Gas-Lift Automation
API RECOMMENDED PRACTICE 19G12 (RP 19G12)
DRAFT #5, July 3, 2010
American Petroleum Institute
1220 L. Street, Northwest
Washington, DC 20005
API
Issued by
AMERICAN PETROLEUM INSTITUTE
Production Department
FOR INFORMATION CONCERNING TECHNICAL CONTENTS OF
THIS PUBLICATION CONTACT THE API PRODUCTION DEPARTMENT,
2535 ONE MAIN PLACE, DALLAS, TX 75202 - (214) 748-3841.
SEE BACK COVER FOR INFORMATION CONCERNING
HOW TO OBTAIN ADDITIONAL COPIES OF THIS PUBLICATION.
Users of this publication should become familiar with its scope
and content. This publication is intended to supplement rather
than replace individual engineering judgement.
Official Publication
API
Reg. U.S. Patent Office
Copyright @ l993 American Petroleum Institute
API RP 19G12
Gas-Lift Automation
Page 1
Foreword
This Recommended Practice (RP) is under the jurisdiction of the API Committee on
Standardization of Production Equipment (Committee 19).
This document presents Recommended Practices for Gas-Lift Automation. Other API
Specifications, API Recommended Practices, and Gas Processors Suppliers Association
(GPSA) documents may be referenced and should be used for assistance in design and
operation of a gas-lift automation system.
API Recommended Practices may be used by anyone desiring to do so, and diligent effort
has been made by the Institute to assure the accuracy and reliability of the data contained
therein. However, the Institute makes no representation, warranty, or guarantee in
connection with the publication of any API Recommended Practice and hereby expressly
disclaims any liability or responsibility for loss or damage resulting from their use, for any
violation of any federal, state, or municipal regulation with which an API Standard may
conflict, or for the infringement of any patent resulting from the use of an API
Recommended Practice or Specification.
Note:
This is the first edition of this recommended practice.
Requests for permission to reproduce or translate all or any part of the material
published herein should be addressed to the Director, American Petroleum Institute, 1220
L Street NW, Washington DC 20005-4070
This Recommended Practice shall become effective on the date printed on the cover but may be
used voluntarily from the date of distribution.
API RP 19G12
Gas-Lift Automation
Page 2
Policy
API PUBLICATIONS NECESSARILY ADDRESS PROBLEMS OF A GENERAL NATURE.
WITH RESPECT TO PARTICULAR CIRCUMSTANCES, LOCAL, STATE, AND FEDERAL
LAWS AND REGULATIONS SHOULD BE REVIEWED.
API IS NOT UNDERTAKING TO MEET THE DUTIES OF EMPLOYERS, MANUFACTURERS,
OR SUPPLIERS TO WARN AND PROPERLY TRAIN AND EQUIP THEIR EMPLOYEES, AND
OTHER EXPOSED PERSON, CONCERNING HEALTH AND SAFETY RISKS AND
PRECAUTIONS, NOR UNDERTAKING THEIR OBLIGATIONS UNDER LOCAL, STATE, OR
FEDERAL LAWS.
NOTHING CONTAINED IN ANY API PUBLICATION IS TO BE CONSTRUED AS GRANTING
ANY RIGHT, BY IMPLICATION OR OTHERWISE, FOR THE MANUFACTURE, SALE, OR USE
OF ANY METHOD, APPARATUS, OR PRODUCT COVERED BY LETTERS PATENT.
NEITHER SHOULD ANYTHING CONTAINED IN THE PUBLICATION BE CONSTRUED AS
INSURING ANYONE AGAINST LIABILITY FOR INFRINGEMENT OF LETTERS PATENT.
GENERALLY, API STANDARDS ARE REVIEWED AND REVISED, REAFFIRMED, OR
WITHDRAWN AT LEAST EVERY FIVE YEARS. SOMETIMES A ONE-TIME EXTENSION OF
UP TO TWO YEARS WILL BE ADDED TO THIS REVIEW CYCLE. THIS PUBLICATION WILL
NO LONGER BE IN EFFECT FIVE YEARS AFTER ITS PUBLICATION DATE AS AN
OPERATIVE API STANDARD OR, WHERE AN EXTENSION HAS BEEN GRANTED, UPON
REPUBLICATION. STATUS OF THE PUBLICATION CAN BE ASCERTAINED FROM THE API
AUTHORING DEPARTMENT (TEL. 214-220-911 1). A CATALOG OF API PUBLICATIONS
AND MATERIALS IS PUBLISHED ANNUALLY AND UPDATED QUARTERLY BY API, 1220 L
ST., N.W., WASHINGTON, D.C. 20005.
API RP 19G12
Gas-Lift Automation
Page 3
Recommended Practices for
Gas-Lift Automation
API RP 19G12
Forward

This publication is intended to provide recommended practices for the use of gas-lift
automation to enhance the functionality and profitability of gas-lift operations for the
production of oil and gas.

This publication is under the jurisdiction of the API Committee on Recommended Practices
for use of Production Equipment.

American Petroleum Institute (API) Recommended Practices are published as aids for the
use of equipment and materials by operating companies, as instructions to manufacturers of
equipment and materials, and as instructions to manufacturers of equipment or materials
covered by an API Specification. These Recommended Practices are not intended to obviate
the need for sound engineering practice, nor to inhibit in any way anyone from using,
purchasing, or producing products to other specifications.

The formulation and publication of API Recommended Practices, Specifications, and the API
monogram program are not intended in any way to inhibit the purchase or use of products
from companies not licensed to use the API monogram.

API Recommended Practices and Specifications may be used by anyone desiring to do so,
and diligent effort has been made by the Institute to assure the accuracy and reliability of the
data contained therein. However, the Institute makes no representation, warranty, or
guarantee in connection with the publication of any API Recommended Practice or
Specification and hereby expressly disclaims any liability or responsibility for loss or damage
resulting from their use, for any violation of any federal, state, or municipal regulation with
which an API Recommended Practice or Specification may conflict, or for the infringement of
any patent resulting from the use of an API Specification.

Any manufacturer producing equipment or materials represented as conforming with an API
Specification is responsible for conforming with all the provisions of that Specification. The
American Petroleum Institute does not represent, warrant, or guarantee that such products
do in fact conform to the applicable API standard or specification.
This Recommended Practice shall become effective on the date printed on the cover but may be
used voluntarily from the date of distribution.
Attention Users of This Publication: Portions of this publication may have been changed from the
previous edition. In some cases the changes may be significant, while in other cases the changes
may reflect minor editorial adjustments.
Note:
This is the first edition of this recommended practice.
API RP 19G12
Gas-Lift Automation
Page 4
Requests for permission to reproduce or translate all or any part of the material published herein
should be addressed to the Director, American Petroleum Institute, Production Department, 2535
One Main Place, Dallas, TX 75202.
API RP 19G12
Gas-Lift Automation
Page 5
Introduction
This API recommended practice provides guidelines and tools to facilitate the effective and efficient
design, operation, optimization, and troubleshooting of gas-lift wells and systems when using automation
systems.
As used in this document, gas-lift automation includes any use of instruments, controls,
communications, computer hardware, computer software, databases, and other computer tools that are
intended to monitor, control, provide surveillance, detect problems, diagnose the cause of problems,
solve problems, and optimize the operation of gas-lift systems for production of oil and gas.
This document may be used as a guide for designing gas-lift automation systems, and as an aide in
providing training in how to design, operate, optimize, and troubleshoot these systems.
API RP 19G12
1.
Gas-Lift Automation
Scope
The scope of this document addresses the following topics:





















Production automation definition.
Overview of gas-lift automation.
Fields that need to be served by gas-lift automation.
Objectives of gas-lift automation.
Methods of using gas-lift automation.
Gas-lift automation business drivers.
Instrumentation and controls for gas-lift automation.
Communication equipment and systems.
Computer automation hardware.
Computer automation software.
Normal automation applications.
Special automation applications.
o Continuous single string gas-lift.
o Continuous dual gas-lift.
o Intermittent gas-lift.
o Gas-lift of gas wells.
Gas-lift database systems.
Gas-lift optimization capabilities.
Benefits of gas-lift automation.
Risks.
Justification of automation systems.
Staffing required.
Training required.
Case histories of automation successes.
Case histories of automation failures.
This document does not include information provided in the documents listed in the
Normative Reverences in the next section of this document, nor in the Informative
References which are listed in the Bibliography.
This document does not recommend any specific automation hardware, automation
software, or automation service/supply companies.
Page 6
API RP 19G12
2.
Gas-Lift Automation
Page 7
Normative References
Normative (required) references used in this document include:
API RP 11V5, Operation, Maintenance, Surveillance, and Troubleshooting Of GasLift Installations
API RP 11V8, Recommended Practice for Gas Lift System Design and Performance
Prediction
API RP 19G9, Recommended Practice for Design, Operation, and Troubleshooting of
Dual Gas-Lift Wells (document being published by API)
API RP 11V10, API Recommended Practice for Design and Operation of Intermittent
and Chamber Gas-Lift Wells and Systems
API RP 19G11, Recommended Practices for Dynamic Simulation of Gas-Lift Wells
and Systems (document ready for Work Group and Task Group review)
API RP 19G13, Recommended Practice for High Pressure and Sub-Sea Gas-Lift
(document currently being drafted)
API RP 19G12
Gas-Lift Automation
3. Terms and Definitions
Terms and definitions used in the document are listed here.
3.n
gas-lift automation
The process of using instruments, controls, and automation hardware and software to
automate some or all of the functions of gas-lift date acquisition, control, problem
detection and diagnosis, and optimization.
3.n
gas-lift, continuous
Gas-lift gas is injected into an oil or gas well at a continuous rate.
3.n
gas-lift, dual
There are two completions (two tubing strings) in the same wellbore, and they are both
on gas-lift at the same time.
3.n
gas-lift, intermittent
Gas-lift gas is injected into an oil or gas well on an intermittent rather than a continuous
basis.
3.n
gas-lift, single
There is one completion (one tubing string) in the wellbore, and it is on gas-lift.
3.n
host computer system
A computer system that provides data processing, centralized control logic, centralized
optimization logic, information access for operating staff, and may provide information
transmission to other computer systems such as corporate systems, databases, etc.
3.n
recommendation
Expression in the content of a document conveying that among several possibilities one
is recommended as particularly suitable, without mentioning or excluding others, or that a
certain course of action is preferred but not necessarily required, or that (in the negative
form) a certain possibility or course of action is disapproved of but not prohibited.
Page 8
API RP 19G12
4.
Gas-Lift Automation
Symbols and Abbreviations
Symbols and abbreviations used in the document are listed here.
4.n
Bit
The smallest element of data; a 1 or a 0.
4.n
Byte
A byte consists of eight bits.
4.n
CAO
Computer Assisted Operation.
4.n
DCS
Distributed Control System.
4.n
Hertz
Measure of data transmission speed. One hertz is transmission of one byte of data per
second.
4.n
IPO
Injection Pressure Operated (gas-lift valve).
4.n
PLC
Programmable Logic Controller.
4.n
PPO
Production Pressure Operated (gas-lift valve).
4.n
RTU
Remote Terminal Unit.
4.n
SCADA
Supervisory control and data acquisition system.
4.n
TLP
Tension Leg Platform.
Page 9
API RP 19G12
Gas-Lift Automation
Page 10
5. Requirements
Note: This is a draft of the API RP 19G12 document. Once the outlines of each section are
complete, they are installed here from the “Outline” document. Each author is then asked to
draft his/her sections based on the outline.
5.1 Introduction to Gas-Lift Automaton
5.1.1
Production automation defined (Rick Peters)
a. Level 0 – Manual operations, pre-automation
b. Level I - Automating data acquisition
c. Level II - Automating injection control (well centric)
d. Level III - Optimizing injection control (system centric)
e. Level IV – Dealing with constraints such as sand production, scale,
water production, water flooding, EOR projects with high pressure
gas injection blended with solvents and intermixing with water
injection, etc.
f.
Recognizing problems
 Level A alarms – comparison of measured parameters with alarm
limits
 Level B alarms – combinations of parameters, e.g. pressure and flow
rate combined
 Level C alarms – comparison of actual performance with models, e.g.
pressure traverse models, nodal models
 Level D – prediction of potential occurrence of events so precorrective actions can be taken
g. Developing strategies to address problems
 Level E - responding to problems – have a range of responses from
manual to partially automated to closed loop control
 Level F – relate information here to other models
h. Providing transparency to users
5.1.2
Overview of gas-lift automation (Rick Peters)
a. Gather information from gas-lift wells



