Every Natural gas well ceases producing as reservoir pressure depletes. The usual liquid presence in the reservoir can cause further problems by accumulating in the wellbore and reducing production even more. There are a number of options in well completion to prevent liquid loading even before it becomes a problem. Tubing size and perforation interval optimization are the two most common methods. Although completion optimization will prevent liquid accumulation in the wellbore for a certain time, eventually as the reservoir pressure decreases more, the well will start loading. As liquid loading occurs it is crucial to recognize the problem at early stages and select a suitable prevention method. There are various methods to prevent liquid loading such as; mechanical methods (gas lift, plunger lift, pumping and velocity string installation), chemical (foamers), and mathematical simulation. This study is set out to develop a mathematical model – an improvement on previous models – ­­to prevent loading in Natural gas well production.










1.1.    Background    1

1.1.1    What is Liquid Loading?    1

1.1.2    Multiphase Flow    2

1.1.3    How liquid loading occurs    5

1.1.4    How to recognize liquid loading symptoms    6

1.1.5    Remedy to liquid loading problem    7

1.2    Statement of Problem    7

1.3    Objectives of Study    8

1.4    Scope of Study    8     CHAPTER TWO    9



3.1    New model development for inception of liquid loading    21

3.2    Criteria for liquid loading and liquid unloading    25

3.3    Existing models for predicting the inception of liquid loading    27

3.3.1    Turner’s et al (1969)    27

3.3.2    Coleman’s et al (1991)    27

3.3.3    Nosseir’s et al (2000)    27

3.3.4    Li’s et al (2002)    27

3.4    The critical rate is given as    27

3.5.1    Turner’s et al (1969)    28

3.5.2    Coleman’s et al (1991)    28

3.5.3    Nosseir’s et al (2000)    28

3.5.4    Li’s et al (2002)    28

3.5.5    New Model    29

3.6    Software Development    29

3.7    Statistical Analysis    30

3.7.1    Average Percent Relative Error    30

3.7.2    Minimum/Maximum Absolute Percent Relative Error    30

3.7.3    Standard Deviation    31     CHAPTER FOUR    32


4.1    Description of the tool used in the study    32

4.2    Results    33

4.2.1    Result of the inception of liquid loading in XY field    33

4.2.2    Evaluating the new model and other existing models on Turner’s data    36     CHAPTER FIVE    40


5.1    Conclusion    40

5.2    Recommendation    41

References    42

Appendix A    44



1.1.    Background

In the industries today, diverse range of equipment and processes encounter two immiscible liquids flow. Particularly in the petroleum industry, where mixtures of oil and water or gas and water are transported from the wellbore via tubing/pipes over long distances which implies that to accurately design and operation of oil production facilities in an optimized way; requires an adequate prediction of the behavior of two-phase flow of hydrocarbon in pipes with different operating conditions.

It would be desired to apply a more unified model to predict the inception of liquid loading in gas wells that is very important to operators, for the reason that remedial measures can be applied in a timely manner to prevent such conditions from being realized, thereby extending the production life of a gas well which is the direction of this study to develop a new mathematical model for liquid loading. However, the mechanism that is responsible for liquid loading still remains controversial (Shu et al., 2014).

In the production of a gas condensate field, gas is mostly produced with some liquid dropout as the pressure drops below dew point pressure; occurring mostly in the separator and can still be produced in the wellbore which ultimately lead to a restriction in the flow of gas. The temperature and pressure may change once the reservoir fluids enter into the wellbore which causes liquid to drop out within the wellbore and if the gas having the larger fraction does not have enough energy to lift the drop out liquid to the surface, a fallback in the wellbore occurs or liquid loading. If this continues, the percentage of the liquid will increase and may eventually restrict the gas production. This challenge can be adequately handled with artificial lift technologies such as gas lift, but this will not be considered in this study.

1.1.1    What is Liquid Loading?

Liquid loading is the inability of a gas well to remove liquids that are produced from the wellbore. The produced liquid will accumulate in the well, therefore creating a hydrostatic pressure in the well against formation pressure, reducing reservoir drawdown and production into the wellbore bottom, reducing inability of the bottom hole flowing pressure to lift wellbore to the surface and thereby resulting in surface production reduction until the well finally ceases production. As defined by Coleman et al (1999) as a phenomenon that occurs whenever the produced gas lost its capacity to carry up the co-produced fluids to the surface production facilities via the wellbore. This occurs when the gas velocity within the well drops below a certain critical gas velocity (The gas velocity at which liquid loading occurs is referred to as the

Critical velocity for liquid loading).

