Comments on 2nd Qtr Presentation

[petrengr1]

In case you have not found it you can go to the IOC web site and click on conference call archives and see a copy of the presentation with the actual words of the presenters. http://tinyurl.com/njby5nv


I will give you a few comments about what I see on a few of the slides and some implications of what they are trying to illustrate.  http://tinyurl.com/p5bttdy Of course I am sure you already know what I will point out.

Slide 5- This is a cross section from West to East through the recently drilled Antelope-5. They show their conception of the reservoir pre-drill in the upper cross section and their conception of the reservoir post-drill in the lower cross section. You will note that the post drill cross section shows a much larger area of reef. Note that they now think the reef may extend all the way to the western boundary and/or the gas/water contact. The size of the red circles is to send a message.

Slide 6- This is another cross section of the field from South to North. Again see that they think the reef (high porosity dolomite) extends all the way to the gas/water contact South of Antelope-4. They are going to side track Antelope-4. They say the side track is because of drilling problems encountered with the first rig. I had previously thought they might kick the well further south to prove that the dolomite is further south. Now I think they just intend to complete the well and see how far the dolomite extends  vertically. Does it extend all the way to the gas/water contact or will we have some of the low porosity limestone at the bottom? Also note that the dolomite zone becomes thicker south of  Antelope-5.

They flow tested Antelope-5 with 6 downhole pressure/temperature recorders in place. We do not know how much of the formation is open for production. It could be all of it as an open hole or it could be that they have cased off the formation and perforated the top.  See the P (producing) symbol at the top of the formation at Antelope-5 and the L (listening) symbol at Antelope-1 which is only open in the lower zone. They have said the pressure changes in Antelope-1 while flow testing Antelope-5 proves connectivity between the two wells both vertically and horizontally. So no compartmentalization, both wells are in the same compartment.

Look at the map on the right side of slide-6.  This map represents the mid-case shown in the AGM presentation  http://tinyurl.com/pnntt2e (Stay with the recent presentation) You will see a line representing the line of the cross section. You will see that the current thinking is that the formation does not slope down to the west but much of the area West of Antelope -3 is as high as Antelope-3 which is the highest well they have drilled. Also note that the area West of the cross section is much higher and larger than the area to the East.  We had previously thought this string of wells were drilled right down the middle of the reefal structure but now it looks like there is much more of the field to the West of the line than there is to the East. All of the light red area is higher than -1,500 meters sub sea which means wells in this area will have more than 2,300 feet of gas column unless the well bore cuts the western fault. Near the fault there will be less than 2,300 feet of gas column but the wells will produce about like Antelope-5 because most of the gas will come from the high porosity high permeability zone at the top of the formation. There may also be additional fracturing near the fault which will increase the permeability.

Chart 7- This chart represents the bottom hole or reservoir pressure during the four rate flow test at Antelope-5. The chart shows that the reservoir pressure, as measured in the well bore, only dropped about 2 psi while producing a rate of 70 MMCFD. That is about the same as producing gas from a cavern or a gas storage well in a salt dome. In other words the permeability is so high that it does not matter. You could produce any volume you want to as long as the tubing size and surface equipment (well head/Christmas tree) were designed to handle it. I know that Talisman had wells in South Sumatra (Indonesia) that produced over 200 MMCFD. They probably used something like 7” tubing and they had two large flow lines off  of the well head . This kind of pressure drawdown is so good that it is almost unbelievable. Also the chart shows that the shut-in reservoir only dropped 0.061 psi after producing 152.9 MMCF. These pressure readings were only taken from the lowest of 6 pressure instruments that were place in the well. What did the other 5 show? I believe these three decimal psi readings are probably pushing the resolution capability of the pressure instrument so I would not use this pressure difference to try to estimate the volume of the gas reservoir. The pressure difference could easily be off several percentage points.

Chart-8 For example if we look at chart 8 we see that the shut-in reservoir pressure at Antelope-1 dropped about .080 psi during the test at Antelope -5. It seems to me that the lowest pressure and the biggest pressure drop in the reservoir would be at the location of the producing well i.e. Antelope-5.  To give you an idea about how sensitive these measurements are it is interesting to note that the weight of the gas in the tubing of the well is 0.071 psi/ft.  So if the pressure gauge was set one foot higher it would read 0.071 psi less just due to the weight of the gas.   So I have some doubts about the accuracy of the pressure drop and again I would not recommend that these numbers be used to calculate the volume of the reservoir. I do accept the fact that they were able to  detect a pressure change at Antelope-1 while producing Antelope-5 thus proving connectivity between the two wells.

