Wrap – Week Ended 10/15/10

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Wrap comments will be in the Monday post. 

4 Responses to “Wrap – Week Ended 10/15/10”

  1. 1
    crysball Says:

    MMR    and Baker's new RCI [realtime reservoir  characterization instrument].
    "Schiller said that in addition to Gamma Ray, Porosity, and Resistivity measurements, they had run Baker’s (RCI) tool.

    Big improvement from old RFT tool.Here’s what Baker’s website says about the fluid sampling module of the tool:

    “Our IFX technology is integral to our Baker Atlas Reservoir Characterization Instrument™ service. It allows an early assessment of your reservoir’s commercial value while verifying reservoir connectivity or compartmentalization. It also detects fluid compositional gradients and validates fluid density derived from pressure gradient analysis.

    The IFX service’s real-time continuous measurements of reservoir fluid properties include in-situ for assessing fluid type, fluid phase, and contamination monitoring. Our IFX service acquires downhole measurements under reservoir temperature and pressure conditions. This reduces risk of compromised PVT data that occurs during the retrieval, transportation, and transfer process before PVT laboratory analysis. Measurements allow real-time decisions regarding sample selection depths, identification of compositional differences, and compartmentalization.

    A sound speed measurement is excellent for contamination monitoring. The measurement is made using a high-frequency transducer. This high-resolution measurement is sensitive to small changes in fluid properties like water salinity and compressibility. It ensures collection of low-contamination formation water in water-based mud environments and differentiates live oil from oil-based mud filtrate.

    The IFX service confirms and correlates pressure gradients to direct density measurements. It also delivers real permeability measurements that are based on mobility and in-situ viscosity measurements. It identifies compositional variation between zones and compartmentalization based on fluid compositional changes. It optimizes fluid sampling programs, reducing rig time for significant customer savings.”


    If the tool worked in BBE as Baker says it should, one could draw the following conclusions:

    1) They knew what the densities of the formation fluid samples were as soon as they obtained them from the formation. Remember, there are big difference between formation water, oil and gas densities.

    2) These fluid densities could then be compared to the pressure gradients they obtained at the well site at various depths in the reservoir.

    3) Data obtained from 1 and 2 would confirm the presence of hydrocarbons in the reservoir, long before laboratory fluid analyses are done.

    4) The tool has the capability to do a mini-DST when a sample is taken. Reservoir pressure response is measured and analyzed using pressure transient to get a formation permeability. Note the tool measures fluid viscosity. To get permeability, fluid has to move through the reservoir, otherwise it will be a failed test.

    So what? When Shiller (engineer) says they have “excellent” reservoir, with 20% “average porosity”, permeabilities in the 20md – 100md+ range and they contain hydrocarbon, it would seem he has data to back it up.
    Bottom Line: Shiller didn’t have to wait for lab analysis of fluid samples to say whether they had hydrocarbon or not. Pressure gradients in the pay intervals alone would have been good enough. Fluid densities, provided by the RCI tool, would be back up to the pressure gradient data. 

    The  implications of this are extremely important.

  2. 2
    crysball Says:

    "A reminder from Shiller on why fluid samples, cores, and pressures are so important:


    EXXI 4th Qtr Earnings Conf Call Webcast

    September 8, 2010

    ~5:48 Minutes into the call

    Discussing Davy Jones 2 extension well.

    Shiller: “ Let’s look at what’s still needed before we begin booking those (Davy Jones) reserves. “…

    “We should be able to get wireline logs, we should be able to get fluid samples, we should be able to obtain reservoir pressures, and seeing the log like we’ve already drilled, we should be able to have cores within our reservoirs. You put all that together and that should be all the data we need, after our conversations with Netherland Sewell, to move these reserves from the contingent resource category into the proved category, at least on some potential spacing area of two or three locations at a time…locations at a time. The other thing that’s important to keep in mind on the data from the offset well is, as I’ve told many of you over the past six months, is there is a one out of three chance that we actually …probably get by with 20,000 lb equipment….uh pressure equipment. That’s sort of dependent on what pressure regression we see and how much condensate this gas has with it.


    16:53 min

    Q: "One of the other things I wanted to ask you about was your comments on liquids…and um liquids expectations from the wells. In the prior core work, and in the core work that you’re doing forward, how certain can you be about liquids content, before you actually produce liquids from the well?"

    Shiller: "Well I mean if we get a live sample, Duanne, down hole, we’ll be very certain about what kind of liquids we have with the gas… condensate, NGL’s , your density of your gas and your components of it. So, what you’re really looking for with regards to a pressure determination is to what is the correct gravity…uh..so you can get a psi/ft sort of weight for the gas stream in your tubing. And, you know, to give you some sense..dry gas is about 0.1 psi/ft, whereas oil is about 0.33-0.35 psi/ft, and water is obviously 0.465 psi/ft. So, the more liquids you have, the heavier the weight of that column (in the tubing), the less of that reservoir pressure you actually see at the surface. " So, the combination of how much liquids we might have in the gas, coupled with the actual bottom hole pressure… Because remember, what we are kind of doing right now is assuming a worst case. We’ve got the mud weight we drilled the formation with as our (assumed) pressure and the dry gas, and you do all that and we come up with 22,500 psi as our shut-in tubing pressure maximum. So to move that down below 20,000, it really doesn’t take a lot more than about a 1PPG drop in bottomhole pressure and a little bit of liquids. Until we show that data (reservoir pressure and liquid content of gas), we have to design around what we know (worst case). And that’s where we’re at right now."

    Q: "And then clearly, the other side of the condensate conversation being …uh…the improvement to economics going forward. So, in your running of economics are you assuming any liquids or is that going to be gravy once you run the economics?"

    Shiller: "Yeah, you know great point Duanne, when we look at things you know, at $4 gas we print money, if when we run 100% gas and no liquids, our break even is about $2, and if you even start adding 20 bbls/MMCF to the condensate yield at $65/bbl condensate then you end up driving your break even economic price below $1/MCF.

    So, obviously, when you start talking about TCF’s of natural gas, condensate adds up real quick in value.

    Q: Very good. Thank you very much."


    1) According to Shiller, MR/EXXI can book proven reserves by collecting the data listed above at Davy Jones 2, without having to produce the wells. I assume this means they could also book reserves based on the data they have collected for the intervals drilled so far at BBE.

    2)Pressures and fluid gradients will determine which intervals can be completed with conventional 20 k completion equipment. This could allow accelerated development, production and cash flows across a large swath of their ultra deep portfolio. Shiller has already indicated this is true for intervals drilled so far at BBE. Depending on pressures of current and yet to be drilled intervals, bottom hole pressures could be lower than what are being assumed as "worst case" from drilling mud weights and an assumed dry gas tubing gradient.

    3) Already robust dry gas economics, improve markedly when you add even a very low (20 bbl/MMCF) condensate yield.

    Keep all this in mind as Jim Bob reveals what they've found on Monday. Things could start to fall into place faster than many of us think


  3. 3
    zman Says:

    Thanks much Crys.

  4. 4
    jat Says:

    based on the HAL call so far I think consensus raises 2011 estimates.  not making a call on the stock, just my quick thoughts on estimates.
    was a miss relative to whisper, obviously, but that's international driven (could be Iraq start-ups, if so that's a positive given the size of the eventual market) and non-ops. 
    given the confidence around NAM here and simple 2010 exit rates vs. current 2011 NAM estimates, it seems like the bulk of 2011 needs to rise, NAM offsetting whatever recalibration comes as a result of the international.

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