Decided to post this here instead -
Sharing a post from Steve 73 on Adfvn which goes into quite some detail about the likely processes taking place over the next 3 to 6 months re. Lancaster EPS.
"The 72 hour contractual “test-run” won’t (or is unlikely to) be a “start/run-for-72-hours/stop”. Operation.
Once all their tests on the wells and topsides (and I’m still expecting a “dummy” offload - i.e. position using DP & connect up to a shuttle tanker, but no actual transfer - to be part of this testing), and both wells are online at the design rates, they will simply declare that a stable 72 hour period has been achieved. They won’t necessarily shutdown production again at the end of it.
But then I’m not expecting them to keep running “forever” at that stage. They have already stated that the first 3 months of operation is expected to average 6.5 kbod, which is equivalent to one well operating 100% of the time at the minimum flowrate (to avoid low temperatures in the flowline), or 2 wells operating at design flowrate for just 32.5% of the time. Whatever they’re planning lies some where between those 2 extremes. For the next 3-6 months they’ve stated they intend to operate at 13.5 kbod average. These “reduced” rates are very unlikely to be due to any constraint imposed by either well performance or operational topsides issues, but a desire to gain information & understanding.
What follows is my understanding of what they’re hoping to achieve, and why. My background is not subsurface, although I’ve worked closely with enough different teams to understand some of their needs for evaluating reservoirs.
When you flow a well at any given rate, the bottom hole pressure or BHP (usually measured at the heel of a horizontal, rather than the toe) immediately drops. The difference between this and the reservoir pressure is the “drawdown” and is used to calculate the IPR (Inflow Production Rate). Shut off production and the BHP should very quickly balance out to the original reservoir pressure. The drawdown will normally exhibit a fairly linear relationship with production rate.
But with extended production over time the BHP will steadily drop as the immediate surrounding reservoir gives up its production, and the rate of this pressure drop depends on how much pressure support there is from the wider surrounding reservoir, or from a gas cap (which Lancaster does not have) or from an underlying aquifer (which HUR believes it does have). Shut in production at this stage and the BHP will take much longer to stabilize (since a wider area of reservoir was depleted), although eventually it should return to the original reservoir pressure. The longer you run and the more oil you produce, the longer it takes for the pressure to fully recover. These extended PBU test will give valuable information as to the wider reservoir characteristics, and more importantly the strength of the aquifer support (which may determine if supplementary water injection is necessary for the FFD’s).
The other test’s I envisage them doing during these first 3-6 months are interference tests between the 2 wells. By flowing one well only and observing how the BHP of the off-line well (which is effectively the reservoir pressure at that distant location) they can further build up the picture of how the wider reservoir is reacting… And then when the producing well is shut off, the BHP recovery from the offline well gives yet more data.
All this data will allow them to fine-tune their computer Reservoir simulation models. If they can match their model to the way the real thing performs over a 6-12 month period, they can be much more confident that it will provide more accurate predictions over the much longer timeframe, and hopefully for their wider FB acreage.
Being “allowed” to run these rate reducing data-gathering tests, rather than having to operate at maximum rate (in order to pay off debts and/or shareholders) is a VERY RARE luxury for a production field. A clear reason why this is called an EPS rather than a First Phase development. This is the benefit of having the geologist Dr. T firmly in the driving seat.
The value of information (which is often somewhat difficult to accurately quantify) is clearly regarded as being higher than the value of the additional oil (which can be very accurately calculated)…
Sorry to have “gone on” a bit, but hopefully it will have answered many others’ questions of "why can’t we increase the rate sooner?
Of course, it’s all JMHO."