Wahoo

[petrengr1]

Let’s have a closer look at Wahoo-1.  I suggest that you open

http://tinyurl.com/m32z6ho

  and go to slide 19. Magnify the map on the right side so you can see it clearly. Now what have they told us they think is here?

You will see a white and black dotted line at the -1,650 meter contour line. I believe that defines the maximum or potential size of the prospective trap or the lower limit of the reservoir because there is a spill point toward the east near the southern end of the structure. If you look at the location of Wahoo-1 you will see that the well is located on the -900 meter contour line. So if the structure is filled with gas to the spill point we will have a gas column thickness at Wahoo-1 of 750 meters (1,650 -900) or 2,461 feet. You will note on the map that the highest part of the structure is shown to be about -650 meters sub sea or about 250 meters (820 feet) higher than Wahoo-1 so the gas column height for the field might be (2,461 + 820) about 3281 feet (1,000 meters) if the structure is full of gas to the spill point. These numbers apply to the Northern part of the structure. The Southern part of the structure (formerly known as Mako) has four different high spots indicated with a top at around -800 meters sub sea. So the Southern part of the structure (Mako) would have a maximum possible gas column height of about 3,100 feet

We have not yet been given the surface elevation of Wahoo-1 but since it is near the coast let’s assume the elevation is 100 feet above sea level. So we might expect the top of the carbonate zone at Whaoo-1 to be at 3,053 feet (900 meters + 100 ft). Then the aquifer depth or gas water contact might be expected to be at 5,514 feet drill depth if the carbonate zone is more than 2,461 feet thick. All of this assumes the structure is full of gas to the spill point. That is the most optimistic possibility so it might be less than that.

If we find a normally pressured aquifer at a depth of -1,650 meters (5,414 feet) sub sea or 5,514 feet drill depth then the reservoir pressure at the gas/water contact will be 2,388 psi. Most of this pressure will be reflected to the top of the reservoir with the pressure only being reduced by the weight of the gas. If we use a gas gradient of 0.04 psi/ft over the 2,461 foot gas column height (2,461 x 0.04) we will see that the pressure at the top of the reservoir at Wahoo-1 would be 98 psi lower than the pressure at the gas/water contact or about 2,290 psi. If this pressure occurs at the drill depth of 3,053 feet the pressure gradient will be 0.75 psi/ft and will require a mud weight of 14.4 lb/gal to balance or a bit more for safe control.

There is some evidence in the area that the aquifer may be over pressured or that we may have some over pressured zones before reaching the carbonate. Tovala-1 and 1A found high pressure gas and water in the late to mid-Miocene zones above the carbonate. These over pressured clastic zones flowed 1.5 - 2 MMCFD with salt water.  If you look at the seismic section to the left of the Wahoo map you will see a yellow line above the top of the carbonate. Could this be an over pressured clastic zone? If so it might require even more mud weight to control than the reef. Do we have the possibility of finding two different reservoirs? One a clastic zone and the other a carbonate reef? What will the reservoirs contain- gas, oil or water?

I hope you found that exercise of  some interest.

Now one last point of interest. Look at http://tinyurl.com/mgeqkj7 page 30. The lines you see south of the Popo wells are the seismic lines for Wahoo/Mako. I call your attention to the symbols for all of the wells around Wahoo. Note that the green color in the symbol indicated that these wells had oil shows while drilling and the red star means they encountered gas shows or gas flows.
Most of the closest wells : Tovala, Popo, Iokea, Apinaipi all had oil shows. Those further to the south: Oiapu and Black Bass had both oil and gas shows. By the way Black Bass also encountered an over pressured zone that required a mud weight of more than 14 #/gal to control.

[sltibbs]

Petengr1,

As always thank you. Unfortunately, for some reason the first link wasn't working though. http://www.interoil.com/iocfiles/documen...0Final.pdf

Thanks again.

Best,

Sam

[ArtM72]

Pet -

Thanks once again. My principle question in looking at this information is just why wasn't this area developed earlier?

I suppose the simple answer is that when this drilling was done seismic analysis was crude, if available at all, and the aerial magnetic and gravity technology was even less common and even less advanced. Thus, locating traps was the chief issue as it had to be widely known this was a mighty large "kitchen" in the neighborhood. The absence of an LNG industry of course meant no market, leaving gas without oil without economic value providing plenty of justification to look elsewhere.

Quick question: What is the maximum available drilling mud density and could delays at Wahoo have been caused not so much by commercial matters as concerns raised about being able to handle potential well pressures?

