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62strat, I slipped (Freudian) up on the extra M and did indeed mean 17.5 Mbbl/d.

I think your concerns about water production are warranted however the operator has taken some calculated steps to mitigate this risk.

First - they drilled a pilot well through the reservoir in order to determine exactly where the oil/water contact is. No guessing allowed.

Second – they took core, at considerable expense, through the reservoir and I’m presuming that this would have included some core through the water leg. This would provide the operator with solid information on the permeability of the reservoir in both the oil and water legs. This in turn would allow the application of some science to place the horizontal leg of the well an optimal distance above the water contact. The further away the well is from the water the less likely water will be produced. Taking core adds additional value in that the cores are logged and calibrated in the lab. This means less error when logging the wells with wireline logs as the tools are calibrated to known conditions of rock and reservoir fluid. Greater accuracy of measurement allowing less uncertainty of reservoir parameters yielding greater precision of well design, production forecasts and eventual reserves upgrades.

Third – The development wells are horizontal. This not only keeps the well away from the water and increases the areal drainage of the reservoir it spreads the pressure drop over the length of the well. Think of a drip hose in reverse. A short length of hose connected to the mains will spray water a greater distance than a long length that has a greater number of holes in the hose. In production terms this means a lower pressure pushing oil into the well and less pressure sucking water up from the water leg. From memory I think the wells have a total combined length of 2,900 m. That’s a long length to drain the reservoir, keep the drainage pressure down and stay away from the water.

Fourth – The production design calls for a production rate of less than the facility capacity. The expectation is that the field will produce at 17.5 Mbbl/d and not at the facility capacity I recall ~ 25Mbbl/d. I’m thinking that this is another mitigation to water production by keeping the production pressure low so as to reduce the possibility of pulling water up from the water leg. Many operators in the past have pulled on the reservoir to its capacity to produce only to have water pulled in earlier than optimal. Short term cash flow at the cost of early water production which reduces the oil production and ultimately reduces the reserves.

Will all this absolutely prevent water production? Nah. It does show, however, that these guys know what they’re doing, have learned from industry experience, are not cutting corners and have taken as many actions as necessary to reduce the early water production risk. In my experience there are not many operators acting with this level of design and diligence.

Regards,

OPT