Chapter 1 – Introduction

1.01 Introduction (11 min.) Sample Lesson
1.02 Unconventional Production (11 min.)
1.03 Sampling - What Are We Really Doing? (12 min.)
1.04 The Challenge of Fluid Characterization (14 min.)
1.05 Radial Inflow Pressure Profile (7 min.) Quiz: 1.05 Radial Inflow Pressure Profile

Chapter 2 - Sampling Bubble Point Fluids

2.01 Corrections to Best Represent Fluid In Situ (17 min.)
2.02 GOR vs Flowrate - A Case Study (15 min.)
2.03 GOR - C20+ and Bubble Point (13 min.)
2.04 Algorithm for Correction (8 min.) Quiz: 2.04 Algorithm for Correction

Chapter 3 - Sampling Dew Point Fluids

3.01 Introducing Dew Point (19 min.)
3.02 Dew Point Continued (20 min.)
3.03 Field Examples (13 min.)
3.04 Oil Presenting as a Dew Point Fluid (24 min.)
3.05 More Examples and Closing (17 min.) Quiz: 3.05 More Examples and Closing

Sampling and Characterization of Difficult Fluids / Chapter 1 – Introduction

Lesson 1.01 Introduction

Access All SAGA Wisdom Training content Subscribe

Already a member? Sign in

Access All SAGA Wisdom Training content Subscribe

Already a member? Sign in

Transcript

01. Sampling & Characterizing of Difficult Fluids - Lesson 1.01: Introduction 02. Sampling & Characterizing of Difficult Fluids 03. My experience in 1988...04. Two Main Types of Sampling 05. When do we recommend BHS?06. Where does it occur?07. Sampling at Surface: Oils

01. Sampling & Characterizing of Difficult Fluids - Lesson 1.01: Introduction

OK, good day. It's a pleasure to be with you. I'm going to talk to you about a topic which we would think would be a simple topic and there wouldn't be much to talk about. But surprisingly, as you get a little bit into further detail on almost anything, it yields up its magic and it causes you to reflect on things that you never really thought of before.

02. Sampling & Characterizing of Difficult Fluids

And so that is exactly the same phenomenon that we see with "Sampling and Characterization of Fluid Systems". I've added "difficult" because some are more difficult than others and even what we think are simple fluid systems can end up being difficult. And so as you know from my introduction, my name's Brent Thomas and I've had a lot of experience in this area. And specifically, what I wanted to talk about is...

03. My experience in 1988...

...an experience that I had early on in my career. So this is 7 years in, 1988. And I find myself over in Algeria, and I hadn't done much traveling before that. I'd spent a couple of years as a young man in Paris, France, from 1975 - 1977, not doing engineering but other things for my church. And that would really be about the only overseas trip that I'd had. And then I got into this industry and then I traveled too much. But one of my first trips was in Algeria. And so I was at a place called Boumerdes just outside of Algiers, and I was at their CRD (their center of research and development). And I'll never forget we had two days of meetings and we were talking about low and high-end phenomena associated with reservoir systems. And at the end of these two days of meetings, the director of the CRD asked me one question and it was after everything was over. He said answer me this question; why is it that after we sample a well, why do we typically observe saturation pressures that are higher than reservoir pressures based upon good production and good recombination techniques? So that was his question. And for about the, what, the last 33 years I have been addressing this theme to one degree or another with everyone. And so nothing has been more dominant in the characterization of fluids than unconventional production. But it doesn't have to be unconventional production that causes this phenomenon. And so we will continue to scratch our heads about why should this be? And I will hopefully be able to succinctly and effectively describe for you some of the factors that create this phenomenon, that is saturation pressures higher than reservoir pressures, and protocols, workflows by which we can correct it and we can converge to the best characterization of our fluid in situ. Because ultimately, the characterization of the fluid in situ impacts the evaluation of your asset and the evaluation of your asset actually impacts your stock price. And most of you would likely probably have some share in the stock of your company. So in fact, it could impact your Christmas bonus. And so this usually makes people pay a little bit more attention than they would originally if I don't include that, but it applies to you.

