Auxiliary Completion Components lec ( 9 )

 Auxiliary Completion Components

The production string is a receptacle for many kinds of flow control devices
and other accessories which are designed to increase the versatility of the
completion. Some of these devices are run as a part of the tubing string while
others are installed and retrieved by wireline or coiled tubing. Items installed
by wireline methods must have a facility in the tubing string which allows
removable devices to be located and secured.

Tubing Landing Devices
– Seating Nipples

Seating nipples are landing devices which have a slightly restricted polished
ID which prevents tools from passing through and allow sealing of devices.
Seating nipples do not have a locking recess. The tool locates on the shoulder
of the reduced ID section and is held in place by pressure from above. The
standing valve is an example of a downhole tool often located in seating nipples.
These nipples are also commonly used to land recipricating rod pumps in.

Subsurface Safety Valves

Nipples

Tubing Landing Devices
– Profile Nipples

Nipples used to land downhole tools fitted with locking mechanisms are known
as profile nipples. In addition to an internal sealing surface, profile nipples
have a profiled locking recess.
There are two basic types of profile nipples, no-go nipples and selective nipples.
These nipples have a restricted ID, or a no-go shoulder at the bottom or top of
the seal surface, on which the downhole tool is located.
Selective nipples (Fig 6-1) can be placed in the tubing string at as many locations
as necessary. Selective nipples in a series can all have the same profile of
locking recess and ID. In this case, the specific nipple must be located by
determining its depth. This is the most common system. However, some
companies manufacture selective nipples with as many as six different profiles.
Such nipples may be run in a specific sequence with special keys conforming
to the position of the desired nipple. The keys on the running mandrel ensure
the device will only locate in the specific nipple desired. This system is not
commonly used anymore. There are several manufacturers of profile nipples,
each of which may have two or more product lines of profile nipples.
It is also possible for a variety of downhole tools to have a nipple profile cut
into them. These profiles may either be selective or no-go and receive a variety
of flow control devices.

Hydraulic Landing Nipples

 For the installation of retrievable surface controlled subsurface safety valves
(SCSSV) that are actuated by hydraulic pressure, it has been necessary to
develop hydraulic landing nipples (Fig 6-3). Again, these nipples may be either
selective or no-go. They have two polished bores with a single port between
the bores for the introduction of hydraulic fluid under pressure.

 

Mandrels

Mandrels
Side Pocket

Side pocket mandrels (Fig 6-4) can also be considered landing devices. Most
side pocket mandrels provide an unrestricted flow path in the tubing string but
can receive a variety of different control devices. Side pocket mandrels have an
offset pocket next to the drift ID at the bottom of the mandrel containing a
polished bore for pressure sealing above and below a port. In addition to
landing gas lift valves, control devices as chemical injection valves, circulating
valves and circulating sleeves may be landed in side pocket mandrels.
A variety of devices for controlling communication between the tubing and the
annulus can be landed in side pocket mandrels. Gas lift valves can be set to
open at a preset pressure in response to either injection gas pressure or
production pressure. As soon as the valve opens, injection gas flows freely
into the fluids of the production conduit (either tubing or annulus, depending
on completion design.).

Mandrels
  Conventional

Conventional mandrels (Fig 6-5) are designed to carry and protect externally
mounted conventional gas lift valves. The internal surface of a conventional
mandrel does not have an upset area or pocket (as with a side pocket mandrel).
The flush internal surface is broken only by a small access port to the externally
mounted gas lift valve.

Down Hole Tubing

 Hangers It is possible to land a section of tubing in a casing hanger nipple that was run
in with the casing. The casing hanger nipple has a no-go in it and is used to
land a tubing hanger attached to the tubing string. The tubing hanger sets in
the casing hanger nipple and supports the tubing. This capability is used
when the tubing may need to be separated above the tubing hanger utilizing a
separation device. The upper section of the tubing string may be pulled without
retrieving the entire string. The tubing string is also landed at the wellhead in
the tubing head. The tubing at the surface is attached to the tubing hanger,
which fits into the tubing head. The restricted ID of the tubing head holds the
slips of the tubing hanger.

Sleeves

Communication Devices Sliding Sleeve
A more efficient method of circulating between tubing and
annulus is to use a sliding sleeve (Fig 6-6) . This device is widely
used to permit circulation between the tubing and the annulus or
for selectively producing a zone. Sliding sleeves can be opened
using wireline methods by either a jar upward or downward with
a special shifting tool. Sliding sleeves have a large circulating
capacity and are excellent devices for communication between
the tubing and annulus for well kill or similar high fluid-volume
applications.

Other communication devices may be placed in side pocket mandrels to control
flow from the annulus to the tubing or vice versa. These circulating devices
include among others:

• Circulating sleeves

Devices to allow circulation in either direction which protect the
side pocket from damage due to the erosive effects of flow.

• Circulating valves

Valves used to circulate in one direction only. Some circulating
valves are designed for flow into the annulus while others are
designed to allow flow into the tubing.

• Dump-kill valves

Valves landed in a side pocket mandrel, which require a
predetermined pressure differential across the tubing before they
will open. Pins are sheared and fluids will flow under pressure
through the valve into the tubing. This device is placed relatively
deep in the well and is used to kill the well.

Tubing String
Protection Devices

Types

 The production string is exposed to many physical forces which can cause
damage. Several devices and tools have been developed to protect the tubing
string and completion equipment from such forces or conditions.

• Safety joint (Fig 6-7)

Safety joints are usually installed above a packer. If the packer
becomes stuck, the safety joint can be separated. This enables a
heavier-fishing string containing jars to be used to retrieve the
stuck packer. Safety joints are available in straight pull or rotation
models.

• Flow coupling

Flow couplings are installed above and below certain components
in the tubing string to protect against erosion damage. Flow
couplings are normally available in lenghts betweeen 4 and 10
feet, and constructed from heavy walled pipe. These sections of
pipe serve to prevent fluid turbulence from eroding the tubing
string (Internal erosion).

• Blast joint (Fig 6-8)

Blast joints are heavy walled joints of pipe, available in lengths
between 2 and 20 feet. Blast joints are installed in the completion
string to withstand the scouring action of fluid flow from
perforations (External erosion).

