Intelligent Field supplement

Intelligent Field supplement
A Supplement to E&P Magazine
Creating & Managing
the Intelligent Field
Controlling the
intelligent field
Extending the intelligent
field subsea
Subsea communication
Wireless finds
new uses offshore
A look into the future
‘Predictive Intelligence’ Powers the Future
As a solutions provider, Emerson helps companies cope with
demands of information and technology advances.
A supplement to E&P
Hart Energy Publishing
1616 S. Voss, Suite 1000
Houston, Texas 77057
Tel: +1 (713) 260-6400
Fax: +1 (713) 840-8585
Judy Maksoud Murray
The Intelligent Field Has Arrived
The future is now in oil and gas exploration and
production processes.
Jo Ann Davy
Kelly Gilleland
MJ Selle
Ashley E. Organ
Controlling the Intelligent Field
PlantWeb’s predictive intelligence capabilities optimize
operations in many facilities.
Alexa Sanders
Laura J. Williams
Jo Lynne Pool
For additional copies, contact
Customer Service +1 (713) 260-6442
Extending the Intelligent Field Subsea
Emerson, Roxar combination brings new growth areas to
both companies.
Russell Laas
Eric Roth
Subsea Communication
Open system architectures are poised to revolutionize
subsea controls.
E. Kristine Klavers
Kevin F. Higgins
Wireless Finds New Uses Offshore
Exploring the potential of wireless networks is
just beginning.
A Look into the Future
Predictive intelligence will increasingly affect how
people work.
Frederick L. Potter
Richard A. Eichler
Intelligent Field technologies
enable optimal management of
the reservoirs and production, giving
operators critical data and information.
all images courtesy of
Emerson Process Management.
‘Predictive Intelligence’
Powers the
As a solutions provider, Emerson helps companies cope with demands of
information and technology advances.
t has been said that “the truth is at the source,” and nowhere does
this axiom ring more true than in oil and gas production. The quality of available information determines the quality of operating
decisions, whether related to safety, production performance, reliability,
asset health, or cost management. The right information, delivered at the
right time, to the right person can enable you to:
n Identify risky operating conditions and provide guidance on how
to resolve these critical safety issues
n Provide true real-time operational data to onshore operations centers, thereby reducing the cost and risk of offshore staffing
n Share that data with subject matter experts, regardless of location
n Enable dynamic production optimization – including model predictive control – to ensure repeatable, safe, and profitable operating strategies
n Identify changes in equipment performance to proactively resolve
problems and avoid failures
n Remotely monitor real-time asset health for predictive maintenance practices, allowing prioritization and planning of maintenance trips offshore at the best cost and schedule
n Provide specific, targeted information to maintenance personnel
on equipment problems, including which tools, parts, and work
processes are required to correct problems
n Streamline compliance documentation and reporting.
However, simply applying enterprise management software
“above” the operating systems won’t help achieve these goals. To
make the best possible decisions, high-quality, reliable information
from the process source must be available in real time, and delivered
quickly, efficiently, and in an easy-to-use manner.
Emerson Process Management’s Intelligent Field solutions include
the company’s state-of-the-art technologies and applications that
can ensure data are received in real time and in easy-to-use formats,
enabling you to resolve problems in a collaborative environment
while achieving optimal and unbroken production.
Wellhead management and more
Operators constantly battle with the dilemma of how to manage
reservoirs to deliver the optimal flow, gain the greatest recovery, and
obtain the maximum life of the field without overproducing and
damaging the reservoirs. Emerson Process Management can help
clients gain valuable insight into reservoir performance, receive early
warning of possible water breakthroughs, and ultimately control and
manage the flow of the production and data through the subsea
environment to surface facilities.
Using Intelligent Field technologies, clients can optimally
manage each wellhead by monitoring pressure, temperature, and
flow inputs, giving the operator critical data and information. This
enables better production management and delivery of optimal flow
to the process facilities, helping you ensure that unplanned shutdowns do not occur.
Most offshore and onshore operations now use digital intelligence with some predictive capabilities, such as smart valves and
measurement devices, and upgraded control systems. With this revolution, however, an additional challenge has developed: As instruments and systems become smarter and generate more information,
operators and maintenance personnel become overwhelmed, and
data become noise.
The solution must go beyond simple filtering. The ultimate solution is information management designed with specific tasks in
mind. At Emerson Process Management, the future of predictive
intelligence has arrived.
