'petrengr1' pid='69337' datel Wrote:

Why might they drill Antelope-7?

IOC has stated that the recent long term flow test failed to see any indication of the western fault. In the recent presentation http://tinyurl.com/j6fu99b on page 6 they show a graph of the pressure build up after the long term flow test. You may note that they conveniently failed to mention the shut-in reservoir pressure prior to the flow test. That is the pressure we would need to make the calculation for gas in place as UBS did last August for the first test.

We have talked about the accuracy of these gauges before but comparing the pressure from both tests is interesting. Remember the lower the pressure drop for a given volume of gas the higher the gas-in-place number will be. I believe the gauges were set at the same depth for both of the two flow tests. Here is a comparison of the numbers reported for both tests:

Test No. 1 Antelope-5 Orig. Res. Pressure 3536.185 psi Pressure after a 5 day build-up was 3536.124 This gives a pressure difference of ).061 psi Apparently they did not know the pressure was still building after the 5 day shut-in period. This gives a gas-in-place number of  10.9 TCF. Which I find disappointing since this is a gas-in-place number and not a recoverable gas number.

Now the interesting part.

Test No. 2 Antelope-5 Orig. Res. Pressure Not reported. (why not?) Reservoir pressure at the beginning of the pressure build-up period after the end of the flow test 3536.38 psi. Note this is slightly higher than any of the pressures reported on Test No.1. As I have said before I do not think these gauges are “perfectly” accurate so let’s just concentrate on the pressure change. After being shut-in the pressure built from 3536.38 psi to 3536.42 psi over a period of 27.5 days for a pressure build-up of 0.04 psi and the pressure was still building. IOC said they think it is because the gas from the lower quality rock is still flowing into the higher porosity rock (the super highway to the well bore) Looking back at the pressure build-up on page 6 of the presentation http://tinyurl.com/j6fu99b , in the first 5 days (120 hours) (the period the well was shut-in on the first test) the pressure built up about 0.01 psi and the next 22.5 days the pressure built another 0.03 psi and was still building. Now the question: can we assume that if the gauges had remained in the well on test No. 1 for another 22.5 days would the pressure have built another 0.03 psi? If so the pressure drop from the original reservoir pressure would have been (0.06 -0.03) or 0.03 psi, half the previously reported pressure drop. Using the same UBS/IOC calculation as before would give us a gas-in-place number of 21.45 TCF. Do I believe this? No, I just show this to emphasize the fact that using numbers this small can be very misleading. So the JV partners may be looking at these numbers and saying “she is a giant” but we don’t believe the numbers and don’t know how big the giant is, so we will have to drill Antelope-7 to get a better idea of the size, at least to the west.

Now let’s look at page 7 of the presentation http://tinyurl.com/j6fu99b to see where they want to drill the well. The eastern most fault is the old interpretation and the western most fault is the new interpretation. So they are going to drill the well between the two faults (as shown). Of course you know there is only one fault, we just don’t know where it is. Drilling the well at this location will definitely prove if the old interpretation is correct. If the old interpretation is correct the well will be a dry hole. If we find the top of the pay as predicted by the map we will have proven that the fault is further to the west. If the well cuts through the fault they should be able to estimate how much further to the west the fault would be at the top of the pay zone which is what they show on the map.

Their map shows the well should find a rock type of “reef slope” which I take to mean that they do not expect to find any high porosity limestone or dolomite. I will  be so bold as to say if they find the top of the pay zone as mapped they will also find some high porosity limestone and /or dolomite. This is simply based on the fact that we have drilled six wells and they all had dolomite. So that is what they will be looking for, top of reservoir, rock type and location of the western fault.

Pet - Appreciate your great thinking as always. I don't quite understand their thought processes on where to drill A 7 and run the risk of a dry hole. As I ponder the map on page 7 a bit more,why not drill the well approximately 5,000 ft west of A 5 or approximately 7,000 ft west of A 3 ?  True,if they drill a dry hole,they will know how much further west our reservoir does NOT go , but several more million dollars are gone without more dolo $$ mite found. True,where I am thinking about one of two locations may still not give us the complete picture, I beleive we would cut the fault and know more than we now know. ( ...and also have another good chunk of highly porous dolomtic rock).

I will quantify my post by saying that due to excessive arthritis pain,I started on my "adult beverages" a little early today, so if my thinking is cloudy,please cut me a "little slack" .  Thanks (hic-up) !

'sageo' pid='69341' datel Wrote:

'petrengr1' pid='69337' datel Wrote:

Why might they drill Antelope-7?

IOC has stated that the recent long term flow test failed to see any indication of the western fault. In the recent presentation http://tinyurl.com/j6fu99b on page 6 they show a graph of the pressure build up after the long term flow test. You may note that they conveniently failed to mention the shut-in reservoir pressure prior to the flow test. That is the pressure we would need to make the calculation for gas in place as UBS did last August for the first test.

We have talked about the accuracy of these gauges before but comparing the pressure from both tests is interesting. Remember the lower the pressure drop for a given volume of gas the higher the gas-in-place number will be. I believe the gauges were set at the same depth for both of the two flow tests. Here is a comparison of the numbers reported for both tests:

Test No. 1 Antelope-5 Orig. Res. Pressure 3536.185 psi Pressure after a 5 day build-up was 3536.124 This gives a pressure difference of ).061 psi Apparently they did not know the pressure was still building after the 5 day shut-in period. This gives a gas-in-place number of  10.9 TCF. Which I find disappointing since this is a gas-in-place number and not a recoverable gas number.