Tubing Separation
Devices

Types 

On - off tools (Fig 6-9)
If frequent removal of a portion of the tubing is expected during
the life of a well, tubing on-off attachments are available. These
attachments consist of a removable skirt section which is attached
to the tubing string, and a slick joint which usually contains a
wireline profile which stays attached to the packer.
Tubing Seal Receptacles (Fig 6-10)
Generally used in lengths of 10 to 30 ft., tubing seal receptacles
are installed immediately above the packer. These devices
resemble on-off connectors but have a much longer stroke, to
allow for tubing movement. The seal receptacle is normally run in
closed position either utilizing a ‘J’ or shear pins. Once landed
the receptacle skirt is released and spaced out on the slick joint
as required.
The slick joint generally incorporates a profile in the top. The
skirt assembly which contains the seals can be removed from the
slick joint and retrieved leaving the slick joint in place.

Tubing Expansion Devices

Expansion Joints

 Under some conditions the tubing string of a producing well may be subjected
to large stress changes due to pressure or temperature changes These forces
cause the tubing string to expand and contract. If conditions warrant it, it may
be necessary to install an expansion device to avoid buckling or possible
separation of the tubing string. Expansion joints are designed to eliminate the
stress produced during these changes allowing the tubing string to expand
and contract without losing the integrity of the production string. They are
commonly produced in stroke lengths of 2 to 20 feet.
Non-splined expansion joints are free to rotate. No tubing torque can be
transmitted through this type of expansion joint.
Clutch type expansion joints (Fig 6-11) are free to rotate through most of their
stroke, but lock when fully extended or compressed to allow torque transmission
through the expansion joint.
Fully splined expansion joints (Fig 6-12) are locked against rotation throughout
their stroke.

Polished Bore
Receptacle (PBR)

Available in lengths of 10 to 30 ft. long. PBR’s (Fig 6-13) consist of a polished
seal bore above the packer which is attached to the packer and a long seal
assembly which is attached to the tubing and seals into the polished bore. The
seal assembly is generally shear pinned into the seal bore when running. Once
landed the seal assembly is sheared and spaced out as required. The seal
assembly may be retrieved to be redressed or repaired. If it is necessary to
retrieve the polished seal bore it will require a second trip with a retrieving tool.

Seal Bore Extension (SBE)

 A ‘SBE’ is run below a seal bore packer in order to extend the length of the
packer’s seal surface. Normally used in lengths of 10, 20, or 30 ft. long. An
extended locator type seal assembly is run into the seal bore and spaced out as
required.
Adjustable Union

 An adjustable union (Fig 6-14) provides a means of spacing out and connecting
tubing on the short string side between dual packers. The adjustable union
may also be used space out production tubing near the surface.

The deisgn function of a subsurface safety valve is to prevent the uncontrolled
flow of well fluids.

Types

There are two major types of subsurface safety valves:
Subsurface Controlled Safety Valve (SSCSV)
This type of safety valve is controlled by well conditions. When
the downhole pressure or velocity reaches a predetermined
setting, the valve will close. The valves are actuated by the
ambient pressure differential created by increased fluid velocity
which occurs when the integrity of the production string above
the safety valve is broken. Subsurface controlled safety valves
are located in a profile nipple.
Surface Controlled Subsurface Safety Valve (SCSSV)
This type of safety valve is controlled by surface hydraulic
pressure transmitted through a small control line to control the
valve. Pressure is used to keep the valve open. If the control
pressure is released and the valve closes. SCSSVs shut off the
flow of the well completely, producing a pressure tight seal.
SCSSV’s may be tubing retrievable or wireline retrievable. The
tubing retrievable type can be pulled only with the removal of the
entire tubing string. Wireline retrievable valves that are controlled
from the surface must be landed in the hydraulic landing nipple
or inside of a locked out tubing retrievable safety valve.

SAtuaxnildiainrgy vCaolmvepletion Components

A standing valve functions as a downhole check valve. This valve allows flow
in one direction and may be landed in a seating nipple or landing nipple.
Pressure from below normally causes fluids to pass freely into the production
tubing while pressure from above results in the ball forming a seal in the seat.
Standing valves are normally run with an internal equalizing device which
allows the pressure to be equalized.
Pressure equalization is necessary before the standing valve can be removed
from the seating nipple. Standing valves are used primarily for setting hydraulicset
packers or for chamber lift applications.

Pump-out plugs

 Pump-out plugs are often used when it is necessary to place a plug in the
tubing string below the packer. These one-time usage plugs, placed beneath
the packer, hold the pressure necessary for hydraulic-set packers to be set.
When pressure is increased to a specific preset value shear pins are sheared,
allowing the ball and sleeve to be forced down and out of the tubing. Once the
ball has been pumped out, the device can serve as wireline re-entry guide and
has a full open bore for the production of fluids. Pump-out plugs are normally
used only in the long string of dual completions, or in single string completions.

Completion Packers lec ( 8 )

Production Packer

Types

There are several types of production packers. Several of the most common
types are identified below:

•  Retrievable mechanical packers
•  Hydraulic/hydrostatic set retrievable packers
•  Permanent seal bore packers
•  Retrievable seal bore packers

Mechanical Packers

Applications

 Mechanical packers represent the most common packers used in the oil field.
Mechanical packers are set and released by manipulation of the tubing string.
Tubing string rotation and the application of weight or tension at the packer
are required to set or release. Mechanical packers can be set or unset without
being removed from the well for redress.They are suitable for application in the
following general conditions:

• Shallow to medium setting depths
•  Low to moderately high pressures
•  Straight hole or moderate deviation

Types

 There are two basic types of Mechanical packers:

•  Single grip retrievable packers (Fig 5-1) which are set and packed

off with either tubing tension or compression. These packers require
the tension or compression force to be maintained in order for the
packer to remain set and packed off.

•  Double grip retrievable packers (Fig 5-2) which contain some

provision to prevent movement in either direction once the packer
is set. This type of packer may be further divided into two types:

1. Those utilizing hydraulic accuated slips (holddown buttons), to prevent upward movement of the packer once it is set.

     2. Those which are mechanically locked into the set and packed off position. Once locked, these packers remain set independent ofthe tubing and hydraulic forces.

Tension Set Retrievable
Mechanical Packers

Description 

Single grip tension set mechanical packers (Fig 5-3) are not commonly used
nowadays except for shallow low pressure applications. Most models of tension
set packers utilize a secondary shear release system, which allows the packer
to be released by pulling a predetermined amount of tension on the tubing in
case the packer cannot be released using normal procedures.
Generally, tension set mechanical packers are best suited for applications in
which the expected pressure differential is from below, such as shallow injection
or disposal wells.
The model SA-3 (Fig 5-3) and the model ‘T’ retrievable packers (Fig 5-4) are
examples of mechanical tension set packers. The SA-3 is a single grip type in
which the slips hold in one direction only and so the packer will only remain set
so long as a tubing tension is maintained on the packer. The model ‘T’ is an
example of a double grip type tension packer, in that once it is set with the
proper amount of tension, it locks in that position and will remain set and
packed off independent of tubing forces, so long as the shear valve of the
secondary release is not exceeded.

