Lesson Contents

01. Fundamentals of Wellbore Flow - Lesson 1.01: Overview of Well Flow02. Oil & Gas Production Engineering03. Field Development04. Production Maintenance & Improvement05. Typical Production System06. Wellbore07. Why do we need to know about wellbore flow?08. Reservoir Performance Prediction09. Reservoir Performance Prediction - 2-Phase Flow10. Reservoir Performance Prediction - Decline Curve Analysis Hello everyone. First of all, I'd like to welcome you all to this course. This course is titled Fundamentals of Wellbore Flow. Our main purpose/objective here is to give you a basic understanding of wellbore flow. And our motivation to do so is coming from prediction abilities or capabilities for reservoir performance or monitoring of the production from a given well. That typically requires the bottomhole flowing pressure. Bottomhole flowing pressure can be obtained by having a downhole gauge, pressure gauge; that is the ideal case. However, we may not have the bottomhole gauge. If we don't have the bottomhole gauge, what we're going to do is estimate the bottomhole flowing pressure based on the surface measurement or wellhead measurement of the pressure.

What happens between wellhead and the sandface then becomes really crucial. How do I estimate bottomhole flowing pressure knowing the wellhead pressure? That is the primary objective of this course. There are a lot of things to cover. I'm going to try to start with the simple basics, and as we go along, we will go deeper into the subject matter. During the course, we will have a lot of example problems and homework assignments. We will also have some tests along the way. Without further ado, let me start with the introduction. I will cover introduction in 2 lessons. First, I will go over the well flow.

What happens between wellhead and the sandface then becomes really crucial. How do I estimate bottomhole flowing pressure knowing the wellhead pressure? That is the primary objective of this course. There are a lot of things to cover. I'm going to try to start with the simple basics, and as we go along, we will go deeper into the subject matter. During the course, we will have a lot of example problems and homework assignments. We will also have some tests along the way. Without further ado, let me start with the introduction. I will cover introduction in 2 lessons. First, I will go over the well flow.

And I will start that with covering what oil and gas production engineering involves. What does it cover? Production engineering covers anything technical that enables or helps the delivery of hydrocarbons, gas or liquid from reservoir to market place. And production engineers are involved in the process from the discovery until the decommissioning of the field.

And production engineers are involved, as I said, they are also involved in the development phase of a field; this is planning phase. After the discovery of a field, the most obvious question is can we economically exploit the discovery? And that will require feasibility study. This feasibility study will have many different scenarios and we play those scenarios. And finally, depending on our objective function, we decide which scenario is more suitable for us. And that design scenarios may vary type a number of wells, platforms (if offshore), well completion schemes, processing, artificial lift, transportation, and abandonment philosophy all goes into it.

However, most production engineers spend their lives in the production maintenance and improvement. Objective would be maintenance of the performance of the wells that are already in production and monitoring them. If they don't behave well, identify why they are not and they come up with solutions to bring them to optimized state. And also, we may venture into improvement of those wells and find a better optimized state.

A typical production system consists of 3 major components. What we are going to have, the first component, the reservoir, 1) reservoir or formation 2) is wellbore and 3) whatever we have at the surface; flow lines, surface facilities in general. We're going to cover each one of them a little bit more in depth.

In the wellbore, we can have 2 types of flow. We can have natural flow, well flows by its own energy. This is typical of early life of a well. However, later on, we will have energy depletion or reservoir pressure depletes and the fluids may not be able to come to the surface by themselves. Then we need to introduce different artificial lift techniques to bring them up.

Another classification for wellbore flow based on the type of the flow itself, we can have single-phase flow. What does that mean? We can have all oil, meaning that we are above bubble point pressure, our pressure is greater than bubble point pressure or liquid. And what we might be also, our pressure might be greater than the dewpoint pressure. And in that case, where we are? We are in the gas phase and we can have single-phase gas flow. However, most of the time where we are in multiphase flow. We have both oil and the gas, oil + gas, and this is called 2-phase. We have also 3-phase flow. When do we have 3-phase flow? In reservoirs, we may have underlying aquifers, and that means we may produce water, right. And then we will have water + oil + gas. This is 3-phase flow. All these type of the flows will make a difference in our bottomhole flowing calculations; going from top to the bottom will depend on what kind of fluids we have in the wellbore, single-phase or multiphase.

Another classification for wellbore flow based on the type of the flow itself, we can have single-phase flow. What does that mean? We can have all oil, meaning that we are above bubble point pressure, our pressure is greater than bubble point pressure or liquid. And what we might be also, our pressure might be greater than the dewpoint pressure. And in that case, where we are? We are in the gas phase and we can have single-phase gas flow. However, most of the time where we are in multiphase flow. We have both oil and the gas, oil + gas, and this is called 2-phase. We have also 3-phase flow. When do we have 3-phase flow? In reservoirs, we may have underlying aquifers, and that means we may produce water, right. And then we will have water + oil + gas. This is 3-phase flow. All these type of the flows will make a difference in our bottomhole flowing calculations; going from top to the bottom will depend on what kind of fluids we have in the wellbore, single-phase or multiphase.