Start-up
Normal operation
Shut down
b. Gather information about gas-lift systems
API RP 19G12
Gas-Lift Automation


Page 11
System pressure
System rate available for gas-lift
c. Gather information about the compression process without
becoming involved with “compressor engineering”






Power factor
Compressor on/off
Suction pressure
Discharge pressure
Discharge rate
Water content
d. Detect problems with gas-lift wells and systems


Visualization of information
Three classes of alarms
e. Diagnose the causes of these problems

f.
Use models to help diagnose problems
Control the operation of gas-lift wells and systems



Normal control – may be automatic or manually initiated
Operational control
Response to diagnosis of problems
g. Optimize the performance and profitability of gas-lift wells and
systems



5.1.3
Optimize well performance
Focus on actual recommended practices; not unproven ideas
Evaluate results of changes; did we take the right action?
Objectives of gas-lift automation (Cleon Dunham)
This section discusses the objectives listed below and how they may be
realized with a gas-lift automation system. Gas-lift automation systems
should be designed and implemented to address specific gas-lift business
functions and to enhance specific business drivers.
a. Minimize downtime of gas-lift wells. There are two types of down time
or off-production time: planned and un-planned.
Planned downtime occurs when a gas-lift well or system is shut down for
some operation reason such as well maintenance, system maintenance,
production facility maintenance, safety, as in the case of a hurricane, etc.
A gas-lift automation system helps minimize this type of downtime and its
associated deferred production by automating the shut-down process so
it is performed safely, and by automating the start-up process so it is
performed rapidly, but consistent with safe well and facility operations.
API RP 19G12
Gas-Lift Automation
Page 12
Unplanned downtime occurs when a gas-lift well or system shuts down
due to any unplanned malfunction or failure in the well, the distribution
system, the compression system, or the production system. A
production automation system helps minimize this type downtime by
immediately detecting the downtime, alerting the production operating
staff, and providing them with information on the likely cause(s) of the
problem. This helps the operating staff respond quickly to return the well
or system to production, thus minimizing deferred production.
b. Enhance gas-lift problem detection and correction. A gas-lift
automation system assists with problem detection and correction in
various ways.
First, the system automatically and continuously collected the pertinent
data (measurements) needed to detect problems. Typically, this consists
of measuring the gas-lift injection pressure and rate, and the production
pressure. Other measurements may include the injection and production
temperatures, and the liquid production rate.
Next, the automation system contains logic to check each value against
alarm limits and for other “problem” conditions. This is discussed further
in Section 5.1.1.
Then, the system contains logic to help analyze problem conditions and
their causes. Common examples of problems that the system can help
to analyze are: (1) instability when the casing and/or tubing pressure are
surging or heading, (2) multipointing or injecting in multiple valves or a
valve and a leak at the same time, (3) gas delivery problems such as
blocks or freezing, and (4) production problems such as a plugged choke
or a blocked flowline.
Finally, in some cases, the automation system can assist with problem
solutions. For example, it can change the gas injection rate if this is
needed to improve stability, or it may be able to take corrective actions to
remove an injection blockage due to hydrate formation.
c.
Optimize oil production from oil wells. Optimization of oil wells is not
just problem solving. It is much more. For each well, there is an
economic optimum production rate. This is discussed in API
Recommended Practice 11V8 and in Section 5.2.4. However, for many
reasons, it is rarely possible to operate a well at its optimum rate. This is
also discussed further in Section 5.2.4.
Speaking simply, the economic gas-lift production rate occurs when the
value of oil (and gas) production, divided by the cost of gas-lift injection
and production handling and treating is maximized. Before this point,
adding more gas will increase the value of oil and production by more
than the cost of adding the gas-lift gas and treating the additional fluid.
Beyond this point, the value of the production will be less than the cost.
The primary reason that wells can not (normally) be operated at their
optimum economic rate is there is rarely (almost never) the right amount
of injection gas available in a gas-lift field to inject each well at its
optimum rate. So here the process of gas-lift optimization must focus
API RP 19G12
Gas-Lift Automation
Page 13
injecting into all of the wells served by the gas-lift system as close to their
optimum as possible.
And, this further complicated when the supply of gas-lift injection
changes, due to a change in supply or a change in demand for gas.
Gas-lift automation can help to keep each well as close as possible to its
optimum injection rate at all times, this maximizing the economic of gaslift operations.
d. Optimize distribution of injection gas to gas-lift wells, e.g. with both
open-loop and closed-loop control. Automation systems must support
gas-lift distribution in both open-loop and closed-loop operations.
Open-loop systems exist where gas-lift injection is controlled by manual
or semi-automatic means. Examples are: manual choke control, manual
control valve control, and manually-set flow rate controllers. In these
cases, the automation system should provide the production operator,
the person who must take the physical control actions, with the
necessary injection rate into each well to approach optimum distribution
when there is need for change in the injection rates. Such system can
be ineffective. It can take too long to make the necessary injection rate
changes to keep the gas-lift system in balance in the face of an upset I
supply or demand.
Closed-loop systems exist where the automation system can
automatically adjust the injection rates, on a moment’s notice, when the
supply or demand for gas changes. For this to work, the system must be
aware of the optimum injection rate for each well and must have the
capability to adjusted the injection in each well, or in selected wells, to
come as close as possible to optimum production for all of the wells in
the system.
With such systems, if is often necessary or desirable to treat some wells
differently. For example, if a well is a dual-gas lift well, and intermittent
gas-lift well, or a well that is difficult to keep stable if the rate is changed,
it may necessary to hold the injection into this well constant while making
adjustments in other wells. Also, if a well is on test, it may be desired to
hold it constant during the test to obtain valid test results.
e. Make best use of a short supply of gas-lift gas. Normally, the supply
of gas is either less than the amount needed to optimize each well, or it
is more. If it is less, the automation system can allocate the available
amount as described in Section 5.1.3.c and Section 5.2.4.
f.
Make best use of an over supply of gas-lift gas. When there is an
over supply of gas, the automation system should not distribute all of the
gas to the wells. Over injection can cause operating problems including
multi-points. Any excess amount of gas should be sold or used for some
the purpose in the field.
g. Optimally deal with cases where there are limits on the ability to
handle water production. It sometimes occurs that the process of
optimizing oil production can result in an increase in the volume of water
production. In these cases, the ability of the production system to handle
API RP 19G12
Gas-Lift Automation
Page 14
water may be a constraint. In these cases, the gas-lift optimization /
allocation system must allocate gas in a way to maximize the profitability
of oil and gas production, taking into consideration the costs of and
constraints caused by the water production.
h. Optimally deal with wells that need special care, such as wells that
can’t be easily stopped and started. There may be gas-lift wells in a
field that are served by a gas-lift system that need special care. For
example, there may be wells that are difficult to safety stop and re-start.
It may be important to keep these wells on production, at a stable gas
injection rate, regardless of upsets or changes in the gas-lift system. The
gas-lift automation system must recognize these wells and treat them
accordingly. This may mean holding the injection rate into these wells
constant while adjusting the total injection rate into other wells in the
system, to maintain an overall balance between supply of gas into the
system and demand for gas from the wells served by the system.
i.
Optimally deal with systems where continuous and intermittent gaslift wells are mixed in the same system. There may gas-lift systems
that need to serve both continuous and intermittent gas-lift wells. When
gas is injected into an intermittent well, the demand for gas from the
system will be temporarily increased, and the system pressure may be
reduced. It may be necessary for the gas-lift automation system to
temporarily reduce the injection into some of the continuous gas-lift wells
to maintain stability in the system. It may also be necessary for the gaslift automation system to schedule the intermittent gas-lift injection cycles
so gas isn’t injected into two or more intermittent wells at the same time,
thus further exacerbating the injection rate and pressure problems.
j.
Optimally deal with dual gas-lift wells. If a gas-lift system serves both
single and dual gas-lift wells, special care may be required for the dual
wells. It can be difficult to successfully inject gas deep in both sides of a
dual and keep this injection rate stable. When this deep, stable injection
is achieved, it may be important to maintain it, even in the face of upsets
in the distribution system. So, in these cases, it may be necessary for
the gas-lift automation system to hold the injection into the dual wells
constant and adjust the injection into single wells to maintain a balance
between supply and demand in the distribution system.
k.
Use control of automated wells to deal with problems and/or safety
issues in the production system, e.g. slugs of liquid, potential
separator carry-over. Sometimes problems occur in a production
system that require that production to the system be quickly stopped to
avoid a liquid carryover or other problem. When this occurs, the gas-lift
automation system must be able to react quickly to turn off the injection
gas to the wells which produce to the affected production system. Then,
when the problem has been corrected, the automation system must restart the affected wells. This may have to be done one or a few wells at
a time to avoid creating surges of fluid from entering the production
facilities.
l.
Analyze best use of control logic in the host automation system vs.
logic distributed in the manifold or wellhead controllers. In many
fields, control logic can exist at several locations. There may be control
API RP 19G12
Gas-Lift Automation
Page 15
logic in a host computer system, in a DCS, RTU, or PLC located at a
gas-lift manifold, and in a RTU or PLC located as the wellhead.
Generally speaking, the best place to implement control logic is as close
to the control point as possible. So, to control gas injection, the best
choice is to place the logic close to location of the control device, which
may at the gas-lift distribution manifold, or close to the gas-lift wellhead.
Other logic should be located at the level in the system where all of the
affected control points are served. Control of the allocation of gas to all
of the wells in the system must be at a level that serves the entire
system. Normally, this will be in a host computer system.
m. Optimize gas production from gas wells. Optimization of gas wells is
different from oil wells. To optimize gas well production, two things are
necessary. The operating bottom-hole pressure must be kept as low as
possible, and the gas flow rate must be kept high enough to remain
above the critical flow rate, so any liquid in the production steam can be
carried up and out of the well.
If not removed, liquid can accumulate in the bottom of some gas wells.
This liquid will impose a back pressure on the gas formation and inhibit
gas inflow. Many methods can be used to remove this liquid. One is
gas-lift. Here the gas must be injected below the column of liquid and
used to lift it out of the wellbore.
To remove liquid and keep the wellbore clear, the gas flow rate must be
above the critical velocity, which is the velocity above which the flow gas
can carry liquid droplets to the surface. If the native gas flow velocity is
not above critical, this can be achieved by injecting additional gas with
gas-lift. Again, the gas should be injected as deep in the well as possible
to facilitate critical flow from the bottom of the well. This can be a
challenge in wells where the tubing (and packer) are set far above the
perforations. The amount of gas to achieve critical flow is much higher in
the casing than in the tubing, due to its larger cross-sectional area.
Some companies have developed gas-lift systems to inject gas in and
even below the perforated interval.
5.1.4
Methods of using gas-lift automation (Rick Peters, John Green)
5.1.5
Types of fields that need to be served by gas-lift automation (Rajan
Chokshi, Cleon Dunham)
a. Introduction. Frankly, all types of fields that use gas-lift are candidates
to be served by gas-lift automation. The purpose of this brief section is to
review the major categories of fields, types of fields, field locations, types
of gas-lift, sizes of operations, and types of operations where gas-lift is
used and automation is pertinent. The appropriate level of automation
may vary with the type of field, but all gas-lift operations, regardless of
type or size, can benefit from automation.
API RP 19G12
Gas-Lift Automation
Page 16
b. Categories of Fields. At least three categories of fields use gas-lift. In
some cases it is obvious that gas-lift automation is pertinent; in others it
may be less so.

Green (new development) Fields. New fields have new wells and
facilities. It may be that the oil and gas wells will naturally flow for
some time before needing artificial lift. However, it is wise to plan for
artificial lift from the start; it is usually much less expensive to equip
the field and wells for artificial lift before it is actually needed, so it can
be started as soon as it is required.
If the field and wells will benefit most from gas-lift, the following
should be considered from the beginning.
- Install gas-lift mandrels in the wells when they are first
completed. Be conservative with the design, since the actual
well performance when gas-lift is needed is not known
initially.
- Install a compression plant; it will be needed anyway to
handle sales gas and can support gas-lift when needed.
- Install a lift gas distribution system, or at least plan for it.
- Install an automation system. It will be needed to monitor
and control the flowing wells and can easily be expanded to
serve gas-lift.