Benefits of
Mechanical Packers

To prevent accidental release or failure, it is essential that an appropriate packer
design be used with the correct compression or tension applied. The benefits
of a retrievable mechanical packers include the following:

•  Cost - Generally these packers require less initial investment
•  Repeated use - The setting mechanism enables the packer to be

set, released, moved and reset without removal and redressing
procedures.

•  Versatile - Packer may be used for a variety of applications including

service work.

Compression Set
Single Grip Retrievable
Mechanical Packers

Description

 Single grip compression set mechanical packers (Fig 5-5) generally utilize one
set of slips, that when activated, prevent the packer from moving down hole.
The continued application of tubing compression packs off the element system
which will remain packed off so long as sufficient compression force is
maintained.
Compression set packers are most suitable for applications in which the expected
pressure differential will be in favor of the annulus.
The model CA is an example of a very simple and basic compression set packer
suitable for shallow low pressure applications. The SR-2 (Fig 5-6) is an example
of a single grip compression set packer with a better element system plus an
equalizing system which makes it more suitable for higher pressure medium
depth applications. Compression set packers were once the most common
type of mechanical packer used, this type has been replaced in most completion
applications by the double grip type packers

Double Grip
Mechanical Packers

Description

 This type of retrievable packer has become the most common type of mechanical
set packers. Double grip mechanical packers are reliable and versatile packers
suitable for shallow to medium depth wells and applications where moderately
high pressures are expected.
Double grip packers are generally packed off with compression force. The
packer is unset with tubing manipulation. Most types of bi-directional packers
utilize a pressure equalizing system to prevent hydraulic problems when
releasing.
The SR-1 (Fig5-7) is an example of a mechanical double grip packer which
utilizes hydraulic upper slips. This type of packer must be set in compression
and tubing compression must be maintained. The hydraulic slips prevent the
packer from being forced up the well due to high pressures on the tubing side.
The SOT-1 (Fig5-8) is an example of a premium bi-directional retrievable packer.
The SOT-1 utilizes two sets of slips placed on either side of the elements. This
allows pressure differential forces across the elements to be taken directly by
the slips. This feature allows the packer to safely handle higher pressures than
other types of double grip packers which have both sets of slips below the
elements. The SOT-1 packer locks into the set position and once set, remains
locked independent of pressure and tubing forces.

Hydraulic Set
Retrievable Packers

Hydraulic and/or hydrostatic-set retrievable packers are set without mechanical
manipulation of the tubing. After the packer is run to depth, hydraulic pressure
is applied to the fluid in the tubing string to set the packer. Once set, the packer
is mechanically locked in the set position. Release mechanisms vary and are
generally right-hand rotation or straight-pull release.
Types of Hydraulic Set Retrievable Packers:

•  Single string differential set retrievable packer
•  Single string hydrostatic set retrievable packer
•  Selective set single string hydrostatic set retrievable packer
•  Dual string hydrostatic set retrievable packer
•  Multiple conduit hydraulic set retrievable packer

Operation 

During the setting operation, the string is temporarily plugged below the packer
to allow pressure to be applied to the setting mechanism. At a preset value,
shear pins are broken allowing the packer slips to be forced out to engage the
casing wall and the sealing elements are compressed. A ratchet mechanism
locks the slips and packing in the set position. The packer can be mechanically
released using either rotation or a straight pull. Most models cannot be reset
once released.
The tubing is plugged during the setting process by one of the following
methods:

•  Positive plug
•  Pump open plug
•  Pump out plug/ball
•  Standing valve

Applications

 Hydraulic set retrievable packers are suitable for application in the following
general conditions:

•  Shallow to medium depths
•  Low to medium pressure applications
•  Multiple packer single string completions
•  Dual string completions
•  Selective set multiple packer completions

Advantages

•  After the packer is set, energy is stored in the ratchet mechanism

that ensures continued force against the element seal and slips to
securing the packer. Therefore, packer setting is not dependent
upon applied tubing force.

•  Since the setting force is mechanically locked into the packer it is

capable of holding differential pressures or tubing forces from
above or below the packer.

•  This type of packer may be set after the wellhead has been installed.

•  Dual tubing string completions and multiple packer applications

generally utilize hydraulic set packers, which require no tubing
movement in the setting process.

Hydro Packers

Differential Set
Hydraulic Packers

This type of packer is set by using the force generated by tubing pressure
acting on a piston against annulus pressure. A specific amount of differential
pressure (in favor of the tubing) has to be applied to complete the setting. The
Hydro-6 packer (Fig 5-9) is an example of this type of hydraulic packer.
With the increased demand for subsurface instrumentation and electric or
hydraulic operated devices, a new type of hydraulic set packer has been
developed to fulfill the requirement for multiple conductors to pass through
the packer without compromising the packers integrity. The model ‘MPP’
hydraulic set packer is an example of this type of packer.

Hydrostatic Set
Hydraulic Packers

These packers utilizing a setting piston similar to differential set packers, but
all or part of the piston area is acting against a chamber containing atmospheric
pressure rather than annulus pressure. This allows the hydrostatic tubing
pressure to assist the setting of the packer. Less pressure is required to generate
a required force than with a hydraulic set Packer. This allows hydrostatic set
packers to have a larger mandrel size than hydraulic set packers
Hydrostatic set packers are more expensive to manufacture than the differential
set and are normally used when larger tubing sizes are required. For example, in
7" casing with 2 7/8 tubing, a differential set packer will work fine but if 3 ½”
tubing is required a hydrostatic packer would be used due to the reduced
piston area resulting from the larger packer mandrel.
The Hydro-8 single string (Fig 5-11) and the Hydro-10 dual string packers are
examples of hydrostatic set packers. The Hydro-8 is also available in a selective
set version as well. Selective setting allows several packers to be run in a
tubing string and each packer to be set independently of the others. The
setting mechanism in each packer is activated by wireline intervention.

Permanent Seal
Bore Packers

Description 

As the name implies, permanent seal bore packers are just that: permanent.
Once set they cannot be unset and if their removal is necessary it must be done
using milling equipment to cut the packer out. This is the main disadvantage of
this type of tool. However, this also allows for several features which are
advantages over retrievable packers.

