horizontal drilling at snatcher, page-20

Reservoir Flow Rates - the physics of why a particular reservoir flows at a particular rate is very complex and because the rock is remotely measured (the fluid and even rock cores change when depressurized at surface), a detailed accurate answer is seldom possible without a direction flow test.

But rules of thumb and anologs to other fields are very useful. For example, if you have a wide-spread coarse grained sandstone with measured high porosity and good permeability (the measure of how well the individual pores are connected) and the pressure of the rock is supported by a massive water drive below, you can expect a flow rate of ~1500+ bopd. This is typically the case for massive sands like the Namur and especially the Hutton.

The Birkhead sands are thought to be more sporatic and deposited in a set of stacked channels. This results in a wider range of production rates. Some wells (Growler, Spencer) are capable of high production rates while other Birkhead wells even in the same field may produce at much lower rates. This is because the reservoir porosity and especially the permeability varies depending on whether you are in the middle of a thich set of stacked channels or off to the side of a channel which only gets coarse sand in a massive flood (think downtown New Orleans one day in 1,000). These 'overbank' deposits will still produce oil but at lower rates.

Using the flows of similar wells and looking at the reservoir measurements and descriptions an experienced geologist/engineer can make a pretty good guess but it will not be certain or accurate enough to state in a press release. It does however tell you whether you want to case the well as a producer and drill a step out well. You would always like the flow test but if this is operationally not possible you use the data at hand and decide what to do with the well.

We will have to wait for the cased hole production to see where Snatcher 1 fits in.

Water Coning - The other big factor in deciding whether to flow the well at maximum is 'coning'. Water underneath the oil is less viscous and will preferentially flow instead of the oil. If you suck too hard on the zone you may draw the water up into your perferations and produce mostly water. In extreme cases the well would need to be redrilled/remediated to resume profitable oil production. In my experience I have seldom seen two engineers from different companies agree on what is the best rate. Putting away the vagaries of the science, many times one company needs the cash flow from the potential increased production and is willing to take a bit of risk coning the well while the more conservative company is not under the same finacial pressure.

Tui - Horizontal wells - yes horizontal wells are at 90 degrees to vertical and my 180 was a typo (brain snap). Also if the Charo/Snatcher wells were in the same channel you could drill a horizontal. But if the verticals drilled to date produced at a solid economic rate and would drain all the oil, the value of a horizontal would only be the economic value of accellerated oil production. Intuition tells me the horizontal would not pay for itself but most companies run spreadsheets on these kinda of what-if options while developing the field.