04. Two Main Types of Sampling

So if we talk about 2 main types of sampling, and I've just added this recently because bottomhole sampling is something that we hardly, at least in my experience, we do very little of. And the reasons why we do less bottomhole sampling maybe than we should is that it's expensive, and in many cases, it can actually be inferior to surface sampling. You say, why would it be inferior to surface sampling? Well, I can give you a myriad of examples from my history, but 1) Western Canada very light. It was the Brassey ring border area of Alberta. But the Brassey oil, very light fluid, apple juice in color, 44 API, 2,000 psi undersaturated. But when 6 bottomhole samples were taken by the same operator, the same well, the same day, we had 2 out of the 6 that were representative and 4 we had to throw away, so we spent a lot of money for nothing. Another example is unconventionals, where you'd drill and then you'd complete with water. If you were to do a bottomhole sample after completion, so when the bottomhole area is full of water and you do a bottomhole sample, you get an expensive bottomhole sample which is full of water. So 2 examples of why it can be inferior to surface sampling our second general type of sampling. And they are more cost-effective than bottomhole samples, and there are ways to optimize surface sampling in order to gain much more insight into the nature of the fluid.

05. When do we recommend BHS?

So when we recommend bottomhole samples, we talk about specifically the area of solid precipitation. So when we think about solids precipitation, whether it's asphaltenes or waxes or diamondoids or a combination of everything, including scale, we can have a liquid-solid separation as the fluids travel from bottomhole conditions up to surface conditions. And so what I've got on the screen here is you can see that if this nature of solids precipitation is occurring between the bottomhole and the surface conditions, and if not all of the components from the liquid phase are actually making it to surface, then by definition, what we have to do is we have to capture a sample at bottomhole conditions. But even with that, there are difficulties associated with the characterization of these systems. But bottomhole sampling, if we have organic solids precipitation, meaning that we have a separation of components from our downhole fluid as it travels to surface, then we need to get the earliest sample possible and that would be downhole. So typically, what we say is that if we have a solids precipitation problem, we would recommend earlier or later in the workflow, we would recommend a bottomhole sample.

06. Where does it occur?

Where does it occur? Of course, if we show on this screen, if on the upper right part of these are reservoir conditions out here; so at high temperature, high pressure. And then if the white line describes the trajectory of temperature and pressure as we travel from bottomhole to surface, then sooner or later we're going to intersect this solid-liquid equilibrium curve. So anything to the left of that we would say we're going to have solids precipitation, anything to the right of that we're not. So again, with bottomhole sampling, we're actually sampling in the area of bottomhole conditions. So that gives us the greatest likelihood of being able to sample all of the components that are in situ in our fluid.
If we switch gears and we look at surface sampling, then it should be very simple. Where we have in black, we have our reservoir containing our reservoir fluid. And we have our well which is completed in that reservoir fluid. And then based upon either a pump or a choke or some means of controlling pressure downhole or bottomhole flowing pressure, we then create a pressure gradient and these fluids will flow up the wellbore out into a surface separator and we collect what's called a separator gas and a separator liquid. So it should be very simple. And normally it is.

07. Sampling at Surface: Oils

But surface sampling and subsequent characterization become more challenging as the in situ fluid becomes more volatile, meaning you've got more volatile components, higher vapor pressure components, which depending upon bottomhole flowing pressure, can drop the fluids belowsaturation pressure and you start to separate these fluids downhole. As the rock becomes less permeable, so requiring a greater differential pressure in order to be able to induce flow, that also makes surface sampling more difficult. And as flow rates increase again, that is also a regime that is more difficult in which to characterize fluid from surface separator samples. And the longer the well is producing. So for example, if you put a well on production now April 2021 and you don't get around to sampling it until September of 2021, and you expect to have a really good representative characterization of your fluid in situ, you may have difficulties. So these parameters, these indicators, are introductions, if you will, into why we have problems when we are trying to characterize the fluid based upon surface separators and sampling at surface. Having said that, I recommend that there is much that we can do with surface sampling and that is basically the go to technology for appropriate characterization of fluids in situ. The caveat being that if we have serious solids precipitation via judicious surface sampling, we can breathe insight and provide some conclusive evidence of whether we actually do indeed have solids precipitation and then that would cause us to recommend bottomhole sampling in addition to surface sampling. But the bulk of what I'm going to talk to you about today is surface sampling techniques and protocols, whereby we can really increase our confidence in the characterization of the fluid that exists downhole. And as I mentioned before, it gives us greater accuracy relative to evaluation of reservoir asset and ultimately, what is the value of a company. And so that's what we're going to talk about today.
So that is the end of our preamble relative to these samples.