•  incorporation of full 360º back-up on the packing element
•  elimination of complicated pressure equalizing systems and their

potential leak path

•  much greater slip coverage in the casing I.D.
•  easier and more economical to manufacture in high alloy materials

for hostile environment service

•  most models are suitable for high pressure application in wells of

any depth

•  allow use of larger tubing sizes

Seal bore packers are not designed to attach directly to the tubing as retrievable
packers are, but instead utilize a polished inside seal area into which a seal unit,
that is run as a part of the tubing string, seals into. This polished seal bore can
either be incorporated as a through bore in the packer or it can be incorporated
above the packer to accommodate larger inside seal diameters. Permanent seal
bore packers are run and set by one of the following three methods:

•  Application of hydraulic pressure to an integral setting mechanism
•  Application of hydraulic pressure to a separate recoverable and

reusable setting tool

•  Reusable wireline setting tool utilizing an explosive charge to

generate the setting force

Design

 Figure 5-14 illustrates a basic wireline set permanent seal bore packer showing
the main components of the packer in both the running and set positions.

Options

 Tubing-to-packer attachment and sealing in a seal bore packer is accomplished
using one of three basic seal assembly options.

•  Latched or No-Motion (Also known as an Anchor Seal)-

The tubing string is attached to the packer with a latching seal
assembly. The tubing is not free to move internally in the packer.
Forces on the tubing will be transmitted directly to the packer.
Such forces can result in failure of the top tubing joint (Fig 5-15).

•  Limited-motion (Landed)- The stinger is fitted with dynamic

seals and runs through the packers polished bore. This type of
seal assembly allows limited movement downward, and uses a nogo
diameter to prevent the seals from moving completely through
the packer bore. This is useful for situations where cooling of the
tubing string (injection of cold fluid) and allows contraction of the
string without placing excessive tension of the top joint (Fig 5-16).

•  Stung-through or Free-motion - This is useful in preventing

corkscrewing and tubing separations. The configuration is similar
to an expansion joint and provides some freedom of tubing
movement (Fig 5-17).


Applications

 Permanent seal bore packers are used in the following situations:

•  Medium or deep set applications
•  Deviated and extended reach wells
•  Multiple packer completions
•  Dual string completions with parallel flow tubes
•  Sump packer for gravel packer operations
•  Medium to high pressure application

Retrievable Seal
Bore Packers

Description

 Retrievable seal bore packers utilize a seal bore similar to the permanent seal
bore packers. Because they are designed to be retrievable most retrievable seal
bore packers have a lower pressure rating than permanent seal bore packers
and are generally more expensive. Retrievable seal bore packers are commonly
used in gravel pack operations as well as completions.
The retrievable seal bore packers utilize many of the same accessories such as
setting adapters, seal assemblies, etc. as the permanent packers. They also are
available in both wireline set versions and self contained hydraulic set versions.

Hydrogen production by natural gas with SRM process

Ceria-Based Materials for Hydrogen Production Via Hydrocarbon Steam
Reforming and Water-Gas Shift Reactions

Abstract: This review paper provides an overview of the use of ceria-based catalytic materials towards the industrial
hydrogen production via the hydrocarbon steam reforming and the water-gas shift reaction routes with a focus on
representative patenting activities mainly in the last 10 years. We first introduce the basic mechanisms of catalytic
hydrocarbon steam reforming and conversion of carbon monoxide by steam towards a mixture of carbon dioxide and
hydrogen at low and high temperatures, the main synthetic approaches of ceria material and its basic structural properties
responsible for its catalytic activity exhibited towards the present reactions. In the case of hydrocarbon steam reforming,
emphasis is given on the (i) sulphur tolerance of catalysts developed, (ii) efforts to reduce the reaction temperature, (iii)
use of the “Absorption Enhanced Reforming” concept, and (iv) its application in fuel cells for power generation. In the
case of water-gas shift reaction, progress in catalyst developments for low- and high- temperature applications is
discussed. Future directions in these fields have been suggested.
Keywords: hydrogen production, CeO2-based catalysts, steam reforming of hydrocarbons, water-gas shift, WGS, auto-thermal
reforming, ATR, absorption enhanced reforming, AER, fuel cell.

Life Cycle Assessment of
Hydrogen Production via
Natural Gas Steam Reforming

REVIEW OF SMALL STATIONARY
REFORMERS FOR
HYDROGEN PRODUCTION

This report to the International Energy Agency (IEA) reviews technical options for small-scale
production of hydrogen via reforming of natural gas or liquid fuels. The focus is on small
stationary systems that produce pure hydrogen at refueling stations for hydrogen-fueled
vehicles. Small reformer-based hydrogen production systems are commercially available from
several vendors. In addition, a variety of small-scale reformer technologies are currently being
developed as components of fuel cell systems (for example, natural gas reformers coupled to
phosphoric acid or proton exchange membrane fuel cell (PAFC or PEMFC) cogeneration
systems, and onboard fuel processors for methanol and gasoline fuel cell vehicles). Although
fuel cell reformers are typically designed to produce a “reformate” gas containing 40%-70%
hydrogen, rather than pure hydrogen, in many cases they could be readily adapted to pure
hydrogen production with the addition of purification stages.
As background, we first discuss hydrogen supply options for the transportation sector; both
“centralized” (e.g. hydrogen production at a large central plant with distribution to refueling
stations via truck or pipeline) and “distributed” (hydrogen production via small-scale reforming or
electrolysis at the refueling site). Several recent studies have suggested that distributed
hydrogen production via small-scale reforming at refueling stations could be an attractive nearto
mid-term option for supplying hydrogen to vehicles, especially in regions with low natural gas
prices.
A variety of reforming technologies that might be used in distributed hydrogen production at
refueling stations are reviewed. These include steam methane reforming (SMR), partial
oxidation (POX), autothermal reforming (ATR), methanol reforming, ammonia cracking and
catalytic cracking of methane. Novel reformer technologies such as sorbent enhanced
reforming, ion transport membranes, and plasma reformers are discussed. The performance
characteristics, development status, economics and research issues are discussed for each
hydrogen production technology.
Current commercial projects to develop and commercialize small-scale reformers are described.