A typical gas well produces natural gas and most often it carries either liquid or condensate in the form of mist. The associated or produced liquid will accumulate in the well creating a static column of liquid which creates a back pressure against bottomhole flowing pressure and reduce production until the well eventually stops production. In order to reduce effect of liquid loading on gas production, loading problems should be diagnosed in time and intervention proffered to dealt with it properly and efficiently. Liquid Loading problem exists for all type of gas wells. Therefore it is important to recognize liquid loading symptoms at early stages, and design proper solution for the gas wells in order to minimize the negative effects of liquids filling up the wellbore.

1.1.2    Multiphase Flow

In order to understand the liquid loading phenomena properly and dealing with it effectively, the knowledge of how liquid and gas behave when flowing together upwards in the production string of the well is required. This concept is called “multiphase flow”. Multiphase flow is, basically, a flow phenomenon that denotes there is more than one fluid phase flowing through a medium; in this case the medium is the production string of the gas well. Multiphase flow is usually represented by flow regimes which include bubble flow, slug flow, churn flow, wispy-annular, annular flow, and mist flow. Flow regime is the behavior of fluid during flow in conduit. It refers to the relation between the different layers to each other in moving fluid and it mostly depends on the relation between the Fluid Velocity & the Critical Velocity.

  Figure 1.1: Basic flow regimes of multiphase flow in the well

a.    Bubble Flow: In bubble flow, the tubular in the well is almost completely filled with liquid. Numerous bubbles of gas are observable as the gas is dispersed in the form of discrete bubbles in the continuous liquid phase and gas is present as small bubbles in the liquid therefore it can cause pressure drops in the liquid, decreasing pressure gradient along the well. The bubbles may vary widely in size and shape but they are typically nearly spherical and are much smaller than the diameter of the tube itself. However, the liquid is the continuous phase along the tubular and completely determines pressure gradient, although presence of gas bubbles may cause drops in pressure.

b.    Slug Flow: The gas is found as large slugs in liquid but the dominant and continuous phase is liquid. With increasing gas void fraction, the proximity of the bubbles is very close such that bubbles collide and coalesce to form larger bubbles, which are similar in size to the tube diameter and have a characteristic shape similar to a bullet with a hemispherical nose and a blunt tail. They are commonly referred to as Taylor bubbles. These bubbles are separated by slugs of liquid, which may include small entrained bubbles. Taylor bubbles have a thin liquid film between them and the tube wall, which may flow downward due to gravity, even though the net flow of fluid is upward. Gas slugs may cause drops in pressure gradient therefore liquid and gas both determine pressure gradient.

c.    Churn flow. Increasing the velocity of the flow, the structure of the flow becomes unstable with the fluid travelling up and down in an oscillatory fashion but with a net upward flow. The instability is the result of the relative parity of the gravity and shear forces acting in opposing direction on the thin liquid film surrounding Taylor bubbles. This flow pattern is in fact an intermediate regime between the slug flow and annular flow regimes. Churn flow is typically a flow regime to be avoided in two-phase transfer lines, such as those from a reboiler back to a distillation column or in refrigerant piping networks, because the slugs may have a destructive consequence on the piping system.

d.    Annular flow. Once the interfacial shear of the high velocity gas on the liquid film becomes dominant over gravity force, the liquid is expelled from the centre of the tube and flows as a thin film on the wall (forming an annular ring of liquid) while the gas flows as a continuous phase up the centre of the tube. The interface is disturbed by high frequency waves and ripples. In addition, liquid may be entrained in the gas core as small droplets, so much so that the fraction of liquid entrained may become similar to that in the film. This flow regime is particularly stable and is the desired flow pattern for two-phase pipe flows.

e.    Wispy annular flow. When the flow rate is further increased, the entrained droplets may form transient coherent structures as clouds or wisps of liquid in the central vapour core.

f.    Mist flow. At very high gas flow rates, the annular film is thinned by the shear of the gas core on the interface until it becomes unstable and is destroyed, such that all the liquid in entrained as droplets in the continuous gas phase, analogous to the inverse of the bubbly flow regime. Impinging liquid droplets intermittently wet the tube wall locally. The droplets in the mist are often too small to be seen without special lighting and/or magnification.