TIA, and best regards,

[CesiumFormate]

Pet - Thanks once again. My principle question in looking at this information is just why wasn't this area developed earlier? I suppose the simple answer is that when this drilling was done seismic analysis was crude, if available at all, and the aerial magnetic and gravity technology was even less common and even less advanced. Thus, locating traps was the chief issue as it had to be widely known this was a mighty large "kitchen" in the neighborhood. The absence of an LNG industry of course meant no market, leaving gas without oil without economic value providing plenty of justification to look elsewhere. Quick question: What is the maximum available drilling mud density and could delays at Wahoo have been caused not so much by commercial matters as concerns raised about being able to handle potential well pressures? TIA, and best regards,

Art, cesium and potassium formates will get you to the 16 to 19.2 ppg without additives.  Due to their expense they are usually used for drilling the pay zone under balanced and for completion.  Most of the demand for this product is in the North Sea where they have deep wells with a long reach.  Once you go above the 16 ppg, you have higher amounts of cesium which is very expensive.  In my experience, it is unusual to need that high of a weight in this shallow of a well.  I will let Pet weigh in since my knowledge is no longer current.

CF

[sageo]

Pet - Thanks once again. My principle question in looking at this information is just why wasn't this area developed earlier? I suppose the simple answer is that when this drilling was done seismic analysis was crude, if available at all, and the aerial magnetic and gravity technology was even less common and even less advanced. Thus, locating traps was the chief issue as it had to be widely known this was a mighty large "kitchen" in the neighborhood. The absence of an LNG industry of course meant no market, leaving gas without oil without economic value providing plenty of justification to look elsewhere. Quick question: What is the maximum available drilling mud density and could delays at Wahoo have been caused not so much by commercial matters as concerns raised about being able to handle potential well pressures? TIA, and best regards,

Art, cesium and potassium formates will get you to the 16 to 19.2 ppg without additives.  Due to their expense they are usually used for drilling the pay zone under balanced and for completion.  Most of the demand for this product is in the North Sea where they have deep wells with a long reach.  Once you go above the 16 ppg, you have higher amounts of cesium which is very expensive.  In my experience, it is unusual to need that high of a weight in this shallow of a well.  I will let Pet weigh in since my knowledge is no longer current.

CF

  CF-Many thanks to you and Pet for the very pertinent information concerning our Wahoo prospect . Good hunting,gentlemen! sageo.

[petrengr1]

Art, cesium and potassium formates will get you to the 16 to 19.2 ppg without additives. Due to their expense they are usually used for drilling the pay zone under balanced and for completion. Most of the demand for this product is in the North Sea where they have deep wells with a long reach. Once you go above the 16 ppg, you have higher amounts of cesium which is very expensive. In my experience, it is unusual to need that high of a weight in this shallow of a well. I will let Pet weigh in since my knowledge is no longer current.
CF

Was that a pun CF? I am out of my league in discussing cesium and potassium formate with a guy who calls himself Cesium Formate.

I have had no experience with either cesium and potassium formate or excessively high mud weights but I will tell you what I think.

The cesium and potassium formates are water soluble so they can be used to make very heavy brines (clean fluids) which are used for completion fluids where the pay zone is over pressured but they do not want drilling mud on the formation for fear that the solids in the mud will damage the formation.

The weighting material in drilling mud is normally barite. There is an article here that says you can make drilling mud as heavy as 21 lb/gal with  barite. http://www.metu.edu.tr/~kok/pete321/PETE...APTER2.pdf see page 22 From a practical stand point I doubt that a mud weight that high can be maintained in the field. Some times they use hematite for weighting material but it is probably not readily available and would also be difficult to maintain in suspension in the mud. I agree with CF that mud weights this high will not likely be needed. If the pressure was this high it would break out to the surface as a gas or oil seep. That is not to say that we could not find an over pressured zone above the carbonate but I do not expect the pressure to be that high. I would be surprised if a mud weight higher than 16 lb/gal will be required. A formation pressure requiring a mud weight of 19.2 lb/gal would probably  exceed the formation strength and break out to the surface.

If they think there is an over pressured zone above the carbonate they may need to set casing above it before drilling into it. If the zone is not too permeable they may be able to drill down to the top of the carbonate with heavy mud or an under balanced mud system before setting casing again at the top of the carbonate.

[Palm]

Pet, the Spill Point term you mention is an interesting one in that from reading and the fact that this would be a low point in the formation it seems to indicate that Wahoo was filled from a formation down Black Bass way. Is that what you feel is going on and if so what might that indicate prospects are Black Bass way. Or might it just be that the formation Wahoo hydros came from filled with water?

