What can I say Mike - I have an excellent Continuity Assistant!😉

@@himanshuchandrajoshi9270 thanks - I really appreciate the feedback! Cheers

​​@@petrophysicsrocks one question, when we calculate the rate of flow we require the pressure difference that will be used in Darcy equation. For that we need reservoir pressure for all the formation that has been penetrated by wellbore plus bhp? Or just one value reservoir pressure for whole as shown in the slide.

@himanshuchandrajoshi9270 - the spreadsheet uses an “average” reservoir pressure to calculate the Net Overburden to calculate an appropriate in-situ correction…….. but IN ADDITION it then uses a single drawdown pressure (differential pressure across the sand face) to calculate flow across each foot down the core/wellbore. As this is calculated in each row of the spreadsheet - it’s a relatively simple task to input a variable reservoir layer pressure and a more accurate wellbore pressure (perhaps with frictional effects?) and then, as you hint at, calculate a variable effective drawdown down the well…….. I just keep it “simple” and say this reservoir is at 10,000 ft and 7000psi - it’ll have X overburden correction and will flow at Y rate given Z drawdown.

Thanks @stevedsouza7735 appreciate the kind words - that’s my main aim, to make things a little more accessible for a wide range of people! Cheers

Thanks for the comment @RedentSC - the interactions really help the KZbin algorithm - apparently! Now I have to admit to not being an expert in what makes a good LNG source gas, but yes there is plenty of gas as well as oil in the Falklands basin (a useful source of fuel to operate the oil production facilities?). I know that Shell (for one) were looking at running a few floating LNG processing plants around the globe to mop up small offshore gas accumulations - that wouldn’t justify a full onshore processing facility. So I assume that’s the sort of thing you’re getting at for these remote operations? However, I would say that the Falklands is so remote that, whether you’re offshore tanker loading for Oil or LNG, I would have thought it would be similarly challenging from a marketing perspective (again though, I can’t pretend to be up to speed with the economic modelling side of things). I should also say that although I mentioned the fluids were a bit tricky (waxy - a common feature of lacustrine source rock) - the oil flows well enough down hole and through most of the sub-surface pipework - it’s not really until the fluids get to the surface processing facilities that you’d probably have to look at some additional heating. Certainly when we looked at the “Flow Assurance” studies…there were no real “show stoppers” as we would say. There’s probably over 1 billion barrels of oil in place in the Sea Lion area - it was/is a tantalising prize…..it’s obviously also in a very environmentally sensitive area - as an Engineer, it’s the sort of thing you want to work on!

Thanks @chichengxu - much appreciated! 👍

Hi @davidanderson7389 thanks for the interaction! Well I have to be careful here, as I’m not an “Unconventional” kinda guy (“Unconventionals” is the term generally given to reservoirs that were previously considered as essentially source rocks!)…. In “conventional” reservoirs - these kerogen (organic) rich shale SOURCE rocks are buried to depth, heat up and generate oil and gas. This then flows (migrates) through porous and permeable carrier beds until it is trapped by a sealing formation in a porous reservoir rock. This presentation focusses on flowing oil out of these conventional reservoirs, and how much is left behind in our “sandstone sponge” if you like. We may also be interested in trying to evaluate the residual oil left behind in the carrier beds on the migration pathways - to try and prove and understand whether the rocks in the basin were at least generating hydrocarbons. Then “all we need to do” with our next well, is find a place where the oil may have moved to! Many a time a desperate geologist has tried to explain his/her near-miss exploration well…by being on a “migration pathway” or having a “leaky trap” - allowing the hydrocarbons to escape….if only we’d drilled the well 25 million years ago! So in unconventional reservoirs the hydrocarbons are generated in-situ by the organic shales themselves and have not really moved anywhere - so I guess by my definition here they wouldn’t be considered residual? However, we are interested in how much hydrocarbon we’re leaving behind in our commercial production schemes, when we rely on fractures to connect us to large-cross-sectional drainage areas….there will be a certain drainage efficiency (before we have to come back and re-Frac the wells). I’m aware of some Nuclear Magnetic Resonance (NMR) techniques to better evaluate the kerogen richness of the source- then we can estimate the hydrocarbon generation potential - then I guess the potential minus the production will give some estimate of the “residual” …..but I thought I had it tough in evaluating the “measurements” we make…….the Unconventional Dudes don’t even seem to have many measurements to evaluate….only differences in “estimates”? Sorry for the long rambling answer….perhaps some of the “Unconventional Folk” can provide more brevity and clarity!

Hi @jearizah - thanks a lot for your comment and engagement......I have to admit to a slight memory loss (as I actually did this work in 1994....some 30 years ago now!)....so I can't quite recall where I got the calibration from G to permeability from (it's likely I just back calculated G from the wireline log saturation (calculating a bulk oil volume) .....if BVOIL = POR * EXP(-G / (log(Pc/Pe)))....then.... G = - (log(Pc/Pe)) * ln(BVOIL / POR) ..... and cross plotted the resultant G factor against the core derived permeability (I may have played around with both linear and log linear fits) but it would have been an empirical fit to Forties Sst reservoir I would have thought....if I find the original work - I'll add a further comment here. Happy New Year!

I managed to find the 1994 equation of Permeability I came up with!! (looks like it was some log-linear fit of G to Perm) PERM = 10**((G * -5.0)+3.8)...........(these days I''d correct Lab-Air Perm to in-situ Liquid Perm too) .....but now I still can't recall whether my original coding for the G calculation gave a negative value, and so the -5.0 gradient was needed to make it it positive for my crossplot,.....if you're trying this you'll just have to suck it and see! Cheers