What's all this appraisal business then?

Everyone knows the oil and gas value chain, I have drawn it for countless investor and strategy presentations, from my days in short trousers in BP's Corporate Planning Department to yet another roadshow presentation for investors. Here is one I had prepared earlier, no need to draw the picture yet again.

Note the drop shadows, very skeuomorphic, very early 2000's.

Note the drop shadows, very skeuomorphic, very early 2000's.

Working forwards it is all pretty obvious, first of all you get the acreage, then you explore – shoot seismic and drill a discovery well, boom success. That is the investment story of most E&P juniors, that is capital E and small p juniors.

Working backwards, it is pretty straightforward too, producing oil and gas is how most oil companies get their revenue, and developing discoveries (drilling wells and installing production facilities) is what you need to do to get production going. But what is that appraisal stage in the middle? That can't be all that important, surely the exploration company finds the oil and sells it on to a major who develops it.

Well not quite, in my opinion, after the moment the bit penetrates a reservoir for the first time and the geoscientists' dreams are put to the test, the appraisal stage is the most critical step in the whole process. It is where all the decisions are made that shape how profitable the development project will be. There is also a lot of money to be spent delineating the discovery and gathering the data that enables those decisions to be made.

That investment and the ingenuity that can go into shaping a development plan explain why discoveries that change hands without a fully formed development plan are often valued from 50¢/bbl to $3 per barrel and those that have a good development plan, approved by the authorities and perhaps even financed, are valued significantly higher, from $4 to $10 per barrel or sometimes even more.

Transaction or market values for discovered but undeveloped oil and gas fields in the UKCS; value per barrel plotted against the oil price prevailing at the time the deal was struck; data from 2008 to 2015. Projects are fields which changed hands just before or just after government approval. Discoveries are fields which were sold well before government approval.


Transaction or market values for discovered but undeveloped oil and gas fields in the UKCS; value per barrel plotted against the oil price prevailing at the time the deal was struck; data from 2008 to 2015. Projects are fields which changed hands just before or just after government approval. Discoveries are fields which were sold well before government approval.

E&P company share prices often soar in the run up to the moment when the drillers get into the reservoir, only to slump if nothing is found or slowly sag, even if a discovery is made, as investors realise that there is a lot of work to do to get from a few dollars per barrel of value to the double figures that everyone hopes their discovery is worth.

The money invested in appraisal matters, it is $1 maybe $2 per barrel, for example the wells drilled on our Pilot reservoir would cost at least $100 million if we had to drill them today, that's 70¢/bbl. 

But I want to focus in on the ingenuity, the conceptualisation of the development plan. Why? Well, the reason for that is simple, that is the bit I love doing.

1990 Harding development plan, gravity based concrete platform planned to be installed over Harding Central, many deviated production wells, Harding South developed using a subsea template. Seawater injection planned.

1990 Harding development plan, gravity based concrete platform planned to be installed over Harding Central, many deviated production wells, Harding South developed using a subsea template. Seawater injection planned.

Let me tell you a story from 1991. 

Are you sitting comfortably? Well, it seems a century ago now, but in those days I was working for BP,  and I, along with David Madill and Hamid Khatib, were put in charge of the Harding development team not long after BP had bought Britoil. The field was called Forth then, after the river, as Britoil had liked to name their fields, but was renamed in honour of the late David Harding who was running BP Exploration in Europe when he passed away.

When we took over the project the field was really well appraised, lots of wells had been drilled and there was a top quality 3D seismic survey over the field. Truth be told, we didn't really have to gather more reservoir data. There was also a development plan, already in the works. It involved drilling lots of deviated wells from a concrete gravity based platform and Harding South was to be developed with subsea wells tied back to the main platform. Pressure support was planned to come from five injection wells which would have used sea water, though that was going to cause a lot of scaling problems. The only trouble was that it didn't quite meet the hurdle rate that BP had set for its projects back then, a 25% internal rate of return at $18/bbl. Those were the days.

So we looked at it this way and that; we knew we had to get the capital costs down, we thought we needed to cut 25% off the budget; it would help if we could get the recovery factor up as well. In conversation, we came up with an idea. I remember sitting with Hamid and Dave, drawing blobs on a whiteboard, we had the idea that if we could switch to horizontal wells (common place now, but not then) we could locate the platform between the two reservoirs, we would save all the subsea costs and maybe the horizontal wells would cost less and improve the sweep and the recovery factor. Then Colin Percival wandered past our office, scoffed at our target of 25% reduction and said – "What are you going to do, saw off a leg and have a three legged platform!". 

The approved Harding development plan, with fewer horizontal production wells, a TPG-500 drilling and production facility placed between the reservoirs and water source wells included.

The approved Harding development plan, with fewer horizontal production wells, a TPG-500 drilling and production facility placed between the reservoirs and water source wells included.

Anyway, we decided we needed to prove we could actually drill and complete horizontal wells in the very unconsolidated sandstones in the Harding reservoir, and we went and asked for the money to do that. We also ran a design competition between the gravity based platform and the TPG-500, which had, you guessed it, three legs.

Darn it, but didn't it all work out. The approved development plan was based on horizontal wells, drilled from a TPG-500 sitting on a concrete base. We also got our injection water from a shallow aquifer that didn't have any sulphate ions in the water so we solved our scaling issues as well.

The upshot was we flew over the hurdle rate and the net present value of the new development plan was four times the original plan. Not a bad result? The basic idea had taken an afternoon, and then about eighteen months to prove it all. And did horizontal wells help the recovery factor? Well, when we modelled it at the time we thought we could sweep up an extra 20 million barrels; it turns out we were being cautious – in fact by 2010 Harding Central had recovered 70% of the oil in place and the team working the field at that time planned to boost the recovery factor to 74%, one of the highest in the North Sea.

Harding turned out to be a very successful, and credit to the project team, a very well executed, project, but its profitability was shaped on a wet afternoon in Glasgow and the reality is that getting the right concept for a development defines the value of the project. 

Ingenuity and innovation need to be encouraged, but the industry struggles with any concept that isn't conventional and proven. In 1991 there hadn't been too many horizontal wells drilled in the North Sea and the idea of using a drilling and production jack-up was quite left field. I think we would have struggled to get our concept through the stage gate processes of today.

Those corporate processes are designed to batter risks out of projects but they often squeeze out innovative and profitable ideas too. But in the early nineties BP knew things had to be done differently to work and our management gave us the room to do that. If the UK is actually going to maximise recovery we need brave managements and investors willing to back ingenious ideas and novel development schemes.