Brown Fields. Existing fields and wells most likely already require
artificial lift, and may require gas-lift. For these, the recommended
practices in this document should give adequate justification and
information for implementing gas-lift automation. The level of
automation (Section 5.1) needs to be chosen, but some level will
almost assuredly be justified and highly beneficial.

Beige Fields (older than Brown Fields). These fields have typically
been on production for many years. They will already have an
artificial lift system. If it is gas-lift, there will already be gas-lift
infrastructure, although it may not be up-to-date. Typically, oil
production rates may be lower, but water production rates may be
higher, so there are many gas-lift problems. As long as such
fields/wells are still above their economic limit, gas-lift automation can
be very beneficial to minimize operating costs while continuing to
produce at optimum rates.
c. Types of Fields. There are many types of fields that use gas-lift. All of
them are candidates for gas-lift automation.

Oil Fields. Gas-lift is one of the leading forms of artificial lift for oil
fields; especially for offshore or inland marine fields, fields with
deviated wells, and wells that produce large amounts of water and
gas. All of these will benefit from gas-lift automation.
API RP 19G12
Gas-Lift Automation
Page 17

Gas Fields. Over 80% of gas wells produce liquids (water and/or
condensate) that must be removed so economic rates of gas
production can be sustained. Many forms of artificial lift are used; but
gas-lift is a favourable method. It supplements the well’s natural gas
flow and can reduce the flowing bottom-hole pressure to a minimum
value, thus enhancing both gas production and ultimate recovery.
Gas-lift automation is important to control the rate of gas injection:
just enough to maintain critical velocity (the velocity needed to
produce the liquid) but not too much.

Water Floods. Many fields use water flooding to help maintain
reservoir pressure and swee[ oil to the producing wells. Typically,
water flood response wells produce large volumes of water. So, gaslift efficiency is important; and automation can help the wells produce
as efficiently as possible.

EOR/IOR Operations. Enhanced oil recovery (or improved oil
recovery) fields may use water flooding or other means to enhance
recovery, such as steam flooding, chemical flooding, or CO2 injection.
In some cases, artificial lift is used to produce the oil wells and gas-lift
is the preferred method. These field systems are usually very
expensive, so high efficiency is important; this can be augmented by
gas-lift automation.

CO2 Recovery Fields. CO2 injection is a special method of enhanced
oil recovery where CO2 is injected in batches (“huff and puff”),
continuously, or in alternating slugs with water. Typically, CO 2 is
produced back with the oil and water in large quantities, so pumping
is not an effective method of artificial lift. These wells can be
produced by gas-lift, and sometimes CO2 is used as the gas for lift.
This is an expensive process, so efficiency is important. Automation
can assist with achieving and maintaining efficient operations.
d. Field Locations. Oil and gas fields are found in various locations. For
these, wherever gas-lift is used, automation is pertinent.

Onshore Fields. Onshore fields often cover a large geographical
area. Often lift gas distribution and gathering systems are long and
complex. In addition to its normal benefits, automation can help
reduce the manual effort required to monitor and control wells that
cover a large area.

Inland Marine Fields. Inland marine locations are typically in swamps
or marshes where transportation to the wells must be by boat or
helicopter, not by roads. Here, automation can assist with routine
monitoring and control of the wells that may be difficult and/or
expensive to monitor and control manually.
API RP 19G12
Gas-Lift Automation
Page 18

Offshore Fields. Offshore, wells are typically drilled from platforms or
well jackets. If they are on a platform, distribution and gathering
systems will be short. One advantage of automation here is that the
wells are monitored and controlled by people who work on different
shifts. Automation can provide consistency and continuity for the
operation.

Sub-sea. Sub-sea gas-lift raises many unique problems. Here, the
wells can not be visited manually, and all equipment is designed for
ultra-high reliability. Automation can assist in remote monitoring and
control of these wells. Refer to API RP 19G13 for detailed
recommended practices on operating sub-sea gas-list systems and
wells.
e. Types of Gas-Lift. For most people, gas-lift refers to producing single oil
wells with continuous gas injection. However, there are other forms to be
considered.

Continuous gas-lift. This is the most common form of gas-lift and
most gas-lift methods, programs, and automation systems focus here.
Refer to:
- API RP 11V2 (Gas-Lift Valve Testing)
- API RP 11V5 (Gas-Lift Operations)
- API RP 11V6 (Gas-Lift Design)
- API RP 11V7 (Gas-Lift Valve Reconditioning)
- API RP 11V8 (Gas-Lift Systems)
- API RP 19G11 (Dynamic Simulation of Gas-Lift Systems and
Wells.)

Intermittent gas-lift. This form of lift is typically used when reservoir
pressures or well productivities have declined so continuous gas-lift is
no longer effective. This form of lift can be labor intensive to maintain
the optimum intermittent injection frequency and gas volume per
cycle. Refer to API RP 11V10 for recommended practices on design,
operation, and optimization of intermittent gas-lift wells.

Dual gas-lift. Some wells have multiple completions in the same
wellbore. If both zones need to be gas-lift, the practice of dual gas-lift
is required. It is challenging to successfully operate dual gas-lift and
automation can provide significant assistance. Refer to API RP 19G9
for recommended practices on design, operation, and optimization of
dual gas-lift wells.

Gas well deliquification. Gas-lift is an attractive method for
deliquification of gas wells, where liquids (water and/or condensate)
must be removed to gas flow can continue at economical rates.
API RP 19G12
Gas-Lift Automation
Page 19
Refer to Gas Well Deliquification, Second Edition, by Lea, Nickens,
and Wells, for recommended practices on using gas-lift for gas wells.
f.
Sizes of Operations. Fields and operations range in size from a very
few wells to entire countries with large fields and huge numbers of wells.
If gas-lift is used, there is an opportunity to improve it with automation.

National Oil Companies. More and more production in the world is
being controlled by National Oil Companies. Sometimes these
companies hire Operating Companies to produce for them, and
sometimes they operate themselves. Often these operations are
huge. Automation can significantly assist by helping to apply state-ofthe-art technology.

Large Operators. Large Operators typically are fully integrated and
operate multi-nationally. Typically they can take advantage of
common systems and standards, and economies of scale.
Automation can assist them in implementing and maintaining
consistency in their operations across the world. Automation systems
can be implemented in various languages for use in various
countries.

Medium Operators. These Operators may be regional, or they may
also be international. Typically they focus on production without
focusing on refining and marketing. These Operators may also
operate multiple fields. Typically, they don’t have Research and
Development facilities and large Information Technology
Departments. Commercially available automation systems are a
significant benefit in helping bring consistency and recommended
practices to their operations.

Small Operators. Typically, small Operators are in one geographical
location. They may not have technical staff; they may rely on contract
personnel to operate their wells. Here, automation can provide a
significant benefit in helping produce their wells effectively and
economically.
g. Types of Operations. Lastly, there are two types of operations that
deserve mention.

“Traditional” Fields. These fields are “traditional” in that they depend
on “conventional” hardware, software, and techniques. Most gas-lift
automation systems have been developed, implemented, and used in
these fields.

“Smart” Fields. Several companies are development enhanced
operations; referred to as “smart” fields, “e-fields,” “intelligent” fields,
or “i-fields.” These fields/wells typically contain downhole
API RP 19G12
Gas-Lift Automation
Page 20
instrumentation and control capabilities. There has been some work
to integrate “smart” technology with gas-lift automation systems, but
this is a relatively new effort. Automation can monitor downhole
information ad execute downhole control, either by manual or
automatic initiation.
5.2 The Business Side of Gas-Lift Automation
5.2.1
Gas-lift automation business drivers (Keith Fangmeier, Cleon Dunham,
Neil de Guzman)
a. Introduction
Oil and gas production is the primary business of the upstream oil and
gas industry. A significant majority of oil and gas production is produced
or augmented by artificial lift. One of the primary methods of artificial lift is
gas-lift. Automation is a key process to enhance the business benefits of
gas-lift.
The purpose of this section is to discuss the primacy business drivers that
for the basis for consideration and justification of automating gas-lift
systems and wells. The first set of drivers is commonly associated with
HSSE (Health, Safety, Security, and Environment).
b. Health, Safety issues. The highest priority for all Operating Companies
is maintaining the health and safety of their employees, contractors, and
others in their areas. Several important considerations are directly
affected by automation.

Minimize exposure to adverse conditions. Many gas-lift systems and
wells are exposed to the elements. Automation can monitor the
status of these facilities and wells and, except for the most pressing
situations, prevent the need for people to visit during adverse
conditions.

Monitor well integrity. Automation systems can monitor the status of
facilities and wells and give warning if there are problems with well
integrity or operating conditions. If there are problems, Operators can
be prepared with the necessary tools and techniques to address them
without taking risky investigatory or diagnostic steps.

Shut in wells that pose a safety risk. If a system or wells produce a
safety risk due to leaks, excessively high pressures, or production of
hazardous gases or liquids, they can be closed in via the automation
system until the necessary corrections can be made.

Monitor annular pressures. In addition to monitoring normal
parameters such as injection rate and pressure, and production
pressure, automation can monitor the pressure is the B and C annuli
and detect if there may be casing leaks.
API RP 19G12
Gas-Lift Automation
Page 21

Monitor pipe in pipe pressures. This is pertinent for deepwater
operations where risers are used to enclose both injection and
production lines. Pressure build-up in the annulus of risers may
indicate a leak.

Monitor caisson pressures for TLP’s. Tension Leg Platforms are
essentially floating facilities tethered to the ocean floor. They remain
afloat with air-filled caissons. If a caisson springs a leak, this can
jeopardize the platform.
c. Environmental constraints. Protecting the environment is essential for
successful operation. Gas-lift automation can help in several ways, some
of which are discussed here.

Address regulatory requirements. Clearly, all Operators must be
concerned with avoiding potential environmental problems and must
comply with all pertinent regulatory requirements that affect the
environment. Automation helps by continuously monitoring gas-lift
systems and wells and alerting Operators of any conditions that may
not be consistent with regulatory requirements.

Minimize leaks. If a leak occurs and can be detected, the leaking
line(s) or well(s) can be shut-in to minimize the leak until corrective
action can be taken.

Close wells during adverse weather conditions. The obvious case is
closing wells when a hurricane is imminent. There can be other
adverse weather conditions such as exceptionally high wind or fire
where wells and facilities should be shut in to minimize risk of spills,
leaks, etc.
d. Security issues. The second “S” in HSSE is for security. Protecting
investments is a key role of automation.

Physical property. Physical property, e.g. facilities, lines, and wells,
can be damaged. And, they can be at risk due to vandalism or theft.
Automation can alert Operators of conditions that may cause potential
damage, and if necessary, can alert Operators to intrusion by
potential vandals or thiefs.

Intellectual property. Intellectual property, e.g. computer programs,
logic, and analysis tools, can be stolen or disrupted by hackers or
others who gain inappropriate access to automation and other
computer systems. Security procedures can be implemented to
minimize the risk of unwanted access to these systems.

Data. Automation and related systems contain valuable information
and data on reservoirs, wells, production, and processes. Hackers
and others can gain access to the data by nefarious means and steal
or disrupt it. Security procedures can be implemented to minimize
the risk of unwanted access to this information. This is particularly
API RP 19G12
Gas-Lift Automation
Page 22
pertinent when data is communicated from wellhead systems to
production automation systems and to corporate systems and data
bases. There are very secure methods to prevent disruption or
unwanted access to information as it is transmitted via a
communication system.
e.
Economic drivers. Gas-lift is a complicated process that must be
closely monitored and controlled. There are many examples of manuallyoperated systems where production was far from optimum. Economic
operation requires close monitoring to detect and diagnose problems,
close control to operate wells efficiently and effectively, and optimization
to gain the most economic benefit from the system, equipment, and
injected gas.

Monitor gas-lift performance frequently with accuracy and
repeatability. The recommended practice is to monitor important gaslift variables at least once per minute. A good practice is to actually
measure the variables at least once per second and average these to
obtain per minute values.
Important variables include lift gas injection rate and pressure, and
production pressure. Other items of importance include injection
temperature, production temperature, production rate, and annular
casing pressure.
In addition to wellhead variables, good well test information is
needed, especially if wellhead production rate is not or can not be
measured or estimated.
Automation helps with effective monitoring by:
- Automatically gathering the needed information so manual effort
is not required.
- Gathering it at a high frequency, so gas-lift problems can be
detected and diagnosed.
- Gathering it accurately with the use of accurate transducers and
meters. Accuracy of better than 1% of full scale is expected.
- Gathering with repeatability of better than 0.1% of full scale.
This automation, frequency, accuracy, and repeatability means that
gas-lift information can be trusted for use in gas-lift surveillance,
control, and optimization.

