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PETE TenTen
เข้าร่วมเมื่อ 5 พ.ย. 2012
วีดีโอ
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มุมมอง 3.6K11 ปีที่แล้ว
Drilling Fluid, mud, mud engineering, drilling, hydrostatic pressure
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มุมมอง 15K11 ปีที่แล้ว
How to calculate oil-in-place (basic - for introduction to petroleume engineering students - not all variables included.
Brazil Energy Production and Consumption
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By: Abby Lindsey, Kyle Pagan, Austin Brocato
World Oil Transit Chokepoints
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Spring 2013 PetE 1010- Section 1 Joe Kiefner Maggie Ross Michael Giles
Angola Presentation
มุมมอง 56012 ปีที่แล้ว
James Brockman, Austin Hardy, Savina Nguyen give a presentation on Angola for PETE 1010.
Nice one but What about formation volume factor?
Thank you
Amazing
Does the drilling fluid stay in the soil at the end or is it pumped out?
So = you have to give more info about it
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Hi
so is underbalanced best ALWAYS?
Good video!
Ok great, but we don't sell oil by the cubic foot. Oil is priced and sold by the barrel. There is 7758 barrels of space in one acre foot. First we subtract the rock matrix. Say 80 percent. Leaving 20 percent porosity. 7758 x 20 percent. Then we seperate out Sw and Sg leaving So. We are not done because we can only recover a percentage of the oil in place. (Recovery factor) Also when oil is removed from the ground it tends to cool at the surface and shrink. We have already subtracted for Sg so we don't do it again we just adjust for cooling. Today we can recover more oil in place using modern technology so a 50-60 percent factor may be reasonable however 40 percent is the factor commonly used by developers looking to get some idea of the probable economics. We end up with something between 100 and 1000 barrels of oil per acre foot recoverable in place in sand and carbonate resivors, depending upon effective porosity, Sg and Sw content. Finally when the buyer pickes up the oil he takes a sample and seperates out the water and sediments (bs&w) and subtracts volume based on temperature.
plz am a petroleum engineer and am looking for job.....plz if you can help me secure a job in your country i we be very happy.....plz whatsapp me on +2347036723410. am good at drilling fluid analysis, gravel packing, demulsification of emulsion and analysis of crude oil
Are you still in the drilling industry? I would like to talk to you about mud readings. Thanks Butch
+RCB58Hustler he's a professor at LSU, head of the undergrad for petroleum students
thanks professor! great video
Great video! Exactly what I needed to help.
If the formation pressure exceeds hydrostatic pressure will the formation cave? How much is lost? Just the bit, entire formation ext.?
The entire formation will not cave but only retract relative to loss of hydrostatic pressure. Operators should never allow zero pressure or presence. In the event of a jam, the bit can be recovered by increasing the hydrostatic pressure and pumping mud out of the hole while spinning the bit in place . Nothing is lost.
The previous answer to this question is not necessarily incorrect, but needs a bit more clarification. If the formation pressure exceeds the hydrostatic pressure (assuming you mean the pressure inside the wellbore provided by the mud), one of two things will happen. 1 - If the hydrostatic pressure is a allowed to drop low enough, the minimum collapse pressure will be realised and the formation will yield. The amount of yielding will depend on the hydrostatic pressure and MAY, if the elastic limit is exceeded, cave in. 2 - On the other hand, if the hydrostatic pressure is lower than formation pressure, but above collapse pressure, the formation will unload wellbore fluids into the well itself. This is what's called a kick. It's possible to have both situations happening at the same time. How much is lost? ... depends. Possibly the whole well if you let things get severe enough and do nothing about it. The previous respondent is correct when he says that operators should never drill on-balance (this means P_hyd = P_form), unless they have the equipment to do so, and it's specifically intended (see Managed Pressure Drilling). Normally you'll drill with a few decimal points lb/gal over the P_form, but this varies. Best starting point when planning a well is always to set your mud weight mid way between pore pressure and frac pressure and all of make adjustments from there. That way you'll avoid all these problems, but there of course there are drawbacks to this ($$).
So we should always go for unbalanced?
What did you guys make in this class?
If I have the log data for a well, and it shows several depths with several porosity, how do i calculate the total porosity of the reservoir ?