From Figure 1.1, as the gas velocity decreases, the flow regime goes from mist to annular and further decrease leads to bubble flow. This shows that it is very difficult for a single flow regime to be present in during the lifetime of a gas well. Since the velocity is a determining factor of the flow regime, it implies that more than a single or one phase may be present at the same time along the production string. It is also worthy to note that the flow regime experience at the surface production facilities may not be the same close to the perforation zone as a result of the downhole conditions. In addition, flow regime above and beneath the production packer (s) may differ due to the cross-sectional area because flow velocity is directly proportional to the cross-sectional area.

1.1.1    How liquid loading occurs

In a gas well, if the velocity of the gas is high enough to lift the liquid associated with the gas, the effluent produced will contain both the gas and liquid at the surface. At a point in the production where the gas velocity in the production tubing drops with time, the flow regime begins to change and eventually leads to liquid accumulation at the bottom of the well as flow continues. Thus, the bottomhole pressure increase while the production of gas decrease until the flow ceases which means that occurs when the velocity of the gas within the wellbore declines below the critical gas velocity.

When this phenomenon occurs, the gas can no longer lift the co-produced water to the surface facility making the water to fall back and with time accumulate downhole thereby exacting a back pressure on the formation leading to intermittent gas production and probably well-die-out (Figure 1.2). Several sources may be suspected as the possible source of liquid such as water from the aquifer, water coning, encroachment of water from a nearby zone, free water of the formation and hydrocarbon condensate leading to this liquid loading issue.

1.1.1    How to recognize liquid loading symptoms

There are several symptoms available today in recognizing liquid loading in gas wells. These have helped field operators to minimize the losses in gas production over the years when it is discovered early and the application of techniques in dislodging the loaded liquid is effected. These symptoms indicate a well is liquid loading:

⦁    Presence of recorded pressure spike through the gas measuring device

⦁    Erratic production and increase in decline rate

⦁    Tubing pressure decreases as casing pressure increases

⦁    Annular heading

⦁    Liquid production ceases

1.1.2    Remedy to liquid loading problem

From literatures reviewed, there are several techniques developed by different authors technically or using mathematical equations to solve the inception of liquid loading some of which are based on increasing the velocity of the gas and artificially waterlifting to reduce liquid loading problems. Veeken (2003) proposed remedial measures which depend solely on purpose of usage as presented in Table 1.1. These methods can be applied singly or a combination of two or more.

Table 1.1: Remedial measure to reduce liquid loading (Veeken, 2003)

Classification    Techniques

Increase gas velocity    ⦁    Intermittent production

⦁    Stimulation

⦁    Compression

⦁    Gas lift

⦁    Venting

Reduce critical velocity    ⦁    Compression

⦁    Mechanical liner solutions

⦁    Batch soap sticks/surfactant

⦁    Continuous surfactant injection

⦁    Bubble breakers

Artificially lift water    ⦁    Plunger

⦁    Chamber pump (plunger plus lift gas)

⦁    Downhole pump (rod, PCP, ESP)

⦁    Swabbing

Remove water    ⦁    Downhole separation & injection (intermittent production)

⦁    Heating tubing

1.2    Statement of Problem

Practically in the field; all gas wells at some time during their producing life, will experience liquid loading problems. When it occurs, there will be a rapid gas-rate decline and can even cease gas production, this is a common phenomenon found in most mature gas wells. Also, when the velocity of the gas within the wellbore declines below the critical gas velocity, liquid starts accumulating in the production string and if action is not taken; it will eventually leads to the gas well to die-out, a case which no operator wishes to experience in the life of the field.   1.3    Objectives of Study

The essence of an operation venturing into the oil and gas business is to maximize profit and minimizes cost (capital and operating cost) in a safe and economic way. Thus, the aim of this study is to develop a new mathematical solution for liquid loading detection in gas well. The following objectives will be met:

⦁    Evaluate the discrepancies in previous model

⦁    Validating the new model with field data and existing models

⦁    A software approach using Microsoft Visual Basic.Net framework

1.4    Scope of Study

This study is basically carried out to develop a new model for liquid loading detection in a gas well which will be validated with other existing models globally.



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