Member Info for Monkey_Junkey

Concrete doesn’t dry, it cures. The strength over time curve is pretty much the same for all concrete (what % of it’s final strength is achieved after so and so many days). This is also assuming curing under correct conditions, not too hot, not too cold, don’t let it dry out, etc .....

You can use readers or accelerators, but this can affect final strength.

The pad is a very simple concrete construction, pretty much the simplest. Put some boards around the edges, some steel in the middle, and concrete run down a shoot. Finish surface and water a few days or cover with plastic sheet (we want the water used up in the chemical curing, not to evaporate and dry out).

Lots happening in Touchstone Exploration the rest of the year before the new winter season. You could do worse than park your funds there while waiting for the next round here.

And the big daddy Royston is going to spud in the coming weeks ........

Coho pipeline hookup bringing first production online any dag now ........

You can also change the concrete quality for more strength in the same thickness. But let’s just say to keep it simple, your driveway is a vastly different compressive strength mix than what’s used on the foundation to a skyscraper.

So, they can have a pad loadable in 7 days if they want. +2 = 9 days from Friday. Doubt they would push it much under that because it starts to be quite diminishing returns.

The pad would obviously be designed for the loads it is expected to carry. If you wanted to utilize the pad quicker (at say 7 days from pouring (65%) instead of 14 days (90%), you could simply increase the thickness and beef up the rebar so that your new pad design at 65% could carry the same load as the older design at 90%.

Different rigs will be different loads, different soils underneath have different properties (which you obviously compact), so no, the pad thickness is not always the same in every drilling location around the world. You can also change the design thickness to either save money, or save time.

The concrete forms and rebar used in these pad are very simple and quick to install. Pour is done a day. It’s not unreasonable to have the pad finished poured two days after this picture was taken, but that depends on having materials and manpower available.

Somehow I think you know all of this already Buffy. But yeah, I studied civil engineering and ended up in the oil business for 25 years as well as owning a small construction company.

Royston pad pic on Twitter ....... how lovely and appreciate TXP showing us the pictures of progress.

Need to dig some holes for the pits and pour the concrete pad. Say three weeks work even allowing for 14 days cure (90% strength) on concrete, so early May is very possible. 7 days cure is 65% strength, so curing time could be less allowing rig setup sooner, so in 14 days start rigging up.

Spawny - Don’t let the door hit you on the way out. Glad you sold, now please go away and don’t come back. Tired of your whiney posts.

Difference in practice for mud weight based on the pressures you would think you might see in the formation. You don’t want an influx of either oil or gas. Oil will change density of mud to be less dense, which is lighter weight allowing more oil in, and the circle continues unless controlled until blowout. Especially don’t want gas influx which expands as it moves towards surface displacing even more mud in well which means less weight to hold, viscous circle, and is the quickest way to blow out land. This is a kick, and has to be dealt with correctly and timely.

Mud too heavy can damage formation by clogging it up, can also lose a bunch of mud to formation, and end up with a blow out for the same reasons above. It’s about finding the happy medium place between not enough and too much.

In my opinion only, I believe it is possible TXP went a bit heavy on the mud after the high pressure experiences in the other wells. We do know they used very heavy mud in the 50’s and 60’s, and this is likely why they didn’t register the gas at Cascadura when it was drilled before.

So, goal is no unflx of either gas or oil, but keep mud as light as possible without screwing it up and having a blowout or uncontrollable kick.

The rig is already moved to Chinook, or is al least removed from Cascadura. Don’t do the flow test itself with the rig on site.

Don’t know how involved is it or what type of pump they will use for EWT, so that will determine what kind of equipment will be required since the zone is already perforated, or maybe they try to do a work over ..... who knows.

Mickey2 - you better start looking for a pole and some rope. I would prefer a very tall flagpole to haul you up. And then me and the proactive girl can have a picnic and make funny noises on the lawn below while you watch upside down.

Mickey2 - you’re full of ****. The Royston spud as we know has been communicated several times is late April / early May.

Did you jump off and the train left without you?

I think they will drill the other wells from a different pad designed for more wells.

Otherwise they would likely stop production, it would be considered dangerous to drill next to a surface wellhead.

Offshore this is not the case, but you have several levels of decks under the Derrick and different slots, so this can be done in a much better separated way.

Chinook area is not written off in my book in the slightest. It is a prospect showing oil that needs further work.

The choke was bigger diameter which would reduce pressure. There is a statement indicating that not all the load fluid was recovered, so it may still continue to clean up.

Also have to compare the relative completion surface area of the two different tests (I don’t have this in my head). Could very easily be that they did not perforate as much length for the very reason of keeping the test better under control, and knowing that they will be able to produce the desired long term production flow rate later on anyways (which is always lower than the flow rate tests).

So, without more detail, I don’t think you can assume that this result is not as good as the Cascadura 1 test.

Very on time, but we all know that. No picture, no flare.

For the 14th time ..... THE TEST EQUIPMENT IS THE SAME, IT IS THE BIGGEST ON THE ISLAND (And why we had to wait for it to become available), AND PAUL ANSWERED A QUESTION I PUT FORTH DIRECTLY DURING A WEBINAR SAYING THAT THEY GET GOOD ENOUGH DATA EVEN THOUGH THE DRAWDOWN IS LIMITED BY THE TESTING EQUIPMENT CAPACITY. The drawdown you would ideally have is much higher, but they are happy with it.

