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Improvement of intermittent gas lifted wells’

production using chamber lift

MSc Thesis

by

Tímea Klára Czene

Submitted to the Petroleum Engineering Department of

University of Miskolc

in partial fulfillment of the requirements for the degree of

MASTER OF SCIENCE

in Petroleum Engineering

09 May 2014

I

Table of contents

Introduction ....................................................................................................................... 1

1 Gas lift .......................................................................................................................... 2

1.1 Continuous-Flow Gas Lift (CGL) ......................................................................... 2

1.2 Intermittent-Flow Gas Lift (IGL) ........................................................................... 3

2 Intermittent-Flow Gas Lift Overview .............................................................................. 4

3 Gas Lift Chambers ....................................................................................................... 7

3.1 Advantages and disadvantages .......................................................................... 8

3.2 Comparison the IGL and two completions of CL ................................................. 8

3.3 Chamber- Lift Principle ......................................................................................10

3.4 Types of Chamber Lift Installations ....................................................................11

3.4.1 Double packer chambers ............................................................................11

3.4.2 Insert chambers ..........................................................................................11

3.5 Design considerations .......................................................................................14

4 Design of chamber system installation ........................................................................16

4.1 Well production modelling ..................................................................................16

4.2 Chamber design with constant surface closing pressure....................................17

4.2.1 Determination of the unloading valve depths ..............................................17

4.2.2 Selection of valve port size .........................................................................19

4.2.3 Determination of chamber length ................................................................21

4.3 Chamber design by API .....................................................................................22

4.3.1 Determination of chamber length ................................................................22

4.3.2 Optimum cycle time ....................................................................................22

4.3.3 Required injected gas volume .....................................................................22

5 Data of wells................................................................................................................23

5.1 Data of reservoir ................................................................................................23

5.2 K-1 well ..............................................................................................................24

II

5.3 K-2 well ..............................................................................................................26

6 Design of the chamber lift construction ........................................................................29

6.1 K-1 well design ..................................................................................................29

6.1.1 Unloading valve string design with constant surface closing pressure ........29

6.1.2 Analytical solution by API [1] .......................................................................37

6.1.3 Adjustment the proper settings ...................................................................44

6.2 K-2 well design ..................................................................................................46

6.2.1 Unloading valve string design for K-2 well ..................................................46

6.2.2 Design by API .............................................................................................50

6.2.3 Choosing the proper settings ......................................................................52

6.3 Economic comparison .......................................................................................53

6.4 The final wells construction ................................................................................55

Summary .........................................................................................................................58

Appendices ......................................................................................................................59

References ......................................................................................................................61

Acknowledgement ...........................................................................................................63

Table of figures

Figure 1 - Scheme of gas lift (Edited by the Author) .......................................................... 2

Figure 2- Intermittent gas lift (Edited by the Author) .......................................................... 3

Figure 3 - Cycle of intermittent gas lift (Edited by the Author) ............................................ 4

Figure 4 - Double packer chamber (Edited by the Author) ................................................ 7

Figure 5 - Insert chamber (Edited by the Author) .............................................................. 7

Figure 6 – Comparison of three completions on pressure-depth diagram (Edited by the

Author) .............................................................................................................. 9

Figure 7 - Cycle of chamber lift (Edited by the Author) .....................................................10

Figure 8 – Insert chamber with Hanger Nipple for „Stripper”-type Wells (Edited by the

Author) .............................................................................................................12

Figure 9 – Insert chamber combination opening-bleed valve (Edited by the Author) .......12

III

Figure 10 – Large OD insert chamber installation without venting free gas from casing

annulus (Edited by the Author) .........................................................................13

Figure 11 – Large and small OD chamber installations with free gas venting from casing

annulus (Edited by the Author) .........................................................................13

Figure 12 – Extremely long insert chamber (Edited by the Author)...................................13

Figure 13 – Insert chamber for tight formations (Edited by the Author) ............................13

Figure 14 – Standing valves (Edited by the Author) .........................................................15

Figure 15- Pressure gradient spacing factor after CAMCO [17] .......................................18

Figure 16 - Graphical solution with constant surface closing pressure at all unloading valves

(Edited by the Author) ......................................................................................18

Figure 17 - Injection gas requirement of the intermittent gas lift [3] and [5] .......................19

Figure 18 - Valve spread required to store a given gas volume in the annulus, [5] ..........20

Figure 19 – Drawing of the K-1 well (Edited by the Author) ..............................................25

Figure 20 – Drawing of K-2 well (Edited by the Author) ....................................................28

Figure 21 - Graphical procedure at K-1 well (Edited by the Author) ..................................30

Figure 22 – The daily liquid rate, Qd and the daily gas consumption, Qg as a function of the

cycle time, T at K-1 well (Edited by the Author) ................................................42

Figure 23 - Graphical procedure at K-2 well (Edited by the Author) ..................................47

Figure 24 - The daily liquid rate, Qd and the daily gas consumption, Qg as a function of the

cycle time, T at K-2 well (Edited by the Author) ................................................51

Figure 25 –The final construction of the K-1 well with chamber lift (Edited by the Author) 55

Figure 26 - The final construction of the K-2 well with chamber lift (Edited by the Author) 56

Figure 27 – Surface dome charge pressure calculation 1. ...............................................59

Figure 28 - Surface dome charge pressure calculation 2. ................................................60

Tables

Table 1 – Parameters of the reservoir (Edited by the Author) ...........................................23

Table 2 – Well construction of K-1 well (Edited by the Author) .........................................24

Table 3 – Production properties of K-1 well (Edited by the Author) ..................................26

Table 4 – Well construction of K-2 well (Edited by the Author) .........................................26

IV

Table 5 – Production properties of K-2 well (Edited by the Author) ..................................27

Table 6 – Summary table of chamber lift design calculations at K-1 well (Edited by the

Author) .............................................................................................................37

Table 7 – Data of production as a function of accumulation time at K-1 well (Edited by the

Author) .............................................................................................................43

Table 8 – Values of chamber installation at K-1 well (Edited by the Author) .....................45

Table 9 – Summary table of chamber lift design calculations (Edited by the Author) ........49

Table 10 - Data of production as a function of accumulation time at K-2 well (Edited by the

Author) .............................................................................................................51

Table 11 - Values of chamber installation at K-2 well (Edited by the Author) ....................52

Table 12 – Additional costs (Edited by the Author) ...........................................................53

Table 13 – Comparison of the different settings (Edited by the Author) ............................54

1

Introduction

When the wells begin the production, it is a natural process, due to the high reservoir

pressure. However, during the life time of the well, the formation pressure will be decrease

continuously and it will reach a point, when this type of production turns uneconomical. At

this stage of production, we should use artificial lift methods to stay economical. The most

common methods what are used all in the world are the sucker rod pump and the gas lifting.

Continuous gas lift helps to increase the recovery of formation fluid with a high pressure

gas. The continuous gas lifting requires more and more lift gas by the time, because of

decreasing reservoir pressure. For this reason, it becomes non-economical and non-

productive. The high gas consumption can be decrease by using of intermittent gas lift. It is

true in Hungary and also all over the world because the lift gas of old fields is increasing.

One of the intermittent gas lift method is the chamber lift system. The chamber lift has been

accommodated, when the reservoir pressure is low and the productivity index is high. There

are two different fundamental types of it.

In Hungary artificial lift methods have been used mainly. The sucker rod pumping and the

gas lift are usually applied. I am going to examine the most familiar methods what are the

continuous and intermittent gas lift in that area. In Hungary this is the first occasion, when

the chamber installation will be used. It is still not a common application everywhere.

2

1 Gas lift

It is used if the flowing bottomhole pressure is not enough to produce the required amount

of oil. During gas lifting high pressure gas is injected from the surface into the well. There

are currently two types in use – continuous and intermittent gas lifting.

1.1 Continuous-Flow Gas Lift (CGL)

Continuous gas lifting has extended the natural flow by constant injection of high pressure

gas. The injected gas has been rolled into the well at the deepest point, in order to “aereate”

the liquid and to reduce the density of the fluids, and consequently bottomhole pressure is

reduced, and the oil yield is increased. Figure 1 shows the change of fluid gradients below

and above the point of injection.

Figure 1 - Scheme of gas lift (Edited by the Author)

Injection

gas

Oil and dissolved

gas from reservoir

Reservoir fluid gradient

Point of gas injection

Fluid gradient with

formation and injected gas

Depth

Pressure

3

1.2 Intermittent-Flow Gas Lift (IGL)

In course of intermittent gas lifting the gas is injected intermittently at predetermined

pressure at predetermined cycle times and volumes. This is a periodic, cyclic displacement

of liquid from the tubing (Figure 2).

At the stage, when there is no gas injection, the fluid accumulates inside the tubing. Then

the gas is injected into the tubing through a gas lift valve preferably closely located to the

perforations. The liquid slug above this valve rises to the surface by the entering gas.

Figure 2- Intermittent gas lift (Edited by the Author)

Injected gas

Unloading valve (closed)


Operating valve (open)

Standing valve (open)

Reservoir

Fluid slug

4

2 Intermittent-Flow Gas Lift Overview

When the formation pressures and fluid rates are greatly reduced, continuous lifting

becomes inefficient due to the huge quantity of injected gas. In this case use of the

intermittent gas flow is becomes effective.

The following figure shows a complete cycle of the intermittent gas lifting (Figure 3).

A. The liquid is accumulating above the closed operating valve.

B. The operating valve is open. The gas from the surface enters into the tubing and it

is lifting the accumulated liquid column.

C. The liquid rise up to the surface and the injection gas transports some oil droplets.

D. In the last period the liquid is accumulating again while the operating valve is closing.

Figure 3 - Cycle of intermittent gas lift (Edited by the Author)

Unloading valves

(closed)

Unloading valves

(closed)

Operating valve

(closed)



Operating valve

(closed)

Unloading valves

(closed)

Unloading valves

(closed)

Injection gas

To separator

5

When is the intermittent gas lift applicable?

