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interpretations and fun times to come!!

  1. 1,226 Posts.
    Gas shows:

    Gas that rises to the surface, usually detected because it reduces the density of the drilling mud. Gas detectors, which the mud logger monitors, measure combustible gases (methane, ethane, butane and others). The mud logger reports total gas, individual gas components, or both, on the mud log. In extreme cases, gas visibly bubbles out of the mud as it returns to the surface. Because the mud does not circulate to the surface for a considerable time, sometimes lagging several hours after a formation is drilled, a gas show may be representative of what happened in the wellbore hours (or many feet) prior to the current total depth of the well.

    Another definaition of a gas show is:
    the appearance of natural gas in the returning drilling fluid. Gas show is a term used in mud logging to show the amount and composition of natural gas above background gas levels.

    I pinched this from the GGP thread from waltage:
    Here's a link to a release by Golden State resources back on 20/11/06

    A couple of excerpts from ann

    - Gas units: 10,000 units = 100% gas i.e. 1,000 units = 10% gas in drilling mud.
    - A significant gas show, with levels up to 800 to 1,000 units
    If you check GDN's chart, share price went up from around 20c to $1.20 throughout November (I'm using comsec so its hard to tell when the rise started from chart) while drilling updates were given on this well (Paradox Basin #1 well). The well encountered a number of gas bearing zones
    And bungy 234 (thanks guys)
    Now that you guys have brought up the subject of that other oil and gas player, it's interesting to note that the following was reported whilst drilling PB #2 well:

    "significant gas show of background gas up to 1,042 units is almost triple the 390 gas units in PB #1 well"

    Now, the 6,800 gas units reported by GGP today is 6.5 times greater than that significant gas show in PB #2 well.

    Still early days, but the well is certainly looking promising.

    Nevertheless lets move on,
    A knowledge of gas composition makes it possible to establish the relationship of methane to possible to establish the relationship of methane to the heavier hydrocarbon shows. An awareness of this relationship led to a new, additional mud log interapretative technique that permits relating the quantitative amounts of methane (C1), ethane (C2), propone (C3), butane (C4), and pentane (C5) in-place propone (C3), butane (C4), and pentane (C5) in-place reservoir fluid content.

    Those are chromatograph readings and interpreted by professional loggers. We will recieve this report like EGO did recently soon enough I assume. I recommend that everyone read this ebcuase it explains what background gas is an some other kep interpretations. You dont need to understand most of the stuff its just interesting to note some terms and procedures. Howver you could conduct some interpretations reading through the article though later on I provide another site where you can interpret.. though DYOR as all interpretations are important:

    furthmore; from the site I got the below information:

    FIG. 3 is a depth versus ethane/methane (C2/C1) chart derived from tabulated data in FIG. 2. The tabulated data from FIG. 2 is used to plot ethane/methane points (X-axis) versus depth (Y-axis). The objective of FIG. 3 is to observe any highC2/C1 ratios (i.e., gas wetness). High ratios are generally those having a value over approximately 0.1. Values over 0.1 or any relatively high value in a data set may suggest a wet gas that may be associated with hydrocarbon fluids, such as oil.

    a wetness background trend issimilarly plotted as a background trend line X. Mud gases released at the surface from the drilling mud form mixtures of predominantly hydrocarbon gases and air. The concentrations of sampled mud gases vary considerably and may show hydrocarbonconcentrations close to 0 vol % or as high as 90 vol %.

    Depending on individual well mud weighting protocols, typical background trend levels are reflected by hydrocarbon gas concentrations between 0.01 vol % and 1 vol %, while hydrocarbon gas concentrations greater than 2 vol % are generallycharacteristic of gas shows.

    This article: is also interesting as it says that high levels of C3 often mean black gold is involved. Also If C1 is 98% of the reading or more, than it is dry gas .. however if C2 or C3 is over 2% it is reffered to as wet gas. It explain about it in the pdf.
    Natural gas produced along with crude petroleum in oil fields or from gas-condensate fields; in addition to methane, it contains ethane, propane, butanes, and some higher hydrocarbons, such as pentane and hexane.