To discover how predictive intelligence can power your future, visit | September 2010 | 1
Executive Overview
Field Has Arrived
The future is now
in oil and gas
and production
2 | Emerson Intelligent Fields
alk into any major oil and gas company in Houston, Aberdeen, or Stavanger and
you will immediately notice the difference – the difference in how people are
using state-of-the-art technology to produce oil and gas more efficiently.
In many of these offices, you will see:
n Real-time data and information displayed on screens on the walls
n Multiple disciplines working together as a single team
n Live “always on” video links from headquarters to the operational locations
n Vendors and service providers supporting operations in real time from remote locations.
This fundamental change in operations support has come about in the last five years and
continues to improve oil and gas processes. Dubbed “the quiet revolution” by Statoil chief executive Helge Lund, it is also known as the Field of the Future™, Integrated Operations, i-Field,
or Smart Fields, among other names. Emerson Process Management refers to this revolution
as the “Intelligent Field.”
The availability of good data and information measured in wells, facilities, and pipelines
enables better responses to changing conditions. Making these data available to everyone in the organization who can add
value allows running core
A major oil company recently
declared that it has attributed
value-adding processes such as production optimization in a
“smarter” way, much faster, and with higher quality.
However, this is not just about the technology; it requires thinking about the way companies are organized to capture the value from
having this real-time data and information. Many businesses see
this as a technology-enabled transformation program, where the company takes a fundamental look at the way people work – from the
technician offshore to the commercial analyst back at headquarters.
This requires updating core work processes, overcoming employee
resistance to changing to a new way of working, and re-aligning
organizational structures. This is commonly referred to as the integration of “people, process, technology, and organization” to deliver
a capability to add value in day-to-day operations.
Having this real-time information at your fingertips allows the
company to:
n Maximize production system throughput
n Reduce and recover from unplanned events
n Balance short-term production goals with long-term recovery
n Reduce costs by optimizing maintenance planning
n Maximize the use of scarce resources
n Carry out remote operations and remove people from harm’s way.
There clearly is value from doing this. A major oil company recently
declared that it has attributed 100 thousand barrels of oil equivalent per
day of production to a digital oil field program at a cost of U.S. $3/bbl
to $6/bbl. Where else can you buy oil that cheaply?
This supplement will highlight the data and information technologies that enable these exciting changes to the way people work.
These technologies are being used to add value in both greenfield and
100 thousand barrels of oil
equivalent per day of production
to a digital oil field program at a
cost of U.S. $3/bbl to $6/bbl. Where
else can you buy oil that cheaply?
brownfield locations in many companies across the globe.
This supplement includes articles on:
n The use of “predictive intelligence” across the value chain to
realize the future of oil and gas
n The integration of surface and subsurface technology domains
n Electronic marshalling and the resulting savings made on new
n The application of wireless technologies to oil and gas
n Human-centered design – the changing way of working.
Many of the real-time data and information technologies that
enable the transformation to a truly collaborative way of working are
already in place. Although the move to global real-time organizations
has only just begun, many companies have embarked on the journey
and are already realizing value.
— Tony Edwards, CEO, StepChange Global
Field of the Future is a trademark of BP. | September 2010 | 3
the Intelligent Field
PlantWeb’s predictive intelligence
capabilities optimize operations in
many facilities.
ptimal production is the goal of any processing facility.
With slim operating margins and increased global
competition, advances in overall performance are
highly coveted. Unplanned shutdowns due to equipment failures,
higher-than-expected maintenance costs, and lack of experienced personnel can dramatically affect the bottom line.
“The more technology develops, grows, and evolves, the more
‘intelligent’ information we can get from our facilities,” said David
Newman, director of Global Oil and Gas at Emerson Process Management. “Instead of sending people out to get the information, we
can now – with the right predictive operations – look at it remotely.
If the facility can diagnose itself and identify potential problems, and
then communicate that information to the right person, the correct
solution can be instituted with little or no downtime.”
Predictive intelligence is intended to catch problems before a catastrophic failure occurs. A wide range of industries, including the oil
and gas industry, use Emerson’s PlantWeb™ digital architecture as an
early warning system. Using field intelligence to improve performance,
PlantWeb can enable at least 2% improvement in overall efficiency and
reduce the costs of operations and maintenance; safety, health, and
environment; energy and utilities; and waste and rework. Additional
savings of up to 30% are possible by reducing risk and startup costs.
“Most equipment can give you hints along the way that there’s a
problem,” Newman said, “but recognizing and reacting to those
hints is much easier when using predictive intelligence applications
such as those available with PlantWeb. When you don’t have the right
information, failures can seem catastrophic.”
