photos?, page-2

Sw3, I dont have photos, but what I can share is that I wrote off to TB yesterday because I had a couple of questions – and he replied quite promptly – so wanted to share a summary of the questions and answers. I cannot cut and paste the emails, but I have written permission from TB to summarise the exchange in my own words, so this is my opinion of the exchange. I also ran this past HC admin to obtain guidance on posting this so that I would minimise the chance that I am infringing any rules in doing so.
 
My two questions, and the answers, are summarised as follows:
 
Q1: I asked whether any of the data obtained prior to the decision to complete the Defender will by commencing the full frac of Defender, i.e. data obtained both before drilling started and during drilling, up till the DFIT stage 1 frac was completed, did they expect the fluid recovery to be at a low pressure as they subsequently found, and could TB provide an explanation for the low pressure.
 
A1: TB’s answer was that they understood that the Niobrara horizon was normally pressured, as opposed to the Bakken which is over-pressured. The reason for the lower pressure in the Niobrara, compared to the Bakken, is that the Bakken has a higher TOC (Total Organic Content), and also the Bakken is an older structure. The organic content expands when it converts into oil and gas, and so in the Bakken with a higher TOC and more time to mature, there is more of a pressure build-up than there is in the Niobrara. They understood this, and while a lot was pre-known about the Niobrara, the true test is to drill and frac to get the in-situ data that can only be obtained that way – which was a key factor in bringing HAL on board for this project. TB also added that he believes the valves of the pump they installed to assist with the fluid recovery were probably damaged during the installation, which explains why the lift has not been as efficient as expected, and he believes with the new pump they will get the much-awaited answers shortly.
 
Q2: I was concerned that the extended duration of drilling at Australia 2 may jeopardise our lease at Fort Peck, because I recall that a lease condition was that they needed to drill two wells by the end of 2011. So I asked whether there was any risk there, and whether FPEC were satisfied with progress there.
 
A2: TB answered that the lease condition was determined by December 2011 or 90 days after issuance of the drilling permit, whichever was later. He stated that they are in compliance with the timetable, and he believes that the relationship with FPEC is excellent, that they are impressed by SSN’s community program, and apparently are so impressed with what Samson is doing they are asking why the other oilers aren’t doing what Samson is doing. TB therefore believes there is no commercial risk out of the relationship with FPEC. TB also added on the technical front that he believes the market hasn’t yet fully digested the importance of the results from Australia 2 so far. He believes the results have de-risked the Fort Peck Bakken play a lot. They weren’t sure what they were going to see prior to drilling, but the published results have given them a big increase in confidence about making this play work.
 
The explanation about the fluid pressure at Defender was a confidence booster to me, because it seems they expected the low pressure even with all the data right up to when they started the full frac. A defective pump would also explain why the fluid recovery total hadn’t increased a lot since the pump was installed. Still have to wait unfortunately, but it seems they still do not know the answer at Defender. The Fort Peck information both commercially and technically sounds very positive. Hope the above is of interest to a few...

Cheers, Sharks.