[CesiumFormate]

Art, cesium and potassium formates will get you to the 16 to 19.2 ppg without additives. Due to their expense they are usually used for drilling the pay zone under balanced and for completion. Most of the demand for this product is in the North Sea where they have deep wells with a long reach. Once you go above the 16 ppg, you have higher amounts of cesium which is very expensive. In my experience, it is unusual to need that high of a weight in this shallow of a well. I will let Pet weigh in since my knowledge is no longer current.
CF

Was that a pun CF? I am out of my league in discussing cesium and potassium formate with a guy who calls himself Cesium Formate.

I have had no experience with either cesium and potassium formate or excessively high mud weights but I will tell you what I think.

The cesium and potassium formates are water soluble so they can be used to make very heavy brines (clean fluids) which are used for completion fluids where the pay zone is over pressured but they do not want drilling mud on the formation for fear that the solids in the mud will damage the formation.

The weighting material in drilling mud is normally barite. There is an article here that says you can make drilling mud as heavy as 21 lb/gal with  barite. http://www.metu.edu.tr/~kok/pete321/PETE...APTER2.pdf see page 22 From a practical stand point I doubt that a mud weight that high can be maintained in the field. Some times they use hematite for weighting material but it is probably not readily available and would also be difficult to maintain in suspension in the mud. I agree with CF that mud weights this high will not likely be needed. If the pressure was this high it would break out to the surface as a gas or oil seep. That is not to say that we could not find an over pressured zone above the carbonate but I do not expect the pressure to be that high. I would be surprised if a mud weight higher than 16 lb/gal will be required. A formation pressure requiring a mud weight of 19.2 lb/gal would probably  exceed the formation strength and break out to the surface.

If they think there is an over pressured zone above the carbonate they may need to set casing above it before drilling into it. If the zone is not too permeable they may be able to drill down to the top of the carbonate with heavy mud or an under balanced mud system before setting casing again at the top of the carbonate.

Pet, I love puns, but it was fortunately a typo!

The problem with barites at 21ppg is the viscosity, and the need to frac the well during completion to get all the mud out of the rock and improve flow.  Formates have the viscosity of milk up to 19.2ppg with no solids added to block the formation.  They do not damage carbonate reservoirs.  The material is so expensive that it is rented and only sold when lost -- the major reason to drill under balanced to reduce the risk of losses.

If you are interested, here is some information on formate brines.  I built the plant near Lac Du Bonnie that produces cesium formate, and was involved in earlier testing to do prof of concept on the research work done by John Downs of Shell who originally proposed the use of formates.  I presented at several drilling conferences on the product.  However, I am not a petroleum engineer and do not consider myself an expert on drilling.

http://www.formatebrines.com/Drillingflu...fault.aspx

http://www.formatebrines.com/cabot/Publi...fault.aspx

One question I have often asked - Is it possible to drown in a pool of 19.2 ppg cesium formate?

CF

[petrengr1]

Art, cesium and potassium formates will get you to the 16 to 19.2 ppg without additives. Due to their expense they are usually used for drilling the pay zone under balanced and for completion. Most of the demand for this product is in the North Sea where they have deep wells with a long reach. Once you go above the 16 ppg, you have higher amounts of cesium which is very expensive. In my experience, it is unusual to need that high of a weight in this shallow of a well. I will let Pet weigh in since my knowledge is no longer current.
CF

Was that a pun CF? I am out of my league in discussing cesium and potassium formate with a guy who calls himself Cesium Formate.

I have had no experience with either cesium and potassium formate or excessively high mud weights but I will tell you what I think.

The cesium and potassium formates are water soluble so they can be used to make very heavy brines (clean fluids) which are used for completion fluids where the pay zone is over pressured but they do not want drilling mud on the formation for fear that the solids in the mud will damage the formation.

The weighting material in drilling mud is normally barite. There is an article here that says you can make drilling mud as heavy as 21 lb/gal with  barite. http://www.metu.edu.tr/~kok/pete321/PETE...APTER2.pdf see page 22 From a practical stand point I doubt that a mud weight that high can be maintained in the field. Some times they use hematite for weighting material but it is probably not readily available and would also be difficult to maintain in suspension in the mud. I agree with CF that mud weights this high will not likely be needed. If the pressure was this high it would break out to the surface as a gas or oil seep. That is not to say that we could not find an over pressured zone above the carbonate but I do not expect the pressure to be that high. I would be surprised if a mud weight higher than 16 lb/gal will be required. A formation pressure requiring a mud weight of 19.2 lb/gal would probably  exceed the formation strength and break out to the surface.

