Offshore Steam: What's the Problem?

Update June 2015: An excerpt from The Steam Oil Production Company Ltd presentation at DEVEX 2015 which covers most of what is in this article

When we first start to talk to potential partners or investors about steam flooding the Pilot reservoir there are often sceptical looks and occasional concern that I might have lost my mind. A favourite question is "Well are there any offshore steam floods?"

The answer to that is "Yes, but not many." We have identified three locations – Lake Maracaibo in Venezuela, Bohai Bay in China and the Emeraude development offshore Congo. None of them are in very deep water, Emeraude is the deepest at 65m, and none of those fields are in harsh environments like the North Sea. So Pilot wouldn't be the first offshore steam flood, but it would be a pioneering project.

We have rifled through the literature and scratched our heads, and tried to work out why people have been so sceptical about taking steam offshore. It seems that there are three main reasons.

Firstly, there aren't all that many good candidates. The conventional thinking is that the reservoir has to be shallower than 3,000' and there are not so many offshore reservoirs that qualify. In fact in a review of EOR techniques done by the University of Texas at Austin for the Danish Energy Agency and Maersk they "did not investigate steam flooding because North Sea reservoirs are too deep and above the pressure limits for successful application." Well, most are, but not all the Pilot reservoir lies at 2,700'.

Secondly, before the advent of horizontal drilling, the sheer number of wells required to implement a pattern steam flood offshore would have been daunting, if not completely impractical. Most steam floods have well spacings that are somewhere between two and a half acres and ten acres. To implement a five acre spacing on Pilot would take about about three hundred wells: that is just not practical. However, a pattern of closely spaced horizontal wells, about 100m to 150m apart, works more effectively than even a dense pattern of vertical wells and is much more practical to implement offshore. Based on a 100m well spacing we will need about 42 wells for Pilot. 

However, even in the horizontal well era, not many people thought steam injection could be done offshore. Here is some of the conventional wisdom:

No, too much heat loss in riser to ocean water”, National Petroleum Council, Global Oil & Gas Study, Topic Paper #22 Heavy Oil; Table IV.4b. page 13, 2007
Potential for heated injection fluid processes are limited in cold or deep water by heat losses in transit.… Even with equipment advances such as vacuum-insulated tubulars, heat losses above the mudline could be unacceptably large.”  Technical Challenges for Offshore Heavy Oil Field Developments, OTC 15281, 2003

At first, we agreed with that conventional wisdom and were exploring interesting technologies such as downhole steam generation (see the video) and vacuum insulated tubing, as well as simpler approaches such as insulating, gel-based packer fluids.

And then we did some calculations.

It turns out that for the kind of wells we are planning in Pilot, heat losses are not such a big deal. You see the conventional wisdom was formed by thinking about typical onshore steam injection wells, maybe injecting 1,000 barrels per day of cold water equivalent (bbls/day cwe). In these sort of wells by the time you get down to about 3000' the proportion of the water that is steam, or the steam quality, can have fallen to less than 60%. Add in 80m of the cold North Sea and a good assumption seemed to be that we would have 50% steam quality at the sand face. In fact all our early work was predicated on exactly this assumption – we assumed that getting the heat into the reservoir would be a very inefficient process and a cost the project would have to bear.

But we were completely wrong. Pilot, along with many other North Sea fields, has a tremendously good reservoir with very high permeability and we expect to be able to inject somewhere between 10,000 and 20,000 bbls/day of cwe into each and every injector. Now the rate of heat loss from the wellbore is just a function of the temperature difference between the well and its surroundings, and the temperature of a steam injection well is constant whether the well is injecting 1,000 bbls per day cwe or 15,000 bbls per day cwe. That is because the steam temperature is dictated by the pressure. As the fluids in the well lose heat, the steam quality falls; but the temperature doesn't change, that may seem odd but that's thermodynamics for you.

We have modelled this on our own wells but the chart above is a good illustration of the concept from a paper extolling the virtues of vacuum insulated tubing. The dark blue lines show the loss in steam quality vs depth without vacuum insulated tubing, the magenta lines are for a well with the insulated completion. The top chart is for a 1,000 bbls/day of injection of 80% quality steam, and the bottom one is for 1,500 bbls/day. The figures are a little blurry but at 3,000' the top chart says the steam quality will fall from 80% to 58.8% and the bottom chart says it will fall to 65.8%. There is an easy calculation that one can do to work out what the heat loss would be at a higher rate. In the top case 1,000 x (80% – 58.8%) bbls per day condense, that's 212 bbls/day, in the bottom case 1,500 x (80% – 65.8%) bbls per day condense which is 213 bbls/day, the heat loss is effectively constant just as we would expect. So in a well injecting 10,000 bbls per day, 212 bbls per day would condense and the steam quality would reduce by just a little over 2% from the top of the well to the bottom.

As long as you have a good quality reservoir and can achieve high steam injection rates, heat loss in offshore wells is a minor concern, not the stumbling block that the conventional wisdom held it to be.

So what's the problem with offshore steam? Well the simple answer is, there is no problem.