In order to understand why the gas lifting is necessary, some conditions are listed as follows.

o Generally the fluid producing is very low, about less than 150-200 bpd.

o If wells have characteristics of high productivity and low formation pressure.

o In that case, when the productivity index (PI) is low and the reservoir pressure (PR)

is high or the formation pressure is low with high productivities, the chamber lift is

recommended.

o If good quality, cheap gas is obtainable, it becomes the best choice in order to

produce fluids with some sand from shallow, high GOR, low PI or low BHP well with

bad dogleg.

It has the following advantages:

o It has an appreciably lower flowing BHP than continuous gas lifting.

o It is very flexible to adapt changes in well inflow parameters.

o It is applicable in low productivity wells with high formation pressure.

o From CGL it is easily transformable to conventional intermittent to chamber or

plunger lift as the BHP and PI decrease.

o It can handle the sand and solid materials with minor problems but sometimes the

standing valve may cause problems.

o It can be used with wireline unit.

o The cost of repair and maintenance is low. Tools are easily repaired or replaced.

o Presence of corrosion and crooked hole is not problem.

o It is inconspicuous in the environment.

The last five statements are also applicable to CGL.

The limitations and disadvantages of the IGL:

o The first most important thing when the reservoir pressure decreases continuously,

therefore the accumulated quantity of fluid in the well also reduces.

o The average flowing BHP of IGL is higher than pressure of rod pumping. This BHP

can be reduced with chamber lift.

o The energy of formation gas is not utilized in the fluid producing. More gas is applied

per barrel of produced fluid than with CGL, so the power efficiency is low.

6

o Pressure fluctuations can cause some problems such as depth and also on the

surface. In the producing BHP it is harmful with sand control because the sand may

accumulate in the tubing or near the standing valve. These fluctuations in surface

equipment can cause faults in gas- and fluid-handlings.

o Its noise level is low, but at compressor is very high.

Intermittent gas lift can be the traditional gas lifting (IGL); chamber lift (CL) that accumulate

a larger volume of slug; and plunger lift (PL) that helps to reduce the liquid fallback losses.

Further part of my thesis examines the chamber lifting.

7

3 Gas Lift Chambers

If the reservoir pressure is low and the productivity index is high, the chamber lift system is

the proper choice, because the liquid production may be increased with this method. It is

possible to produce with a chamber twice barrels per day as much as a conventional

installation from 6000 to 8000 feet. During application of the chamber installation more

quantity of liquid can be accumulated for a giving low bottomhole pressure. There are two

basic types of chamber lift: two-packer chamber Figure 4 and insert chamber Figure 5

installation and any other variations of each type depending on the casing size, well

conditions, and applicability of special equipment for assembling a chamber installation.

The insert chamber likes a bottle into the largest pipe, which collects the fluids. The other

type operates by inserting a dip tube through the smallest pipe and producing the fluids up

through it. The purpose of the chamber lift system is to reduce the required flowing

bottomhole pressure in order to permit the entry of formation fluids into the wellbore. The

use of a chamber lift system offers many advantages over other artificial lift methods, but

there are some disadvantages as well.

Figure 4 - Double packer chamber (Edited by the Author)

Figure 5 - Insert chamber (Edited by the Author)

Retrievable chamber valve

By-pass type packer

Retrievalbe standing valve

Retrievalbe bleed valve

Lower packer

Chamber

Retrievable chamber valve

By-pass type packer


Retrievalbe bleed valve

Insert chamber

8

There are two primary reasons for selection of this method.

1. The fluid-head backpressure has to be decreased to achieve the minimum possible

average FBHP.

2. A long perforation or open hole is necessary to lower the point of gas injection in a low

FBHP well.

3.1 Advantages and disadvantages

Advantages

o If the PI is high enough, it could be possible to increase the liquid rate for a given

FBHP.

o This always reduces the injection gas liquid ratio.

o For deep well with low PI, it might be the only way to have an economically suitable

injection GLR

o The double packer chamber system offers greater annular capacity than other

chamber installations.

o Insert chambers can significantly increase the drawdown in wells with extremely

long perforations or open-hole completions.

Disadvantages

o This completion is more complex; due to any completion failures the risk of any

production may be increased.

o If a well is a high gassy well, the chamber lifting is not recommended. The reason

why it does not operate properly, the gas fills the chamber annulus and reducing the

ability of the chamber to accumulate high liquid volume.

o There may be sand problems that limit the use of chamber lift system due to the

difficulty in operations and reparation a chamber installation.

3.2 Comparison the IGL and two completions of CL

Hernandez et al. prepared a paper [11] about experiences of chamber installations. In this

case they wanted to reduce the BHP and to increase the fluid production rate. Due to

9

continuous reduction of reservoir pressure they can decrease the BHP in order that BHP is

smaller than the reservoir pressure. If it is successful, the production rate increases. That

is why the traditional intermittent gas lift installation was changed to an insert chamber

without bleed valve. The decreasing of BHP was successful but the increasing of produced

liquid was unfortunately not. Because of the formation gas, the accumulation of liquid was

limited in the chamber. After second installation when a bleed valve was also installed, the

production increased from 160 b/d to 270 b/d. For example Figure 6 represents the pressure

distribution for the same well with [1]:

a. Simple completion of an intermittent gas lifting

b. Insert chamber without bleed valve

c. Insert chamber with a bleed valve

Figure 6 – Comparison of three completions on pressure-depth diagram (Edited by the Author)

Figure 6 shows the beginning of liquid accumulation. The minimum pressure along the

perforation is the highest at the simple completion. Without bleed valve the pressure along

perforations is higher than with the bleed valve at the packer. The reason is that

accumulation of the formation gas below the packer prevents the inflow into the chamber.

Dep

th

Dep

th

Dep

th

10

3.3 Chamber- Lift Principle

At this point I describe a mechanism in the chamber installation that is drawn by Figure 7.

1.) The chamber annulus is filled with formation fluid through the perforated nipple

located right above the lower packer in the dip tube. As the liquid level rises in the

annulus, the injection gas is introduced into the tubing through a bleed valve located

below the upper packer.

2.) When the chamber annulus and the dip tube are completely filled, the gas-lift valve,

is located just above the upper packer, opens and the gas in the high-pressure

injection annulus is injected to the upper part of the chamber annulus. During is

forced downwards closing the standing valve.

3.) The liquid is U-tubed into the dip tube and the tubing above the chamber to form the

initial slug length and are finally produced to the surface as a continuous liquid slug.

4.) After producing the liquid the injection gas transports some droplets.

Figure 7 - Cycle of chamber lift (Edited by the Author)

Unloading

valve

(closed)

Standing valve (open)

Reservoir

Operating valve (closed)

1.

Liquid slug



Standing valve (closed)

Injected gas

3.




Injected gas

4.

Injected gas




2.

11

Not all of the initial slug is produced because of injection gas can breakthrough and can

cause liquid fallback. During the production the standing valve is closed however the

formation fluids continue to enter the annulus. After the liquid slug arrives to the surface,

the injection gas shut off and the FBHP in the chamber reduces. When the pressure in the

chamber gets less than the formation pressure around and below the chamber, the standing

valve opens. First the liquid enters in the chamber, followed by the formation gas, that rises

up above the liquid. The cycle repeats again and again.

3.4 Types of Chamber Lift Installations

Basically there are two groups of the chamber lift – double packer- and insert chamber –

nevertheless the insert chamber installation has some further types. In the following points

these installation will be introduced.

3.4.1 Double packer chambers

The double packer chamber installation (Figure 4) uses the annulus for the accumulation of

fluids. This type is installed to allow for large storage volumes with a minimum quantity of

back pressure on the formation.

3.4.2 Insert chambers

The insert chamber installation (Figure 5) is usually fabricated from the largest pipe and is

used instead of the two packer chamber installation. This type of installation is

recommended for wells with long perforated intervals, low reservoir pressure, damaged

casing or open hole completion. It can keep more fluid than the same length of tubing, but

not as much as the two packer chamber.

Types of insert chambers

Some examples for different types of insert chamber are contained in this part by [1].

o Chamber installation for low rate, low BHP well, and this well is stripper wells. They

produce less than 100 bpd. (Figure 8)

12

o There is an installation, where the operating valve that acts as a bleed valve that

allows communication between the chamber annulus and the tubing when it is open.

When the valve opens high pressure gas is injected into the chamber annulus

(Figure 9)

o Large OD chamber without venting free gas from casing annulus (Figure 10)

o Large and small OD chambers with free gas venting from casing annulus (Figure

11)

o Extremely long perforations (Figure 12)

o Chambers for tight formations. It is usually referred to as “open hole chamber”. It is

good for wells with low PI which produce sand (Figure 13)

Figure 8 – Insert chamber with Hanger

Nipple for „Stripper”-type Wells (Edited by

the Author)

Figure 9 – Insert chamber combination

opening-bleed valve (Edited by the

Author)

Hanger nipple

Hookwall packer

Standing valve

Bleed valve

Chamber valve

Retrievable combination blood valve

Hookwall packer


Retrievable dip tube

Chamber mandrel with inline nipple

13

Figure 10 – Large OD insert chamber installation without venting free gas from

casing annulus (Edited by the Author)

Figure 11 – Large and small OD chamber installations with free gas venting from casing annulus (Edited by the Author)

Figure 12 – Extremely long insert

chamber (Edited by the Author)

Figure 13 – Insert chamber for tight formations (Edited by the Author)

Hookwall packer

Hanger nipple

Retrievable standing valve

Dip tube

Bleed valve

Gas bleed valve

By-pass type packer

Dip tube

By-pass packer

Standing valve

Chamber bleed valve

Chamber valve

Annulus vent valve

Dip tube

By-pass packer

Standing valve

Chamber bleed valve

Chamber valve

14

3.5 Design considerations

Some considerations are necessary in the design of a chamber installation to guarantee the

maximum liquid production with a minimum desired injection-gas. I have collected these

considerations and the following list shows them.

a) Type of well:

As I mentioned chamber installations are recommended for wells with low PR, high PI

low formation GLR and low sand problem

For insert chambers: this type is recommended if the well is long perforated, the

reservoir pressure is low, the casing is damaged or open hole completion.

b) Chamber length:

The chamber length has to be selected properly. The size of the chamber is equal to

the liquid column length calculated at the optimum cycle time, but correcting its value

with the true liquid gradient. It is important that the chamber is not too much that no

injection gas wasted.

c) Unloading valve depths and design:

The unloading valve is closed in normal operating cycle; it should only be operated

for unloading the well. The opening pressure of the unloading valves should be set at

a value as high as possible so that they will not open due to the hydrostatic pressure

caused by the long liquid slugs produced from the chamber. The point of gas injection

for the chamber is at the lower end of the dip tube and not at the depth of the chamber

valve.

d) Operating valve calculation:

The tubing production pressure affecting on the operating valve is only due to the

wellhead pressure and the weight of the gas column from the wellhead to the bleed

valve. Therefore the operating valve should be above the liquid level. The initial

opening pressure of the chamber-operating gas lift valve should be at least 50 psi less

than the initial opening pressure of the bottom-unloading gas lift valve to guarantee

operation from the chamber.

e) Chamber-Bleed Valve:

It is important to vent the gas and allow filling chamber with liquid production. A bleed

valve with a large port is necessary for high-rate chamber installations with a high

15

injected gas cycle frequency. The large bleed port is needed to vent the injection gas

that is trapped in the chamber annulus between cycles.

f) Standing Valve: (Figure 14)

Standing valves are always needed in chamber installation. They are able to prevent

being pushed the fluids back to the formation by the injection gas. When sand is

produced with chamber installation, extended standing valve should be applied.