    Wet-Basis" is analysis without removing the water from the flue gas
    "Dry-Basis" is the analysis after the water has been removed (theoretically completely, but usually in part )
    Dry gas is natural gas that is always in the gaseous state in the reservoir and produces little condensable hydrocarbons (compounds composed mainly of hydrogen and carbon) when brought to the surface. Thus, these gases contain very small proportions (less than 0.1 gallon condensables per 1,000 cubic feet) of hydrocarbons heavier than ethanebutane or propane, for example
    Wet gas produced from a reservoir will always contain some amounts of water. This is the ground water/formation water vapour in equilibrium with the gas under the pressure and temperature in the reservoir. When produced some of this water will precipitate out as free water in the production flow line as pressure and temperature decreases. This water will contain no salts because its origin was water vapour. Later in the production lifetime of the gas reservoir you might get free water breakthrough. This water will contain salts from the reservoir. It must be emphasized however that the term wet refers to the presence of hydrocarbon components which are heavier than ethane and not water. It should also be noted that the presence of water is not exclusive to wet gas but may be present in each of the other four main types of reservoir fluids (black oil, volatile oil, retrograde gas and dry gas) in varying percentages.
    Wet gas is a natural mixture of hydrocarbons that may be gaseous or both liquid and gaseous in the reservoir and that contains an appreciable proportion of compounds heavier than ethane (e.g., propane or butane) that are condensable when brought to the surface. Such gases usually are characterized by the volume or weight of the condensables contained in a given volume of total gas produced. This figure, computed for volumes at 15 C (59 F) and 750 mm of mercury, is usually expressed either in gallons per 1,000 cubic feet or in grams per cubic metre; for a gas to be classified as wet, it must contain more than 0.3 gallon of condensables per 1,000 cubic feet of gas. The condensables are recovered, the propane being marketed as liquefied petroleum gas and the heavier hydrocarbons being made into gasoline. Compare dry gas.

    Now that I have explained how to interpret gas chromatograph readings an excellent way to interpret the results to see if the gas/oil is productive or not productive. Check out the table

    In contrast, gas samples from wireline samplers or production tests are usually uncontaminated by atmospheric gases, so hydrocarbon concentrations are usually quite high.

    Here is an article on drilling for gas for students everyone who doesnt have a geophysics or geology degree:

    Drilling for Oil
    Once the environmental and seismic surveys are completed, and if the results look good drilling an exploratory well is considered. Even at this stage, it remains an uncertain business with no guarantees. There is still a high risk that nothing at all will be found, or that the oil will be in such small quantities that it would not be worthwhile extracting it. In the North Sea only about 1 in 8 exploration wells find quantities of oil and gas that are economic to develop.

    Drilling exploratory wells
    Three different ways of drilling exploratory wells:

    Jack-up unit
    This is a barge with legs that can be raised and lowered. It is usually towed into position, its legs lowered and then once they are sitting on the seabed, the barge is raised out of the water creating a stable drilling platform. Jack-up units are usually used in up to 100 metres of water.

    Semi-submersible drilling rig
    These usually have an engine so they don't need to be towed. The working platform is supported on vertical columns that are attached to submerged pontoons. Once in position the pontoons can be flooded with water to lower the whole unit further into the water. The lower the pontoons are beneath the water, the less likely they are to be affected by wave action. This makes them stable in rough seas and in depths of 300 metres or more.

    These look more like a conventional ship and can be easily moved between locations. The latest drill ships can drill in water depths of 1500 metres or more, but they can be unstable in rough seas.

    Spudding the well
    The first step is to drill a 90cm hole and then put a wide pipe into the seabed to guide the drill and the drilling fluid. As each section of the well is completed it is lined with a heavy steel pipe casing that is cemented in place to prevent it caving in. This process is called "spudding the well".

    The derrick
    The derrick is the tall structure that supports all the drilling operations. It is designed to haul the drillstring - lengths of drillpipe with the drill bit on the end - in and out of the hole. Sections of drillpipe or drillstring are added as the hole gets deeper. Each piece of drillstring is typically 10 metres long, about the length of a bus which explains why the derrick, which needs to accommodate 3 lengths of drillpipe, has to be so tall. The drillstring can weigh several hundred tonnes, so a powerful motor is needed to winch it up and down.

    The drill bit
    The drill bit is attached to heavy drill collars that put weight onto the bit. The drill bit is rotated either by turning the whole drillstring or by a turbine down the hole that is driven by drill fluid. Depending on how hard the rock is, the drilling rate can be less than 30 centimetres an hour or as much as 60 metres an hour in relatively soft rock.