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Production of hydrogen by steam reforming of methanol

Abstract

Binary Cu/ZnO catalysts (with a Cu/Zn atomic ratio of 50/50) prepared via a novel dry synthetic approach based on solid-state oxalate-precursor
synthesis were studied in regard to their performance in the steam reforming of methanol (SRM). The synthesis route involves facile solid-phase
mechanochemical activation of a physical mixture of simple copper/zinc salts and oxalic acid, followed by calcination of the as-ground oxalate
precursors at 350 ◦C. For comparison, their conventional analogues obtained by aqueous coprecipitation techniques were also examined. Structural
characterization of the samples was performed by means of N2 adsorption, X-ray diffraction (XRD), diffuse reflectance infrared Fourier transform
spectroscopy (DRIFTS), thermal gravimetric and differential thermal analysis (TG/DTA), scanning electron microscopy (SEM), temperatureprogrammed
reduction (H2-TPR), N2O titration, and X-ray photoelectron spectroscopy (XPS). The results show that the grinding-derived Cu/ZnO
catalysts exhibit superior SRM performance to their conventional counterparts obtained by wet-chemical methods. The enhanced performance of
the grinding-derived catalysts can be attributed to a higher copper dispersion as well as the beneficial generation of highly strained Cu nanocrystals
in the working catalyst. It is proposed that the present soft reactive grinding route based on dry oxalate-precursor synthesis can allow the generation
of a new type of Cu/ZnO materials with favorable surface and structural properties, providing an attractive alternative for preparation of improved
heterogeneous catalysts.

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Completion Components lec ( 7 )

Introduction 

The selection of completion equipment and hardware is based on the reservoir,
field, wellbore and operational requirements that will achieve efficient, safe and
economic production.
There are many types of components available, each of which may be specified
in a number of service or dimensional variations, (e.g. H2S or normal service).
Principal completion components are categorized as follows:

•  Production packers
•  Gas lift equipment
• Safety valves
•  Tubing flow control equipment
•  Permanent
•  Retrievable
•  Completion accessories

Production Packers 

The packer is often considered the most important downhole tool in the
production string. Completion packer types vary greatly and are typically
designed to meet specific wellbore or reservoir conditions, (e.g., single or
tandem packer configurations, with single, dual and triple completion strings).
Production packers can have several functions. However, the principal function
of a packer is to provide a means of sealing the tubing string from the casing or
liner. This seal must provide a long-term barrier compatible with reservoir
fluids or gasses and the wellbore annular fluid.
The production packer must also enable efficient flow from the producing (or
injection) formation to the tubing string or production conduit.

Downhole Anchor

 A secondary, but nonetheless important function of most packers is to provide
a downhole anchor for the tubing string. However, cup or isolation packers do
not anchor the tubing stringcontinued next However cup or isolation packers,
do not anchor the tubing string.

Subsurface Safety Valve

These hydraulically operated tubing flow control valves are used offshore, in
critical locations (next to a school or home) and areas of concern of the
environment, the reservoir, the facilities and the personel.

Gas Lift

Sidepocket mandrels with dummy valves are run in new free flowing completions
where workover costs are high and the reservoir will require artificial lift to
deplete.

Tubing Flow Control Equipment

This equipment expands the value of the completion by introducing flexibility.
Nipples, sleeves, plugs, chokes, test tools, standing valves, bomb hangers,
etc. could be utilized.

Casing String
Protection Example

For Casing
String Protection.

In most wellbores, the casing string or liner is a permanent component of the
completion system. Since casing replacement or repair procedures are
complicated and expensive, systems are designed (using packers) to protect
the casing from pressure differentials and corrosive conditions. The packer
and tubing string is typically easier to repair and/or replace than the casing
system.

Formation Safety
Control Example

For Downhole Formation
Safety Control


High Pressure gas and fluids are generally encountered at some depth. In the
absence of heavy completion fluids, a packer provides an effective means of
isolation. The high pressure can then be controlled by subsurface safety
valves in the tubing string attached to the packer. This also enables some
control of pressure on the wellhead. By inserting a tubing plug in the packer,
creating a temporary bridge plug, workover work above the packer can be
carried out with a greater degree of safety.

Multiple Zone
Completion Examples

For Zone Separation

 In multiple zone completions, it is generally necessary to separate the producing
zones for the following reasons:

•  Legality - Government regulations monitor produced flow-rates as

allowable production. Often each production zone must be isolated,
which is more easily accomplished through the use of a packer.

•  Control of formation fluids - Frequently, high and low pressure

zones are encountered. Packers are used to prevent cross flow of
reservoir fluids.

Artificial Lift Example
To Facilitate
Artificial Lift

When using gas lift to enhance production, a packer is utilized to separate
the produced fluid pathway from the injected gas pathway down the
annulus. Packers are often used with ESP’s to facilitate control of well zones.
Tubing anchors are commonly used to increase the efficiency of rod pumps.
Anti-rotational anchors are commonly used with progressive cavity pumps.

Remedial and
Repair Examples

To Facilitate
Remedial / Repair Work


In situations where casing is damaged, two packers can be used to seal off and
bypass the damaged area. With the use of accessory completion equipment,
such as stingers and on-off attachments, tubing can be pulled for repair and/or
replacement without releasing the packer.

Completion course

Tubulars con't lec ( 6 )

High Strength
Tubing Failure

Failures of high-strength tubing are normally caused by:

•  Manufacturing defects
•  Handling/transportation damage
•  Hydrogen embrittlement

API Tubing
Connections

There are two standard API coupling tubing connections available:

The API EUE type of connection is available in 23/8”, 27/8”, 31/2” and 41/2”.

Extra Clearance

 It is occasionally necessary to provide extra clearance to enable tubing
installation. To accommodate this, API couplings can be turned down (to
specified tolerances) without loss of joint strength. Special clearance collars
are usually marked with a black ring in the center of the color band indicating
steel grade. Extra-clearance, coupling-type thread forms have been developed
for non-upset tubing which have 100% joint strength.
Integral-joint premium threads provide additional clearance and are available
in a number of configurations. Some can be turned down to provide even
greater clearance. This type of joint is more expensive and is generally used in
special situations (high-pressure or gas well application).

Premium Tubing
Connections

In addition to the standard API connections, there are a wide variety of specific
joint connections available usually referred to as premium connection. Most
premium connections use a metal-to-metal seal which requires that the mating
pin and box surfaces are forced together with sufficient stress to establish a
bearing pressure greater than the differential pressure across the connection.
The bearing pressure (Pb) is defined as the pressure exerted between the metal
surfaces created by the torque used at make-up.
Premium connections are available in a wide variety of types, weights and
materials

Connection Seals

 Round thread connections form several metal-to-metal seals between the tapered
portions of pin and box surfaces. The small void between the crest and root of
the mating threads must be filled with thread compound solids in order to
transmit adequate bearing pressure from one threaded surface to another.
Some connections (e.g., HYDRIL) have large smooth metal-to-metal
connections. The threads in this type of connection have a relatively large
clearance and do not act as seals. Threads like Armco Seal Lock have both a
sealing thread and a smooth metal scaling surface (Fig. 10). A Teflon ring is
used in some premium connections to provide a supplementary seal and provide
corrosion protection.
The stresses applied during make-up and subsequent service determine the
success of the connection seal. When compiling tubular make-up procedures
the minimum, optimum and maximum torque for each connection type must be
known.

