Is O&G boom over in Alberta?

[toonmaster]

Originally Posted by Tinordi

If toe to heel, vapex, and other solvents are so great why isn't the industry using them in new wells right now?

If you have not reached your recovery %, then you have to prove it is no longer economical to produce using your existing method before regulatory approval will be granted for enhanced methods of recovery.

[Erick Estrada]

Originally Posted by keratosis

I just want cheap gas/ gasoline.

If you live in Alberta you already get cheap gasoline.

[SeeGeeWhy]

Originally Posted by Tinordi

If toe to heel, vapex, and other solvents are so great why isn't the industry using them in new wells right now?

Toe to heel (fireflooding) does not produce commerical rates with existing drilling and completion technology. Controlling the flood front will ALWAYS be the biggest challenge with this idea that "works on paper". The geology needs to be very specifically suited for firefloods to work in practice, and the zones being produced by steam currently just don't have that right shape to them.

VAPEX & Other solvent based methods aren't being used commercially because you can't prove whether or not you recover the solvent. The cost of solvent is very large and if you can't recover/re-cycle, it does not justify scaling up especially when the cost of generating steam is "so low".* That is a huge attitude in industry right now. The main benefit of solvent assisted schemes isn't so much on the economic side, as it is a relief from the water requirements of the project (in my opinion). That's not a bad thing, its just not an economic driver. There are a lot of joint industry studies and pilots ongoing in this area. Lots of papers and research being produced.

*I say "so low" because the present value of the cost of natural gas (including carbon penalties) for a typical SAGD project (30,000 bbl/d, 3.0 SOR at peak rate, 30 year life) is about $350 million at gas prices of $2/mcf. That's not getting any lower any time soon. Just so you know, a project of this size is usually built with initial capital on the order of $25 - 50k/bbl capacity. That equates to 750,000,000 - 1,500,000,000, so fuel+carbon costs being committed to at the inception of the project are a big piece of the returns expected for that project. It makes me laugh with a full fricken belly whenever I hear the phrase "gas is so cheap" in meetings discussing steam production. When your fuel costs are equal to 30 - 40% of your initial capital outlay, in the best possible conditions, you cannot tell me that it is "cheap". Drilling costs are on that order and they're constantly scrutinized and thought to be quite expensive.

The interesting thing about LNG terminals for me is the possibility of natural gas behaving more like a global commodity... which might mean it is not strongly coupled with the price of oil, as it traditionally has been (save for the last 5 years or so). That means increasing gas prices do not necessarily mean increasing oil prices - they move more independently of one another. A scenario of increasing gas prices and flat oil prices would hurt SAGD projects signficantly.

With differentials being what they are.. I think one has to question how much they believe the emergence of tight oil produciton in the US. That's the volume thats pushing Canadian heavy out of Mid-west refineries, driving the differentials wider. There is a GLUT of this production right now, and there are a lot of questions as to what the long term production rates and ultimate recovery factors will be from these formations, for those fluids. I'm watching this one with great interest. Differentials being held wide for a long time would certainly hurt the viability of oil sands projects in Alberta unless we found other ways to either upgrade, refine, or transport our products to gain a more favourable price.

[SeeGeeWhy]

Originally Posted by Tinordi

Most concerning to the industry are increasing whispers about new in situ wells not performing nearly to spec. It's a dirty little secret that most of the best in situ sites are already taken and vertical faults are significantly reducing production from new wells.

I could talk to you about the multiple points you are making for a long time, but what do you mean?

[burn_this_city]

Originally Posted by Tinordi

If toe to heel, vapex, and other solvents are so great why isn't the industry using them in new wells right now?

Where did I say anything about those. That stuff is only being attempted by a handful of producers. Traditional SAGD projects have been successful at incremental improvements lowering SOR and increasing production.

[Skootenbeeten]

Originally Posted by Fozzie_DeBear

The other factor in play is that fracking technology has unlocked incremental oil and gas supplies in the US...thus lowering the demand and price for Alberta product.

Kind of ironic that lots of the knowledge needed for fracking was developed in Alberta

Isn't fracking also unlocking earthquakes?

[Reaper]

Originally Posted by Skootenbeeten

Isn't fracking also unlocking earthquakes?

No, it is not. This is one of the pseudoscience leaps that are made about fracking.

Yes, fracking does involve seismic activity. The seismic activity happens when the frack occurs. Of course there will be seismic activity as frack fluid is pumped at high enough pressure to fracture rock. This does not mean earthquakes. Practically all fracking can't be felt above ground at all.

[red sky]

Yeah difficult to feel on the surface when we are talking 6,000 feet below:

[mrgreen]

http://www.bbc.co.uk/news/science-environment-20595228

[Hi-Psi]

Everything is still going full tilt up north and will continue to do so for years. There are tons of projects either just starting or in the middle of production and they can't find enough workers or camps to fill the demand.

