consuming.

The players all have oil sands projects (EnCana is an 'in-situ' oil sands extractor):

Alberta firms study ways to ship, sell CO2

CALGARY -- Major players in the oil sands of northern Alberta are in talks to form a consortium to turn carbon dioxide emissions from hot air into cold cash.

EnCana Corp., Shell Canada Ltd. and Suncor Energy Inc. are all part of the discussions, aimed at setting up a co-operative effort to capture, transport and sell carbon dioxide from the oil sands. Those discussions are still in their early stages, but the group is examining options to create the infrastructure to ship carbon dioxide southward, and find customers.

Oil sands projects, particularly mining operations, emit a large volume of carbon dioxide, but a specialized pipeline would be needed to transport that gas hundreds of kilometres to the mature oil fields of central Alberta, where it could be injected underground and used to push more crude to the surface.

here's an interesting explanation of ghawar and water from an ex-halliburton guy  ---the point implicit in his argument is that peak oil is a farce and matt simmons is a nut.

you can understand this guy's position on peak oil ---him being a halliburton guy and all--- since peak oil is what caused his boss, dick cheney, to yap about peak oil in 1999, call for "a new pearl harbor" to get the oil wars going in 2000, call for 1300 to 1900 new nuke plants in may of 2001, caused cheney's National Energy Policy Development Group to emphasize hydrogen and nuclear electricity in june of 2001, ....and probably caused 9/11, which was the "new pearl harbor" cheney and his merry band of likud loons needed to kick off the wars.

i have known Ali (the author of the piece) for a long time. And what he says, within context, is true.  (And sometime in the future I hope to get around to explaining in more detail some of the production techniques he mentions).  But what he misses is the volume part of the equation.  If a well is producing 10,000 bd with a 30% water cut, it is producing 7,000 bd of oil.  When that water:oil ratio rises to 1 then it is producing 5,000 bd oil, and when it rises to 12 then the well is producing only 769 bd.  To sustain production you have to drill more wells, and you are probably putting these as either infill or step-out from the existing ones so that the field will already be flooded (and you are hoping to take advantage of that for your production).  The problem is that with maximum reservoir contact and intelligent well control (the valves in the wells that were shown in that post) you get the production by draining the field out several kilometers per well.  Thus your well spacing increases (I have explained earlier that with a conventional well it is about 400 yds).  Thus you can only put a lower density of wells into the field.  Thus the theoretical argument for long term production,  applied from the case of conventional wells (of which there are thousands over Texas to get that production) cannot be applied to the MRC well case.
huh! i didnt realize that they are including water in the production figures. where's that guy with the car that runs on water when we need him?

okay, so i'm assuming that a MRC operation involves lots of horizontal pipe. do they drill vertical monitoring wells to give you some warning about the rising water? you dont want the whole damn line going down at the same time without warning, do you?

and if the water level is getting too high, can you back off on the water injection and hope more oil comes into the reservoir, or is it curtains once the water gets too high?

Increasingly they monitor the activity using 3-D and 4-D seismic techniques (the fourth dimension being time).  I had a reference to that somewhere relating to Ghawar and I'll see if I can't dig it out.  

Unfortunately as we have discussed before (and I will again in a couple of Saturdays as I get more into horizontal well development) once you get much water into a horizontal well then it is done.  There are a couple of remedial measures you can apply (multiphase pumping and intelligent valve control) but these are very expensive to put in, and I think that IWC has only just been tried for the first time at Shaybah as Ali mentions - though it has always been part of the plan for Haradh (which will see an increase of 300,000 bd at the beginning of next year

The $280 million Haradh-3 project aims to increase production capacity at the Haradh oil field to 900,000 bbl/d by February 2006. This will involve adding a third, 300,000-bbl/d GOSP to Haradh (in addition to two other 300,000-bbl/d GOSPs, one of which was inaugurated in January 2004). Haradh also will produce significant volumes of non-associated natural gas, natural gas condensates (perhaps 170,000 bbl/d), and sulfur.
. I got the quote from the EIA country brief, in which it also mentions that Shaybah is now looking to increase production another 300,000 bd, which has not otherwise appeared on any  published plan that I have seen, but may be the South Shaybah develpment that Ali is talking about.
What about Kenneth S. Deffeyes observation that the oil bearing rock in Ghawar has dolimite lime steaks that will affect the rate at which oil can be drawn from the reservoir using water injection http://www.princeton.edu/hubbert/current-events-04-06.html
It depends, relative to the overall formation permeability, vertical and horizontal, where the streaks lie in terms of the horizontal bores,
From this table you can see that there are 129,000 producing wells in Texas, and you can also read off their production data.
okay, so texas is pumping 7.3 barrels per day from each of 129,000 wells.

to give us an idea of the scale of this, there are reports that the saudis are injecting 7 million barrels of water a day into ghawar.

another report says they're injecting 500,000 barrels of sea water a day into Haradh to get 300,000 barrels per day of oil back out.

are those figures anywhere close to the truth, or does anyone know?

Ali seems casual about the water cut, stating that the Saudi cut is not exceptional and giving examples of Texas production continuing with much worse water and pressure issues. However, his argument is off the mark. He's not replying to Simmons' central points. Of course production continues, but at much lower rate. Despite new finds and new technology, Texas production peaked in 1972 and continues to fall. This is what Simmons is concerned about happening in Saudi Arabia. If anything, Ali's point proves Simmons' concerns. As pressure drops and water increases, oil production declines despite technology, and you have your peak.
So essentially he cites three regions which are well past their prime (Texas, Alaska, North Sea) as examples why he is confident that the Saudis can fulfill their claim that they are going to be able to produce "15 million for 50 years" (that would be 270 billion barrels btw.) if necessary. Quite convincing indeed...
how many gallons of crude oil does it take to refine into a gallone of gasoline?  does anyone know?  trying to determine underlying (real) price of oil...
The amount of gasoline recovered from unit crude oil volume depends on the type of refinery.  Some refineries get all their gasoline from distilling crude oil (this is called virgin gasoline).  So in this case, the gasoline recovery is proportional to the API gravity.  The lighter the crude, the more the gasoline.  

The gasoline yield is higher if the refinery has "cracking" units.  Almost all large U.S. refineries have crackers, but this is not the case every in the world.

The typial product distribution fo a U.S. refineries is 3% LPG, 10% naphtha, 27% gasoline, 40% middle distillates (diesel, kerosene, jet-fuel), and 20% fuel oils.

I could never understand why drawing down the reservoir too quickly lowers its ultimate recovery.  So thanks to Heading Out for this explanation.

Simmons's "Twilight in the Desert" never explains why this is the case -- which is strange since the whole thesis of the book is about the effect of premature water injection on reservoir life.

By the way, on a general note, the Saturday petroleum geology lessons of this web site are much appreciated.

Ditto. Excellent job, Heading Out!