Chart -9 This chart just illustrates that the flow characteristics of Antelope-5, as far as pressure drawdown and flow rate is concerned , is better than any other well at Antelope and better than wells in the Arun Field.

I guess that is about all I have for you tonight. Of course I was very disappointed that Wahoo-1 was a dry hole. It looks like they are having a hard time interpreting their seismic data to identify the carbonate reservoir in this area. They had the same problem at Black Bass-1 which is also in this area. Looking forward to getting some results from Triceratops-3 and I am hoping for some porosity better than what we saw at Triceratops-2 and I hope the zone is thicker than was indicated by PRE. Maybe they were not through drilling at the time of the PRE comment.

Have a good day.

[Putncalls]

That delta in pressure measurement is probably done by a very smart sensor. The two measurements are done with the exact same device and if there is ANY change in temperature it would be compensated for by the measuring device's computer. It seems like they were using a time constant of about 20 hours. I would think the the low pass filter removes ALL the noise sources. I don't mean to disagree with what pet said. I suspect I could design something that sensitive? I used to do that kind of work for HP.

[Palm]

Thanks Pet. Great analysis. Once Ant 4 is done do you expect much other than confirmation of the same when they include it in the testing? Anything different they will be looking for?

[sageo]

Pet - Just got home and read your fine post . I'm impressed with the increasing dolomite thickness in the Ant 4 well in the southern portion of the reservoir . Am anxious to see if this is present in the Ant 6 well . If true, will certainly bode well for our overall picture of what we have at Antelope.  Best to you !

[petrengr1]

Thanks Pet. Great analysis. Once Ant 4 is done do you expect much other than confirmation of the same when they include it in the testing? Anything different they will be looking for?

Palm- It difficult to guess how they may proceed based on the information available. They have said they will be drilling a sidetrack because of “mechanical” problems experienced with the first rig. Mechanical problems could cover  many things but since they are drilling a sidetrack we can assume the problem was down hole.

We do not know if they are still using the down hole deployment valves (DDV’s), the same casing design or using managed pressure drilling.  Here is a little history on the well pieced together mainly from the OilSearch drilling reports and an IOC presentation:

1. IOC announced the spudding of Antelope-4 on Sept. 16, 2014.
2. OilSearch - as of Feb. 5, 2015 drilling 12” hole at a depth of 1986 meters.
3. OilSearch- March, 2015 drilling report: coring at a depth of 2002 meters.
4. OilSearch- As of Apr. 30, 2015 well was suspended at a depth of 2134 meters.
5. IOC June 9 presentation-Top of reservoir at -1,911 meters sub sea (same as 1,986 meters drill depth)    
6. IOC June 9 presentation- recovered 33 meters of high quality dolomite core. (core recovered between the casing shoe at 1,986 meters and suspended depth of 2,134 meters.)
7. IOC June 9 presentation- Significant mud losses suggest high fracture permeability

Conclusions:
1. Based on the above it appears they set 9 5/8” casing at about 1986 meters which is the top of the pay zone.
2. They drilled and cored the formation to a depth of  2,134 meters where the well was suspended for mechanical reasons.
3. They were apparently drilling with mud since they mentioned significant mud losses. This probably means that the Old Rig was not capable of doing managed pressure drilling. When they lost circulation they probably stuck the drill pipe and were unable to free the pipe. My guess is they left bit and some drill  collars in the hole.
4. With the new rig, Rig103, they should be able to clean out the hole below the 9 5/8” casing to give enough room to side track the well and fish and drill the well to the planned TD of 2378 meters (-2,300 meters sub sea). Fishing with the well under pressure may present some problems. If so they may have to plug the open hole and sidetrack through  a window cut near the bottom of the 9 5/8” casing.
5. If this is the plan they should be able to conclude the drilling operations within a month. At the August 13 conference call IOC said they had resumed operations at Antelope 4.

After completing the drilling and completion of Antelope-4 they plan to use it as a listening well and again test Antelope 5 as the producing well. They will no doubt also be monitoring for a pressure response at Antelope-1.  If both Antelope-1 and Antelope-4 pick up a pressure response  from the testing of Antelope-5 that means Antelope Field is one big compartment from Antelope-1 on the north to Antelope-4 on the south. See chart and cross section on chart 6 of  http://tinyurl.com/p5bttdy .


After the testing is complete they will move Rig 103 to the Antelope-6 well site and spud that well.

[Palm]

Thanks Pet. Makes perfect sense and likely will end up being proof to all of what mgmt and the JV partners expect to have 99.9% chance of being the case; Ant is one "giant" of a reservoir that doubters and shorts years ago said couldn't be. Too bad it's taken so long to be proven out.