Figure 14 – Standing valves (Edited by the Author)

Extended standing valve

Gas-lift valve

Bleed valve

Perforated nipple

Packer

Standing valve

Perforations

16

4 Design of chamber system installation

In this chapter I model a given well because the production, the PI and the reservoir

pressure are too low and gas usage is too big. This well is working with intermittent gas

lifting, and its life has to be extended for several years. Therefore the aim of my thesis is

that to design a chamber lift which meets the requirements. The main requirement is to

increase the production.

This part deals with methods to design the chamber lift installations. First method is

composed by Takács [14] and the second is by API [1]. Both of them can be determined a

chamber length and any other important part of the design.

4.1 Well production modelling

Before planning the new well structure, the current status has to be modelled. The well is

an intermittent gas lift well, therefore I use for a specially developed software for a modelling

the production. After collected the data, I examined the well with ISG 1.1 program that is

developed by Turzó.

It divides a cycle to three sections:

o The first section is the rising of liquid slug

o The second is the production of the liquid slug

o The last is the production of liquid drops

The accumulation is not a separate part because it presents in the first and the second part,

too. The first part is divided to further subsections because of the precise.

I have to fill in the necessary data into the program, for example:

o Pressures of separator, reservoir, casing and injected gas

o Depths of reservoir, valve and packer

o Diameters of tubing casing

o Parameters of fluids and injected gas

o Parameters of the valve

17

I can choose between different methods for every section. I select the following methods

during my calculations:

o For the first period: Original Neely-method [13]

o For the second period: Ros-Duns-method (without friction increment) [6]

o For the third part: Ros-Duns dynamic model

o Turner critical settling velocity of drop [15]

During calculations I need for the maximum liquid rate that can be determined by this

program. This program uses the Equation 1:

Qlmax = 6.28 ∙ (1.1 ∙ 𝐴𝑡 ∙ 𝑃𝑤𝑠 ∙ 𝑎𝑡𝑎𝑛ℎ (

0.89 ∙ 𝑃𝑡𝑜 + 0.11 ∙ 𝑃𝑤𝑠 − 0.89 ∙ 𝐷𝑣 ∙ 𝑔 ∙ 𝜌𝑙 + 0.89 ∙ 𝐷𝑝𝑒𝑟𝑓 ∙ 𝑔 ∙ 𝜌𝑙

𝑃𝑤𝑠)

𝑔 ∙ 𝑡𝑎𝑐𝑢𝑚 ∙ 𝜌𝑙

−1.1 ∙ 𝐴𝑡 ∙ 𝑃𝑤𝑠 ∙ 𝑎𝑡𝑎𝑛ℎ (

0.89 ∙ 𝑃𝑡𝑜 + 0.11 ∙ 𝐴𝑡 ∙ 𝑃𝑤𝑠 − 0.89 ∙ 𝑉 ∙ 𝑔 ∙ 𝜌𝑙

𝑃𝑤𝑠 ∙ 𝐴𝑡)

𝑔 ∙ 𝑡𝑎𝑐𝑢𝑚 ∙ 𝜌𝑙)

Equation 1

4.2 Chamber design with constant surface closing pressure

4.2.1 Determination of the unloading valve depths

In this part I detail the processes of the design. The beginning of design of chamber lift

system is similar to a conventional intermittent lift system. An exception is the maximum

distance between the bottom unloading and the chamber operating gas lift valves.

The following section describes one of procedures available for mandrel spacing for wells

on intermittent gas-lift. This procedure is well suited for unloading the well by intermittent

injection using pressure operated unloading valves and choke control.

4.1.1.1. Analytical and graphical procedure for spacing unloading mandrels/valves

The graphical procedure is more meaningful; that Takács described in [14].

I summarize this method shortly, showing the main feature of it. I detail the calculation step

by step in Chapter 6.1.1.

o Determination of the spacing factor using the estimated production rate and the

extant tubing size. The spacing factors are pressure gradients that are used to space

the valve string. These are increase with the production rate and the tubing size, as

18

shown in Figure 15. For very low production rates the use of spacing factor is 0.04

psi/ft is recommended.

Figure 15- Pressure gradient spacing factor after CAMCO [17]

o A graph is needful where the x axis will be the pressure, the y axis will be the depth.

The different values of pressures and depth are signed here (Figure 16).

o The closing pressure, Pclose as 100-200 psi less than injection pressure, Pinj. This

line shows the valves closing pressure at depth.

Figure 16 - Graphical solution with constant surface closing pressure at all unloading valves (Edited by the Author)

Pwh Pclose Pinjection

Dv1

Dv2

Dv3

gl

gg

gt

Pt1

Pt2

Pt3

Pc1

Pc2

Pc3

19

o Determination of the depth of the valves, Dv, on the basis of available injection gas

gradient, gg, unloading fluid pressure gradient, gl, wellhead pressure, Pwh and Pinj.

The line of unloading fluid pressure gradient, gls starts form Pwh and where the line

of gls intersects the line of gg.

o The depth of the two packer chamber: the lower packer should be set at perforations

and the depth of upper packer with assumed length of chamber, LC.

o All unloading valves have to be deleted between the assumed packers.

o Operating chamber valve is installed at upper packer, and its surface closing

pressure as 50 psi less than that of the unloading pressure and the downhole Pclose

can be calculated.

4.2.2 Selection of valve port size

The selection is based on the required injection gas volume and the pressure conditions at

valve setting depth. The unloading valves’ ports can be smaller than the operating valve’s

port size. The following process is written by ([2], [7] and [8]) assuming that choke control

is used at the surface.

Figure 17 - Injection gas requirement of the intermittent gas lift [3] and [5]

20

o An assumed surface opening pressure is necessary to find the intermittent cycle’s

gas requirement. After calculating the opening injection pressure, Pio, at valve depth

with Figure 17.

o From Figure 18 the pressure differential, ΔP is found, that is required to store

demanded gas volume in the annulus.

Figure 18 - Valve spread required to store a given gas volume in the annulus, [5]

o The opening pressure of the valve is the closing pressure plus the pressure

differential.

o If the assumed and calculated Pio pressures are very different from each other it has

to be recalculated until these pressures are in agreement.

o The port size is found from the following equation where R is ratio of valve areas

o The opening pressure of operating valve at depth is solved by the opening equation:

Pio =Pic

1 − R− Pt

R

1 − R

Equation 2

o For determination of chamber length the ratio of volume of chamber annulus and

the tubing are required.

o With assumed opening pressure of the chamber operating valve, the port size of the

chamber valve, RC can be determined. After that, a proper valve with the nearest R

21

value can be chosen and the real opening pressure can be counted with the proper

value of R.

o Finally the dome charge pressure, Pd, (from the valve opening equation), the Pd at

surface conditions, P’d (at a charging temperature of 60 °F) and TRO (from the

surface P’d) are defined.

4.2.3 Determination of chamber length

The chamber length equation is based on two assumptions. The first is that the top of the

chamber is located at the working fluid level. This assumption implies that the chamber and

the dip tube are full at the instant the chamber-operating gas lift valve opens. The second

assumption requires that the inside diameter of the chamber and the size of the dip tube do

not change for the entire length of the chamber. The chamber length equation applies to

the two packers and insert chamber equally.

𝐶𝐿 =Pi − Pt

gl ∙ (R𝑐 + 1)

Equation 3

Where

o CL – chamber length, ft

o Pi – injection-gas pressure at the depth of the chamber-operating valve for

calculating chamber length, psig

o Pt – tubing pressure at the depth of the chamber-operating valve, sum of Pwh and

gas column pressure, psig

o gl – pressure gradient based on liquid production, psi/ft

o Rc – ratio of capacities of the chamber annulus and the tubing along the chamber

(Va/Vt)

The actual effective chamber length is the distance from the top of the chamber to the lower

end of the dip tube, which is the point of gas injection. The injection pressure, Pi for

calculating the chamber length should be less than the initial opening pressure of the

chamber-operating gas lift valve. A suitable pressure differential across the liquid slug is

required at the instant injection gas enters the lower end of the dip tube to attain a slug

velocity that ensures maximum liquid recovery with a minimum injection-gas volume per

cycle and a minimum liquid fallback. A recommended value for Pi would be Pi = 0.6 to

22

0.75*(Pio), where Pio is the initial injection-gas opening pressure of the operating-chamber

pilot valve at depth, psig.

4.3 Chamber design by API

This method takes into consideration the reservoir pressure and the productivity. It can

calculate the chamber length, optimum cycle time and proper injected gas consumption.

4.3.1 Determination of chamber length

At this procedure the reservoir and flowing bottomhole pressure and PI are very dominant.

It uses the Darcy’s equation and with the proper accumulation time, cycle time it is able to

determine the daily liquid production and the daily gas injection.

The calculation can be seen as detailed in Chapter 6.1.2.

4.3.2 Optimum cycle time

It is an indispensable part of the design because the daily production has to be maximized

and the optimized of the cycle time contributes to reach the proper production. If the injection

time is too short, there is not enough energy to push the liquid slug to the surface. If it is too

long, greater part of the injected gas consumption is unnecessary because a given time has

to be required to rise the liquid plug and after it the injected gas has not any work.