Obtain downhole pressure/temperature information for reservoir or
integrated production modelling. In some wells, it is justified to install
downhole pressure/temperature measurement systems. These can
confirm the depth of gas injection, provide information of well inflow
performance, and be used during shut-in periods to provide
information for reservoir pressure build-up analysis.
Automation can gather, process, and display this information at
minimal additional cost beyond the costs of the downhole
instruments.
API RP 19G12
Gas-Lift Automation

Page 23
Provide efficiency through accurate, consistent control. The three
most important objectives of continuous gas-lift are:
- Inject as deep as practical.
- Inject at a steady rate and pressure.
- Inject at an optimum rate.
With frequent, accurate information, automation can help control the
gas-lift operation in each well and for all the wells in the system to:
- Determine the depth of injection and assist Operators in
achieving the desired depth by controlling the injection rate to
assist with unloading to the correct depth.
- Maintain a steady injection rate as specified by the Operator or
determined by the system.
- Control the overall demand for lift gas from the system to keep
the system demand for gas (for injection into the wells) in balance
with the source(s) of gas form compressors, gas wells, and
purchase points.
- Control other items as required, such as wellhead tubing back
pressure control chokes/valves. This may be needed to maintain
stability in a well that has a tubing leak.
Other points relevant to control are:
- The system can include both surface and downhole equipment
that impact gas-lift operations.
- In addition to monitoring key parameters it can calculate key
performance indicators to assist Operators in prioritizing
surveillance and control work.

Troubleshoot gas-lift equipment with high frequency data acquisition
and analysis tools. Before problems can be addressed, they must be
detected, and the cause(s) of the problems must be discerned.
Automation can contain troubleshooting techniques and can transmit
information to other tools to assist. Examples of troubleshooting are
detecting:
- Heading (pressure fluctuations in the casing and/or tubing) and
determining the causes.
- Under injection due to a partially closed injection choke or valve,
hydrate formation due to freezing, or other restrictions.
- Under production due to a partially closed production choke or
valve, a partially plugged flowline, or a reservoir inflow restriction.
- Insufficient depth of lift due to a leaking valve, tubing leak, or
inability to unload to the desired operating depth.

Optimize gas injection, well production, and system pressure. A
theoretical lift gas injection rate can be determined for each well if its
inflow and outflow performance are known. This optimum point is
where the plot of income from oil and gas production vs. the cost of
injection and treating is a maximum. To the left of this point, more
can be made by increasing gas injection. To the right, net income is
reduced.
API RP 19G12
Gas-Lift Automation
Page 24
An important objective of optimized control is to maintain the gas-lift
system pressure constant. Gas-lift valves open and close on
pressure. Valve spacing and settings are based on pressure. With
constant pressure, the gas-lift system can have a much better chance
of working as designed. System pressure can be held constant by
balancing the source(s) of gas in the system with the demands of gas
from the system.
If there is just the right amount of lift gas, automation can control each
well at its optimum injection rate. Unfortunately, this is rarely the
case; there is normally too little gas to provide optimum injection for
each well, or there is too much gas.
If there is too little, automation can optimize the overall system by
reducing injection into the wells where the loss in income will be
smallest. If reducing lift gas in a well can cause it to become
unstable, automation can temporarily turn off gas to the well so the
better wells can remain on production at their optimum rates.
If there is too much, automation can hold each well at its optimum
rate and cause excess gas to be sold or recirculated through the
compressor.

f.
There are other actions that can assist with good system economics.
- Reduce deferred production and/or improve operating up time by
detecting problems and assisting Operators to solve them and
return the wells to production.
- Support co-mingling when this is required for operational
reasons. An example is production from a sub-sea manifold.
Often one flowline is used to bring production from two or more
wells to the host platform. Automation can assist with helping to
determine the production rates of each well.
Operational drivers. Often gas-lift operations need to occur when
Operators are involved with other important activities. Automation can
assist in performing these operations in a safe, timely, and consistent
manner.

Support initially unloading wells. Initial unloading, the removal of
completion fluid from the well’s annulus, is the most critical in a well’s
lifetime. If it is done improperly, equipment can be damaged and it
may never be possible to properly unload the well. If it is not done
well, the well may not be successfully unloaded to the desired
operating depth. Both can be result in uneconomic operation, for the
long term.
Automation can help monitor and control the unloading process to be
certain it is performed safely and correctly, and to provide Operators
with information on how the process worked, i.e. was the well
successfully unloaded to the desired depth, and can it continue to lift
from that depth.
Unloading is designed with steady state logic. But, the unloading
process is never steady; it is always dynamic and unstable.
Automation can monitor the actual dynamic unloading process and
API RP 19G12
Gas-Lift Automation
Page 25
provide Operators with knowledge on how the process actually works.
This information can be used to improve unloading designs in the
future.

Support kicking off wells to return them to production. Frequently
gas-lift wells are temporarily stopped and must subsequently be
restarted. Normally, gas-lift is simply re-started with the normal
injection rate and pressure. This may not be optimum, especially if
the well must undergo a mini unloading process to re-start.
Automation can monitor the kick-off process and inform the Operator
is special control is needed to successfully return the well to
production.

Help with shutdown. When gas-lift wells must be shut down, the
usual practice is to abruptly stop lift gas injection. This may cause
undesirable conditions in the well. Automation can monitor the well’s
response to a shutdown and inform the Operator if the shutdown
caused undesirable upsets. If it is necessary to shutdown more
gradually to avoid upsets, automation can mange this process over a
period of minutes or longer.

Support shutting down fields or key wells. Sometimes it is imperative
to shutdown wells as quickly as possible, to avoid facility upsets,
major leaks, or other critical operating problem. Automation can stop
the lift gas injection into all of the wells in a field or group in an instant,
if this is needed.

Support more rapid start-up and/or response to recover from system
problems to minimize downtime, reduce deferred production,
enhance safety, and reduce overall staff requirements. Sometimes it
necessary to shut down a group of wells and when the problem has
passed, it is necessary to bring the wells back on production. They
can’t all be restarted at once; this could overload the facilities, and
there may not be enough lift gas to start them all at one time.
Automation can bring the wells back in priority order, over a period of
time, to maximize return to production while minimizing facility upsets
or too heavy draw on the injection system.

Implement gas-lift gas allocation requirements. As mentioned
elsewhere in this document, there is rarely the right amount of gas to
optimize injection into all of the wells at the same time. If the overall
supply is less than required for overall optimization, the available
amount must be allocated to the wells on a priority basis. The goal of
this is to injection the optimum rate into the best wells while injecting
less in the poorer wells, or possibly not injecting into them at all.

Address multi-well system constraints. There may be cases where
production from gas-lift wells must be constrained due to excessive
low pressure gas production, excessive water production, or
excessive flowline pressure losses. Automation can control lift gas
injection into selected wells to address these constraints.

Understand the system and its constraints to best manage overall gas
injection and system pressure response. As noted elsewhere, an
automation objective is to help keep the lift gas supply and demand in
API RP 19G12
Gas-Lift Automation
Page 26
balance so the system pressure can be maintained at the desired
value. Gas-lift design is based on pressure. If the system pressure is
allowed to fluctuate, this can upset well operation. If system pressure
is kept stable, design can be based on this pressure.

The automation system is controlled by:
- Human interaction via a production automation or SCADA
system.
- Automation logic implemented in the SCADA.
- Programmable logic controllers (PLC’s), remote terminal units
(RTU’s), or distributed control systems (DCS’s) programmed to
follow a set of specified rules/routines.
- Intelligent systems which use “intelligent agents” to monitor and
control the gas-lift process.
g. Maintenance drivers. Gas-lift systems must be maintained to
continuously achieve optimum economic operation.

Detect gas-lift well and system problems. Before problems can be
addressed, they must be detected. Automation can continuously
monitor gas-lift system and wells, detect problems as they occur, and
alert Operators through alarm reports, status reports, automated
plots, or other means.

Determine causes of the problems. Operators should not address
symptoms but actual causes of problems. Automation can assist in
determining the causes. Is it due to a problem in the surface injection
system, the surface production system, or downhole? It is due to a
design problem, a valve problem, or a leak?

Prioritize corrective actions. Once a problem has been detected,
automation can help prioritize corrective action. Is the problem
adversely affective the system or well’s economic operation? Is it
affecting only one well or multiple wells? Can it be addressed quickly
and easily, or will correction be time consuming and expensive?

Recommend corrective actions. Once the cause has been
determined, automation can often assist with recommending the most
appropriate corrective action(s). Can the problem be solved by
adjusting lift gas injection? Must a valve be pulled and replaced?
Must tubing be pulled and repaired?

Evaluate corrections: did they help? Whenever a correction is made,
the results need to be captured and evaluated. Did the correction
work? Was it economically worth while? Should the corrective
procedure be used in the future or must it be revised for future use?

SCADA and communications system availability/functionality. The
production automation and communications systems must also be
maintained, so there is continuous reliable information on system and
well operation. Automation systems can “tattle tale” on themselves to
alert Operators if the automation or communication system needs
maintenance.
API RP 19G12
Gas-Lift Automation
Page 27
h. Personnel drivers. See Section 5.4 for a detailed discussion of
personnel issues associated with gas-lift automation.
5.2.2

Improve gas-lift staff performance. Use of gas-lift automation can
improve the performance of gas-lift staff by giving them a better
understanding of how their system and wells are performing and the
factors that affect performance. They can observe the impact of their
decisions.

Company culture. Some companies focus on maximizing production;
some on minimizing costs; some on operating with minimum staff
counts. Automation can assist with true economic optimization so
companies can find the right balance between investment to
maximize production, expense to maintain production, and use of
staff to monitor and control production.

Third party monitoring for optimization. Some companies don’t have
adequate staff for routine monitoring, control, surveillance, and
optimization. They depend on third parties to perform operating
functions. Automation can assist third party personnel and can inform
Company personnel on the success of the operations.
Justification for gas-lift automation (Cleon Dunham)
This section discusses the components of gas-lift automation justification
listed below and how they may be used to justify a gas-lift automation
system. With these various components considered, gas-lift automaton
systems have been documented to increase oil and gas production by 5 10% relative to manual operations, reduce operating and maintenance costs
by 5 – 10%, reduce capital costs, improve operating safety, and improve
personnel effectiveness..
a. Reduce gas-lift downtime, deferred production. Any amount of
unplanned down or off production time results in deferred or lost
production. Production automation can help minimize unplanned
downtime and resulting deferred or lost production.
With a gas-lift automation system, unplanned downtime can be detected
immediately. Since automation systems may not be monitored
continuously, the downtime may not be recognized by the production
operator(s) until the system is monitored, a report is received, or perhaps
the next morning. However, on the average, downtime can be
recognized within 8 – 12 hours, or less. And this may be much less time
than it would be with manual surveillance.
And, the automation system does more than recognize that unplanned
downtime has occurred. It provides information and insight into the
cause(s) of the downtime, so the problem can be addressed more quickly
and effectively.
API RP 19G12
Gas-Lift Automation
Page 28
A reasonable assumption is the unplanned downtime and associated
deferred or lost production can be reduced by 50 – 75% relative to the
losses when manual surveillance is used.
b. Reduce gas-lift operating costs. When a gas-lift system and its wells
are operated manually, operating costs may be high due to the time
required for monitoring, control, surveillance, and other manual activities.
All of these can be significantly reduced by automation.
Or conversely, these costs may not be high for a manually-operated
system, because they aren’t performed. But is this case, the profitability
of the system suffers because of their lack.
An automation system addresses the primary sources of operating costs
in these ways:
c.

Monitoring. The automation system continuously monitors each well
and its primary parameters; so people don’t need to spend item
travelling around the field, checking wells, changing and reading
charts, etc.

Control. The automation system continuously controls the rate of gas
injection into each well; so people don’t need to adjust control chokes
or valves. And, the automation system can do this much more
effectively since it can respond immediately to problems whereas
people can not.