The AOF Numbers are interpolated from the data, the wells will not be put on production at anywhere near AOF values. To do this would damage the reservoir and mean less cash for us overall. It’s also not even physically possible due to the diameter of the well vs. the total AOF numbers at Cascadura. You would need almost two 20 inch pipelines to move the gas away

The AOF is an estimate of what the pay could theoretically deliver to the wellbore, if you have a thicker section of pay, you get more surface area = more gas. The well still cleaning up is they observed increasing pressure, this is the drilling fluid that enters the formation during drilling very near the wellbore. It gets pushed backed to the well (hopefully), and as the permeability cleans up, you get more flow = more pressure. You can severely damage the producing properties of a formation with mud that is too heavy.. The mud weights are adjusted to be as heavy as necessary to avoid a blowout, but not too heavy to avoid as much damage as possible during drilling. There other things we won’t get into. You can also drill under balanced so go and google that if you are interested.

The choke used on the testing equipment is something I couldn’t fit my pp into, so look at the size of the flare, this gives you some idea of the pressure (it’s higher than a high pressure variant of scuba of diving tanks).

Several wells will be drilled to produce large volumes of gas.

Auto correct typing sucks

I think Paul did mention this larger casing diameter, but it’s also obvious given the known production role of Casc Deep well.

I would produce the lowest volume zone from Casc 1 well and the largest volume zone from Casc Deep well. There is little point producing the same zone from both wells since they are so close together and not producing from the other on. Commingling production could also be something, but you would want very equal pressures to avoid utter chaos and potential formation mage down there when the two zones were equalizing.

The exception to this split would be to produce the top zone from both wells, and produce the lower zone from other later wells. This would be related to isolating the perforated upper zone in Casc 1 or not with more complex production string 9th packers to allow Production that flows past upper zone, but is isolated from perforations.

It is also about the plugs that are set in Casc 1 already. Are they removable or permanent set plugs?

Many different ways to kill a cat and we don’t have the detailed info required to make any educated guesses.

Most exploration wells are never produced from, they are primarily used to gather information. Then you plan and drill production wells. On land Trinidad is a very simple and cheap environment to operate in (easy to tie in), so I suppose this is why you would also produce from an exploration well that is not optimally sized and planned for production. Or maybe the “Exploration” well designs we have drilled are something In between exploration and production.

If anyone has talked to Paul in depth about the testing it would be far more efficient to post it here than everyone calling and using our CEO’s time to answer questions individually.

I don’t think Paul considers Chinook a complete miss at all. What the miss is Is that they conveyed the thought that they had another Cascadura, and that it would be on production at the end of this year.

What we got instead at Chinook is a well which will require further testing and wider geo work to determine where to stick the next hole. I guarantee you that there will be another hole at Chinook in the future. There is no way Touchstone will give up here, this is also the reason For the “science experiments”, to gather data about the reservoir properties and along with seismic data, plan the placement of the next well.

We wanted a bird in the hand right now, but we might have two in the Bush instead. Time will tell if we end up with a bird in each hand.

Starbuck911

Where do think we are in relation to the owc’s of the 3 Chinook structures?

Think there might be any significant gas over the oil?

What about lateral offset from the Chinook wellbore to the structural highs of the traps?

Anticline traps, fault traps, or stratigraphic traps?

Do you think the overthrust contours, or whatever other contours that are present in the lower structure with 1000 ft updip is mirrored in the other two structures above?

I haven’t seen any illustrations of the structure, nor nice 3D models. 2d seismic slices are not anywhere near my strong point. Does anyone have a better grip on this?

Would gas lift be the logical choice at Chinook for artificial lifting from these zones since we have a high pressure supply at Cascadura?

With the previous legacy oil production at Chinook, do you think we have a tight reservoir?

Was the original oil production stopped due to well placement (structural edge) and owc water production or low permeability? Why did they not drill another well at Chinook in a better location?

I notice that the original well, then sidetracked well, and then Chinook are all stepping out in the same direction. Was the stepout at Chinook the maximum deviation that could be done without going to a horizontal well or using another pad?

What kind of pump do they use for the EWT test at Chinook?

The lowest zone produced high volume high pressure water with light oil shows, and so there is a potential they drilled into a fracture or fault. Wouldn’t this potentially be a potentially self stimulating or self injecting point to this lower zone, and the Chinook well could be used for injection for one or both of the other zones. Could you remove the plugs and inject every perforated zone from the same well (I’m assuming there isn’t space for any fancy completion equipment in this well to select different zones)?

Logs from Original Chinook well said oil on core. So they actually took a core (wonder where that is today - would be nice to analyze that for porosity and permeability), and the sidetrack flowed free oil. Wouldn’t it be kind of weird to flow free oil if the permeability in the reservoir was tight?

How over balanced do you think the mud was at Royston in 1965?

Western Atlas
Schlumberger
BP
Statoil
Exxon Mobile
Offshore Subsea Construction
Offshore Geophysical Surveys
Crazy Geophysics developement, but mechanical expertise, not a Geophysicist or Geologist.
Been on some rigs for extra trips fixing stuff for fun. Seen some drilling ops, stuck pipe, wireline logging, etc ...

Having worked in the oil business 25 years, many things I know, know about, and much more I don’t know details of. It’s not so, surprising some in here get it wrong. It’s pretty complicated all in all and many disciplines involved from exploration to production.