The longer the column of liquid slug is the longer the accumulation time is and the less the

number of cycles per day.

4.3.3 Required injected gas volume

It is important to rise the liquid slug. It has to be set adequately that it is not used needlessly.

It depends on the tubing diameter, the API gravity of oil, the depth of the point of injection

and the initial column length.

23

5 Data of wells

In this section I list some properties of reservoir and the reservoir fluids and I detail some of

the well construction.

5.1 Data of reservoir

Table 1 shows parameters related to the given reservoir. Both of the wells has the same

reservoir. This reservoir locates near Szeged-Algyő.

Table 1 – Parameters of the reservoir (Edited by the Author)

Geometrical data

Area 22.8 km2 8.8 mi2

Depth of gas-oil boundary 2440 m 8003.3 ft

Thickness of oil body 27 m 88.6 ft

Rate of gas/oil voidage 4 -

Parameter of reservoir

Type sandstone

Porosity (φ) 18.3 %

Permeability (k) 195 10-3 μm2 195 103 Darcy

Water saturation (Swi) 43.9 %

Pressure (pR) 156 bar 2262 psi

Temperature (TR) 121 °T °K

Parameter of reservoir fluid in reservoir

Solution GOR (Rsi) 97.2 m3/m3

Oil volume factor (Boi) 1.315 m3/m3

Gas volume factor (Bgi) 5.3 m3/m3

Gassy oil viscosity (μo) 0.84 10-3

Pas

24

Parameter of reservoir fluid at surface

Density of oil 877 kg/m3 ppg

Relative density of natural

gas

67 10-2

Content of inert material 3.07 %

5.2 K-1 well

The data of well dimensions can be found in Table 2 and the original well construction is on

the Figure 19. This well has two perforated intervals, but their length are not long. There is

only one valve installed at the depth of 7363.6 ft.

Table 2 – Well construction of K-1 well (Edited by the Author)

Name of data Data

Casing diameter 7 in

Tubing outside diameter 2 3/8 in

Tubing inside diameter 2.441 in

Depth of top of cement 2458 m 8062.2 ft

Depth of casing shoe 2469 m 8098.3 ft

Depth of perforation I. 2441-

2446

m 8006.5-

8022.9

ft

Depth of perforation II. 2451-

2456

m 8039.3-

8055.7

ft

Depth of packer 2403 m 7881.8 ft

Valves parameters

Valve I.

Type E plug

Setting depth 1293 m 4241.1 ft

Valve II.

Type PK-1

Port size 1/8 in

Setting depth 2245 m 7363.6 ft

Opening pressure 99 bar 1435.5 psi

Closing pressure 61 bar 884.5 psi

25

Table 3 shows production data of the well. The rate of fluid production is very low, therefore

it is needed to examine this well and design a new completion.

Figure 19 – Drawing of the K-1 well (Edited by the Author)

13 3/8” 113.2 ft

2 3/8” tubing

9 5/8” 2629.7 ft

2 3/8” KBM side pocket mandrel, 4242.3 ft, E-plug

2 3/8” KBM side pocket mandrel, 7365.8 ft, PK-1 valve

7” 8136.9 ft

7” HRP-1 packer, 7886.5 ft,

Perforation, 8009 - 8025


26

Table 3 – Production properties of K-1 well (Edited by the Author)

Name of data Data

Number of daily cycle 6.1 cycle

Accumulation time 190 min

Gas injection time 45 min

Type of control Time cycle control

Tubing pressure during

production

24 bar 348 psi

Casing pressure during

production

75 bar 1087.5 psi

Fluid production 7 m3/day 43.96 BPD

Oil production 2.5 m3/day 15.7 BPD

Injected gas 8300 m3/day 292990 ft3/day

Water Cut 64 %

5.3 K-2 well

In Table 4 the well construction of the K-2 well can be found that is demonstrated by Figure

20. The Table 5 contains the current production data.

This well is differ from K-1 well because K-2 well has a smaller casing and tubing diameter,

5 ½” and 2 3/8” and there is only one perforation.

This well has three side pocket mandrel, but has only one valve at depth of 7912.8 ft.

Table 4 – Well construction of K-2 well (Edited by the Author)

Name of data Data

Casing diameter 5 1/2 in

Tubing outside diameter 2 3/8 in

Tubing inside diameter 1.995 in

Depth of packer 2434.04 m 7983.65 ft

Depth of perforation 2453.5-

2462.2

m 8047.5-

8076

ft

27

Valves parameters

Valve I.

Type E plug

Setting depth 1302.8 m 4273.1 ft

Valve II.

Type E plug


Valve III.

Type BK


Opening pressure 74 bar 1073 psi

As Table 5 the total cycle time is 220 min and the number of cycle is 6.5 per day. The liquid

production is low, therefore this well is also chosen.

Table 5 – Production properties of K-2 well (Edited by the Author)

Name of data Data

Number of daily cycle 6.5 cycle

Accumulation time 200 min

Gas injection time 20 min

Type of control Time cycle control

Tubing pressure during

production

27 bar 392 psi

Casing pressure during

production

90 bar 1305 psi

Fluid production 5 m3/day 31.4 BPD

Oil production 1.7 m3/day 10.68 BPD

Injected gas 7600 m3/day 268280 ft3/day

Water Cut 66 %

28

Figure 20 – Drawing of K-2 well (Edited by the Author)

13 3/4” 134.5 ft

2 3/8” tubing

9 5/8” 4160 ft


2 3/8” KBM side pocket mandrel, 7912.8 ft, BK valve

5 1/2” HRP-1 packer, 7983.65 ft,

Perforation, 8047.5-8076 ft


29

6 Design of the chamber lift construction

6.1 K-1 well design

6.1.1 Unloading valve string design with constant surface closing pressure

The unloading valve string permits a stepwise transfer of injection point from surface down

to the operating valve according to [14].

For the design procedure I use constant surface closing pressure ([2], [7], [8]). This

procedure can be used for single element valves, pilot valves or choke with intermittent

surface gas injection control. The graphical procedure is shown on the Figure 21.

1 Step

The gas pressure distribution is started from surface injection pressure, Pinj. The

specific gravity of the gas is 0.65, in this case the gas gradient, gg is 0.03 psi/ft.

2 Step

I have to determine the spacing factor, gt from Figure 15. But in this case I have not

known yet the exact liquid production rate, therefore I calculate with a low daily

production rate, where the generally accepted value of the spacing factor is 0.04

psi/ft. It is started from the Pwh=50 psi.

3 Step

I draw a plot for the graphical solution (Figure 21). The x axis is pressure and the y

axis is depth. The gg and gt can be drawn into the plot.

4 Step

The surface closing pressure, Pclose_at_surface was selected to be 150 psi less than the

surface injection pressure. These are equal to 1050 and 1200 psi. I plot it and the

surface injection pressure in Figure 21. I draw them pressure gradient as a function

of the gg.

5 Step

I calculate the unloading liquid gradient, gl from water cut and the oil gravity.

30

gl = (WC ∗ ρw + (1 − WC) ∗ ρo) ∗ 0.052

Equation 4

gl = ((0.64 ∗ 8.345 + (1 − 0.64) ∗ 7.319) ∗ 0.052) = 0.415 psi

ft

Figure 21 - Graphical procedure at K-1 well (Edited by the Author)

Summary of the starting data:

o Well head pressure, Pwh 50 psi

o Injection surface pressure, Pinj 1200 psi

o Surface closing pressure, Pclose_at_surface 1050 psi

0

1000

2000

3000

4000

5000

6000

7000

8000

0 500 1000 1500 2000

De

pth

, ft

Pressure, psiPwh

=50 Pclose

=1050 Pinj

=1200

2990

5512

7969

gg=0.03

gl=0.415

gt=0.04

Pc1

Pt1

Pt2 P

c2

Pt3 P

c3

31

o Gas gradient, gg 0.03 psi/ft

o Spacing factor, gt 0.04 psi/ft

o Unloading fluid gradient, gl 0.415 psi/ft

o Water Cut, WC 0.64

o Water density, ρw 8.345 ppg

o Oil density, ρo 7.319 ppg

6 Step

I calculate the first unloading valve depth, Dv1 (Equation 5). I plot a horizontal line at

Dv1 where the horizontal line crosses the spacing pressure line. The value of

pressure in the tubing at the first valve depth, Pt1 can be read. After I can determine

the tubing pressure, Pt1 (Equation 6) and closing pressure, Pclose1 (Equation 7) at the

valve depth. The unloading fluid gradient is drawn from Pwh.

Dv1 =Pinj − Pwh

gl − gg

Equation 5

Dv1 =1200 − 50

0.415 − 0.03= 2990 ft

Pt = gt ∙ Dv + Pwh

Equation 6

Pt1 = 0.04 ∙ 2990 + 50 = 169.6 psi

Pclose = gg ∙ Dv + Pclose_at _surface

Equation 7

Pclose1 = 0.04 ∙ 2990 + 1050 = 1140 psi

7 Step

I find the second unloading valve depth with the Equation 8 that is the depth

increment between the first and the second valve. I draw a parallel to gl line from

intersection of Pt1 and Dv1. The second valve depth is where this line crosses the gl

line. At the graphical solution the parallel unloading fluid gradient is started from Pt1

at the depth of the top valve to the gas gradient of the closing pressure.

32

∆Dv2 =Pclose − Pt1 + Dv1 ∙ gg

gl − gg

Equation 8

∆Dv2 =1050 − 169.6 + 2990 ∙ 0.03

0.415 − 0.03= 2522 ft

Dv2 = Dv1 + ∆Dv2 = 5512 ft

Pt2 = 0.04 ∙ 5512 + 50 = 270.5 psi

Pclose2 = 0.04 ∙ 5512 + 1050 = 1216 psi

The third valve’s depth is calculated with similar formula:

∆Dv3 =1050 − 270.5 + 5512 ∙ 0.03

0.415 − 0.03= 2457 ft

Dv3 = Dv2 + ∆Dv3 = 7969 ft

Pt3 = 0.04 ∙ 7969 + 50 = 368.8 psi

Pclose3 = 0.04 ∙ 7969 + 1050 = 1289 psi

I do not calculate more valves because the top of perforation is located at 8009 ft and the

following valve would certainly be under the perforation.