Surveillance. The automation system used the collected data to
check for alarming conditions and evaluate well and system
performance. It does this on a continuous basis and reports to
production operators on an “exception” basis; so people spend time
solving problems, not looking for them.
Reduce or contain gas-lift capital costs. Gas-lift automation systems
make “optimum” use of injection gas. In manually-operated systems,
wells are often over injected. There can be a tendency to justify adding
more compression capacity on the theory that more gas is good. There
have been documented cases where installation of additional
compressors has been deferred to eliminated because the wells were
optimized without adding more gas injection.
d. Reduce or contain gas-lift maintenance costs. Because gas-lift
automation systems help detect problems and their causes, they give
insight into corrective actions needed to solve problems. This helps
reduce maintenance costs because operators know what maintenance
actions are needed and when they are needed.
API RP 19G12
Gas-Lift Automation
Page 29
For instance, in a manually-operated field, the reaction to any gas-lift
problem may be to pull and replace the gas-lift valves. But the problem
may be with one particular valve, with too much or too little injection, with
hydrate formation, or some other more-easily corrected problem.
e. Optimize oil production in oil wells. In many manually-operated oil
wells, there is a tendency to be satisfied if the well is on production, gas is
being injected, and some production is occurring. However, the operation
may be far from economically optimum.
A gas-lift automation system knows the economic optimum injection and
production rates of each well can continuously works to keep each well as
close to optimum as it can.
f.
Optimize gas production in gas wells. The same can be said for gas
wells. In manually-operated systems, people are satisfied if gas is being
injected and more gas is being produced.
A gas-lift automation system continuously injects just the right amount of
gas to maintain “critical” flow. This may be more or less gas than would
be injected in a manually-operated system, but it is the right amount to
keep the well deliquified and production at its optimum rate.
g. Optimize gas-lift gas utilization. As mentioned elsewhere, the volume
of injection gas in a system is (almost) never equal to the sum of the
economic optimum injection rates for all of the wells served by the
system.
In manual operations, it is (next to) impossible to allocate the amount of
gas that is currently available optimally. This is particularly true when the
available amount frequency changes due to compressor problems,
production facility problems, problems in other wells, etc.
Gas-lift automation systems continuously adjust the injection rate into
selected wells to keep the system in balance and keep each well as close
as possible to its economic injection rate.
h. Deal with production constraints, such as excess water production.
In some cases, it isn’t possible to optimize oil and/or gas production
without taking other factors into consideration. In some cases, optimizing
oil production may increase water production, or gas production, to
exceed the capacity of the existing production facilities. Or, there may be
fields with a mixture of continuous gas-lift, intermittent gas-lift, and dual
gas-lift wells. It may be necessary to control some wells differently to
gain the overall good for all of the wells in the system.
It can be (virtually) impossible to deal with these situations with manual
operations. However, a gas-lift automation system can handle these
API RP 19G12
Gas-Lift Automation
Page 30
constraints and operate the overall system and its wells in a manner that
is best for all wells and facilities considered.
i.
Use to validate well tests and/or production rates. With gas-lift
automation, information form each gas-lift well is gathered before, during,
and after each well test. Also, the injection rate into a well on test can be
held constant, even if the rates into other wells must change.
Furthermore, the automation system provides information to determine, or
at least estimate, the current depth of injection and operating bottom-hole
pressure. This can be used with the current inflow performance
relationship (IPR) for the well to estimate the well’s current production
rate. This can be compared with the current well test rate to either
validate (or question) the well test results, and/or to help diagnose
problems in the well.
5.2.3
j.
Enhance safety of gas-lift operations. Manual operations require that
people travel to wells and conduct manual operations on platforms, well
jackets, manifolds, wellheads, etc. Automation of these operations
doesn’t eliminate the need for manual intervention, but it does
significantly reduce personnel exposure.
k.
Enhance environmental protection of gas-lift operations. If there is a
leak or other surface problem, the gas-lift automation system can
recognize and respond immediately to the problem by turning off the gas
to the well. This can minimize losses and environmental damage.
l.
Improve understanding and effectiveness of operating staff. Often
production operators only see what’s happening on the surface. A gas-lift
automation system provides insight into what’s happening downhole:

The pressure profiles in the casing annuls and tubing.

The status of the operating valve(s) and/or choke.

The operating bottom-hole pressure,

The position of the bottom-hole pressure on the IPR curve, and thus
the potential production rate increase possible if the well can be
optimized and/or operated deeper.

The response of the well to more or less gas injection.
Gas-lift automation risks (Cleon Dunham)
This section discusses the risks that may be associated with a gas-lift
automation system, and how they may be alleviated to achieve a successful
system.
API RP 19G12
Gas-Lift Automation
Page 31
a. The system may perform poorly or be under-utilized due to lack of
trained staff. A gas-lift automation system can provide many
opportunities and benefits for enhanced operation. However, if it is not
used, for whatever reason, it will not realize its value. One of the primary
reasons for under-utilization is lack of sufficient numbers of trained and
motivated staff.

The first challenge is to have enough people on staff to support the
gas-lift process and gas-lift automation system. This may be a
challenge when budgets and staff counts are constrained. However,
unless sufficient numbers of people are assigned, there is limited
value in investing in a gas-lift automation system.

The second challenge is training the available staff. They must
understand the gas-lift process, the gas-lift automation system, and
how to apply automation to enhance gas-lift operations. There are
several gas-lift training courses available from Operating Companies,
Service Companies, and Consultants. But courses are not enough.
Each Operating Company should invest in developing qualified staff
that can serve as mentors and one-on-one trainers for others in the
organization. See Section 5.4.2 for a discussion of training required
for gas-lift automation.

The third challenge in motivation. People who enjoy working with
gas-lift and gas-lift automation will usually be motivated if they are
supported by their management and are given sufficient recognition
for their work. However, if they are not recognized, or if they are
frequently assigned to perform other (non-gas-lift) tasks, their
motivation may suffer.
b. There may be problems caused by instrument failures. Accurate,
timely measurement of important gas-lift variables is essential for good
gas-lift operation. A gas-lift automation system can help monitor and use
information only if the information is accurate and timely. It can not create
good information without good instruments.

Instruments, or the electrical connections to them, may fail. The
automation system can’t prevent these failures, but it can help to
identify them. When an instrument failure is recognized or suspected,
the automation system must report this to the Instrument Support
Technicians so the failed instrument can be replaced.

Instruments may fall out of calibration. Again, the automation system
can’t prevent this, but it can recognize the problem and alert the
Technicians so the problem can be addressed.

In some cases, not all pertinent information is measured. The
required measurements are defined in Section 5.3.1. If a required
API RP 19G12
Gas-Lift Automation
Page 32
measurement hasn’t been installed, the automation system will be
handicapped in performing its functions.
c.
There may be problems caused by control system failures. The
primary control function performed by gas-lift automation is control of the
gas injection in each well.

This control must be performed correctly. That is, the system must
inject the correct amount of gas into each well.

It must exercise control in a stable manner. That is, the system must
not continuously adjust the injection rate because of small changes in
measured values. The control system must be tuned to prevent
continuous seeking.

It must perform its control function in a timely manner. If the injection
rate(s) are not controlled quickly after a system upset caused by a
compressor going down or returning to service, the overall system
pressure may fall too low or rise too high, causing system instability
ad inefficiency.

If a controller ceases to function, the automation system must alert
the Technicians to correct the problem. To prevent upsets when a
controller fails, the system should employ a “fail safe” design that
should keep the injection rate the same until the controller can be
repaired or replaced.
d. The system may be under-deployed due to poor cost estimates. If
the cost estimates, and therefore the budget, for implementation of an
automation system are too low, the system may not be fully implemented.
If not all of the wells are served by the system, or if some important
measurements or controls are left out, the system may be ineffective.
This can lead to under deployment, since Production Operators will have
to resort to manual methods for at least some of the wells and some of
the system’s intended functions. If some manual methods are used, the
Operating staff may resort to using manual methods for all wells and
system functions and either under utilize the system or abandon it
altogether.
e. The gas-lift automation system may be incompatible with other
automation systems in the field. A complex oil or gas field will likely
have automation functions for monitoring and control of production
facilities, secondary recovery wells and facilities, artificial lift of other wells
such as wells produced by electrical submersible pumps, etc. Some
automation system provide a common approach and a common “look and
feel” regardless of the oil and gas field functions it provides. Some don’t.
If a system does not provide a common approach, it may be more difficult
API RP 19G12
Gas-Lift Automation
Page 33
and more frustrating for the Operating staff. This may cause them to not
spend the time needed to master and effectively use each system.
f.
5.2.4
Look at the presentation on “why projects fail.” This is a “telling”
story about why some projects fail. It is good to understand these
reasons and work to avoid them.
Gas-lift optimization (Cleon Dunham)
This section discusses methods used to optimize a gas-lift system when
using gas-lift automation.
a. Determine the “optimum” technical and/or economic gas-lift
injection rate for each well. The first thing to realize is that there will
(almost) never be just the right amount of gas to inject the optimum rate
for each well. There will either not be enough gas to optimize all of the
wells served by a gas-lift system (the usual case), or there will be too
much gas. The process to determine the optimum rate for each well is:

Measure or determine the static bottom-hole pressure (SBHP) for the
well. This is normally done by measuring the SBPH when the well is
off production. It may be done in conjunction with a flowing bottomhole pressure (FBHP) measurement, or it may be done in conjunction
with a pressure build-up (PBU) test. If the SBHP can’t be measured,
in some cases it can be estimated based on date in nearby wells.

Measure or determine the flowing bottom-hole pressure (FBHP). This
is normally done with a FBHP survey with the well producing in a
stable manner. If a well normally doesn’t produce stably, it should be
“forced” to be sable for the FBHP measurement.

Measure the well’s oil production rate during the FBHP survey.
Ideally the well test should be conducted at the same time that the
FBPH survey is being run. If it must be conducted at a different time,
make sure that producing conditions are the same as when the FBHP
survey was run.

Use the measured SBHP, measured FBHP, and measured well test
rate to determine the well’s inflow performance relationship (IPR).
The IPR equation is:
Qwf/Qmax = 1.0 – 0.2(Pwf/Pr) – 0.8(Pwf/Pr)2
Qwf
Qmax
Pwf
Pr
flow rate during well test
maximum flow rate at 0.0 flowing bottom-hole pressure
flowing bottom-hole pressure during well test
static bottom-hole pressure (SBHP)
The unknown is Qmax. Solve for Qmax
API RP 19G12
Gas-Lift Automation
Page 34
Qmax = Qwf / (1.0 – 0.2(Pwf/Pr) – 0.8(Pwf/Pr)2)
Then, once Qmax is known, solve for Q at any Pw
Q = Qmax * (1.0 – 0.2(Pw/Pr) – 0.8(Pw/Pr)2)

Determine gas-lift production rates at different gas injection rates.
Draw the inflow performance relationship (IPR) curve. Draw tubing
response curves for several different gas injection rates. Determine
the production rate associated with each injection rate from the
intersections of the outflow curves with the IPR curve. There are
NodalR analysis programs to perform this calculation.

Plot the gas-lift performance curve for the well. Note that the curve
reaches a maximum and then the production rate decreases at high
gas injection rates. This is caused by excess friction at very high gas
injection rates.
API RP 19G12
Gas-Lift Automation
Page 35

Plot the optimum point on the gas-lift performance curve. This is the
point where the incremental value of one more unit of production is
equal to the incremental cost of one more unit of injection. Inject less
and income is lost. Inject more and expense is too high.

Determine the minimum and maximum effective injection rates.
Below the minimum rate, the well will become unstable. Above the
maximum rate, the operation will become uneconomic.
API RP 19G12
Gas-Lift Automation
Page 36

Determine the gas-lift performance curve, optimum injection rate, and
minimum and maximum injection rates for each well in the gas-lift
system.

If a performance curve can’t be developed using an IPR curve and a
NodalR analysis program, it may be developed by using a multi-rate
well test. Fit a curve through the well test points. Don’t fit points that
are not on the curve. This can help define the unstable range. This
curve can become the gas-lift performance curve.

Create a table for all wells in the gas-lift system. For each increment
of additional gas-lift injection that is available, add it to the well that
will respond with the most additional production. For each increment
of gas that must be removed from the system, for example, if a
compressor trips, remove it from the well that will lose the smallest
amount of production.

If the total amount of gas to be injected is so low that the injection rate
into one or more wells would fall below their minimum inject rate, the
wells should be held at their minimum rate and gas should be
removed from other wells. Or the injection into the wells should be
temporarily stopped.

If the total amount of gas to be injected is so high that the injection
rate into one or more wells would exceed their maximum injection
rate, the wells should be held at their maximum injection rate and the
gas should be injected into other wells. If wells reach their maximum
rate, the excess gas should be sold.

