IVZ (ASX) Ann: $15m raised to fund Well Test &amp; Cabora Bassa Operations

Originally posted by Grfe4: ↑

"To have high confidence that all is going to be good with the flow test you'd really need to have the logs in front of you along with some other data. I'd give my left nut to see the field logs for the MDT sampling."

At M-2 and M-2ST the quality of the rock formation and the average porosity in the Upper Angwa do not appear to be as good as in the Lower Angwa. In the Upper Angwa, in M-2 and M-2ST most of the potential reservoir horizons appear to be below the standard petrophysical cut-off criteria, so how might Mukuyu be transformed into a commercial development?

In his most recent webinar (14 December 2023), SM stated there may be need for well stimulation to get the gas to surface. I have therefore included an extract from PetroWiki on tight gas sands (below), which highlights the benefits for "large scale" (propped) fracture treatments that can transform marginal/ non-productive horizons (e.g. with porosities in the range 6-9% and with Sw in the range 35-50%) into commercially viable gas condensate fields.

In deep, high pressure, thick reservoirs, excellent completions can be achieved when the formation permeability to gas is in the microdarcy range (0.001 md). In comparison, in shallow, low pressure, thin reservoirs, permeabilities of several millidarcies, might be required to produce the gas at economic flow rates, even after a successful fracture treatment. (PetroWiki: Tight Gas) PEH:Tight Gas Reservoirs - PetroWiki (spe.org).

I would expect the over-pressured sands in the LA to produce at reasonable stable flow rates initially provided a reasonably large interval of reservoir is opened to flow. If the same interval is flow tested for several days or weeks, the best way to maintain a stable flow rate would be to limit the drawdown during flow testing and production to about 1500 psi and of course having many production wells would help to limit the drawdown, but that would be too costly. My plan would be to assess whether it is possible to perform large scale (economically viable) propped frac treatments in each of the multi-lateral wells i.e. can each lateral be stimulated independently without affecting the final frac treatments in the neighbouring laterals? Hydraulic fracture treatments may be a necessity in the Upper Angwa, but there may also be economic benefit in enhancing production by fracturing each lateral in the Lower Angwa. Each well containing multilaterals would usually be assigned to a particular fault block and the largest fault blocks would require more than one multi-lateral well to achieve full areal coverage. There would likely be some areal variation in reservoir quality within a fault block because the depositional environment is fluvial and alluvial, and 3D seismic data would certainly help in optimising the location of each lateral well.

What can happen if there is no drawdown pressure control during flow testing and production? During extended flow testing and during the production of over-pressured zones, there would be a tendency for the porosity to decrease over time (increase in the net overburden pressure). Consequently, the pore volume compressibility is expected to be larger in the over-pressured zones compared to normally pressured zones, and the relatively high water saturations (30-50%) in poor/tight rock should allow for some pressure support by way of water expansion as the pressure drops. On the other hand, gas compressibility at very high pressure is lower than it would be at hydrostatic pressure. A reduction in porosity due to pressure depletion would normally correspond with a decrease in permeability for a sandstone (decrease in flow rate), hence the need to limit the drawdown in order to enhance the recovery factor and stabilise the flow rates. Well stimulation also enhances the recovery of hydrocarbons and helps to stabilise the flow rates.

Obviously, it is difficult to make meaningful recommendations based on very limited field data and with not having access to the simulation model. I am sure most of us would like to know what is considered to be the minimum gas in place required to make the Mukuyu field development economically viable? How low would the average permeability need to be before the net present value (NPV) is negative (1 mD?). How many triple-lateral wells, each containing hydraulic fractures, and the total cost (10-15 wells and a total of 30-45 laterals on Mukuyu)? Average sales gas price allowing for sales to industry and to the domestic market in AUD/mscf?

Best regards,

Expand

Also you again quoted the number of wells in an unconventional gas system. Again incorrect as conventional gas onshore discoveries need minimal well amounts together with lateral wells. Porosity and permeability values represent a conventional gas system for IVZ

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1	150000	0.069
8	567793	0.068
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827176

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Price($)	Vol.	No.
0.071	150000	2
0.072	22928	1
0.073	317251	4
0.074	724171	3
0.075	1008979	3

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150000

0.072

22928

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317251

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724171

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1008979

(20min delay)
Last 7.0¢		Change 0.000(0.00%)		Mkt cap ! $106.1M

Open	High	Low	Value	Volume
7.0¢	7.0¢	6.9¢	$34.93K	503.7K

Ann: $15m raised to fund Well Test & Cabora Bassa Operations, page-768

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