8 Step

I choose two-packer chamber installation. The bottom packer of the chamber is

located near the top of perforation so the bottom of the chamber is at 8008 ft. The

chamber length is determined by iteration procedure so I have to assume the first

value of chamber length and it is equal to 300 ft. Therefore the chamber operating

valve should be located at 7708 ft.

9 Step

I can calculate the closing pressure, Pcchv (Equation 9) and the tubing pressure, Ptchv

(it is sum of the wellhead and gas column pressure at liquid slug) at depth of

operating chamber valve, Dchv with Equation 6. This valve’s surface closing pressure

is 50 psi is less than the other unloading valves’ surface closing pressure to ensure

single-point gas injection.

33

Pcchv = Pclose − 50 + Dchv ∙ gg = 1232 psi

Equation 9

Ptchv = Pwh + Dchv ∙ gg = 281 psi

10 Step

I estimate the opening pressure, Pio of the chamber valve:

Pio = 1320 psi

11 Step

Then I have to find the required gas of intermittent gas lift cycle from Figure 17 and

it is 8.3 Mscf. Figure 18 can be used to determine the pressure reduction in the

annulus and in this case it is ΔP=83 psi.

12 Step

Therefore the opening pressure is sum of the Pcchv and ΔP as Equation 10.

Pio = Pcchv + ∆P = 1315 psi

Equation 10

13 Step

I can determine the port size of the chamber valve, R as Equation 11.

R =Pio − Pic

Pio − Pt

Equation 11

𝑅 =1315 − 1232

1315 − 281= 0.08

R =Av

Ab

where:

Av – area of valve port

Ab – area of bellows

34

14 Step

I have to find the suitable valve with proper port size. I choose the BPV-1.5 Injection

Pressure Operated Pilot Valve, which has 5/16 in port size. The value of

R=Ap/Ab=0.0959, the area of the port, Ap=0.0767 in2. The punctual opening pressure

at the valve’s depth is the following as Equation 2:

𝑃𝑖𝑜𝑛𝑒𝑤 =1232

1 − 0.0959− 281 ∙

0.0959

1 − 0.0959= 1332 𝑝𝑠𝑖

15 Step

I select the design tubing load, Pi, which depends on the opening pressure. It is 60-

75% of the opening pressure. I decide that the proper value is

𝑃𝑖 = 75% ∙ 𝑃𝑖𝑜𝑛𝑒𝑤 = 75% ∙ 1332 = 999 𝑝𝑠𝑖

Equation 12

16 Step

The next step is to calculate the capacities of the chamber and the tubing, Ca and

Ct using Equation 14 and Equation 15 accordingly. The ratio of these capacities is

Rc (Equation 13).

Rc =𝐶a

Ct

Equation 13

𝐶a = 9.71 × 10−4 (IDch2 − ODt

2)

Equation 14

𝐶𝑎 = 9.71 ∙ 10−4 ∙ (6.2762 − 2.3752) = 0.033 𝑏𝑏𝑙

𝑓𝑡

Ct = 9.71 × 10−4 IDt2

Equation 15

𝐶𝑡 = 9.71 ∙ 10−4 ∙ 1.9952 = 0.003863 𝑏𝑏𝑙

𝑓𝑡

o IDch – inside diameter of chamber, in

o IDt – inside diameter of tubing, in

o ODt – outside diameter of tubing, in

35

o Ca – capacity of chamber annulus, bbl/ft

o Ct – capacity of tubing, bbl/ft

17 Step

The new chamber length will be here as Equation 3:

𝐶𝐿𝑛𝑒𝑤 =𝑃𝑖 − 𝑃𝑡𝑐ℎ𝑣

(1 + 𝑅𝑐) ∙ 𝑔𝑙=

999 − 281

(1 − 8.543) ∙ 0.415= 182.6 𝑓𝑡

18 Step

Because of the result of the chamber length which differs from the assumed length,

I have to repeat Steps 8-17 until the two CL values are agree.

The values are the following:

o Assumed chamber length: CL = 182.6 ft

o Top of the chamber: Dcht = 7825 ft

o Closing pressure of the chamber operating valve: Pcchv = 1235 psi

o Tubing pressure of the chamber operating valve: Ptchv = 285 psi

o Assumed opening pressure: Pio = 1320 psi

o Pressure reduction in annulus: ΔP = 83 psi

o Calculated opening pressure: Pio = 1318 psi

o Assumed port size: R = 0.08

o Found port size of BPV- 1.5 Injection Pressure Operated Pilot Valve: R = 0.0959

o New opening pressure: Pio = 1336 psi

o Design tubing load: Pi = 1002 psi

o New chamber length: CL = 182.37 ft

The new chamber length is suitable because the difference is negligible between the two

calculated chamber lengths.

I calculate every injection pressures and opening pressures of the valves and I choose the

suitable type and size of the valves.

The top valve’s assumed R value is: 0.134. I choose a RP-6 valve and its port size is 3/8”,

because R value of this port size is the nearest to the assumed R value. The R is 0.168 so

the new opening pressure is 1336 psi.

36

The second valve selected to be the same type as the first valve, and the new opening

pressure of it is 1407 psi.

19 Step

The flowing temperature at each valve depths are 106 °F, 153 °F and 196.5 °F.

20 Step

The dome charge pressure of each valves are calculated from opening equation

(Equation 2), and the results are as follows:

𝑃𝑑 = 𝑃𝑖𝑜 ∙ (1 − 𝑅) + 𝑃𝑡 ∙ 𝑅

Equation 16

𝑃𝑑1 = 1140 𝑝𝑠𝑖

𝑃𝑑2 = 1216 𝑝𝑠𝑖

𝑃𝑑𝑐ℎ𝑣 = 1235 𝑝𝑠𝑖

21 Step

I determine the surface dome charge pressure of valves from Figure 27 and Figure

28 in Appendices. These are: P’d1=1050 psi, P’d2=1045 psi, P’dchv=945 psi

22 Step

Finally, TRO pressures are found from surface dome charge pressures (Equation

17):

𝑇𝑅𝑂 =𝑃′

𝑑

1 − 𝑅

Equation 17

𝑇𝑅𝑂1 = 1370 𝑝𝑠𝑖

𝑇𝑅𝑂2 = 1461 𝑝𝑠𝑖

𝑇𝑅𝑂𝑐ℎ𝑣 = 1045 𝑝𝑠𝑖

The Table 6 contains a summary, data of two unloading valves and one chamber valve.

With this method the chamber length is 176 ft that it means 6.45 bbl accumulated liquid,

about 17-19 cycle per day and just over 50 bbl/day.

37

Table 6 – Summary table of chamber lift design calculations at K-1 well (Edited by the Author)

Valve Valve depth

Surface closing

pressure

Closing pressure at depth

Tubing pressure at depth

Valve type

Port size

R Pio Pi

injection pressure

- ft psi psi psi - in - psi psi

1 2990 1050 1140 169.6 RP-6 3/8 0.137 1336

2 5512 1050 1216 270.5 RP-6 3/8 0.137 1407

3 7826 1000 1235 284.7 BPV-1.5 5/16 0.0959 1336 1002

Valve Valve

temp. at depth

P’d TRO

- °F psi psi

1 106 1050 1461

2 153 1045 1370

3 196.5 945 1045

6.1.2 Analytical solution by API [1]

As I mentioned in Chapter 4.3 this method takes in account the reservoir pressure and the

productivity index. The optimum cycle time, the liquid production and injected gas should

be set properly that they meet the economic requirements.

As this calculation is available for the conventional intermittent gas lift therefore I have to

adapt the calculation to be usable for chamber lift design.

1 Step

First of all I write an equation to express the liquid column length, K as a function of

time, t in the following equation:

𝐾 =𝐴 ∙ (𝑒𝛼∙𝑔𝑡∙𝑡 − 1)

304.8 ∙ 𝑔𝑡 ∙ (𝑒𝛼∙𝑔𝑡∙𝑡 − 𝑐𝑚)

Equation 18

The members of the equation:

𝐴 = 𝑃𝑅 − (𝐷𝑝𝑒𝑟𝑓 − 𝐷𝑐ℎ𝑝𝑒𝑟𝑓) ∙ 𝑔𝑙 − 𝐷𝑐ℎ𝑝𝑒𝑟𝑓 ∙ 𝑔𝑔 − 𝑃𝑤ℎ

Equation 19

38

The A is the maximum drawdown just after the production of liquid column and there

are forces that are acted on the perforation, such as liquid column between perforation

and perforated nipple, the gas column above the liquid and the wellhead pressure.

𝐴 = 2263 − (8009 − 8002) ∙ 0.0415 − 8002 ∙ 0.03 − 50 = 1970 𝑝𝑠𝑖

o Dchperf – Depth of perforated nipple, in

o t – Accumulation time, min

o cm – sum of fallback along the well from the perforated nipple, -

𝑐𝑚 = 𝐹𝐹 ∙𝐷𝑐ℎ𝑝𝑒𝑟𝑓

1000= 0.05 ∙

8002

1000= 0.4

Equation 20

o FF – Fallback factor, it is an assumed value: 5-7% per 1000 ft.

2 Step

The depth of perforated nipple is set 8002 ft because I take into account the thickness

of the packer.

𝛼 =𝑃𝐼

1440 ∙ 𝐵𝑡∙ 1000 =

0.043

1440 ∙ 36.648∙ 1000 = 8.138 ∙ 10−4

𝑓𝑡

𝑚𝑖𝑛

Equation 21

o PI – Productivity index, bbl/day/psi

Where Bt is the volume of accumulation space, so the chamber volume:

𝐵𝑡 = 0.97143 ∙ [(𝐼𝐷𝑐2 − 𝑂𝐷𝑡

2) + 𝐼𝐷𝑡2]

Equation 22

𝐵𝑡 = 0.97143 ∙ [(6.2762 − 2.3752) + 1.9952] = 36.648 𝑏𝑏𝑙

1000 𝑓𝑡

3 Step

I should give a constant productivity index, PI in the original calculation method, that it

means the using of linear inflow performance relationship but I determine it from the

Vogel-equation that is suited better for the well. I define the flowing bottomhole pressure

of the actual liquid rate from the Vogel-equation then with this pressure, the reservoir

pressure and the known liquid rate I calculate a PI and I use this value due to the

calculation.