Mechanical equipment failure is the number one cause of availability problems in oil and gas facilities. Pumps, compressors, motors,
valves, and instruments are subject to friction, fouling, and normal
wear and tear. PlantWeb can monitor these devices and highlight
potential problems. For example, if a valve has a maintenance issue
that requires investigation, a message to the operator might read, “I/P
is starting to plug” or “I/P blocked by grit.” PlantWeb can suggest the
necessary action such as “Check screen filter, material buildup.”
The operator is notified when operations are affected. This feature is
especially useful if operations are in a remote location and the operator
is thousands of miles away. “An engineer in Houston can see how a plant
in Africa is performing without making a day-long journey,” Newman said.
Maintenance savings
Maintenance is another area that has experienced significant cost
reductions and productivity enhancements. “One study found that
86% of maintenance is either reactive (too late) or preventive (unnecessary),” Newman said. “Best practice is 40%, with a shift to predictive/proactive maintenance.”
Many facilities in North America and Europe have already made
significant cuts to their maintenance staff such that safe operation has
become a concern. PlantWeb helps make the most of available staff
by improving productivity. “Sixty-three percent of maintenance work
orders resulted in no value-added work,” Newman said.
4 | Emerson Intelligent Fields
Remote diagnostics help alleviate unneeded trips to the field. As
many as 35% of these trips are for routine checks, 28% are for non-existing problems, 20% are for calibration shifts, 6% are for “zero off,” 6%
for plugged lines, and 4% are actually failed instruments. “That’s
mostly ghost chasing – going out to the field and checking things that
were working,” Newman said. “With PlantWeb, you can send someone
out there when work is actually needed, not just as a matter of routine.
“You also can see savings in relation to your scheduled maintenance costs,” he said. “There may be nothing wrong with the unit that
is due to be replaced – it’s working fine – but it’s been there a year and
the schedule says it’s time for a change. Using PlantWeb will give you
the warning needed ahead of when the unit needs to actually be
replaced. By using PlantWeb, you can save on spare parts and recalibration costs. These are all OPEX [operational expenditure] costs that
can save on the overall efficiency of the facility.”
Offshore maintenance presents unique challenges. For example,
performing maintenance on subsea equipment requires time to
organize a subsea intervention with a support vessel. “Unfortunately,
you can’t just send an operator out to fix something on subsea equipment the same way you can on topsides equipment,” Newman said.
Since subsea maintenance is much more costly than topside
maintenance, knowing when a piece of equipment needs repair
before a failure shuts down production is a huge advantage. “Being
able to safely delay maintenance and defer the cost also can be an
advantage while reducing the risk of lost production,” said Newman.
Decreasing human intervention
PlantWeb customers report reductions of 20% to 40% of control
loops in manual control, and improved optimization of 80% of control loops that have demonstrated excessive process variability. “When
facilities are new, loops are tuned for the ‘perfect’ plant,” Newman
said. “As conditions change and loops don’t perform properly for the
changing conditions, the operators start moving loops to manual to
‘line out,’ to stabilize, and to compensate for the variability that has
entered the process. Additionally, we found that many loops were
never properly tuned to begin with, and were still set up with default
tuning parameters.”
As a result, many advanced process control (APC) benefits are
being missed. Because APC sits on top of regulatory control, as the
conditions change and manual intervention takes place, many operators turn off the APC because it depends on feeding set points to a
well-tuned regulatory control system.
Enhancements Enable Industry Change
Emerson Process Management’s DeltaV S-series platform is designed
to streamline engineering practices and enhance PlantWeb’s project and
operations performance. One game-changing feature of the DeltaV Sseries platform is electronic marshalling.
“When a project is designed, the I/O count has to be decided very
early in the project,” said David Newman, director, global oil and gas,
Emerson Process Management. “Very often, that leaves marginal
room for error. If, later in the construction phase, we have a major
change to the process and I/O count, it would sometimes require a
redesign of the system, incorporating significant cost increases and
time delays to the project.
“As part of our ‘I/O on Demand’ approach, electronic marshalling
brings I/O wherever and whenever a user needs it. The clients decide
what type of I/O they want, when, and where they want the I/O –
whether for late project changes, during startup, during operation,”
Newman said. “They also can decide where they want the I/O – in a
control or marshalling room or in the field. They can also add channels
on a channel-by-channel basis, noting that any channel can be consumed by any controller.”
delivering project execution savings. For example, for an average platform of 5,000 I/O, a cost reduction of 58,000 man-hours is anticipated.