Basic String Design
and Selection

When selecting completion components, consider the factors shown below.
This of course is in addition to the basic efficiency, safety and economic
requirements of all completions.

•  Facilitate installation
•  Optimize production
•  Simplify maintenance
•  Enable stimulation or workover
•  Provide for contingency

Tubular
Design Factors

The basic string design and selection process should take into
account the following guidelines before detailed planning is begun:

Drift Inspection

 Before running in the hole, drift the tubing with an API drift mandrel to ensure
the internal clearance is within tolerance.
Handle all tubing (new, used or reconditioned) with thread protectors in place.
Do not remove the thread protectors until the tubing is ready to be stabbed.
High-strength tubing is particularly susceptible to damage caused by improper
shipping and handling practices.

Measurement

 When running tubing and completion components, careful measurement of
each joint or item is essential. Each measurement is recorded in a tally book
against the joint number which should be clearly marked on each joint. The
tape used is divided into feet and decimal fractions, (e.g., the reading for 20 ft.,
6 in., would be read as 20.5 ft.).
Tubing joints (and other string components) are measured from the box end to
the beginning of the threads on the pin end (not the end). Record completion
components on a separate sheet of the tally book. The length, OD, grade and
ID are listed as appropriate for each component.
When the grade and size of pipe has been chosen, details of the following
points should be made known to field personnel:

•  Handling - Tubing, especially high grade tubing (P-105, etc.)

must be handled carefully without dropping, denting, or nicking.

•  Torque - Too loose or too tight make-up on a joint connection

can result in failure.

•  Record (Tally) keeping - Accurate measuring and recording of

tubulars and placement of downhole components is essential. A
packer accidentally placed below the perforated interval is a prime
example of mis-measuring or miscounting tubing joints.

Running the
Tubing String

NOTE: Use PPE equipment.

Formulas and Calculations for Drilling, Production, and Workover Second Edition Norton J. Lapeyrouse free download

CONTENTS

PREFACE .................................................. vii
1 BASIC FORMULAS ...................................... .1
Pressure Gradient 1. Hydrostatic Pressure 3. Converting Pressure into
Mud Weight 4. Specific Gravity 5. Equivalent Circulating Density 6.
Maximum Allowable Mud Weight 7. Pump Output 7. Annular
Velocity 9. Capacity Formulas 12. Control Drilling 19. Buoyancy
Factor 20. Hydrostatic Pressure Decrease When Pulling Pipe out of
the Hole 20. Loss of Overbalance Due to Falling Mud Level 22.
Formation Temperature 24. Hydraulic Horsepower 25. Drill Pipe/Drill
Collar Calculations 25. Pump Pressure/Pump Stroke Relationship 27.
Cost per Foot 28. Temperature Conversion Formulas 29.
2 BASIC CALCULATIONS ................................. .31
Volumes and Strokes 3 1. Slug Calculations 33. Accumulator
Capacity 37. Bulk Density of Cuttings 41. Drill String Design
(Limitations) 42. Ton-Mile Calculations 44. Cementing Calculations 47.
Weighted Cement Calculations 53. Calculations for the Number of
Sacks of Cement Required 54. Calculations for the Number of Feet to
Be Cemented 57. Setting a Balanced Cement Plug 61. Differential
Hydrostatic Pressure Between Cement in the Annulus and Mud Inside
the Casing 65. Hydraulicing Casing 66. Depth of a Washout 70. Lost
Returns-Loss of Overbalance 7 1. Stuck Pipe Calculations 72.
Calculations Required for Spotting Pills 75. Pressure Required to
Break Circulation 79.
3 DRILLING FLUIDS ....................................... 81
Increase Mud Density 81. Dilution 85. Mixing Fluids of Different
Densities 86. Oil-Based Mud Calculations 87. Solids Analysis 91. Solids
Fractions 95. Dilution of Mud System 96. Displacement-Barrels of
Water/Slurry Required 97. Evaluation of Hydrocyclone 97. Evaluation
of Centrifuge 99.
4 PRESSURE CONTROL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .lo3
Kill Sheets and Related Calculations 103. Prerecorded
Information 115. Kick Analysis 124. Pressure Analysis 137.
Stripping/Snubbing Calculations 139. Subsea Considerations 144.
Workover Operations 153. Controlling Gas Migration 157. Gas
Lubrication 159. Annular Stripping Procedures 161.
5 ENGINEERING CALCULATIONS . . . . . . . . . . . . . . . . . . . . . . . . . .165
Bit Nozzle Selection-Optimized Hydraulics 165. Hydraulics
Analysis 169. Critical Annular Velocity and Critical Flow Rate 173.
“d” Exponent 174. Cuttings Slip Velocity 175. Surge and Swab
Pressures 179. Equivalent Circulation Density 187. Fracture Gradient
Determination-Surface Application 190. Fracture Gradient
Determination-Subsea Application 194. Directional Drilling
Calculations 197. Miscellaneous Equations and Calculations 203.
APPENDIXA .............................................. 209
APPENDIX B .............................................. 217
INDEX .................................................... 221
vi


PREFACE

Over the last several years, hundreds of oilfield personnel have told me that
they have enjoyed this book. Some use it as a secondary reference source:
others use it as their primary source for formulas and calculations; still others
use it to reduce the volume of materials they must carry to the rig floor or
job site.
Regardless of the reason people use it, the primary purpose of the book
is to provide a convenient source of reference to those people who don’t use
formulas and calculations on a regular basis.
In the preface to the first edition, I made reference to a driller who carried
a briefcase full of books with him each time he went to the rig floor. I also
mentioned a drilling supervisor who carried two briefcases of books. This
book should reduce the number of books each of them needs to perform
his job.
This book is still intended to serve oilfield workers for the entirety of their
careers. I have added several formulas and calculations, some in English field
units and some in Metric units. I have also added the Volumetric Procedure,
the Lubricate and Bleed Procedure (both Volume and Pressure Method), and
stripping procedures (both the Strip and Bleed Procedure and the Combined
Stripping and Volumetric Procedure).
This book has been designed for convenience. It will occupy very little
space in anyone’s briefcase. It has a spiral binding so it will lay flat and stay
open on a desk. The Table of Contents and the Index make looking up formulas
and calculations quick and easy. Examples are used throughout to
make the formulas as easy as possible to understand and work, and often
exact words are used rather than symbols.
This book is dedicated to the thousands of oilfield hands worldwide who
have to use formulas and calculations, whether on a daily basis or once or
twice a year, and who have problems remembering them. This book should
make their jobs a little easier.

