Hi Kiwigeo,
Your comment regarding the possibility of requiring many more fracked wells in the Upper Angwa due to the possibility of tight permeability is misleading because I do not believe the reservoir permeability will be classified as tight. For gas reservoirs and gas condensate reservoirs, tight rock is classified as permeability less than 0.1 mD. The reports have stated that the expected condensate-gas ratios (CGRs) are in the range 130 to 30 stb/mmscf, so they are expected to contain gas condensate, but if the Upper Angwa contained oil, then potentially a permeability less than about 5mD might be considered tight. Typically, unconventional reservoirs (shale/source rock) have nano-Darcy permeability, and it would be like deciding to frack the source rock layers- not in the plan at all.
As Scott mentioned in one of the recent videos, without having the benefit of 3D seismic, the M1/M1-ST location was probably not an optimum well location, and in an alluvial/lacustrine sedimentary environment there is a possibility that the long-awaited side wall core data will reflect a poorer, more clay-prone sedimentary environment at the edge of the geologic basin. However, on the upside is the potential for thicker Upper Angwa reservoir layers at the planned M2 well location, which is up dip of M1/M1-ST. As you mentioned a few days ago, thicker layers tend to have reduced clay content and therefore better permeability.
I performed some calculations to estimate the expected gas flowrate from the Upper Angwa assuming the permeability is as low as 10 mD. I chose 10 mD as an example of poor permeability because there was published research which showed that during depletion of a gas condensate reservoir (without gas injection pressure support) for a 10 mD sand, the liquid condensate bank around the wells could reduce the gas relative permeability by up to 80%. I also included a very high skin factor of +20 to try to establish the minimum flow rate. I found that 100 ft of reservoir could produce a minimum of 4 mmscf/d, and if there is 225 m (738 ft) of gross pay in the Upper Angwa , and assuming 50% NTG (a complete guess), it should be possible to produce about 15 mmscf/d from the Upper Angwa, excluding the undrilled deeper layers, the Lower Angwa and the Pebbly Arkose (Pebbly Arkose now estimated to be much thicker based on an estimated 60-80m gross compared to 8m gross, has 20% matrix porosity and probably naturally fractured given the amount of mud losses).
Even if the Upper Angwa permeability was found from M1/M1-ST SWC tests to be as low as 10 mD, the productivity of the future production wells could be enhanced by creating propped fracks. I would expect 2-3 times greater well productivity following fracking with increased cost in the range 25% - 40% per well, but it does not mean having to drill many more wells as they do in shale gas fields in the US.
The Pebbly Arkose formation probably has the greatest potential of all the reservoirs. With reference to VOGC’s recent post, the images of the SWC samples at 2418 mMD and 2467 mMD contain blue fluorescence, which should be indicative of liquid condensate in a gas condensate sand. If it was an oil reservoir, we would expect to see gold coloured fluorescence under UV light. Having gas condensates is great news because Invictus Energy has a market for selling the gas. Having 60 – 80m gross and naturally fractured, I would expect to hear outstanding results when the well is flow tested!
Let’s hope the spud date is soon!
