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)
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 (open)
Operating valve (open)
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 standing valve
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
Unloading valve (closed)
Operating valve (open)
Standing valve (closed)
Injected gas
3.
Unloading valve (closed)
Operating valve (open)
Standing valve (closed)
Injected gas
4.
Injected gas
Operating valve (open)
Unloading valve (closed)
Standing valve (closed)
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
Retrievalbe standing valve
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
Perforation, 8038 - 8058
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
Setting depth 1776.54 m 5827.05 ft
Valve III.
Type BK
Setting depth 2412.44 m 7912.8 ft
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, 4273.1 ft, E-plug
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
2 3/8” KBM side pocket mandrel, 5827.05 ft, E-plug
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
Perforation, 8009 - 8025
Perforation, 8038 - 8058
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
Perforation, 8050 - 8076
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
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[3] Brown, K., & Lee, R. (1968). Easy-to-Use Charts Simplify Intermittent Gas Lift
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[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.
[10] Hernandez, A., Perez, C., Navarro, U., & Lobo, W. (1999). Increasing fluid
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.