download from here

Tubulars lec ( 5 )

Introduction

The design of an efficient, safe and economical completion system is dependent
upon the acquisition of accurate data and the selection of appropriate
components. Since the ultimate success of the completion system is dependent
on its successful installation, the installation procedures should also be given
some consideration.
Completion designs will vary significantly with the variation of the following
reservoir and location characteristics:

•  Gross production rate
•  Well pressure and depth
•  Formation properties
•  Fluid properties
•  Well location
•  Existing stock

Completion Equipment
Selection

As with all downhole components, data on completion components must include
full details of dimensions, profiles and connections. This is a basic requirement
of all downhole equipment, but is of special significance in completion design
and installation since many future well service activities will require throughtubing
access.

Basic Dimensional Data

•  Length (depth)

•  ID/OD (internal & external diameters)

•  Thread type

Tubular Components

When completing a well, the proper selection of tubular components is possibly
one of the most important decisions. Tubular components come in a number of
different grades and diameters and several factors must be considered prior to
selection.
The higher formation pressures encountered in recent years requires tubing
and components have a greater yield strength. In addition, improved sealing
mechanisms at connections are also required. The types of connections
available have also increased. Those involved with completion design and
installation must understand the proper application of common tubing and
component types. Similarly, a good working knowledge of common seals and
connections is necessary.

Inspection Procedures

A critical part of any well completion operation is the inspection of components
prior to final assembly and installation. Completion specialists and supervisors
must be aware of necessary inspection procedures, as well as the basic handling
procedures for each completion component.

Tubing String
Specification

Tubing generally provides the primary conduit from the producing interval to
the wellhead production facilities. Therefore, the proper selection, design and
installation of tubing is a very important part of any completion system.

Tubing Length 

Tubing joints vary in length from 18 to 35 feet although the average tubing
joint is approximately 30 feet. In any tubing shipment the joint length will vary,
so accurate measurement of each joint is essential. Pup joints (for spacing out
the string) are available in shorter lengths (2’ - 20’) in 2’ increments.

Tubing Diameter

Tubing is available in a range of OD sizes. The most common sizes are 23/8", 27/8",
31/2" and 41/2" (51/2", 7" and 95/8" tubing is fairly common in some areas e.g., the
North Sea). The API defines tubing as pipe from 1" to 41/2" OD. Larger
diameter tubulars being termed casing (41/2" to 20").

Tubing Construction 

Most types of tubing joint are threaded on each end (pin end) and connected
by couplings (box). The pipe used for production tubing may be manufactured
by one of two methods

Tubing Classification
Criteria

The following criteria are used to classify or specify tubing string material and
joint construction:

API Tubing Grades 

Much of the tubing used is manufactured according to API specifications and
must undergo a wide variety of tests and checks before shipment and
installation.
Standard API steel grades for tubing are J-55, C-75, L-80, C-95, N-80, P-105 and
V-150. Grades C-75, L-80 and C-95 are intended for hydrogen sulfide service
where higher strength than J-55 is required.
NOTE: L-80 may be 4130/4140 LHT material, 9Cr LHT, or 13Cr material.

Color Bands

The grade of new tubing can be identified by color bands:

High Strength
Tubing

High strength tubing is generally considered to include grades with a yield
strength above 80,000 psi. C-75, L-80 and N-80 are often included because
their as-manufactured yield strength often exceeds 80,000 psi. High strength
tubing, particularly P-105, presents an increased sensitivity to sharp notches
or cracks.
Any sharp-edged notch or crack in the surface of a material is a point of stress
concentration which tends to extend the crack progressively deeper into the
material, much like driving a wedge. Low strength materials are soft and ductile
and will yield plastically to relieve the stress concentration. High strength
materials do not yield to relieve the stress concentration and tend to fatigue or
fail more rapidly when subjected to cyclic stresses.

Maximum Allowable
Stress

Calculation of the maximum allowable stress of a certain pipe is carried out by
multiplying the minimum cross sectional area of the pipe, times the minimum
yield strength rating of the pipe

Well Completion Planning con't lec ( 4 )

Drilling

Drilling and associated operations, (e.g., cementing), performed in the pay
zone must be completed with extra vigilance. It is becoming increasingly
accepted that the prevention of formation damage is easier and much more
cost effective, than the cure. Fluids used to drill, cement or service the pay
zone should be closely scrutinized and selected to minimize the likelihood of
formation damage.

Evaluation

Similarly, the acquisition of accurate data relating to the pay zone is important.
The basis of several major decisions concerning the technical feasibility and
economic viability of possible completion systems will rest on the data obtained
at this time.

Pre-Completion

 A precompletion stimulation treatment is frequently conducted. This is often
part of the evaluation process in a test-treat-test program in which the response
of the reservoir formation to a stimulation treatment can be assessed..

Completion Assembly
and Installation

With all design data gathered and verified, the completion component selection,
assembly and installation process commences. This phase carries importance
since the overall efficiency of the completion system depends on proper
selection and installation of components.
A “visionary” approach is necessary since the influence of all factors must be
considered at this stage, i.e., factors resulting from previous operations or
events, plus an allowance, or contingency, for factors which are likely or liable
to affect the completion system performance in the future.
The correct assembly and installation of components in the wellbore is as
critical as the selection process by which they are chosen. This is typically a
time at which many people and resources are brought together. The demands
brought by high and mounting, daily charges imposes a sense of urgency
which requires the operation to be completed without delay. To ensure the
operation proceeds as planned, it is essential that detailed procedures are
prepared for each stage of the completion assembly and installation. The
complexity and detail of the procedure is largely dependent on the complexity
of the completion.

Primary Completion
Components
Primary completion components

 are considered essential for the completion to
function safely as designed. Such components include the safety valves, gas
lift equipment, tubing flow control tools and packers. In special applications,
(e.g., artificial lift), the components necessary to enable the completion system
to function as designed will normally be considered primary components.

