PVT and Flow course - Sampling

1

Vote

There are three types of sampling methods that we're going to talk about:

• Open Hole Bottomhole Samples - Formation Tester (MDT|RCI|...)
• Surface Separator Samples
• Cased Hole Bottomhole Samples

Sampling MDT Intro

Openhole formation tester.
The first version of this was called the repeat formation tester (RFT) and this was about 1980, probably a little before that. That was a SLB product. And the today's version of that is MDT from SLB (I don't know when that came out, after probably after 1990) or RCI, it's the equivalent for one of the other companies.

This is a sample that is taken before setting pipe (casing).
MDT sampling process explained:


It is a local production test, at a specific depth, you're not going to get fluids for more than about half a meter above and below plus minus one meter. And what we sample is reservoir fluid plus some mud filtrate. What they do is they'll do these measurements, maybe spend six hours, measure pressures as well, and temperatures and so forth and then they'll just lower this thing or raise this thing to another depth and do the same thing so they might have four or five or six deaths. They get samples, they get pressures and or both.

So if you have water-based mud then the reservoir fluid sample is very close to being exactly what you have in situ (initial) at that particular depth. We know exactly what mother nature put at that depth, at that location, the composition of it, we know if it's a bubble point or dew point, we can measure in the laboratory.

If it's oil-based mud, depending on the contamination level, we basically will have this reservoir fluid sample that's equal to some instituted plus the mud, the the oil-based stuff. The percentage here can be anywhere from 0.X% to twenty or more percent for example on a weight basis or molar basis. What we can do is that we don't usually use samples these kind of samples for lab PVT measurements unless two reasons:

• if the percentage of oil-based mud is very low I'm going to say let's say less than 1%, or
• you don't have any better samples

But we will always make a mathematical decontamination to get (and it's usually a very accurate) estimate of the in-situ reservoir fluid composition. And it's a fairly simple mathematical calculation, the actual sample composition is just the two other compositions: the one is the oil-based mud and the other is not oil-based mud (or reservoir fluid). So we have the analysis of the sample from the laboratory, the people who sell us the oil-based mud will give us the composition of that mud, so we know that and so you can back calculate the fliuid composition.

An explanation of mathematical decontamination:

Sampling Surface Separator Intro

During the production testing you will be collecting the two types of samples: surface separator and/or cased bottomhole.
We have a single surface separator, what we call a test separator. Typically it's for a single well. Thr big separators will often be for five wells or the entire field - those are production separators - much bigger and a lot more equipment. So there is a single surface, specifically for testing, a single well and you have control of the separator temperature and separator pressure. And out of that separator comes a gas stream and an oil stream. Of course there could come water as well but I'm ignoring that in connection with the discussion.
So, we have the volumes of the separate oil and that it's an oil volume at separator pressure and separator temperature it's not a stock tank oil volume.
And the gas volume is actually a gas volume at standard conditions, they don't measure the physical volume at separator conditions, they report it as volumes at standard conditions.
The two volumes are reported as a gas or ratio (GOR). You'll see it hopefully in how they report the units, so the units of this would be for example standard cubic feet per sep barrel written like that: [scf/sep-bbl] or standard cubic meters per sep cubic meter written like that: [Sm3/sep m3] - some indication of whether the barrel of the oil volume is at separator conditions or if they've done some tricky thing to take the separator oil down to Stock tank condition.

The lab needs to recombine physically the sep boil and the sep gas. They need the following:

1. GOR [scf/sep-bbl] or [Sm3/sep m3]; njt given [scf/stb] - if the testing company reports the oil volumes as stock tank barrels, you have to figure out what was the separator barrel, using the reported shrinkage factor.
2. Separator pressure and temperature

When is surface separator sampling not recommended, or when could this give us a not good samples? Basically the SEP test samples can be used for:

• oils
• gas or gas condensates

Possible problems would be in the situation usually for an oil with solids precipitation that would either be a wax or an asphaltene.

If the flowing bottom old pressure drops below the saturation pressure of the in-situ fluid we get two phases - gas plus oil flowing in the near well region. The problem is that the relative mobility of gas will be different than the relative probability of oil. The producing gas oil ratio is will typically be less than the initial which is the solution Gas Oil Ratio for oils. But usually not too much it's usually not a big issue.
For gas condensates, then the GOR produced will be higher than the initial GOR, which is one over the solution oil gasp ratio. It might be anywhere from two percent higher to maybe fifteen percent. What happens is the liquid drops out, it doesn't have any mobility, so you're losing this liquid and it may take a while, it may take a week, before you get enough oil mobility so this is probably a more serious problem.

The separator test type sample it used to be the most common sample even though it has some downsides it's relatively simple to conduct and collect.