The maximum liquid flow rate (Qlmax) is determined by the ISG 1.1 by Equation 1:

39

Qlmax = 67.57 bbl

day

I use the Vogel-equation (Equation 23) to determine the flowing bottomhole pressure.

Ql

Qlmax= (1 − 0.2 ∙ (

Pwf

PR) − 0.8 ∙ (

Pwf

PR)2

)

Equation 23

We know the liquid rate from the measured data, Ql is equal 43.96 BPD. The reservoir

pressure, PR is 2,263 psi. I calculate with the following data:

The Vogel-equation is rearranged and the flowing bottomhole pressure can be

expressed:

Pwf = 1,239 psi

The Darcy-equation (Equation 24) can express the productivity index:

𝑄𝑙 = 𝑃𝐼 ∙ (𝑃𝑠𝑏ℎ − 𝑃𝑤𝑓)

Equation 24

The Psbh can be equal to the reservoir pressure, so it is PR. After rearrangement the

Equation 24, the PI is:

𝑃𝐼 =𝑄𝑙

𝑃𝑅 − 𝑃𝑤𝑓=

43.96

2263 − 1239= 0.043

𝑏𝑏𝑙

𝑑𝑎𝑦 ∙ 𝑝𝑠𝑖

4 Step

After the substitutions to Equation 18, I got the values of K as a function of the time:

𝐾 =2204 ∙ (𝑒0.758∙0.04∙𝑡 − 1)

304.8 ∙ 0.758 ∙ (𝑒0.758∙0.04∙𝑡 − 0.48)

In Table 7 I collected the values of K for different accumulation times. The K can be

equal the chamber length.

5 Step

The total cycle time, T is sum of the accumulation time and the rising of liquid slug. As

a rule of thumb the liquid slug velocity is, vat is equal to 1000 ft/min. Nevertheless time

40

is necessary to push the liquid from the chamber to the tubing. The calculated total cycle

times are in Table 7.

𝑇 = 𝑡 +𝐷𝑐ℎ𝑡𝑜𝑝

𝑣𝑎𝑡+

𝐷𝑐ℎ𝑝𝑒𝑟𝑓

𝑣𝑎𝑡

Equation 25

6 Step

The daily production can be calculated with Equation 26:

𝑄𝑑 = 𝐾 ∙ (1 − 𝑐𝑚) ∙ 𝐵𝑡 ∙1440

𝑇

Equation 26

7 Step

For calculation of the required gas volume per cycle, Vgs I have to get through with the

following method.

𝑉𝑔𝑠 =520

14.7∙

𝑃𝑔𝑎

𝑇𝑎 ∙ 𝑍𝑎∙ 𝐵𝑔 ∙ (𝐷𝑐ℎ𝑝𝑒𝑟𝑓 − 𝐾𝑡)

Equation 27

o Pga – average pressure of the gas under the slug, psi

o Ta – average temperature of the gas,= 576.53 °R

o Za – average compressibility factor of the gas, = 0.871

o Bg – volumetric capacity of the tubing, ft3/ft

o Kt – accumulated liquid column length only in the tubing, ft

𝐾𝑡 =𝐾 ∙

𝐵𝑡1000𝐶𝑡

Equation 28

𝐵𝑔 =5.45415

1000∙ 𝐼𝐷𝑡

2 =5.45415

1000∙ 1.9952 = 0.022

𝑓𝑡3

𝑓𝑡

Equation 29

o IDt – inside diameter of the tubing, in

The average pressure is given by the next equation:

𝑃𝑔𝑎 =𝑃𝑔𝑢 + 𝑃𝑡𝑚

2+ 14.7

Equation 30

41

Where:

o Pgu – the pressure under the liquid slug, psi

o Ptm – the pressure at valve depth, psi

𝑃𝑡𝑚 = 𝑔𝑡 ∗ 𝐷𝑐ℎ𝑝𝑒𝑟𝑓 + 𝑃𝑤ℎ

Equation 31

𝑃𝑔𝑢 = 𝑃𝑤ℎ + 𝐾 ∙ (1 − 𝑐𝑚) ∙ 𝑔𝑙 ∙ 𝐶𝐹

Equation 32

8 Step

𝐶𝐹 =207.23 ∙ 𝜆 ∙ (

𝑣𝑎𝑡1000

)2

𝐼𝐷𝑡+ 1 =

207.23 ∙ 0.025 ∙ (10001000

)2

1.995+ 1 = 3.597

Equation 33

The λ value is the friction coefficient and I use the Colebrook-equation for determining

it. This equation must be solved by iteration.

𝜆 =

[

1

−2 ∙ 𝑙𝑜𝑔 [2.51

𝑅𝑒 ∙ 𝜆0.5 +

𝑘𝑑

3.72]

] 2

Equation 34

Where:

λ – Darcy-Weisbach friction coefficient, -

Re – Reynolds-number, -

k – roughness of pipe, ft

d – hydraulic diameter, ft

One of the necessary values is Reynolds-number, Re:

𝑅𝑒 = 12.434 ∙ 𝐼𝐷𝑡 ∙ 𝑔𝑙 ∙𝑣𝑎𝑡

𝜇𝑜= 12.434 ∙ 1.995 ∙ 0.415 ∙

1000

0.84= 12 255

Equation 35

42

o µo – viscosity of oil from Table 1, cp

I assume the value of relative roughness, k so it is 0.002. I read the friction factor,

λ=0.025.

9 Step

The required volume of gas per cycle is calculated by Equation 27 and the daily

consumption of gas is calculated by Equation 36 as shown in Table 7.

𝑄𝑔𝑖 =1440

𝑚𝑖𝑛𝑑𝑎𝑦

𝑇 𝑚𝑖𝑛𝑐𝑦𝑐𝑙𝑒

∙ 𝑉𝑔𝑠

𝑓𝑡3

𝑐𝑦𝑐𝑙𝑒 [1000𝑓𝑡3

𝑑𝑎𝑦]

Equation 36

Figure 22 – The daily liquid rate, Qd and the daily gas consumption, Qg as a function of the cycle time, T at K-1 well (Edited by the Author)

The Table 7 shows the summary of production and injection data for different accumulation

times. In the table the chamber length can be seen in the second column. In the next column

15

30

45

60

75

90

105

120

135

150

57,5

60

62,5

65

67,5

70

72,5

75

77,5

20 60 100 140 180 220

Liq

uid

pro

du

cti

on

per

day,

bb

l/d

ay

Inje

cte

d g

as p

er

day,

1000 f

t3/d

ay

Cycle time, min

Liquid production

Injected gas

43

there is the liquid column length in tubing, Kt, which is the state when the liquid is pushed

from the annulus to the tubing.

𝐾𝑡 =𝐾 ∙

𝐵𝑡1000𝐶𝑡

Equation 37

Table 7 – Data of production as a function of accumulation time at K-1 well (Edited by the Author)

t -

Accumu-lation

time, min

K - Liquid column

length in chamber,

ft

Liquid column

length in tubing, ft

Liquid column pressure in tubing, psi

Pressure at perforation,

psi

1 20 53.02 503 208.62 483.8

2 30 79.2 751.6 311.7 579.4

3 40 105.2 998.2 414 674.3

4 50 131.02 1243 515.5 768.5

5 60 156.6 1486 616 861.9

6 80 207.2 1966 815.3 1047

7 100 257.1 2439 1011 1228

8 125 318.3 3019 1252 1452

9 150 378.4 3589 1489 1671

10 200 495.2 4698 1948 2098

T - Cycle time, min

NOC, Number of cycle per

day

Qd - daily liquid

production, bbl/day

Qg - Daily injected gas

consumption, 1000ft3/day

Qo - daily oil production,

bbl/day

1 28.1 51.3 59.8 146.2 39.47

2 38.1 37.8 65.9 109.1 43.49

3 48.1 30 69.2 87.1 45.67

4 58.1 24.8 71.4 72.5 47.12

5 68.2 21.1 72.8 62 48.05

6 88.2 16.3 74.4 47.8 49.10

7 108.3 13.3 75.2 38.4 49.63

8 133.3 10.8 75.6 30.2 49.90

9 158.4 9.1 75.5 24.2 49.90

10 208.5 6.9 75.2 15.6 49.63

44

In the fifth column the pressure at perforation at the end of accumulation, Pp:

𝑃𝑝 = 𝐾𝑡 ∙ 𝑔𝑙 + (𝐷𝑐ℎ𝑝𝑒𝑟𝑓 − 𝐾𝑡) ∙ 𝑔𝑔 + 𝑃𝑤ℎ

Equation 38

With the accumulation time the cycle time and the liquid column length also increase as a

result the number of cycle per day decreases. The daily oil production as a function of

accumulation time is maximize close to 101 BPD. Because the quantity of injected gas

depends on the liquid column length, so the daily gas consumption decreases as a function

of liquid column length increment. The last column in the table is the oil production. It is

counted from the liquid production and the water cut.

Figure 22 shows the liquid production and injected gas as a function of cycle time. It can be

seen that the liquid production has a peak and the gas injection decreases.

6.1.3 Adjustment the proper settings

In this chapter I choose the appropriate cycle time with the liquid production and injected

gas fits for the economic requirement. I have to pay attention to sufficient energy and

injection time should be provided for the injection gas and the pressure difference of the

inflow is adequate.

According to [1] the optimum cycle time should be calculated when the liquid production is

maximized. In this case it is 75.6 bbl/day with 133.3 min cycle time according to as Table 7.

As I mentioned in Chapter 6.1.1, the planned surface injection pressure is 1200 psi that is

at valve depth is 1440 psi. Unfortunately this injection pressure has not enough energy to

push the liquid slug that is seen in the fourth column in Table 7.

As a rule of thumb 1.5 times excess is needed to rise the slug. The 133.3 min cycle time

choice has 1452 psi pressure in the tubing and it is high. The proper liquid column pressure

can be 960 psi. Therefore I have to find the adequate cycle time and liquid rate.