Completion System 

Several types of devices, with varying degrees of importance, can be installed
to permit greater flexibility of the completion. While this is generally viewed as
beneficial, a complex completion will often be more vulnerable to problems or
failure, (e.g., due to leakage).
The desire for flexibility in a completion system stems from the changing
conditions over the lifetime of a well, field or reservoir. For example, as the
reservoir pressure depletes, gas injection via a side pocket mandrel may be
necessary to maintain optimized production levels. The selection of completion
components and fluids should reflect a balance between flexibility and simplicity.

Completion Assembly
and Installation Factors

Completion Fluids

A significant fluid sales and service industry has evolved around the provision
of completion fluids. Completion fluids often require special mixing and hauling
procedures, since (a) the level of quality control exercised on density and
cleanliness is high and (b) completion fluids are often formulated with
dangerous brines and inhibitors.

Initiating Flow

The process of initiating flow and establishing communication between the
reservoir and the wellbore is closely associated with perforating operations. If
the well is to be perforated overbalanced, (higher pressure in the wellbore than
in the formation) then the flow initiation and clean up program may be dealt
with in separate procedures. However, if the well is perforated in an
underbalanced condition, (lower pressure in the wellbore than in the formation)
the flow initiation and clean up procedures must commence immediately upon
perforation.Production Initiation

Underbalanced
Perforating

Perforating when the reservoir pressure is substantially higher than the wellbore
pressure is referred to as under-balanced perforating. While the reservoir/
wellbore pressure differential may be sufficient to provide an underbalance at
time of perforation, the reservoir pressure may be insufficient to cause the well
to flow after the pressure has equalized.
Adequate reservoir pressure must exist to displace the fluids from within the
production tubing if the well is to flow unaided. In the event the reservoir
pressure is insufficient to achieve this, measures must be taken to lighten the
fluid column typically by gas lifting or circulating a less dense fluid.
The flow rates and pressures used to exercise control during the clean up
period are intended to maximize the return of drilling or completion fluids and
debris. This controlled backflush of perforating debris or filtrate also enables
surface production facilities to reach stable conditions gradually.

Wellbore Clean Up

Wellbore cleanup is normally not required with new completions. However, in
wells which are to be re-perforated or in which a new pay zone is to be opened,
a well bore clean up treatment may be appropriate. There is a range of perforation
treatments associated with new or recompletion operations.

Overbalanced
Perforating

Perforating when the wellbore pressure is higher than the reservoir pressure is
referred to as Overbalanced Perforating. This is normally used as a method of
well control during perforating. The problem with this method is it introduces
wellbore fluid into the formation causing formation damage.
It is sometimes desirable to place acid across the interval to be perforated when
overbalanced perforating. The resulting inflow of acid results is a matrix type
acid treatment occurring.

Extreme Overbalance
Perforating

In this type of perforating operation the wellbore is pressured up to very high
pressures with gas (usually nitrogen). When the perforating guns are detonated
the inflow of high pressure gas into the formation results in a mini-frac, opening
up the formation to increase inflow.

Stimulation Treatments

Acid Washing
of Perforations

Perforation acid washing is an attempt to ensure that as many perforations as
possible are contributing to the flow from the reservoir. Rock compaction, mud
and cement filtrate and perforation debris have been identified as types of
damage which will limit the flow capacity of a perforation and therefore,
completion efficiency.
If the objective of the treatment is to remove damage in or around the
perforation, simply soaking acid across the interval is unlikely to be adequate.
The treatment fluid must penetrate and flow through the perforation to be
effective. In which case all the precautions associated with a matrix treatment
must be exercised to avoid causing further damage by inappropriate fluid
selection.

Hydraulic Fracturing

Hydraulic fracturing treatments provide a high conductivity channel through
any damaged area and extending into the reservoir. The natural fractures
within the formation material are opened up using hydraulic fluid pressure.
Commonly a proppont such as sand is introduced to ‘prop’ the fracture open
after the pressure is removed, but still will allow flow of reservoir fluids and
gases. Hydraulic fracturing treatments require a detailed design process which
is usually performed by the service supplier.

Well Service
and Maintenance
Requirements

The term “well servicing” is used (and misused) to describe a wide range of
activities including:

•  Routine monitoring
•  Wellhead and flowline servicing
•  Minor workovers (through-tubing)
•  Major workovers (tubing pulled)
•  Emergency containment or response

Well service and maintenance preferences and requirements must be considered
during the completion design process. With more complex completion systems,
the availability and response of service and support systems must also be
considered.
Well bore geometry and completion dimensions determine the limitations of
conventional slick line, wireline, coiled tubing or snubbing services in any
application.

Logistic and
Location Constraints

Restraint imposed by logistic or location driven criteria often compromise the
basic cost effective requirement of a completion system. Special safety and
contingency precautions or facilities are associated with certain locations,
(e.g., offshore and subsea).

Logistic and
Location Criteria

Client Requirements

The completion configuration and design must ultimately meet all requirements
of the client. In many cases, these requirements may not be directly related to
the reservoir, well or location (technical factors). An awareness of these factors
and their interaction with other completion design factors can help save time
and effort in an expensive design process.
The following factors are common criteria which must be considered:

•  Existing stock or contractual obligation
•  Compatibility with existing downhole or wellhead components
•  Client familiarity and acceptance
•  Reliability and consequences of failure

Regulatory Requirements

There are several regulatory and safety requirements applicable to well
completion operations. These must satisfied during both the design and
execution phases of the completion process.

•  Provision for well-pressure and fluid barriers
•  Safety and operational standards
•  Specifications, guidelines and recommendations
•  Disposal requirements

•  Emergency and contingency provision

Revenue and Costs

When completing an economic viability study, or comparison, the costs
associated with each of the following categories must be investigated.

•  Production revenue
•  Capital cost (including completion component and installation cost)
•  Operating cost (including utilities and routine maintenance or

servicing cost, also workover, replacement or removal cost)
Installation costs are significant if special completion requirements impact the
overall drilling or completion time. The actual cost of completion components
is often relatively insignificant when viewed alongside the value of incremental
production from improved potential or increased uptime.

Economic Factors

A rudimentary understanding of the economic factors is beneficial.

•  Market forces (including seasonal fluctuations and swing

production)

•  Taxation (including tax liability or tax breaks)
•  Investment availability

Company Objectives

A measure of success can only be made if there exists clearly stated objectives.
Such objectives may macroscopic, but nonetheless will influence the specific
objectives as applied to an individual well or completion. In addition, the wider
company objectives may allow clarification of other factors, (e.g., where two or
more options offer similar or equal benefit and no clear selection can be made
on a technical basis).

•  Desired payback period
•  Cash flow
•  Recoverable reserves