BH Samples - Why Collect Samples

Cased hole bottom samples only used for oils.
We basically have a casing set, we've got perforations into the formation and we run on a wire line a sampling device. It's going to measure pressure and temperature as well. It's basically just hanging at bottomhole and either as the well:

• is flowing at a low rate - the idea being that you want to keep the bottom will pressure as high as possible for example to avoid asphaltene precipitation, avoid gas coming out of solution.
• the well has been shut in after flowing, after production testing.

Some bottom hole samples will maintain the pressure in the bottle greater than the pressure during sampling as the tool is removed. And that's again to avoid this asphaltene precipitation or gas coming out of solution - you try to keep the sample single phase. If you don't have wax or asphaltene precipitation then you probably don't really need to worry about it. Maybe they also have samplers that can maintain temperature.

This is used to be the kind of default for all oil wells okay now because the MDT samples are there and the bottomhole samples there more common, this is becoming less and less common in general.

Why is it not used for gas? The main reason is that if you have a gas well then basically the wellbore is full of gas and you sample the gas into the container. But if you got liquids in the production tubing- because maybe you float at low rates, you had some liquid dropping down, you didn't have enough rate to lift the liquids - if for some reason you have condensate accumulation down in the wellbore when you sample you may get some of that excess liquid hanging in the oil. So when you sample you don't sample the gas, you sample some odd mixture. So it has to do with two phase effects in the in the production and the fact that gravity - the liquid is going to be hanging down in the area where your sampler is and you don't want to sample excess liquid, because that would give you a misleading composition. That's the reason it is not recommended for gas condensates.

Why Collect Samples

1. To establish the initial fluids in place. To get an estimate of what is initially in-situ fluid composition in the reservoir: spatial variations in this reservoir composition, in the I, J, K directions compositions can vary. And mapping that spatial variation is like mapping the spatial variation of permeability or porosity or water saturation or anything else that vary spatially. So we have to have some idea of what fluids are where.
2. Build a PVT Model to describe gas and oil properties (densities, viscosities, phase amounts, saturation pressure, compositions of phases below the saturation pressure of the initial fluid).

There are two types of PVT models we use today:

• empirical correlations
• more rigorous thermodynamic model that has consistency in describing gas, oil, critical, near critical single phase - Equation of State. The type of equations of state we use are called cubic equations of state of which the first one was this Van der Waals.

Why do we need a model if we have measured data? We go to the laboratory, we measure the data, why can't we just use the the measured data directly? In reality a production system, a reservoir of the production system might cover from day one to the end, it might cover a big chunk of the space of pressure-composition-temperature diagram. And you're only making a few measurements within this pressure-composition-temperature space but you need pvt properties everywhere. The only way you can get that is to use a more rigorous thermodynamic model like an Equation of State and even then there's some uncertainty or we really don't know how accurate is out here because we don't have data. What we do is that we tune the Equation of State model to our measured data and hope that the Equation of State model does okay outside in in the region where we need calculations. You have to get measurements to get pvt data to tune the Equation of State model more accurately depending on what processes you're looking at (flow flow assurance, reservoir, gas injection, etc). A good model where the key pvt data are within three to five percent at the worst better than three percent in general certainly for densities. Viscosity is you can't get that accurate, viscosities are hard to get, if you're within ten percent on viscosity you're probably safe. Phase boundaries, bubble point, dew points within a few percent at the worst. Generally speaking, except viscosity should be within a few percent accuracy for them all.

Other lectures from the PVT and Flow course

• Blog:PVT and Flow course - Gas or Oil Reservoir?
• Blog:PVT and Flow course - Single Component Vapor Pressure.
• Blog:PVT and Flow course - Two-Component Phase Behavior
• Blog:PVT and Flow course - Multi-Component Phase Diagrams
• Blog:PVT and Flow course - K Values
• Blog:PVT and Flow course - Flash Calculations
• Blog:PVT and Flow_course - Surface Separation Processing
• Blog:PVT and Flow course - Sampling
• Blog:PVT and Flow course - PVT Lab Tests
• Blog:PVT and Flow course - OBM Decontamination
• Blog:PVT and Flow course - Lab PVT Tests CCE
• Blog:PVT and Flow course - LAB PVT Tests Multistage SEP
• Blog:PVT and Flow course - Lab PVT Tests DLE
• Blog:PVT and Flow course - Lab PVT Tests CVD
• Blog:PVT and Flow course - Black-Oil PVT
• Blog:PVT and Flow course - Rate Equation (Darcy) Intro

Class notes developed during lectures are available as PDF files, named with the format yyyymmdd.pdf located on: http://www.ipt.ntnu.no/~curtis/courses/PVT-Flow/2016-TPG4145/ClassNotes/

See also

Curtis Whitson Petroleum Engineering Videos

Sort by date Sort by score

Enable comment auto-refresher

Add your comment

petrofaq welcomes all comments. If you do not want to be anonymous, register or log in. It is free.