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Gold/Mining/Energy : gothic resources -- Ignore unavailable to you. Want to Upgrade?

To: Patrick Lauder who wrote (131)	12/14/1998 8:03:00 PM
From: Bearcatbob	Respond to of 299

Thread, When pressure is measured is it an absolute gauge pressure or is adjusted for the static pressure of the mud column in the well bore. By that I mean, is there a gauge at the top of the well bore that gives a pressure. That pressure would be the down hole pressure minus the static pressure of the well bore mud. The alternate is that the pressure is adjusted for the static mud pressure. Bob

To: Patrick Lauder who wrote (131)	12/14/1998 10:54:00 PM
From: Ed Pakstas	Respond to of 299

Patrick... First of all I gained that limited experience 18 years ago as a frac hand (well stimulation), and it was unfortunately limited to about 2 and half years... As you may know, if you don't work at it on a continual basis a lot of what you learn disipates from the mind as you get older...<ggg>...Besides that, I'm 100% sure that a lot of the technologies and procedures have changed since then... At the time a V16 turbine pumper was a big deal at the time... Don't know what they use these days... >>can you get pressure and still not have gas flow? <<< Definitely... Take a look at the water fountain the KOB has in East Lost Hills...(that's supposed to be funny <gggg>)... Logs will record flow rates and pressures through various openings of the choke in the well head, over a predetermined period of time... (that much I remember)...From that you can estimate reserves... Also, assuming there is gas present and it flows, how do they (in lay terms) determine the proven reserves? ... I'm sorry, but I never got into it that far... I know they tell us the formation has porosity which is necessary for the gas to flow, but can't the logs also tell us if there is gas present. At the time that I was in it, the logs recorded flow rates no matter what it was that flowed... I don't know how they can determine what it is that flows through the well head right now, unless it flows through a separator first...Then the different gases and condensates are measured...Mind you I'm sure that they have labs the test the contents of fluids that flow out of a well just as they have assay labs for metals and minerals... I would imagine if we knew there was gas present and the pressure was there, it would eliminate the risk considerably. Not necesarily... As I said before, the uphole pressure can be caused by different fluids and gases... Do you happen to know how many feet of pay we have here, and is it relatively a large amount? Don't know that for sure yet... The news releases said that they were about 1200 feet into the Ellenberger formation and that they were still a few hundred feet shy of the total depth they where attemting to reach... I'm assuming that the formation is the pay zone... I guess that will be determined by the flow rates... I'm going to try and get an individual over to this thread, who's oil and gas knowledge I've grown to respect over the past several months... I'm hoping he can come over and answer the rest of your questions as I cannot because I don't know... ...ed

To: Patrick Lauder who wrote (131)	12/14/1998 11:41:00 PM
From: Ed Pakstas	Read Replies (1) \| Respond to of 299

Patrick here's an excellent post re description of a separation process... techstocks.com ...ed

To: Patrick Lauder who wrote (131)	12/16/1998 4:38:00 AM
From: grayhairs	Read Replies (2) \| Respond to of 299