If a well is on test, the injection rate into the well should not be
changed. If injection needs to be changed, it should be changed in
other wells.

If a well is particularly difficult to start, the injection rate into the well
should not be changed.
API RP 19G12
Gas-Lift Automation
Page 37
b. Control each well to operate at or near its optimum rate. As indicated
above, there is (almost) never the right amount of gas to inject the
optimum amount into each well. The process described above will tend
to keep each well as close as possible to its optimum rate while keeping
the system in balance by keeping the total amount of gas available for
injection approximately equil to the total demand for gas by the gas-lift
wells. This is accomplished as follows:
c.

The automation system monitors the amount of gas available for
injection on each one-minute scan.

If the total gas injection rate decreases, the system uses the table
and the associated logic described above to determine which wells to
receive less gas.

If the total gas injection rate increases, the same process is used to
determine which wells to receive more gas.

These adjustments are only made if the total gas injection rate
changes by more than a specified amount. For example the injection
into the gas-lift wells might not be changed if the change in the total
amount of gas is less than a specified amount.

These changes in injection rate, to keep the wells as close as
possible to their optimum injection rates, are based on the measured
amount of injection gas. There can be metering errors. To address
this, the following process is used.

The pressure of the gas-lift system is measured. This measured
pressure is compared with the target system pressure which is preestablished. If a change in overall injection rate, in response to a
change in the supply rate, causes the system pressure to increase or
decrease, the injection rates are “tuned” to keep the system pressure
stable. This is important since gas-lift wells and their valves are
designed to work at a prescribed pressure.
Minimize losses if less than optimum gas is available. As described
above, of the supply of gas decreases, for example due to a compressor
trip, the system reduces the injection into some of the wells to keep the
system in balance. The process for reducing the injection rates is
designed to remove gas from the wells that will loose the least production,
while keeping injection rates up for wells that produce more.
d. Minimize waste if more than optimum gas is available. If too much
gas is available for optimum injection into each well, some process is
needed to dispense with the excess gas without wasting energy or losing
production by over injection. The best solution is to sell the excess gas, if
this is possible. Another option is to re-circulate the excess gas from the
compressor discharge to the compressor suction.
API RP 19G12
Gas-Lift Automation
Page 38
e. Optimize the gas injection rate when gas-lifting gas wells. Normally
the process for gas wells is different. The goal is not to optimize the
production of oil or liquid; it is to remove water or liquid so the gas can
continue to flow. The following process is used:
f.

Determine the critical flow rate that is needed to maintain critical
velocity. Critical velocity is that gas flow velocity that is high enough
to remove liquid droplets and film from the wellbore. There are
programs available in the industry to calculate critical velocity. It is a
function of pressure, depth, gas flow rate, liquid flow rate, surface
tension, and other factors.

Inject enough gas so that, when it is combined with the produced gas,
critical flow is maintained.

A goal in gas well operation is to inject the gas as deep as possible.
If possible, this is beneath the perforated interval. The goal is to
remove liquid from the entire wellbore, to enhance gas flow.

If gas is injected in the casing, below the end of the tubing, much
more gas will be needed to achieve critical flow due to the larger
cross-sectional area of the casing. However, if a large rate of gas in
injected, this can lead to excessive pressure drops when the gas
flows up the tubing. There are ways to address this.

One option is to install a blank tube below the packer. This will
reduce the cross-sectional area of the casing and reduce the amount
of gas needed for critical flow.

Another option is to evaluate the relative vertical distances in the
casing and tubing. If the casing distance is long, as for example with
a long perforated interval, it may be preferable to inject enough to
achieve critical flow in the casing.

If, however, the perforated interval is short and the end of tubing is
close to bottom, it may be preferable to inject just enough for critical
flow in the tubing.
Optimize oil or gas production when there are other constraints. In
some cases, it is not possible to optimize oil or gas production without
considering other constraints. For example, it may be necessary to
consider the amount of water production, or the impact of production in
one well on production from other wells. Each situation is different, so it
isn’t possible to provide general recommended practices. However, there
are some general guidelines.

If there is a problem with flow interference in the gathering system,
and if this interference is exacerbated by increased production from
some wells, a network analysis can be used to optimize not only the
API RP 19G12
Gas-Lift Automation
Page 39
production of each well but the relative production rates to make sure
that one well or set of wells isn’t interfering will wells. There are
several network analysis programs available in industry.

If there is a constraint or limit on fluid handling capability in the
production facility, the optimization system may need to focus on low
water cut wells instead of wells that produce more water. This can be
done by setting lower maximum injection rates on the high water cut
wells.

If there is a similar constraint or limit on low pressure gas handling, a
similar approach can be used on high gas-oil ratio wells.
5.3 Gas-Lift Automation Hardware and Software
5.3.1
Gas-lift automation hardware issues (Keith Fangmeier)
Scope or Level of Automation will define hardware requirements as Automation
sophistication will most likely vary from onshore location to deepwater/platform
location.
c.
Instrumentation
 Surface (or wellhead if sub-sea)
- Injection pressure
- Production pressure
- Injection rate
- Injection temperature
- Production temperature
o Very important in sub-sea operations
- Production rate
o Determined with a test separator
o Measured or estimated with instruments
o Model to infer production
o Water cut measurement
- More on Instrumentation
o What instrumentation is needed for each level of automation
o “Punch list” of instrumentation issues to be considered
o Quality – Accuracy
o Data collection frequency – once per day, once per minute,1
Hz?
o Data synchronization (time/date stamps)
o PLC’s and/or RTU
o Pressure & temperature ratings
o Metallurgy
o Availability and serviceability
o Location
 Casing annulus—pressure/temperature
 Both A and B annulus
 Tubing-- pressure/temperature
 Surface gas lift injection measurements per well, per
subsea manifold
 Subsea Manifolds/Wellhead/mud line
 Caissons, pipe-in-pipe for TLP’s
 Flowlines
API RP 19G12
Gas-Lift Automation
o

Page 40
 Injection manifolds
 Compressor outlets
 Gas-lift distribution system branches
Method(s) to measure or estimate production on a continuous
basis:
 List different technologies that can be considered
Downhole
- DTS (temperature)
- Fiber-optic DTS systems for temperature, pressure, stress, etc.
- Electrical connection to pressure, injection rate, temperature
- Surface controlled downhole gas-lift valve control (electric,
hydraulic)
- Surface controlled formation control (or isolation) valves
- More on Downhole Instrumentation
o Smart Wells
 Does this include “closed loop” control of downhole
valves?
 Does this include control of sleeves, etc.?
o DTS (distributed temperature system)
o Downhole gauges –pressure/temperature/flow meter
 Downhole gauge @ point of gas lift injection
o Downhole chokes-flow control valves
o Surface controlled gas lift valves—electric or hydraulic
o Metallurgy
b. Injection Control
 Fixed chokes
 Variable chokes
 Automated control valves
c.
Production Control
 Fixed chokes
 Variable chokes
 Automated control valves

More on Injection and Production Control
o Chokes—wellhead, flowline, manifolds, subsea distribution, mud
line, risers
 Position or flow area indications
 Chokes in unloading gas-lift valves (move to the section on
gas-lift valves)
o Valves—wellhead, flowline, mud line, injection manifolds (surface
and/or subsea)
 Functional time to operate
 Status
 Reliability
 Automated or manually operated
 Gas-lift valves (move to the section on gas-lift valves)
o Safety valves
 What is intended here? Sub-surface, surface on the trees,
etc.
API RP 19G12
Gas-Lift Automation

Page 41
Should this be in a separate section?
d. SCADA
 DCS
 Wellhead RTU’s
e. Communication equipment and systems
5.3.2
Gas-lift automation software issues (Neil de Guzman, Larry Lafferty,
Larry Peacock)
a.
Objective. The broad objective of gas lift automation software is to
enable better operation and management of gas- lift wells, even when
there are staff constraints. The primary functions that may be performed
by a gas-lift management software system include:




Monitor periodic and continuous data available for a well.
Diagnose abnormal conditions in a well.
Make recommendations for corrective actions.
Automate adjustment of well operating parameters such as gas
injection rate to the extent possible and desirable.
b. Recommended Data. Effective management of gas-lift requires three
broad classes of data: well test data, analog data from well sensors, and
data from a well model. Although all the data items identified in this
section are desirable, they may not all be available. Gas-lift automation
software must therefore be designed to function with subsets of the full
data set.

Well Test Data. Table 1 identifies recommended data points to be
collected during a well test for management of gas-lift wells.
Engineering units for all variables are given in (Eric Laine
reference).
Table 1: Well Test Data Elements
Data Element
Description
Well test date
The date the well test was performed.
Fluid level
True vertical depth from the wellhead to the
fluid interface in the tubing-casing annulus.
Qoil
Quantity of oil produced during the test,
measured in units of oil production per day,
Qliq
Total liquids produced during the test,
measured in units of liquid production per
day.
Qgas
Quantity of gas produced during the test,
measured in units of gas production per day,
API RP 19G12
Gas-Lift Automation

Page 42
Data Element
Description
Water cut
Water cut; percentage of water in the total
produced fluid.
GOR
Calculated gas/oil ratio.
Qgi
Gas injection rate during the test, measured
in units of gas injection per day.
FWHP
Average flowing well head pressure,
measured in pressure units.
CHP
Average casing head pressure, measured in
pressure units.
FLT
Average flow line temperature measure in
temperature units.
Analog Data. Analog data consists of measurements gathered by
well sensors.
Table 2: Analog Data Elements

Data Element
Description
Supply pressure
Measured in pressure units at one or more
“common” points in the lift gas distribution
system.
Qgi
Instantaneous gas injection rate, measured
in units of gas injection per day.
CHP
Instantaneous casing head pressure
measured in pressure units.
FWHP
Instantaneous flowing well head pressure
measured in pressure units.
FLT
Instantaneous flow line temperature
measured in temperature units.
Well Model Data. Well model programs provide information about
predicted well performance. A reasonably accurate model of flowing
rates, pressures, temperature, and flow regimes is required for
effective monitoring and diagnosis of gas-lift wells. By “reasonably
accurate”, the discrepancy between the well’s total liquid production
rate, as measured by the most recent well test, is within an
acceptable limit of the total liquid production rate predicted by the
model. Table 3 identifies gas-lift valve data that is typically stored in a
model as part of the well’s configuration.
API RP 19G12
Page 43
Gas-Lift Automation
Table 3: Gas Lift Valve Data
Data Element
Description
For each valve provide
the following information.
Valve number
Numeric position of the valve in the
well, with valve 1 being closest to the
surface.
Measured depth
Measured depth of the valve.
True vertical depth
True vertical depth of the valve.
Test rack opening
pressure
Test rack opening pressure of the
valve.
Port size
Valve port size, measured in 64th of
inches.
Manufacturer
Valve manufacturer, a recommended
data element.
Model
Valve model, a recommended data
element.
For gas-lift well monitoring and diagnosis, a model is used for
predicting pressure, temperature, and production conditions for the
well. The following curve data should be provided by the well model.
Table 4: Well Model Curve Data
Data Element
Description
IPR curve
Inflow performance relationship curve.
Tubing performance
curve
Tubing performance curve; plot of
outflow rate vs. bottom-hole pressure.
Casing pressure gradient
Casing head pressure vs. measured
depth, generated from the casing
head.
Tubing pressure gradient
Tubing head pressure vs. measured
depth, generated from the tubing
head.
Tubing temperature curve
Tubing temperature, generated from
the tubing head.
Gas lift performance
curve
Predicted production rate plotted vs.
gas lift injection rate.
API RP 19G12
Page 44
Gas-Lift Automation
Data Element
Description
Deepest Point of Injection
Casing pressure gradient
Casing head pressure vs. measured
depth, Generated using the deepest
point of injection. (Is this different
from the Casing Pressure
Gradient? Do we mean casing
head or casing pressure vs.
depth?)
Tubing pressure gradient
Tubing head pressure vs. measured
depth, generated using the deepest
point of injection. (Is this different
from the Tubing Pressure
Gradient? Do we mean tubing
head or tubing pressure vs.
depth?)
Tubing temperature
curve
Tubing temperature, generated using
the deepest point of injection. (Is this
different from Tubing Tempearture
Gradient? Do we mean tubing
head or tubing temperature vs.
depth?)
In addition to gas-lift valve and curve data, the following data elements
may be either obtained from a model or calculated separately.
Table 5: Additional Attributes
Data Element
Description
Stability check value
Slope of the tubing performance curve
at the point where it intersects the IPR
curve. Values range from < 0 to >0.
Deepest point of injection
Deepest point of injection as
calculated by the model.
Model CHP
Casing head pressure employed
during model calculations.
Model Qgi
Total liquid production calculated by
the model.
Model operating rate
Estimated production rate at the
operating point.
Model Qgi
Gas injection rate used when
calculating the model operating rate.
Valve status
The status of each valve, represented
as open / closed / back-checked.
API RP 19G12
Page 45
Gas-Lift Automation
Data Element
Description
(What does back-checked mean?)
Valve capacity
c.
The calculated gas passage rate for
each valve.
Data Cleansing. The data obtained from well tests, sensor systems, and
well models may not be accurate. Accordingly, reasonable steps should
be taken to ensure data quality. Representative methods include data
validation, cleansing, and smoothing.
d. Data Storage and Retention. The recommended practice is to store the
data items identified in Tables 1 – 6 in a database or process data
historian that uses an industry standard query language. Data storage
mechanisms proprietary to a single company are discouraged.
Given ongoing development of database and query languages, a
definitive set of data storage technologies or products cannot be defined.
However, the following recommendations apply.

