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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