Now the interesting part.

Test No. 2 Antelope-5 Orig. Res. Pressure Not reported. (why not?) Reservoir pressure at the beginning of the pressure build-up period after the end of the flow test 3536.38 psi. Note this is slightly higher than any of the pressures reported on Test No.1. As I have said before I do not think these gauges are “perfectly” accurate so let’s just concentrate on the pressure change. After being shut-in the pressure built from 3536.38 psi to 3536.42 psi over a period of 27.5 days for a pressure build-up of 0.04 psi and the pressure was still building. IOC said they think it is because the gas from the lower quality rock is still flowing into the higher porosity rock (the super highway to the well bore) Looking back at the pressure build-up on page 6 of the presentation http://tinyurl.com/j6fu99b , in the first 5 days (120 hours) (the period the well was shut-in on the first test) the pressure built up about 0.01 psi and the next 22.5 days the pressure built another 0.03 psi and was still building. Now the question: can we assume that if the gauges had remained in the well on test No. 1 for another 22.5 days would the pressure have built another 0.03 psi? If so the pressure drop from the original reservoir pressure would have been (0.06 -0.03) or 0.03 psi, half the previously reported pressure drop. Using the same UBS/IOC calculation as before would give us a gas-in-place number of 21.45 TCF. Do I believe this? No, I just show this to emphasize the fact that using numbers this small can be very misleading. So the JV partners may be looking at these numbers and saying “she is a giant” but we don’t believe the numbers and don’t know how big the giant is, so we will have to drill Antelope-7 to get a better idea of the size, at least to the west.

Now let’s look at page 7 of the presentation http://tinyurl.com/j6fu99b to see where they want to drill the well. The eastern most fault is the old interpretation and the western most fault is the new interpretation. So they are going to drill the well between the two faults (as shown). Of course you know there is only one fault, we just don’t know where it is. Drilling the well at this location will definitely prove if the old interpretation is correct. If the old interpretation is correct the well will be a dry hole. If we find the top of the pay as predicted by the map we will have proven that the fault is further to the west. If the well cuts through the fault they should be able to estimate how much further to the west the fault would be at the top of the pay zone which is what they show on the map.

Their map shows the well should find a rock type of “reef slope” which I take to mean that they do not expect to find any high porosity limestone or dolomite. I will  be so bold as to say if they find the top of the pay zone as mapped they will also find some high porosity limestone and /or dolomite. This is simply based on the fact that we have drilled six wells and they all had dolomite. So that is what they will be looking for, top of reservoir, rock type and location of the western fault.

Pet - Appreciate your great thinking as always. I don't quite understand their thought processes on where to drill A 7 and run the risk of a dry hole. As I ponder the map on page 7 a bit more,why not drill the well approximately 5,000 ft west of A 5 or approximately 7,000 ft west of A 3 ?  True,if they drill a dry hole,they will know how much further west our reservoir does NOT go , but several more million dollars are gone without more dolo $$ mite found. True,where I am thinking about one of two locations may still not give us the complete picture, I beleive we would cut the fault and know more than we now know. ( ...and also have another good chunk of highly porous dolomtic rock).

I will quantify my post by saying that due to excessive arthritis pain,I started on my "adult beverages" a little early today, so if my thinking is cloudy,please cut me a "little slack" .  Thanks (hic-up) !

Sageo- Your proposed locations 5,000 feet (1.5 k) west of Antelope-5 and 7,000 feet (2.1 km) west of Antelope-3 look good to me. They would be a safer bet to avoid a dry hole but might not give us as much information as the location they are building if the fault is truly west of that location as shown on the map. The location they will be drilling would seem to indicate that all three of the JV partners agree that the western fault is west of the location. Maybe that should give us a warm fuzz feeling.

Regarding the timing of the drilling David Kirk had this to say at the conference call:

"The Operator needs to close out a few outstanding queries around well design and cost, before being in a position to submit a formal proposal to the Venture. We expect the Operator to clarify those issues in the next few weeks, leading to a decision this quarter."

It was recently pointed out to me by one of our esteemed members that the producing wells will need to be big bore wells so that they can accomodate 7 " production tubing. Maybe Total has decided to start drilling big bore wells so that they can be used for high rate producers. If so they will need to develop a new casing program and get all of the larger size tubulars for the well. I believe the rig we have will be able to handle everything but they may need to obtain some additional equipment for handling the larger pipe. Anyway ordering the new size casing and pipe handling equipment could delay the spud date if that is what they are doing. Morgan Stanley estimated IOC's cost at $35 million which seems higher than usual at $90 - $100 million gross cost. They probably got the number from IOC so this may also indicate they are planning a more expensive well than we have drilled in the past.

This is very helpful Pet, thanks a lot. I wasn't in favor of drilling Antelope 7, as I (wrongly) assumed it would not make all that much of a difference and we have another certification at a later date to account for any additional gas, but I now see a rationale for drilling it. I thought we had a better grip on the size of E/A, to be honest.