With 960 psi the accumulation time is 70.58 min and 73.75 bbl/day liquid rate and the further

data is in Table 8. The chamber length will be 183.5 ft. With this chamber length I calculate

the closing, tubing and opening pressure. Then the next step is the counted R value and to

choose a proper valve [14].

45

Table 8 – Values of chamber installation at K-1 well (Edited by the Author)

Accumulation time, min 70.58 70.76

Liquid column length, ft 183.5 184

Cycle time, min 78.77 78.95

NOC 18.28 18.24

liquid rate per day, bbl/day 73.75 73.77

injected gas, 1000 ft3/day 53.69 53.57

Pcchv, psi 1235

Ptchv, psi 284.74

Pinj, psi 1342

Rassume 0.101

Valve

R-20 valve 5/16 port size

R 0.103

New Pi, psi 1344

New Pcchv, psi 1235

New Ptchv, psi 284.72

New chamber length, ft 183.95

Liquid in tubing, ft 1741 1745

liquid pressure in tubing, psi 721.95 723.75

pressure at perforation, psi 960 961.67

The chosen valve is R-20 valve with 5/16“. I have to determine the proper values with the

new R that is 0.103.

Therefore the optimum cycle time is 78.95 min and the further production data are:

o The daily injected gas is: 53,570 ft3/day

o The daily liquid production is: 70.76 bbl/day

The new chamber length and the calculated length in Chapter 6.1.1 are the same. Both of

them are 184 ft.

The Table 8 details on the values, the first column is the assumed, and the second is the

optimized data of the well.

46

6.2 K-2 well design

I also perform the design calculations for the K-2 well.

6.2.1 Unloading valve string design for K-2 well

I make the same calculation for the K-2 well.

I choose the surface pressure as following:

o Pwh = 50 psi

o Pinj = 1200 psi

o Pclose_at_surface = 1050 psi

The value of gg is same than at K-1 well, because the injected gas also has 0.65 specific

gravity, so gg = 0.03 psi/ft.

Because of the production rate is low, I use the generally accepted value of the spacing

factor, gt = 0.04 psi/ft.

The unloading liquid gradient is calculated from water cut (WC = 66%) and oil density (ρo =

6.1 ppg), gl = 0.416 psi/ft.

I can begin the graphical solution that is illustrated on Figure 23. I draw the line of pressure

gradients, the gg begins from Pinj and I have to draw a parallel line from Pclose_at_surface. The

gl and gt start from Pwh.

I calculate the first valve depth with Equation 4 and its tubing and closing pressure with

Equation 5 and Equation 6.

Dv1 =1200 − 50

0.416 − 0.03= 2982 ft

Pt1 = 0.04 ∙ 2982 + 50 = 169.26 psi

Pclose1 = 0.04 ∙ 2982 + 1050 = 1140 psi

I find the second valve depth and its related pressure values.

∆Dv2 =1050 − 169.26 + 2982 ∙ 0.03

0.416 − 0.03= 2516 ft

47

Dv2 = 2982 + 2516 = 5497 ft

Pt2 = 0.04 ∙ 5497 + 50 = 269.88 psi

Pclose2 = 0.04 ∙ 5497 + 1050 = 1215 psi

Figure 23 - Graphical procedure at K-2 well (Edited by the Author)

I determine the third valve with this procedure. These values are: Dv3 = 7947 ft; Pt3 = 367.9

psi; Pclose3 = 1289 psi.

0

1000

2000

3000

4000

5000

6000

7000

8000

0 500 1000 1500

De

pth

, ft

Pressure, psi

Pwh

=50 Pclose

=1050 Pinj

=1200

2998

5497

7947

gg=0.03

gl=0.416

gt=0.04

Pc1

Pt1

Pt2 P

c2

Pt3 P

c3

48

I do not calculate more valves because the top of perforation is located at 8706 ft and the

following valve would certainly be under the perforation.

I choose two packer chamber again. During calculations I take into account the bottom

packer length, so the bottom of the chamber is located around 8044 ft.

In the next step I have to estimate a chamber length, because it determined by iteration.

𝐶𝐿𝑎𝑠𝑠𝑢𝑚𝑒𝑑 = 200 𝑓𝑡

The assumed chamber valve is located 7844 ft. I calculate the closing and tubing pressure

of the chamber valve with Equation 8 and Equation 5: Pcchv =1236 psi and Ptchv = 285 psi

I assume the opening pressure of the chamber valve: Pio = 1330 psi and I determine the

pressure differential: ΔP = 80 psi. The calculated Pio = 1316 psi is near the assumed value.

I define the R value with Equation 11:

𝑅 =1316 − 1236

1316 − 285= 0.078

I found a valve with a proper R value: R-20, with ¼” port size and R = 0.075. The new

opening pressure from Equation 2: Pio = 1313 psi. The tubing load is 75% of the opening

pressure: Pi = 984.5 psi.

The determination of annulus and tubing capacity is necessary for calculation of the new

chamber length.

𝐶𝑎 = 0.018 𝑏𝑏𝑙

𝑓𝑡

𝐶𝑡 = 0.003863 𝑏𝑏𝑙

𝑓𝑡

𝐶𝐿𝑛𝑒𝑤 =984.5 − 285

(1 −0.018

0.003863) ∙ 0.416= 292.92 𝑓𝑡

Because of the result of the chamber length which differs from the assumed length, I have

to repeat Steps 9-19 until the two CL values are agree.

The values are the following:

o Assumed chamber length: CL = 292.92 ft

o Top of the chamber: Dcht = 7751 ft

49

o Closing pressure of the chamber operating valve: Pcchv = 1233 psi

o Tubing pressure of the chamber operating valve: Ptchv = 285.5 psi

o Assumed opening pressure: Pio = 1330 psi

o Pressure reduction in annulus: ΔP = 77 psi

o Calculated opening pressure: Pio = 1310 psi

o Assumed port size: R = 0.075

o Found port size of R-20 valve: R = 0.075

o New opening pressure: Pio = 1310 psi

o Design tubing load: Pi = 982.4 psi

o New chamber length: CL = 293.2 ft

The new chamber length is suitable because the difference is negligible between the two

calculated chamber lengths.

I calculate every injection pressures and opening pressures of the valves and I choose the

suitable type and size of the valves.

Table 9 – Summary table of chamber lift design calculations (Edited by the Author)

Valve Valve depth

Surface closing

pressure

Closing pressure at depth

Tubing pressure at depth

Valve type

Port size

R Pio

- ft psi psi psi - in - psi

1 2982 1050 1140 169.26 R-20 5/16” 0.0126 1280

2 5497 1050 1215 269.9 R-20 5/16” 0.0126 1352

Chamber

valve 7750 1000 1233 285.5 R-20 1/4” 0.075 1310

Valve Valve

temp. at depth

P’d TRO

- °F psi psi

1 106 1050 1304

2 153 1012 1390

Chamber

valve 207 985 1065

The flowing temperature at each valve depths in sequence are 106 °F, 153 °F and 207 °F.

50

The dome charge pressure of each valves are calculated from opening equation: 1140 psi,

1215 psi and 1233 psi (Equation 16). I can determine the surface dome charge pressure of

valves from Figure 27 and Figure 28 in Appendices, finally the TRO from surface dome

charge pressure and R.

The Table 9 contains a summary about data of two unloading valves and one chamber

valve.

6.2.2 Design by API

With this method I calculate the main production features and I can choose the proper

chamber length.

First I have to determine the possible chamber length, K as a function of accumulation time

with Equation 18. The terms of this equation have to be defined, the A with Equation 19, cm

with Equation 20 and α with Equation 21.

𝐴 = 2263 − (8050 − 8043) ∙ 0.0416 − 8043 ∙ 0.03 − 50 = 1968 𝑝𝑠𝑖

𝑐𝑚 = 𝐹𝐹 ∙𝐷𝑐ℎ𝑝𝑒𝑟𝑓

1000= 0.05 ∙

8043

1000= 0.402

𝛼 =0.036

1440 ∙ 22.188∙ 1000 = 1.119 ∙ 10−3

𝑓𝑡

𝑚𝑖𝑛

Where Bt is the volume of accumulation space, so the chamber volume from Equation 22:

𝐵𝑡 = 0.97143 ∙ [(4.952 − 2.3752) + 1.9952] = 22.188 𝑏𝑏𝑙

1000 𝑓𝑡

To calculation of α, the PI is necessary. I use again the Vogel-equation. The maximum liquid

rate is defined by ISG 1.1 and I can determine the flowing bottomhole pressure finally the

PI.

o Ql = 31.4 bbl/day

o Qlmax = 38.06 bbl/day

o PR = 2263 psi

o Pwf = 812.5 psi

51

Figure 24 - The daily liquid rate, Qd and the daily gas consumption, Qg as a function of the cycle time, T at K-2 well (Edited by the Author)

𝑃𝐼 =31.4

2263 − 812.5= 0.036

𝑏𝑏𝑙

𝑑𝑎𝑦 ∙ 𝑝𝑠𝑖

I calculate the total cycle time, the daily liquid production and daily injected gas consumption

with calculation that is known during previous well design. I use from 25 Equation to 35

Equation. I summarize the obtained results in Table 10.

Table 10 - Data of production as a function of accumulation time at K-2 well (Edited by the Author)

t - Accumu-

lation time, min

K - Liquid column

length in chamber,

ft

Kt - Liquid

column length in tubing, ft

Liquid column

pressure in tubing, psi

Pressure at perforation,

psi

1 20 72.86 418.44 173.99 451.71

2 30 108.7 624.28 259.59 531.13

3 40 144.16 827.93 344.26 609.7

4 50 179.24 1029 428.04 687.42

5 60 213.95 1229 510.92 764.33

6 80 282.27 1621 674.08 915.71

7 100 349.16 2005 833.83 1064

8 125 430.84 2474 1029 1245

9 150 510.44 2932 1219 1421

10 200 663.67 3812 1585 1761

20

35

50

65

80

95

110

125

140

155

47,5

52,5

57,5

62,5

20 60 100 140 180 220

Liq

uid

pro

du

cti

on

per

day,

bb

l/d

ay

Inje

cte

d g

as p

er

day,

1000

ft3/d

ay

Cycle time, min

Liquid production

Injected gas

52

T - Cycle time, min

NOC, Number of cycle per day

Qd - daily liquid

production, bbl/day

Qg - Daily injected gas

consumption, 1000ft3/day

Qo - daily oil

production, bbl/day

1 28.16 51.22 49.5 152.96 32.67

2 38.15 37.75 54.43 116.15 35.92

3 48.19 29.88 57.15 94.36 37.72

4 58.22 24.73 58.8 79.83 38.81

5 68.26 21.1 59.88 69.37 39.52

6 88.32 16.3 61.05 55.13 40.29

7 108.39 13.29 61.54 45.69 40.61

8 133.47 10.79 61.66 37.38 40.69

9 158.55 9.08 61.5 31.27 40.59

10 208.71 6.9 60.75 22.54 40.09

6.2.3 Choosing the proper settings

According to Table 10 the maximum daily liquid rate is 61.6 bbl/day. In this case the

pressure at perforation is 1245 psi and the injected gas is not able to hold the liquid slug

because the surface injection pressure is 1200 psi and the pressure in the tubing has to be

955.1 psi. I find the proper chamber and the cycle time.