If they think there is an over pressured zone above the carbonate they may need to set casing above it before drilling into it. If the zone is not too permeable they may be able to drill down to the top of the carbonate with heavy mud or an under balanced mud system before setting casing again at the top of the carbonate.

Pet, I love puns, but it was fortunately a typo!

The problem with barites at 21ppg is the viscosity, and the need to frac the well during completion to get all the mud out of the rock and improve flow.  Formates have the viscosity of milk up to 19.2ppg with no solids added to block the formation.  They do not damage carbonate reservoirs.  The material is so expensive that it is rented and only sold when lost -- the major reason to drill under balanced to reduce the risk of losses.

If you are interested, here is some information on formate brines.  I built the plant near Lac Du Bonnie that produces cesium formate, and was involved in earlier testing to do prof of concept on the research work done by John Downs of Shell who originally proposed the use of formates.  I presented at several drilling conferences on the product.  However, I am not a petroleum engineer and do not consider myself an expert on drilling.

http://www.formatebrines.com/Drillingflu...fault.aspx

http://www.formatebrines.com/cabot/Publi...fault.aspx

One question I have often asked - Is it possible to drown in a pool of 19.2 ppg cesium formate?

CF

You might be able to drown but only if you lay face down. You only weigh about 8.1 lb/gal so if you lay on your back less than half of your body will be below the cesium formate solution surface.

[petrengr1]

Pet, the Spill Point term you mention is an interesting one in that from reading and the fact that this would be a low point in the formation it seems to indicate that Wahoo was filled from a formation down Black Bass way. Is that what you feel is going on and if so what might that indicate prospects are Black Bass way. Or might it just be that the formation Wahoo hydros came from filled with water?

Palm - I have no idea how the gas migrated into Wahoo (assuming there is gas there). What I think we can say is that in a sedimentary basin the rocks were formed or deposited in water. So they were originally filled with water. In this over thrust area there is a lot of faulting. The source beds are deeper than the potential reservoirs.  Hydrocarbons are lighter than water. So the hydrocarbons migrate from the source rock through faults, fractures or permeable beds toward the surface until they are trapped in a place like wahoo. The trap fills until the water is all displaced out of the trap to the highest spill point. To fill the trap may take millions of years. What stage are we at at Wahoo? I do not know. May be zero filled, may be half filled or may be fully filled to the spill point.
My guess is the gas migrates more through faulting from the source rock toward the surface. Black Bass gas and Wahoo gas may come from the same deeper source rock (kitchen) but the gas would not likely migrate in the shallow zones at Black Bass to Wahoo.

Regarding wells drilled in the area. Some were drilled with a minimum or no seismic data. The Popo wells were very shallow, not drilled deep enough to test the most promising zones. Looks like Black Bass was drilled with perhaps one line of legacy seismic from somewhere. They said they were off structure. This was all before they used the airborne magnetic/gravity surveys to identify the larger structures. So most of these wells were drilled “in the dark”. It is probably a good sign that they found any sign of gas or oil. IOC learned the lesson that they need to identify the major structures with magnetic/gravity surveys and then check those indications with seismic before drilling. I hope they don’t have to learn that lesson again. I was a little worried that they jumped on Bob Cat so quick. They have said they are getting some seismic although they have already built the location. They must have some seismic data by now but it has not been made public as far as I know.

So we have good indications from the old wells in the Wahoo area that there is oil and gas present. We just need to find the large structures with some kind of trapping mechanism i.e. Anticline with 4 way dip or anticline with fault traps, reefal buildups covered with shale/mudstone etc.



See http://tinyurl.com/may8c52  ; page 21

I think IOC has enough data to justify all of the prospects along coast in PPL 236. They probably need more seismic data before drilling but they have a very good chance of finding gas in these carbonate reefs. Some of them may be relatively small and will need some help to commercialize. One way to do this would be to lay an on shore pipe line from Tuna right down the Government highway to or near the Exxon LNG plant site. All of the small fields could be tied into the gas line without too much expense and delivered to an LNG Plant near Port Moresby. We might need a liquids pipeline also. I think it would take about 130 miles of pipeline to reach from Tuna to the Exxon plant. This would be much cheaper than an offshore pipeline.

I don’t have much faith in Whale and Barracuda at this time with the data available to the public. They ran one line of seismic at each of them and then never mentioned it again. There may be some zone below the Miocene limestone but I think the limestone is too shallow or possibly out cropping.