Industry standard data storage technologies are preferred such as
relational data bases, object oriented database, and process
historians.

Storage technologies that support a variety of access techniques are
encouraged such as direct invocation of SQL queries or the use of
web services. Again, the evolution of software technologies prevents
full specification of desirable capabilities.
An organization’s understanding of the historical performance of its wells
depends on the data retained in data stores. While each organization is
responsible for defining its own data retention policy, the recommended
approach is to store all data related to the analysis of a gas-lift well
including (a) well test data, (b) analog data from well sensors (c) data
generated by the well modelling program and (d) results obtained from
analysis.
e. Diagnostic Software. The diagnosis function provides information about
the well’s operating condition – i.e., is the well operating normally, and if
not, what are the most likely problem(s) it is experiencing? A gas lift
automation application uses the data described above to perform a
diagnosis.
The scope of diagnosis may address a broad range of gas lift system
types including




Continuous gas lift
Intermittent gas lift
Dual gas lift
Well unloading and shutdown
API RP 19G12
Page 46
Gas-Lift Automation
Table 6 identifies the recommended information generated by the
diagnosis function.
Table 6: Diagnosis Function Outputs
Data Item
Sub Item
Date
Analysis Results
(One or more
may be provided)
f.
Description
The date and time at
which the analysis was
performed.
Diagnosis
A description of the
well’s condition such as
‘Normal’, ‘Multi-point
injection’ and so on.
Cause
A description of possible
causes for the
diagnosed condition.
Recommendation
Recommended steps
that can be taken to
correct problem(s)
identified during
diagnosis.
Design Software. Design software is used for designing a gas-lift well’s
mandrel spacing or valve characteristics. There are several commerciallyavailable design programs. Most of them use steady-state design
methods. A recommended practice is to validate a design by using a
dynamic simulator to see if the well will appear to unload and operate as
intended. See API RP 19G11 for recommended practices in using
dynamic gas-lift system and well methods.
g. Analysis Software. Analysis software is used to evaluate a gas-lift well’s
performance at a level of detail deeper than that performed by a
diagnostic application. There are several commercially available analysis
programs. Most of them use steady-state methods, even if the well is
acting dynamically. A recommended practice is to validate an analysis,
and attempt to determine the cause(s) of its behavior, by using a dynamic
simulator.
g. Allocation Software. Allocation software is used for allocating limiting
resources such as injection gas or water disposal capabilities. Typically
the allocation function is concerned with resource allocation across a
group of wells or an entire field. Often there is a scarcity of lift gas to
meet the needs of all of the wells. The allocation software must allocate
the scarce lift gas resource to produce the most oil or gas from the group
of wells, even though some wells may be under produced or turned off
altogether.
If there is not enough water or low pressure gas handling capacity, the
allocation software may need to allocate production capacity to the lower
API RP 19G12
Gas-Lift Automation
Page 47
water cut or GOR wells so they can produce, while production from some
higher water cut or GOR wells must be curtailed or stopped altogether.
h. Management Software. When coupled with diagnosis and/or allocation
software, the management functions support decision making that is tied
to economic and key performance indicators. For example, under certain
economic conditions, operating a marginal well may be economically
sound. Under other conditions, operating the same well could cost more
than the value of oil and gas produced.
Recommended features of management software are to:
5.3.3

Enable exploration of alternative scenarios for well operation.

Have access to current economic data such as the values of oil and
gas and the costs of gas injection and water disposal.

Create key performance indicators (KIPI’s) for use in prioritizing wells
for corrective action. A KPI is a non-dimensional parameter that can
allow wells to be evaluated over time, or vs. other wells. They can
also be used to evaluate one group of wells vs. other groups of wells.
Gas-lit automation applications (Cleon Dunham. Larry Peacock, John
Green)
This section discusses gas-lift applications and how gas-lift automation can
be used to help implement them.
a. Continuous single string gas-lift. This is the most common type of
gas-lift. There is one tubing string installed in a casing string. Normally,
gas is injected down the casing/tubing annulus and into the tubing
through an operating gas-lift valve or orifice. Normally the well has a
packer to prevent produced fluid from entering the annulus after the well
has been unloaded. See API RP 11V5, 11V6, and 11V8 for detailed
information on single gas-lift.

There three primary objectives in continuous gas-lift:
- Inject the gas as deep as possible, and if possible, just above the
packer.
- Inject gas in a stable manner.
- Inject gas at an optimum rate.

Gas-lift automation helps achieve these objectives by:
- Providing information to help determine the depth of injection, so
Operators can make adjustments if needed. The system may
also contain logic to calculate (or estimate) the depth of injection.
- Control the rate of gas injection to keep it stable. Stable injection
rate does not necessarily mean stable injection pressure. But the
automation system can detect pressure instability (heading) so
Operators can make adjustments to correct it. It can also help
determine the cause(s) of instability. Is it due to over injection,
API RP 19G12
Gas-Lift Automation
-
Page 48
under injection, a port or orifice tat is too large, or multi-pointing
through more than one valve>
Control the rate of gas injection to keep it as close to optimum as
possible. See Section 5.2.1.
b. Continuous dual string gas-lift. In dual gas-lift, there are two tubing
strings installed in one casing. Gas is injected down the casing annulus
and into the two tubing strings through separate gas-lift valves or orifices.
These wells have two packers (an upper dual packer and a lower packer)
and normally the depth of gas injection in both tubing stings is limited by
the depth of upper dual packer. See API RP 19G9 for detailed
information on dual gas-lift.

c.
The objectives of dual gas-lift are the same as for single gas-lift, but
there are additional complications that lead to additional goals:
- Inject as deep as possible, but normally above the shallower dual
packer.
- Control the gas injection rate to keep it stable. Inject enough gas
to lift both sides of the dual. There is a complication here. Many
dual gas-lift wells use production pressure operated (PPO) gaslift valves. With these valves, multi-pointing with injection through
more than one valve at the same time is likely because the valves
are primarily sensate to production pressure which can fluctuate.
- Control the rate of gas injection to keep both sides of the dual
optimum.
- Try to prevent one side of the dual form taking too much of the
gas, thus leaving too little for the other side.
Intermittent gas-lift. Intermittent gas-lift is primarily used on wells with
low bottom-hole pressure, or low productivity, which can not sustain
continuous flow. Gas is injected in slugs beneath a slug of liquid which
has accumulated in the bottom of the tubing string. These wells typically
have a packer and a standing valve installed beneath the bottom gas-lift
valve to prevent fluid from being pushed back into the formation during
gas injection cycles. There are two primary means of controlling gas
injection; with a time clock and with “choke” control. A timer controls the
frequency of period of each injection cycle. With “choke” control, which
may use a control valve rather than a choke, gas is injected continuously
at the surface but the downhole operating valve controls intermittent
injection in to the tubing. Typically a “pilot” gas-lift valve is used; it can
open quickly and fully to quickly admit a slug of gas beneath the liquid
column in the tubing. See API RP 11V10 for detailed information on
intermittent gas-lift.

The objectives if intermittent gas-lift are:
- Inject slugs of gas at the optimum frequency. The slug of liquid in
the bottom of the tubing should not be too small; or gas will be
waste. The slug should not be too large; of it may exert
API RP 19G12
Gas-Lift Automation
-
-
-
Page 49
excessive back pressure on the formation, and the gas may no
be able to lift if to the surface.
Inject the optimum amount of gas with each injection slug. If too
little gas is injected; it may not be possible to lift the slug to the
surface. If too much gas is injected, some of it will be wasted.
Automation helps by controlling the frequency (with time control)
and period of injection, and allowing these to be changed as
needed. For “choke” control, automation controls the rate of gas
injection to the desired amount.
The automation system also detects ineffective operation,
including too little or too much liquid after flow, and alerts the
Operator so corrective action can be taken.
d. Plunger-assisted intermittent gas-lift. Plunger-assisted intermittent
gas-lift is a version of intermittent gas-lift where a plunger is used to “help”
lift the column of liquid. There are several plusses/minuses with this
technique. The primary plus is, at least in principle, the plunger can help
lift the liquid slug and can sweep some of the liquid film from the tubing
wall, thus helping to recover more liquid per intermittent cycle. The
primary minuses are: (1) the plunger adds weight to the column of liquid
that must be lifted by the gas, (2) the plunger can become stuck on the
way up or down the tubing, and (3) there can be problems when the
plunger needs to move past the side-pocket mandrels in the tubing string.
In general, except in very special cases, use of a plunger to assist with
intermittent gas-lift is not recommended.

If plunger-assisted intermittent gas-lift is used, the automation system
can help in the following ways:
- It can determine when the plunger arrives at the surface, so the
injection of gas can be stopped.
- In a similar manner, it can detect if the plunger doesn’t arrive,
thus indicating a problem that needs to be addressed.
e. “Auto” gas-lift, where gas from one formation in a well is used to lift
another formation. In some wells, the wellbore intersects both a high
pressure gas zone and an oil zone that needs to be gas lifted. In such
wells, it may be possible to use gas from the gas zone to lift the oil and
water in the oil zone. This a very special application that is not frequently
encountered.

For “auto” gas-lift, the automation system can help by:
- Monitoring the wells casing pressure, tubing pressure, and production
rates with well tests or other production measurements.
- Possibly monitor downhole pressure and gas injection valve status, if
this is provided in the well.
- Recommend a change in injection rate, which will need to be made
by changing the downhole injection valve or orifice.
API RP 19G12
Gas-Lift Automation
f.
Page 50
Gas-lift of gas wells. Use of gas-lift for gas wells is discussed in Section
5.1.3. A typical design for using gas-lift in a Figure 5.3.3.a. Gas is injected
Figure 5.3.3.a
Gas-Lift Design for Gas Well Deliquification
Compliments of Schlumberger
as deep as possible, and hopefully below the perforated interval. This is
to lift as much of the liquid as possible from the well. A special
completion design may be required to do this. The unloading design for a
gas well is essentially the same as for a continuous single-string gas-lift
well.

The gas-lift objectives are similar to those of continuous single-string
gas-lift and the automation system should perform similar functions.
In addition, the primary objective is to inject enough gas (not too little
and not too much) to achieve critical flow. The critical flow rate is a
function of the gas production rate, the gas-lift injection rate, the liquid
production rate, etc. The role of the automation system is to calculate
the amount of injection gas needed to achieve and maintain critical
flow and then control the rate of injection to maintain this rate.
API RP 19G12
5.3.4
Gas-Lift Automation
Gas-lift database applications (Rick Peters)
5.4 Gas-Lift Automation Issues
5.4.1
Gas-lift automation people/staffing issues (Cleon Dunham)
This section discusses the gas-lift staff functions that need to be involved in
gas-lift automation and how they need to be involved to make the systems
effective.
The following personnel must be actively involved in gas-lift automation.
They should be part of one or more teams as described below.