[SeeGeeWhy]

My understanding of the issue with the tight oil/gas boom and "fracking" is that it actually consumes A LOT of water, and let's be honest... the issue isn't the completion method, it is the fact that you're penetrating possibly sensitive groundwater formations above. Cement jobs blow pretty much 85% of the time, so just with the sheer number of wells being put down the probability of future issues just increase.

How happy are you with the quality of a house that gets built during a boom vs one that gets built with awesome contractors during a slow period?

I really would like to see more resources being put towards reclamation of legacy wells in Western Canada, and industry doing a better job of getting good bonds in place.

[JD]

Originally Posted by SeeGeeWhy

My understanding of the issue with the tight oil/gas boom and "fracking" is that it actually consumes A LOT of water, and let's be honest... the issue isn't the completion method, it is the fact that you're penetrating possibly sensitive groundwater formations above. Cement jobs blow pretty much 85% of the time, so just with the sheer number of wells being put down the probability of future issues just increase.

85% is a gross exaggeration, but I do agree that not nearly enough resources and money gets put towards good cementing practice.

That said, when it comes to the zone being fractured, the cement bond around that horizon is good probably 99.9% of the time. Why? Because that's where the good expensive cement is, it's where the highest temperature is which is good for the cement transition, and it's the zone that is most adequately cleaned and centralized. Much of the focus is put on that part of the cement job.

It's the uphole secondary zones that are the big issues. The gas-bearing Belly Rivers and the like. Cheap lightweight cement gets placed along those shallower formations and often not a second thought is given to these zones that also require hydraulic isolation. As long as you can frac the primary objective.

[JD]

Originally Posted by fotze

Oh the service company/cementer advocating to use their overpriced "expensive cement" more, don't see that every day.

True, true! But I'm not that guy anymore, thankfully. Now I get to sit on the other side, blaming all the industry's woes on poor cement jobs.

[SeeGeeWhy]

Originally Posted by JD

85% is a gross exaggeration, but I do agree that not nearly enough resources and money gets put towards good cementing practice.

That said, when it comes to the zone being fractured, the cement bond around that horizon is good probably 99.9% of the time. Why? Because that's where the good expensive cement is, it's where the highest temperature is which is good for the cement transition, and it's the zone that is most adequately cleaned and centralized. Much of the focus is put on that part of the cement job.

It's the uphole secondary zones that are the big issues. The gas-bearing Belly Rivers and the like. Cheap lightweight cement gets placed along those shallower formations and often not a second thought is given to these zones that also require hydraulic isolation. As long as you can frac the primary objective.

I agree with you, and you support my claim in your follow up. Cementation designs are focused on isolating the zone of interest. That's not good enough to protect against what non-mineral right owning stakeholders are concerned about.

I'm sure you've reviewed CBLs. How many have you seen that you can be confident there is isolation top to bottom? It might be less than 10% from what I've reviewed, and in my opinion - that blows.

[JD]

Originally Posted by SeeGeeWhy

I'm sure you've reviewed CBLs. How many have you seen that you can be confident there is isolation top to bottom? It might be less than 10% from what I've reviewed, and in my opinion - that blows.

Well the discussion was initially about frac fluids entering groundwater zones, and I guess I was getting at the argument that's not likely happening in the majority of cases. But yeah, I am there with you on the other side of it - isolation among shallower zones is far more dubious. Operators aren't interested in spending the money to get good cement up to surface.

But another aspect of the argument is that a CBL is only the best of a bad lot of tools for evaluating a cement job. In my experiences, it can be a mixed bag in terms of using it to demonstrate hydraulic isolation.

Originally Posted by fotze

Probably less than .01% if you are needing isolation for all zones with porosity greater than 1-3% (as per unenforced regs).

Also would be very hard to prove isolation without extreme cost.

Yup, this is basically what I'm saying. A CBL is one thing, but many times it's an indicator of sweet-F-all, depending on cement density, tool centralization, presense of microannuli (which may or may not actually be a problem).

Add to that fact, every service company seems to have its own special way of displaying the data and you have mass confusion as to what a good CBL even looks like these days. Overseas was even more fun when Service Company Blue (for anonymity) would do the CBL of our jobs when they were trying to get our cementing work! Nope, no conflict of interest there.

Anyway, what I'm saying is that no CBL would convince me there is or isn't isolation top to bottom. It may correlate somewhat. Empirical observation is really the best tool there is, and in your words, "that blows". The only time you know you have a problem is, well, when you have a problem.

[oilyfan]

So the boom is not over?