[Getitrt2]

Pet, do you have enough information to reach an at least tentative conclusion as to whether you think they need to or should drill an Antelope 7 for certification?

[petrengr1]

In case you have not found it you can go to the IOC web site and click on conference call archives and see a copy of the presentation with the actual words of the presenters. http://tinyurl.com/njby5nv


I will give you a few comments about what I see on a few of the slides and some implications of what they are trying to illustrate.  http://tinyurl.com/p5bttdy Of course I am sure you already know what I will point out.

Slide 5- This is a cross section from West to East through the recently drilled Antelope-5. They show their conception of the reservoir pre-drill in the upper cross section and their conception of the reservoir post-drill in the lower cross section. You will note that the post drill cross section shows a much larger area of reef. Note that they now think the reef may extend all the way to the western boundary and/or the gas/water contact. The size of the red circles is to send a message.

Slide 6- This is another cross section of the field from South to North. Again see that they think the reef (high porosity dolomite) extends all the way to the gas/water contact South of Antelope-4. They are going to side track Antelope-4. They say the side track is because of drilling problems encountered with the first rig. I had previously thought they might kick the well further south to prove that the dolomite is further south. Now I think they just intend to complete the well and see how far the dolomite extends  vertically. Does it extend all the way to the gas/water contact or will we have some of the low porosity limestone at the bottom? Also note that the dolomite zone becomes thicker south of  Antelope-5.

They flow tested Antelope-5 with 6 downhole pressure/temperature recorders in place. We do not know how much of the formation is open for production. It could be all of it as an open hole or it could be that they have cased off the formation and perforated the top.  See the P (producing) symbol at the top of the formation at Antelope-5 and the L (listening) symbol at Antelope-1 which is only open in the lower zone. They have said the pressure changes in Antelope-1 while flow testing Antelope-5 proves connectivity between the two wells both vertically and horizontally. So no compartmentalization, both wells are in the same compartment.

Look at the map on the right side of slide-6.  This map represents the mid-case shown in the AGM presentation  http://tinyurl.com/pnntt2e (Stay with the recent presentation) You will see a line representing the line of the cross section. You will see that the current thinking is that the formation does not slope down to the west but much of the area West of Antelope -3 is as high as Antelope-3 which is the highest well they have drilled. Also note that the area West of the cross section is much higher and larger than the area to the East.  We had previously thought this string of wells were drilled right down the middle of the reefal structure but now it looks like there is much more of the field to the West of the line than there is to the East. All of the light red area is higher than -1,500 meters sub sea which means wells in this area will have more than 2,300 feet of gas column unless the well bore cuts the western fault. Near the fault there will be less than 2,300 feet of gas column but the wells will produce about like Antelope-5 because most of the gas will come from the high porosity high permeability zone at the top of the formation. There may also be additional fracturing near the fault which will increase the permeability.

Chart 7- This chart represents the bottom hole or reservoir pressure during the four rate flow test at Antelope-5. The chart shows that the reservoir pressure, as measured in the well bore, only dropped about 2 psi while producing a rate of 70 MMCFD. That is about the same as producing gas from a cavern or a gas storage well in a salt dome. In other words the permeability is so high that it does not matter. You could produce any volume you want to as long as the tubing size and surface equipment (well head/Christmas tree) were designed to handle it. I know that Talisman had wells in South Sumatra (Indonesia) that produced over 200 MMCFD. They probably used something like 7” tubing and they had two large flow lines off  of the well head . This kind of pressure drawdown is so good that it is almost unbelievable. Also the chart shows that the shut-in reservoir only dropped 0.061 psi after producing 152.9 MMCF. These pressure readings were only taken from the lowest of 6 pressure instruments that were place in the well. What did the other 5 show? I believe these three decimal psi readings are probably pushing the resolution capability of the pressure instrument so I would not use this pressure difference to try to estimate the volume of the gas reservoir. The pressure difference could easily be off several percentage points.

Chart-8 For example if we look at chart 8 we see that the shut-in reservoir pressure at Antelope-1 dropped about .080 psi during the test at Antelope -5. It seems to me that the lowest pressure and the biggest pressure drop in the reservoir would be at the location of the producing well i.e. Antelope-5.  To give you an idea about how sensitive these measurements are it is interesting to note that the weight of the gas in the tubing of the well is 0.071 psi/ft.  So if the pressure gauge was set one foot higher it would read 0.071 psi less just due to the weight of the gas.   So I have some doubts about the accuracy of the pressure drop and again I would not recommend that these numbers be used to calculate the volume of the reservoir. I do accept the fact that they were able to  detect a pressure change at Antelope-1 while producing Antelope-5 thus proving connectivity between the two wells.