Gas-lift champion
Management
Project engineer
Other engineers
Automation specialists – hardware and software
Gas-lift technicians
Automation support personnel
Field operators
Maintenance staff
Well analysts
Well servicing
Service company staff
Accounting/finance
Consultants
Others
a. Steering committee or team
 Provide overall priority, justification, direction, focus
 Representation from broad spectrum of stake holders in the
company
Page 51
API RP 19G12
Gas-Lift Automation




Page 52
Chaired by a member of the management team
- Essential to have strong management buy in
Automation champion must be the facilitator of the team
- Call meetings, set agendas, “drive” the project
Most members should be from Operating Company staff
Most important early in project life, but may exist over life of the
project
b. Automation team
 Responsible for project execution
- Define, design, build, test, implement, commission, maintain
 Chaired by project engineer
 Champion serves as advisor
 Must function for life of the project
 Must have members with special skills
- Applications, instrumentation, communications, hardware,
software, automation, training
- Some may come from 3rd parties
 Must have members from operations, maintenance, well analysis
- They must provide input and feedback
- Their objectives and needs must be met
a. Surveillance team
 They use the system every day to monitor, control, optimize gas
production operations
 May have a formal “core” team and many ad-hoc members
 The team chair may be a:
- Well analyst, production engineer, production technologist, well
surveillance Specialist, automation specialist, lead operator
 Chair must assure that:
- People are continuously assigned and motivated to use
automation system for routine daily monitoring, control,
optimization
- They have training they need
- They have support they need from other functions in company or
from third parties for troubleshooting, maintenance, well
servicing, system enhancements, training
b. Workflow process
 Each company has a different work flow process that they follow for
project initiation, justification, design, purchase, installation,
operation, monitoring, control, optimization, surveillance,
troubleshooting, and maintenance.
 It is necessary that the workflow process be understood and followed
to avoid conflicts with management, the project mangers, the finance
department, etc.
- If the process is followed, the supporting departments will help to
facilitate the process.
- If there is an attempt to avoid or short circuit the process, it will
probably need to be done over again, with a waste of time, effort,
and well effectiveness.
API RP 19G12
5.4.2
Gas-Lift Automation
Page 53
Training required for gas-lift automation (Cleon Dunham, Larry
Peacock)
This section discusses gas-lift training functions and how they can be used to
make gas-lift automation systems become and remain effective. It presents
guidelines for selection, development, training, and qualification of gas-lift
automation personnel.
a.
Competency overview. The competencies described below are
presented as the minimum requirements for persons who are responsible
for the selection, design, installation, operation, optimization,
troubleshooting, and surveillance of oil and/or gas producing wells that
use gas-lift automation systems.
Three competency levels are suggested:

Awareness. Awareness is a basic level of understanding of gas-lift
technology, operations, and automation. Any person who is involved
in oil or gas-field production operation that utilizes gas-lift and gas-lift
automation shall have this basic level of competency, as a minimum.
Typically, this level of competency would be sufficient for managers
or supervisors who oversee production operations that utilize gas-lift
and gas-lift automation. This level of competency is not sufficient for
any person who is directly involved in performing or supervising
others who perform gas-lift or gas-lift automation operations including
selection, design, installation, operation, optimization,
troubleshooting, and surveillance of gas-lift operations and
automation systems.

Knowledgeable. Knowledge includes a more detailed understanding
of gas-lift and gas-lift automation technology and operations.
Practical experience is desired but not required. This level of
competency is required for a person who is directly involved in
supervising any aspect of gas-lift engineering or operations, including
selection, design, installation, operation, optimization,
troubleshooting, surveillance, and automation of gas-lift equipment
and/or operations. It is not sufficient for persons who are performing
these operations.

Skilled. Skill includes a detailed knowledge of gas-lift technology,
operations, and automation, including a practical ability in applying
that knowledge. This level of competency is required for persons
(engineers, well analysts, technicians, operators, etc.) who are
directly involved in performing or training or mentoring others to
perform any aspect of gas-lift engineering, operations or automation,
including selection, design, installation, operation, optimization,
troubleshooting, and surveillance of gas-lift equipment and/or
operations.
b. Levels of competency. Persons seeking qualification at these levels of
competency shall pass a qualification examination administer by a
qualified organization.
API RP 19G12
Gas-Lift Automation

Requirements for awareness level. The following shall be required
to demonstrate the awareness level of competency. The aware
person shall have:
-
-
-

Page 54
Attended a "high level" artificial lift course that provides a basic
introduction to each form of artificial lift, including gas-lift.
Maintain an awareness of important artificial lift issues by
attending appropriate company and/or industry artificial lift
seminars and/or workshops.
A good understanding of the relative merits of each form of
artificial lift and artificial lift automation.
A good understanding of the relative economics of each form of
artificial lift.
A good understanding of why gas-lift has been chosen to produce
the field(s) with which he/she is involved.
A good understanding of the inter-dependencies between the
gas-lift system and the other production/injection systems in the
production operation, for example, for gas compression, gas
dehydration, gas delivery, gas metering, gas control, well testing,
production treating, etc.
A good understanding of the skills and personal characteristics
needed by knowledgeable and skilled gas-lift staff
A good understanding of the value of the various aspects of
artificial lift deployment, including selection, design, installation,
operation, optimization, troubleshooting, surveillance, and
automation of gas-lift equipment and/or operations.
Requirements for knowledgeable level. The following shall be
required to demonstrate the knowledgeable level of competency. The
knowledgeable person shall have:
-
-
-
-
Attended a "high level" artificial lift course that provides a basic
introduction to each form of artificial lift, including gas-lift.
Attended an "intermediate level" artificial lift course that provides
a thorough understanding of each facet of artificial lift technology,
including selection, design, installation, operation, optimization,
troubleshooting, surveillance, and automation of gas-lift
equipment and/or operations.
Maintain an awareness of key gas-lift technologies and practices
by attending appropriate company and/or industry gas-lift
seminars and/or workshops.
Work experience in one or more facets of gas-lift engineering,
operations, or automation, although this is not a requirement.
Satisfied the requirements of the "aware" level of competency.
Have detailed knowledge of both the technical and business
issues involved with all aspects of artificial lift, including selection,
design, installation, operation, optimization, troubleshooting,
surveillance, and automation of gas-lift equipment and/or
operations.
The ability to advise people who are directly involved in gas-lift
engineering and/or operations, including assisting them in
obtaining needed resources, prioritizing their work, evaluating the
economics of their projects, etc.
API RP 19G12
Gas-Lift Automation

Requirements for skilled level. The following shall be required to
demonstrate the skilled level of competency. The skilled person shall
have:
-
-
-
-
-
-
c.
Page 55
Attended a "high level" artificial lift course that provides a basic
introduction to each form of artificial lift, including gas-lift.
Attended an "intermediate level" artificial lift course that provides
a thorough understanding of each facet of artificial lift technology,
including selection, design, installation, operation, optimization,
troubleshooting, surveillance, and automation of gas-lift
equipment and/or operations.
Attended "comprehensive" artificial lift courses that provide a
thorough and detailed understanding of all of the facets of gas-lift
with which the person is to be involved. These courses should
provide significant "hands on" training in performing the various
aspects of gas-lift engineering, operations, and automation.
Maintain an awareness of key gas-lift technologies and practices
by attending appropriate company and/or industry gas-lift
seminars and/or workshops, and/or sessions for sharing
recommended practices.
Be fully conversant with the key gas-lift specifications and
recommended practices that are produced and maintained by the
ISO and API.
Worked under the direct tutelage of a skilled gas-lift engineer,
well analyst, technician, or operator for a minimum of 480 hours.
The full set of "awareness" that is required for the "awareness"
level of competency.
The full set of "knowledge" that is required for the
"knowledgeable" level of competency.
Practical, hands-on experience with each aspect of gas-lift
engineering and/or operations with which the person is involved.
Received "feedback" from his/her supervisor or mentor on
activities performed, in terms of evaluations of success or failure
of actual gas-lift installations.
An ability to train "new" staff in effective gas-lift engineering
and/or operations.
Competency verification. Companies shall have a documented gas-lift
specialist training program. To become certified to a certain level of
competency, a person shall:






Work at the specified competency level, under the supervision of a
person certified to that level, for a minimum of 480 documented
hours.
Pass a written examination generated and administered under a
documented training program.
Pass a practice examination generated and administered under a
documented training program.
Once certified, the level of competency certification shall remain valid
for three years. Persons who have been certified shall be entitled to
display the certificate in their workplace and list it on their resumes.
To renew certification at a certain level of competency, a person shall:
Work at the specific competency level for a minimum of 480
documented hours in the year before seeking re-certification.
API RP 19G12
Page 56
Gas-Lift Automation

Pass a written re-certification examination generated
administered under a documented training program.
and
d. Training levels required. The table below shows the levels of training
that are required for each of the staff positions defined in Section 5.4.1.
5.4.3
Training methods for gas-lift automation (Cleon Dunham, Larry
Peacock)
This section presents methods that can be used to train gas-lift automation
personnel.
a. Gas-lift automation courses. Courses are always popular. However,
there are not many Gas-Lift Automation courses available. Here are
some that can be considered;

Some automation courses are taught in association with the annual
Gas-Lift Workshop and the annual Gas Deliquification Workshop.
These are normally for part of one day or an entire day.

Some Service Companies offer automation courses. If these are
offered by Gas-Lift Service Company, or by an Automation Service
Company, they may focus primarily on the equipment and techniques
offered by that company. These courses can be excellent, but may
not cover a wide range of automation services. Typically they will be
for several days up to a week.

There are other Service Companies that offer general automation
courses. These may cover a broader range of automation services,
but may also cover automation of other forms of artificial lift. These
may be for several days up to a week.

There are some Operating Companies that offer gas-lift automation
courses. They may be excellent, but they may be restricted to internal
staff only. However, some Operating Companies are willing to open
their courses to people from other companies.
API RP 19G12
Gas-Lift Automation
Page 57

There are professional training organizations that may offer courses
in gas-lift automation. It would be necessary to check their training
schedules to see if and when these are available. These are typically
one-week courses.

Finally, Consultants can offer gas-lift automation courses. These can
offered to the public, or they can be focused on the areas of interest
of an individual company. They can be on any duration that is
required.
b. Gas-lift automation mentors. A mentor is a person who is well versed
in gas-lift automation who can train new staff in an organization.
Normally, a mentor is a person on the company’s staff who works in gaslift automation. Typically, he/she has significant experience in automation
and has attended one or more courses. This can be an excellent way for
new staff, or people transferring into the automation area, to learn while
working. Equipping people to be mentors is sometimes referred to a
“train the trainer” where a person in the organization receives extensive
training and then trains (mentors) others on his/her staff.
c.
One-on-one training. One-on-one training can be performed by a
mentor, or by a consultant brought in for this role. This can be very
effective, but may be expensive. The training program and be tailored to
meet the specific needs of the person being training. The training period
can range from a day, to a few days, to weeks.
d. On-line “help” systems. Most good gas-lift automation systems have
extensive on-line “help” systems. Often these are much more than simply
providing instructions on how to enter data and obtain reports and plots.
Good on-line “help” system also provide extensive information on how to
use the automation system for gas-lift monitoring, control, surveillance,
troubleshooting, design, and optimization. When an Operating Company
is evaluating potential gas-lift automation systems, the extent and quality
of the on-line “help” system should be reviewed and used to assure that it
provides quality information of value to the users of the system. Good online “help” systems not only provide access when one clicks on a “help”
button. They also provide direct assistance in entering and using each
function in the system.
e. On-line training. There are some on-line training programs which can
be accessed via the internet. Typically the student can take these
courses at his/her leisure. There may or may not be a way for the student
to interact with an instructor.
f.
Computer-based training. Finally, there are actual computer-based
training programs where the student can take a course in gas-lift
automation. These courses typically include a lecture session, followed
API RP 19G12
Gas-Lift Automation
by tests or quizzes. Students are graded and learn from their right and
wrong answers.
5.5 Gas-Lift Automation Case Histories
5.5.1
Case histories – successful gas-lift automation systems (Grant
Dorman)
5.5.2
Case histories – unsuccessful gas-lift automation systems (Grant
Dorman, Stan Groff)
Page 58
API RP 19G12
6. Annexes
Gas-Lift Automation
Page 59
API RP 19G12
7.
Gas-Lift Automation
Bibliography
Informative references used in this document:
API RP 11V6, Recommended practice for design of continuous flow gas lift
installations using injection pressure operated valves. - 2nd edition.
API RP 11V7, Recommended Practice for Repair, Testing, and Setting Gas Lift
Valves
ISO 17078-1, Petroleum and natural gas industries — Drilling and production
equipment — Part 1: Side-pocket mandrels
ISO 17078-2, Petroleum and natural gas industries — Drilling and production
equipment — Part 2: Flow-control devices for side-pocket mandrels
ISO 17078-3, Error! Reference source not found.
ISO 17078-4, Error! Reference source not found.
Page 60