Hi Patrick, Sorry to be tardy getting to your questions. I can not address your questions thoroughly but I'll try to provide you with some general and basic principles/rules of thumb. can you get pressure and still not have gas flow? Usually, with all other things being equal, high pressure means: - Higher reserve numbers. - Higher reservoir energy levels and higher recovery factor. - Higher well production rates. - Greater risk in drilling and completion operations. For hydrocarbons to flow from the reservoir and into a wellbore, the reservoir rocks must have permeability. Usually, the greater the porosity of a reservoir rock, the higher the permeability. But, there are many cases where porous rocks have very low permeability (Eg. shales) and even though high pressure hydrocarbons may be present, they may not flow at economic rates. what do the logs tell us exactly? There are two general types of logs, open hole logs (run after drilling and before casing the well), and cased hole logs (run in cased wellbores). Open hole logs are run to enable a calculation of the following characteristics of the formations penetrated by the wellbore: - Formation tops. - Formation gross thicknesses. - Formation dip. - Porosity. - Mineralogy including clay contents and types. - Fluids present in the pore spaces. - Net pay thicknesses. - Formation Permeability (not generally reliable). - Cross-Sectional geometry of the wellbore (It isn't always circular!!) Open hole logs are carried out primarily to determine the parameters required to make a volumetric estimate of reserves. To conduct these log calculations certain assumptions are required. As in most calculations, garbage in generates garbage out. In heavily drilled areas, good assumptions will usually be possible so the calculations will be quite reliable. But, when drilling a wildcat well, good "assumptions" will be more difficult and calculated results may be less reliable. When log interpretations are difficult\inconclusive, drill stem tests will often be carried out to assist with or confirm the log evaluations. But, drill stem tests are not always practical due to safety and other issues. Cased hole logs are used to assist in completion operations, remedial workovers or reservoir performance evaluations. Cased hole logs can help with: - Casing inspection \ damage appraisal. - Cement bond evaluation. - Identification of perforation intervals. - Identification of casing collars and centralizers. - Evaluation of formation porosity (not real accurate). - Evaluation of fluid interface movement (in the formation). - Determination of perforations contributing production. - Determination of fluid types being produced from different perfs. ...can't the logs also tell us if there is gas present? Well, we can make calculations from the log data but sometimes these calculations are not reliable (Eg. In a wildcat we may not know the salinity or resistivity of the brines in the formation so our calculated fluids depend somewhat upon our assumptions. Or perhaps the hole "caved in" during drilling operations and so neither the measurements generated by the logging tool nor the equations used to compute the estimate are accurate.). how do they (in lay terms) determine the proven reserves? Do they assume the entire structure is the same as where the well hole is,... Most lay people incorrectly believe that a high production rate means a big reserve. It doesn't. A high initial production rate just enables a more rapid depletion rate of whatever reserve may be present. Initial production rates tell you NOTHING about the size of the reserves. (Long term production rate histories can be useful for estimating reserves in mature fields, however.) There are three basic kinds of reserve estimates - Volumetric, Material Balance and Decline Curve. The first and least reliable estimates made will be volumetric. After some production history more reliable estimates, Material Balance, are possible. These estimates will normally yield reliable reserve estimates only after 5-10% of the reserve has been produced. Decline Curve analysis can be used on very mature (50%+ depleted) reservoirs to obtain reliable reserve estimates. If from seismic and/or geological studies you can estimate the areal extent of the reservoir (acres), and if from well log data you know the thickness of the pay zone (feet), the porosity of the rock (%), the type of fluid (%), and if from other information\measurements you know the reservoir pressure (psia), and the reservoir temperature (degrees F) and the formation volume factor of the hydrocarbons (fractional), then you can ESTIMATE a volume of hydrocarbons in place in the reservoir. Then if you have detailed analysis of the hydrocarbons you can estimate shrinkage loss due to removal of impurities and byproducts and if you have an analog reservoir or other studies you can predict the ultimate recovery factor, and voila!! You can come up with your bottomline estimate of recoverable marketable reserves. This is a Volumetric Estimate. To the extent that the estimator has confidence in the data and the economic producibility of the reserve, a portion will be classified as proven. Some additional portion may also be considered probable while the remaining reserve, if any, would be ranked as potential. Public companies must report reserves as per requirements imposed by the exchanges but reserve classification remains quite subjective. Following the drilling of a discovery well, a production test is performed. Pressures of the reservoir are measured both before and after the test. The test information enables a Material Balance Estimate of Reserves. BUT, the reserve computed by this type of test is only reliable if the reserve is very limited in areal extent and is significantly depleted by the test!!! Also, how long after the final test does it take to calculate the proven reserve? There are so many factors to consider that a general answer is impossible. Suffice it to say that the bigger the reserve, the longer it takes to calculate a reliable proven reserve. Do you happen to know how many feet of pay we have here, and is it relatively a large amount? The News Releases indicated a gross pay interval of about 1,200 feet, I believe. That number is VERY LARGE but there has not yet been any indication of what the net pay may be. Hope the info herein is of some use to you, Patrick. Later, grayhairs