    The drill bit needs changing every few days, or maybe every few hours, depending on the hardness of the rock. When the drill bit has to be changed, the whole drillstring is pulled back up, uncoupled in sections, stacked up, the drill bit changed and the whole process starts again. This is known as a 'round trip' and can take 10 hours or more.

    Use of 'mud'
    Drilling fluid, which is commonly known as 'mud', is continuously pumped at high pressure down to the drill bit to lubricate it and keep it cool. The mud also flushes out the rock cuttings and brings them back to the surface. Geoscientists are able to inspect and analyze these tea leaf sized samples and gain more information about the rock structures and the presence of hydrocarbons. The person who does this is known as a mudlogger.

    Another important consideration is that the force and weight of the mud that is pumped down the drillstring into the well, balances the pressure of the crude oil and gas in the surrounding rocks and so significantly reduces the risk of a blow out.

    Controlling the well
    Because the oil and gas, deep below the Earth's surface are at high pressure great care has to be taken to control the pressure. In cinema films they often show what is called a 'blow out'. This can occur when a drill enters a reservoir and the pressure causes the oil and gas come spurting out of the well. The result is potentially very dangerous. Although blow outs are very unusual, all wells are fitted with an emergency valve designed to prevent this from happening.

    Core samples
    If the geologists find something particularly interesting they can ask for a core sample. A hollow drill, called a core barrel, is attached to the drillstring and as it goes down a core of rock forms inside - a bit like using a giant apple corer! This core sample gives a continuous record of the different layers of rock and therefore more detailed information than the rock cuttings. Collecting a core sample is expensive and time consuming because it involves a complete 'round trip'.

    Before a well is finally capped, vital information is gathered by lowering measuring devices contained in what as known as a sonde down the hole on a wireline. As the line is pulled back up the hole, the sonde transmits information to a computer on the surface about the porosity and other qualities of the rock it is cutting through. This information provides a survey of the well and gives more information about the presence of hydrocarbons in the pores. This technique is called logging.
    Field Appraisal
    If an exploratory well shows that hydrocarbons are present, more seismic data is gathered and then a number of appraisal wells are drilled and more data is collected. From this data it is possible to estimate how much oil and gas the field contains, how difficult it will be to extract and what percentage of the oil and gas can be extracted.

    Unfortunately, it's not possible to get every last drop of oil out of a reservoir - in the North Sea, for example, operators expect to recover about 40 - 50% of the total reservoir. This figure may seem quite low, but remember there isn't a lake of oil and gas. Instead it is trapped in the pores of the reservoir rock and you can appreciate that it isn't possible to get every last drop out. Think back to the idea that oil is held in pores in much the same way that water is held in a sponge. We know that it isn't possible to get every last little drop of water out of a sponge - it's always a bit damp.

    Oil exploration involves lots of people with different skills, for example geologists, geophysicists, surveyors, mudloggers, computer scientists, marine biologists, drilling engineers, the drilling crew. Alongside these are all the people employed back onshore for example economists, planners, lawyers, IT specialists, environmental advisers and safety advisors to name a few.

    This is an article about the North west shelf I found interesting. I found the bottom paragraph the most interesting.
    Development of an $1.6 billion gas and condensate field off the North West Shelf in Western Australia is expected to commence following completion of final investment decisions by all of the joint venture participants.

    Development of the North West Shelf Ventures Angel field will include installation of the Ventures third major offshore production platform and associated infrastructure, including a 50 km subsea pipeline. The field development is expected to underpin current gas contracts and future sales and builds on LNG business at the North West Shelf.

    The remotely-operated Angel processing platform will be in 80 m of water approximately 49 km east of the Ventures existing North Rankin production facility and will include three production wells which are scheduled for drilling between 2006 and 2007. Hydrocarbons will be produced through one processing unit with a capacity of up to 800 MMscf/d and up to 50,000 bbl of condensate a day.

    If you see BCCs expected average of MMscf it is between 7-10. 800 is extremely high.. we (VIL and GGP) will nowhere near gain results of that level.. though it is interesting to see the potential of the northwest shelf bit off topic though. Nevertheless with 6800 units of gas just thinking about what happened to GDN makes my mouth moist . I can taste the sweetness of money!!
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