I've already talked about this, but just to sum up, wellbore flow is important for a couple of reasons. First of all, system design and production management requires pressure losses in the wellbore.

Secondly, reservoir prediction models require bottomhole flowing pressure estimates if we do not have direct measurement of the pressures downhole.

Secondly, reservoir prediction models require bottomhole flowing pressure estimates if we do not have direct measurement of the pressures downhole.

Next, I will go to reservoir performance very briefly. I'm not going to cover the entire reservoir performance and reservoir behavior, just enough for us. Inflow performance relationship, we call them. And we have different inflow performance relationships for single-phase and 2-phase. Let us look at the single-phase first.

This equation here is single-phase IPR. Flow rate is related to draw down or Pr - Pwf, average reservoir pressure minus bottomhole flowing pressure, through what we call productivity index. And productivity index expression is given here. As you see, it includes many different parameters from reservoir permeability, formation thickness, fluid properties, viscosity and formation volume factor, drainage radius, wellbore radius, and skin factor. We may not have all of them readily available to us. In production engineering, what we do to get J, we employ production tests.

In production test, we measure qo at the surface and we assume we know average reservoir pressure and we also measure or estimate the bottomhole flowing pressure. Our focus is the estimation of bottomhole flowing pressure. Let's say we have an estimate of bottomhole flowing pressure. I plug it in here, I have the measured qo, that will give me J. When I have the J (productivity index), I will have my inflow performance relationship. That is very useful because if I know this, then depending on bottomhole flowing pressure, how much I can produce from that well will be known. That's the whole idea.

This equation here is single-phase IPR. Flow rate is related to draw down or Pr - Pwf, average reservoir pressure minus bottomhole flowing pressure, through what we call productivity index. And productivity index expression is given here. As you see, it includes many different parameters from reservoir permeability, formation thickness, fluid properties, viscosity and formation volume factor, drainage radius, wellbore radius, and skin factor. We may not have all of them readily available to us. In production engineering, what we do to get J, we employ production tests.

In production test, we measure qo at the surface and we assume we know average reservoir pressure and we also measure or estimate the bottomhole flowing pressure. Our focus is the estimation of bottomhole flowing pressure. Let's say we have an estimate of bottomhole flowing pressure. I plug it in here, I have the measured qo, that will give me J. When I have the J (productivity index), I will have my inflow performance relationship. That is very useful because if I know this, then depending on bottomhole flowing pressure, how much I can produce from that well will be known. That's the whole idea.

How do we do this for 2-phase flow? We have different relationships because 2-phase flow in the reservoir is significantly more complex. And in the literature in our industry, there are ways to do that. The simplest of all, I'm presenting here; Vogel equation or Fetkovich equation. Both equations relate qo with the bottomhole flowing pressure.

If you look at Vogel equation, we have actually one unknown within the box here, square box, I'm presenting it to you, it is qo(max), absolute open flow potential of the well for oil. And that is an unknown. How do we determine that? We go back to, again, production test. We have Pwf measured or estimated and measured qo. OK, then I know everything else except qo(max), and then I can get qo(max).

The other method is Fetkovich method. It has 2 parameters to be determined based on production tests. For this, we typically do 4-point production test. And we plot it in log-log terms; we would have Pr - Pwf², qo is on the vertical, and our data points will fall on a straight-line and the slope will give me the "n". And intercept at value of this pressure squared term equal to 1 will give me the "C" value. And knowing "C" and "n", now, I have a very determined inflow performance relationship then I can play with Pwf and q to find a particular relationship for a particular well.

If you look at Vogel equation, we have actually one unknown within the box here, square box, I'm presenting it to you, it is qo(max), absolute open flow potential of the well for oil. And that is an unknown. How do we determine that? We go back to, again, production test. We have Pwf measured or estimated and measured qo. OK, then I know everything else except qo(max), and then I can get qo(max).

The other method is Fetkovich method. It has 2 parameters to be determined based on production tests. For this, we typically do 4-point production test. And we plot it in log-log terms; we would have Pr - Pwf², qo is on the vertical, and our data points will fall on a straight-line and the slope will give me the "n". And intercept at value of this pressure squared term equal to 1 will give me the "C" value. And knowing "C" and "n", now, I have a very determined inflow performance relationship then I can play with Pwf and q to find a particular relationship for a particular well.

And in the field, what we have, we all know that we monitor the flow rates and also pressure losses or bottomhole flowing pressures as best as we can. This is a sample graph for a gas well. I have gas rate here and time here. As you see, we have a decline. What we do looking at the initial decline, we try to predict what would be into the future, the production.

This concludes the presentation of Lesson 1. We will continue with the Lesson 2 in a second.

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This concludes the presentation of Lesson 1. We will continue with the Lesson 2 in a second.