[JD]

Originally Posted by oilyfan

So the boom is not over?

The boom was over in 2007.

[GP_Matt]

Originally Posted by oilyfan

So the boom is not over?

It sure doesn't feel like it.

I just just got a bunch of summer wells in. And earlier than usual which makes me think that companies are planning longer term. They only do that if they are confident in cash flow.

[Mr.Coffee]

Originally Posted by GP_Matt

Yes and No.
A lot of gas currently flows from BC into Alberta. A lot of this gas will now stay in BC and be exported instead of coming into Alberta. That is gas that was previously competing with Alberta gas and its absence from the system should help prices.
There are also hundreds of pipelines that currently flow gas between the two provinces and the entire system is integrated. The TransCanada line will start in Dawson and will connect to TransCanada network. This network currently flows into Alberta and can easily be reversed to pick up gas from the Peace region and beyond.
In the end the cheapest gas will go into the pipeline though, so if Alberta gas is cheaper than Horn River gas it will head west. Shell isn't going to drill a new well in Horn River if they can drill cheaper gas in Alberta. (Unless they want enough gas to take from both)

Shell doesn't operate in Horn River. They do have an LNG terminal that I presume they'll be using Montney gas to supply an Asian contract.

Yes Alberta gas may (likely actually) be used in the export of gas to Asia, as these terminals have such large volume asks that producers will have to buy off the grid to fulfill commitments.

Even if no Alberta gas is used, again unlikely, the gas that is then re-routed from BC to Asia reduced supply to Alberta, and Alberta will have to make up the difference for North American demand that BC currently helps satisfy. We will see a rise in nat gas prices in the mid-long term depending on your definition.

[Rutuu]

Originally Posted by SeeGeeWhy

Toe to heel (fireflooding) does not produce commerical rates with existing drilling and completion technology. Controlling the flood front will ALWAYS be the biggest challenge with this idea that "works on paper". The geology needs to be very specifically suited for firefloods to work in practice, and the zones being produced by steam currently just don't have that right shape to them.

VAPEX & Other solvent based methods aren't being used commercially because you can't prove whether or not you recover the solvent. The cost of solvent is very large and if you can't recover/re-cycle, it does not justify scaling up especially when the cost of generating steam is "so low".* That is a huge attitude in industry right now. The main benefit of solvent assisted schemes isn't so much on the economic side, as it is a relief from the water requirements of the project (in my opinion). That's not a bad thing, its just not an economic driver. There are a lot of joint industry studies and pilots ongoing in this area. Lots of papers and research being produced.

*I say "so low" because the present value of the cost of natural gas (including carbon penalties) for a typical SAGD project (30,000 bbl/d, 3.0 SOR at peak rate, 30 year life) is about $350 million at gas prices of $2/mcf. That's not getting any lower any time soon. Just so you know, a project of this size is usually built with initial capital on the order of $25 - 50k/bbl capacity. That equates to 750,000,000 - 1,500,000,000, so fuel+carbon costs being committed to at the inception of the project are a big piece of the returns expected for that project. It makes me laugh with a full fricken belly whenever I hear the phrase "gas is so cheap" in meetings discussing steam production. When your fuel costs are equal to 30 - 40% of your initial capital outlay, in the best possible conditions, you cannot tell me that it is "cheap". Drilling costs are on that order and they're constantly scrutinized and thought to be quite expensive.

The interesting thing about LNG terminals for me is the possibility of natural gas behaving more like a global commodity... which might mean it is not strongly coupled with the price of oil, as it traditionally has been (save for the last 5 years or so). That means increasing gas prices do not necessarily mean increasing oil prices - they move more independently of one another. A scenario of increasing gas prices and flat oil prices would hurt SAGD projects signficantly.

With differentials being what they are.. I think one has to question how much they believe the emergence of tight oil produciton in the US. That's the volume thats pushing Canadian heavy out of Mid-west refineries, driving the differentials wider. There is a GLUT of this production right now, and there are a lot of questions as to what the long term production rates and ultimate recovery factors will be from these formations, for those fluids. I'm watching this one with great interest. Differentials being held wide for a long time would certainly hurt the viability of oil sands projects in Alberta unless we found other ways to either upgrade, refine, or transport our products to gain a more favourable price.

Those fuel costs figures are quite interesting as well as the economic SOR of 3.0; I say that because I was under the impression that SOR's of 6.0 and below were economic (my rule of thumb could be dated as it's been a few years).

I also appreciated your comments on gas price direction as I agree. Oil linked contracts are going out the window in the LNG game down here.

If Cowboy89 could comment on the what the sensitivites of Oilsands company valuations would be to a $6+/mcf gas price with out an increase in bitumen price I'd be very curious.