The Case for Offshore Steam

When we talk to folk in the industry, about our plans to steam the Pilot, Elke & Narwhal fields in the middle of the Central North Sea, sometimes we get a pretty sceptical reaction, sometimes we don’t. 

I prefer it when we get to talk positively about the potential of steaming offshore reservoirs, but not everyone has an open mind. You see, that’s not how the industry develops heavy oil in the North Sea. How to develop North Sea heavy oil was all worked out in the early nineties by the people who put together the development plans for Alba, Captain, Harding & Gryphon, the last big wave of heavy oil developments in the UKCS.

Those were stunningly successful development plans, none more so than the Harding development plan, which is reputed to be achieving a 74% recovery factor from the Harding Central reservoir. Who could do better than that?

So the industry already knows how to develop heavy oil in the North Sea. It is pretty simple, maximise well productivity by having long horizontal production wells, put them as high in the reservoir section as possible, sweep as much water around the system as you can and Bob is your proverbial uncle.

Harding Platform in UKCS Block 9/23b

Harding Platform in UKCS Block 9/23b

There is no doubt in my mind that those fields were developed in the best way possible. Modesty forbids me from mentioning that as a youngster, I led the BP team that prepared the Harding development plan and, back then, we had a great team designing a development scheme which in the end delivered even more than our most optimistic forecasts.

"Modesty, you were meant to stop me mentioning that."

The development plans for Mariner, Kraken and Bentley don’t just pay homage to the fundamental nature of the reservoir depletion plans from the nineties, they copy them. Yes, the well density is tightened, the water handling capacity increased and the well designs take advantage of new technologies like multi-lateral junctions, but fundamentally what is being done to these reservoirs is just the same as was done to Alba, Captain, Harding & Gryphon.

But the heavy oilfields of the nineties were (Captain excepted) a very different kettle of fish from the heavy oilfields that are being developed today. For one thing the oil wasn’t actually all that heavy, 18º to 21º API, and at reservoir temperature, not all that viscous, at about 10 centipoise, cP. 

What does that mean? Well, the critical parameter, in working out how effective a water flood process will be, is the mobility ratio; that is, the mobility of water divided by the mobility of oil. As that ratio increases the sweep efficiency suffers and the recovery factor falls. Captain oil has a reservoir viscosity of about 90 cP, which means the mobility ratio is about ten times the Harding mobility ratio, so the expected recovery factor for its water flood is about 35%, roughly half of the Harding recovery factor. That difference is nothing to do with BP engineers being smarter than Chevron engineers, it’s everything to do with the nature of the oil. Chevron had hoped to boost the Captain recovery factor towards 50% by adding polymer to the injection water thereby improving the mobility ratio, but that project seems to be a casualty of the oil price slump.

This next generation of heavy oil fields sport oils with reservoir viscosities that run from 100 cP to as high as 1,500 cP. Viscosities that high make a huge difference to the mobility ratio and thus the proportion of oil in the fluids coming out of the ground. So, it isn’t only the recovery factor that suffers, the water handling capacity required soars. Take a look at the picture below. It shows the actual oil and water production profile for Harding and the projected oil and water production profiles for Kraken and Bentley.

Water and oil production profiles for Harding (Source OGA), Kraken (source EnQuest investor presentations) & Bentley (source Xcite CPR)

Water and oil production profiles for Harding (Source OGA), Kraken (source EnQuest investor presentations) & Bentley (source Xcite CPR)

You can see how the proportion of oil in the total produced fluids is falling as viscosity increases. For Bentley, based on Xcite’s reservoir modelling, the proportion of oil in the produced fluids is just 4.4%. Xcite will have to produce nearly 6 billion barrels of fluids to get over 250 mmbbls of oil out of the ground. That is an extraordinary volume of fluids and it takes a lot of wells, equipment, money and energy to move that volume of fluid out of the reservoir, process it and re-inject it.

But what else can you do? The oil is the oil, you can’t change that. Well that is true, you can't change the oil but you can change its viscosity. Oil viscosity varies dramatically with temperature and you may have noticed steam is hot. Indeed, at Pilot reservoir pressure, steam is 600ºF hot, and at that temperature our oil viscosity, indeed anyone’s oil viscosity, is in single digits.