Chart -9 This chart just illustrates that the flow characteristics of Antelope-5, as far as pressure drawdown and flow rate is concerned , is better than any other well at Antelope and better than wells in the Arun Field.

I guess that is about all I have for you tonight. Of course I was very disappointed that Wahoo-1 was a dry hole. It looks like they are having a hard time interpreting their seismic data to identify the carbonate reservoir in this area. They had the same problem at Black Bass-1 which is also in this area. Looking forward to getting some results from Triceratops-3 and I am hoping for some porosity better than what we saw at Triceratops-2 and I hope the zone is thicker than was indicated by PRE. Maybe they were not through drilling at the time of the PRE comment.

Have a good day.

In addition to the notes provided by IOC at ( http://tinyurl.com/njby5nv ) here is a pretty good transcript where you can see what was said in the question and answer period of the conference call: >http://tinyurl.com/pzepxcj

[petrengr1]

Pet, do you have enough information to reach an at least tentative conclusion as to whether you think they need to or should drill an Antelope 7 for certification?

Getit- I will not be so presumptuous as to say what they should or need to do before certification. That decision will depend on several things such as cash burn rate, need for the company to get the certification payment sooner etc....

I will say this however. If the field truly looks like the current map shown at  http://tinyurl.com/p5bttdy Chart 6 then the field will not have been properly appraised until they have drilled two or three wells far enough west to identify the fault which is the western boundary of the field. If they had about three wells that cut the fault they could more precisely draw the fault plane and make an accurate picture of the size of the field. From the looks of the map, and beginning at the south end of the cross section line, they have room for two or more  wells west of  Antelope-4, two or more wells west of Antelope-2,  one or more wells west of Antelope-5, and two or more wells west of  Antelope-3. So they have enough room for at least seven more wells to the west of the line of the cross section. How many wells do they need? They have said, based on the performance of Antelope-5, there are positive implications about the number of wells that will be required i.e. fewer wells will be needed. In order to load a two train LNG plant they will need to produce about 1 BCF/day (365 BCF/year x 20 years = 7.3 TCF).  That means we need five wells producing 200 MMCFD each or ten wells producing 100 MMCFD each. I think I am on record from several years ago saying they will need at least ten wells. I will stick to that assessment as I believe 200 MMCFD from each well is a bit too  aggressive even though the wells will easily be capable of producing that much. With properly designed tubulars and well head they could produce up to 200 MMCFD from each well but as the field pressure declines they will need more wells anyway.

[sageo]

Pet, do you have enough information to reach an at least tentative conclusion as to whether you think they need to or should drill an Antelope 7 for certification?

Getit- I will not be so presumptuous as to say what they should or need to do before certification. That decision will depend on several things such as cash burn rate, need for the company to get the certification payment sooner etc....

I will say this however. It the field truly looks like the current map shown at  http://tinyurl.com/p5bttdy Chart 6 then the field will not have been properly appraised until they have drilled two or three wells far enough west to identify the fault which is the western boundary of the field. If they had about three wells that cut the fault they could more precisely draw the fault plane and make an accurate picture of the size of the field. From the looks of the map, and beginning at the south end of the cross section line, they have room for two or more  wells west of  Antelope-4, two or more wells west of Antelope-2,  one or more wells west of Antelope-5, and two or more wells west of  Antelope-3. So they have enough room for at least seven more wells to the west of the line of the cross section. How many wells do they need? They have said, based on the performance of Antelope-5, there are positive implications about the number of wells that will be required i.e. fewer wells will be needed. In order to load a two train LNG plant they will need to produce about 1 BCF/day (365 BCF/year x 20 years = 7.3 TCF).  That means we need five wells producing 200 MMCFD each or ten wells producing 100 MMCFD each. I think I am on record from several years ago saying they will need at least ten wells. I will stick to that assessment as I believe 200 MMCFD from each well is a bit too  aggressive even though the wells will easily be capable of producing that much. With properly designed tubulars and well head they could produce up to 200 MMCFD from each well but as the field pressure declines they will need more wells anyway.

Pet -GOOD AM ! Let me be the first to grade your post ......"AAA+++++" . That's why you are such a credit to our board. Straight to the 'bottom line' . Like the old "Dragnet" ...just the facts m'am,just the facts. Thanks for the true "skinny". [repeat Hemi's health and happiness] .