Table 11 - Values of chamber installation at K-2 well (Edited by the Author)

Accumulation time, min 85.27 85.47

Chamber length, ft 300 300.7

Cycle time, min 93.62 93.8

NOC 15.38 15.35

liquid rate per day,9 bbl/day 61.22 61.23

Oil rate per day,9 bbl/day 40.41 40.41

injected gas, 1000 ft3/day 52.3 53.35

Pcchv, psi 1233

Ptchv, psi 285.3

Pinj, psi 1331

Rassume 0.094

Valve

BPV valve 3/8” port size

R 0.0959

New Pi, psi 1333

New Pcchv, psi 1233

New Ptchv, psi 282.33

Liquid in tubing, ft 1108 1109

liquid pressure in tubing, psi 460.9 461

pressure at perforation, psi 717.9 718

53

The chosen valve is BPV-1.5 Injection Pressure Operated Pilot Valve 3/8“. The necessary

chamber length is 300.7 ft, the daily oil production is 40.41 bbl/day and the daily injected

gas is 53,350 ft3/day.

The Table 11 details on the values, the first column is the assumed, and the second is the

calculated data of the well.

6.3 Economic comparison

Nowadays everything is defined by the economy. Therefore I have to deal with the impact

of the reconstruction on the economy. It is determined by the budget which well continues

to operate and which is not. In our case, the budget has a major influence on:

o the running costs,

o the maintenance costs and

o the preparation and other costs.

The running and maintenance costs of the new well do not differ from the old well’s. The

preparation cost is detail in Table 12.

Table 12 – Additional costs (Edited by the Author)

Preparation at main gathering station,

$/t

0.00391

Water injection, $/bbl 0.01511

Compressor of injected gas, $/1000 ft3 0.15149

Gas preparation, $/1000 ft3 0.01441

Sulphur exoneration, $/1000 ft3 0.00702

Redevelopment cost, $ 782 608.7

oil price, US$/bbl 100

gas price, US$/1000 ft3/day 8

Table 12 contains oil rate, the injected gas per day and their prices. We can see that with

the original construction the return was very low and it can be increased with the new

construction.

54

Table 13 – Comparison of the different settings (Edited by the Author)

K-1 well K-2 well

original new original new

Accumulation time, min 190 70.58 200 85.47

Liquid rate per day, bbl/day 43.96 73.77 31.4 61.23

Injected gas, 1000 ft3/day 293 53.57 268.28 75.31

Oil rate per day, bbl/day 15.83 25.08 10.68 20.82

Ro - Return from oil production, $/day

1583 2508 1068 2082

K-1 well K-2 well

original new original new

Preparation at main gather, $/day 0.17 0.29 0.12 0.33

Water injection, $/day 0.43 0.74 0.31 0.85

Compressor of injected gas, $/day 44.41 8.12 40.64 11.41

Gas preparation, $/day 4.22 0.7717 3.8648 1.0849

Sulphur exoneration, $/day 2.06 0.38 1.88 0.53

Sum of costs, $/day 51.29 10.29 46.83 14.21

Profit, $/day 1443.3 2497.89 1020.77 2891.77

Redevelopment cost, $

780 000

730 000

Recovery of redevelopment, day 313 252

The quantity of injected gas was very high which I can cut down. It can be reduced by 80%.

The daily profits are higher in both of two cases. At K-1 well it increases with 42% and at

the other well it increases with 65%. The redevelopment costs are 780 000 $ and 730 000

$ that are recovered over 313 and 252.

55

6.4 The final wells construction

The final wells’ construction are formed that they are illustrated on the Figure 25 and Figure

26.

Figure 25 – The final construction of the K-1 well with chamber lift (Edited by the Author)

13 3/8” 113.2 ft

2 3/8” tubing

9 5/8” 2629.7 ft

RP-6 valve, 5512 ft

BPV-1.5 1/4“ valve, 7833 ft

7” 8136.9 ft

7” packer, 8008 ft



Standing valve, 8008 ft

RP-6 valve, 2990 ft

Perforated nipple, 8002 ft

Chamber length, 175 ft

56

Figure 26 - The final construction of the K-2 well with chamber lift (Edited by the Author)

The casing and the perforations are not changed. The tubing is reconstructed it will be 2

3/8” and it reaches the top of perforation. I take into account the length of lower packer that

is assumed 6 ft. The standing valve is a very important part of the construction. The

13 3/8” 113.2 ft

2 3/8” tubing

9 5/8” 2629.7 ft

RP-20 valve, 5497 ft

BPV-1.5 3/8“ valve, 7742.3 ft

7” 8136.9 ft

7” packer, 8049 ft


Standing valve, 8049 ft

RP-20 valve, 2982 ft

Perforated nipple, 8043 ft

Chamber length, 300.7 ft

57

unloading valves’ parameters are determined in Chapter 6.1.1 and 6.2.1 and the operating

chamber valve’s characteristics are defined in Chapter 6.1.3 and 6.2.3.

58

Summary

In the first two chapters I summarized the gas lifting practice generally. The third chapter is

about the chamber installations, where I detailed the main characteristics, advantages,

disadvantages and the main design considerations. There is a comparison between the

conventional and two chamber constructions – with and without bleed valve.

The fourth chapter deals with the chamber design. I described two ways of design. One of

them is with a constant surface closing pressure, it is able to determine the unloading valves

depth, their parameters and the chamber length. The other one is performed according to

API RP 11V10 6/2008 [1]. I determine the chamber length, the optimum cycle time and the

required injected gas volume. I slightly modified the calculation because it is originally a

conventional gas lift design.

The fifth chapter contains the parameters of the reservoir, the reservoir fluids, and the old

well construction. I examine these wells because that kind of wells will be installed in

Hungary in the near future. These wells have high reservoir pressure however their liquid

productions are very low.

In the last chapter I detail the calculations and the economic comparison between the

conventional gas lift installation and the chosen chamber installation. During calculations I

used to program MathCAD and Excel. The final results are:

o I determined the depth and type of the unloading valves and the chamber valve.

o I defined the chamber length, the chamber of K-1 well is 175 ft, and K-2 well has a

300.7 ft chamber.

o The injected gas consumption reduced with 81% at K-1 well and with 72% at K-2

well.

o The investigation of the reconstruction costs are recovered over less than one year

– 313 and 252 days.

o The daily profits are more than the old wells in both the two cases, they increase

with 42% and 65%.

In examined cases the results show the liquid production rates get better and the applied

injected gas decreases. The reconstruction is more expensive than the case when

continuous gas lift well is changed to intermittent gas lift well, but the profit increases with

the chamber installation. With these constructions change, the life time of the wells get

longer than without them. From the results my statement is that the reconstructions in both

cases are recommended according to engineering and economical side.

59

Appendices

Figure 27 – Surface dome charge pressure calculation 1.

Nitro

ge

n D

om

e C

harg

e P

ressure

at V

alv

e D

ep

th, p

si

Nitrogen Dome Charge Pressure, psi

Valve Temperature, °F

60

Figure 28 - Surface dome charge pressure calculation 2.

Nitro

ge

n D

om

e C

harg

e P

ressure

at V

alv

e D

ep

th, p

si

Nitrogen Dome Charge Pressure, psi

Valve Temperature, °F

61

References

[1] API. (2008). RP 11V10. Washington, USA.

[2] Brown, K. (1980). The Technology of Artificial Lift Methods, Vol. 2a. Tulsa, OK:

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[3] Brown, K., & Lee, R. (1968). Easy-to-Use Charts Simplify Intermittent Gas Lift

Design. World Oil.

[4] Chacin, J., & Lake, L. (1994). Selection of optimum intermittent lift scheme for

gas lift wells. Tulsa, USA.

[5] Davis, L., Thrash, P., & Canalizo, C. (1970). Guidlines to Gas Design and Control.

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[6] Duns, H., & Ros, N. (1963). Vertical Flow of Gas and Liqiud Mixtures in Wells.

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[7] Gas Lift. (1984). Book 6 of the Vocational Training Series. Dallas, TX: American

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[8] Gas Lift Manual. (1970). Section 3: Intermitting Gas Lift. Garland, TX: Teledyne

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[9] Gasbarri, S., Marcano, L., Inciarte, J., & Faustinelli, J. (1999). Insert chsmber lift

experiences in Mara-la Paz field . Venezuela.

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production by properly venting formation gas in insert chamber. Houston, USA.

[11] Hernandez, A., Perez, C., Navarro, U., & Lobo, W. (1999). Intermittent gas lift

optimization in Rosa Mediano field. Venezuela.

[12] Lake, L., & Clegg, J. (2006). Production Operations Handbook, Petroleum

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[13] Neely, A., Montgomery, J., & Vogel, J. (1973). A Field Test and Analytical Study

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62

[15] Turner, R., Hubbard, M., & Dukler, A. (1969). Analysis and Prediction of Minimum

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63

Acknowledgement

I would like to render thanks to Zoltán Turzó PhD (faculty adviser) who works at the

Petroleum Engineering Department at University of Miskolc and Mihály Szűcs (field

adviser) who works at Hungarian Oil and Gas Company for their kind help and

mentoring me. Furthermore, I would like to thank for my professors, who taught me

during the four semesters and I acquired a lot of knowledge from them.

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