Heat the oil up, sweep the reservoir with steam and the recovery factor can be fantastic. Steam flooding heavy oil reservoirs is a well proven technology onshore that delivers exceptionally high recovery factors, up to 80%. No one disputes the potential for steam flooding to deliver a very high recovery factor, if we could only apply it to the high permeability sandstone reservoirs we are blessed with in the North Sea.

The RECOVERY FACTOR case for steam is well proven.

But the sceptics and naysayers believe the cost of steam, especially the cost of generating steam offshore will far outweigh the benefits. But that just isn’t true. However, you do have to start to think differently about how and when to apply a steam flood. Most people imagine that steam flooding is an enhanced oil recovery (EOR) technique, and of course you only ever think of applying EOR techniques after you have captured all the easy inexpensive oil and the field is on its last legs and you are desperately trying to defer decommissioning. If I sound like a cynical person, it’s because I am. EOR is the red-headed step-child of the oil and gas business.

An EOR project is how most steam flood projects have started, but it actually makes no sense. It makes no sense to push water into a heavy oil field to force some of the oil out only to have to sweep all that water out of the reservoir with steam as you try to eke more oil out to boost the recovery factor.

No, the right way to go about it, is to steam the reservoir from the start; and to steam it quickly. The key to a successful steam flood is to minimise the heat losses and the way to do that is to inject steam at as high a rate as you can and to sweep the reservoir between injectors and producers as quickly as possible.

Here is what a production profile for a steam flood of the whole Pilot field might look like, based on the thermal reservoir simulation we have done so far. The profile is flat and short and the proportion of oil in the fluids we pump out of the reservoir is projected to be even higher than the Harding field. The field life is just eleven years, not the thirty-five years required to produce Bentley with a water drive scheme. 

Pilot profiles based on thermal reservoir simulation of four representative sectors of the Pilot field and c. 100,000 bcwe/day of steam injection

Pilot profiles based on thermal reservoir simulation of four representative sectors of the Pilot field and c. 100,000 bcwe/day of steam injection

That’s two thirds of your operating costs saved. Combine that with reductions in facilities capacities and there is more than enough money saved to pay for the steam boilers. The cost of the gas you need to burn is not trivial but between the potential for a doubling in reserves and the operating cost savings... 

…the ECONOMIC case for steam is well made.

But what about the emissions? What about the carbon footprint? Well I am not going to claim that this is something that we should ignore, but in a conventional water drive scheme all that water doesn’t move around the reservoir by itself, it takes energy to do that and energy that is expended for more than thirty odd years.

Based on Xcite’s 2013 environmental statement the carbon footprint of producing Bentley oil was expected to be over 60 kg CO2/bbl. The production profile in that 2013 environmental statement had over 7% oil in the fluids produced so I suspect an updated environmental statement would have a higher carbon footprint. I might be wrong, however the 2013 statement is all that is in the public domain.

We estimate that a gas fired steam flood of Pilot with a steam oil ratio of about 2 barrels of steam for each barrel of oil would have a carbon footprint of about 55 kg CO2/bbl. That is already an improvement on the Bentley environmental impact, but it’s a heavier footprint than Statoil expect for Mariner, which is about 35 kg CO2/bbl. Not by much though, and it’s a gap that technology could bridge.

If we could improve our steam oil ratio we could substantially improve our carbon footprint. MEG Energy give us a clue that such a thing is possible, they have seen a dramatic improvement in steam oil ratio as they have implemented a methane co-injection scheme in their SAGD project in Alberta. They report a significant reduction in steam requirements and a lowering of the steam oil ratio from 2.7 to 1.3 (see slide 8).

If by adopting that innovation we could achieve a steam oil ratio of about one, that would be a 50% reduction in our steam requirements, with that, our carbon footprint could be among the best in the UKCS, possibly as low as 30 kg CO2/bbl.

And that makes the ENVIRONMENTAL case for steam.

So there you have it, an overwhelming case for steam in terms of the recovery factor, the economics and even the environmental impact.

What’s not to like?