“When you consider the amount of time and cost in logistics in
transporting and housing personnel offshore who are completing
upgrades,” said Newman, “the use of electronic marshalling will significantly reduce the time of the upgrade, and ultimately, the costs, and
it will also improve the risk factors in safety and the potential of lost production during these critical upgrade periods.”
Emerson developed electronic marshalling in response to customer
needs. “They want their facilities to be easy to wire and operate,”
Newman said. “Electronic marshalling is a step in the right direction.”
Project implementation savings
Electronic marshalling saves significant project man-hours, and makes
late design changes easy to accommodate. System engineers can reallocate I/O on a channel-by-channel basis, simplifying system design and | September 2010 | 5
Networked, not centralized
The PlantWeb system is networked. It does not depend on a distributed control system (DCS). “PlantWeb is designed around
the fact that there’s intelligence everywhere,” Newman said. “Integrating that intelligence and getting the right information to the
right person is what’s important today.”
Emerson was a leader in developing FOUNDATION™ fieldbus
(FF), a key technology in PlantWeb architecture. Emerson devices,
systems, and software work together to deliver the benefits of digital, two-way communication using this technology.
Emerson’s Smart Wireless technology uses the IEC 62591
(WirelessHART) standard to give operators a flexibility not seen
previously, bringing “new eyes” to parts of the facility that were
previously out of reach. WirelessHART uses a self-organizing
mesh technology that overcomes limitations of “line-of-sight”
wireless installations. The network automatically finds the best communication route back to the network gateway (receiver). If a connection is temporarily blocked, signals are rerouted to adjacent
wireless devices, which act as transceivers (or repeaters), maintaining connectivity. These redundant data pathways eliminate single
points of failure.
The widely supported WirelessHART technology enables users to
quickly and easily gain the benefits of wireless technology while
maintaining compatibility with existing devices, tools, and systems.
A large number of field devices, valve and equipment position mon-
Collaboration Centers Are Key
to the Intelligent Field
With today’s focus on decreasing operational costs for remote offshore
platforms, the use of “collaboration centers” can enable companies to
solve operational issues with real-time information. Collaboration centers make the best use of scarce resources by creating an operations
hub where experts from a variety of disciplines can access information,
troubleshoot, monitor, and optimize the oil and gas fields from a single location.
The intelligent field is the perfect collaborative environment for communication, data collection, reporting, monitoring, and information sharing. These physical workspaces are intended to help people make
better, more informed decisions in order to take the appropriate actions
across the enterprise in real time, and precisely when needed. Opportunities can be prioritized, with the common goal of maintaining optimal and unbroken production.
Innovations in various collaboration technologies are helping companies make the intelligent field a reality. Today’s collaboration centers
provide a high-tech physical workspace as well as a new way of operating. Access to a complete array of digital, real-time data facilitates the
operations process and gives personnel the comfort level to make
decisions quickly and intelligently.
6 | Emerson Intelligent Fields
itors, vibration data transmitters, and smart gateways meeting this
standard are currently in use throughout the industry.
Smart engineering, smart instrumentation
Emerson has adopted the PEpC approach for project construction in
which it partners with a contractor as a strategic supplier during the
design, engineering, and procurement process. Using a PEpC instead
of an engineering-procurement-construction (EPC) model could
produce time savings of 10% to 15%, and cost savings of 4% to 8%
compared to the traditional EPC process.
Design and engineering functions are streamlined during this
process using Emerson’s DeltaV™ digital automation system. Specifically,
instrument engineering and configuration time are reduced using
DeltaV software’s standard function blocks for designing control strategies. Engineers can determine their needs by using a library of pre-engineered control strategies. A single user interface allows configuration of
I/O types including 4-20 mA, HART, WirelessHART, and FF.
Space and weight are continuing concerns with offshore projects. PlantWeb and FF allow the control room footprint to be much
smaller. Traditional DCS I/O cards consist of digital input, digital
output, and analog input cards. The DeltaV system uses a fieldbus I/O
card that can accommodate 64 channels, compared to eight channels
for traditional cards. DeltaV’s native wireless support also reduces the
amount of physical wires. Wireless technology eliminates the need and
cost for building in spare I/O capacity, and also reduces material and
labor costs for installing wire, cable tray, conduit, marshalling cabinets, junction boxes, terminal blocks, and intrinsic safety barriers.
During startup, predictive maintenance software can detect installation errors. For example, the same devices that monitor maintenance
issues on rotating equipment can tell operators if there are vibration
or lube oil problems. Instrument diagnostics can detect heat or
line plugging problems. Valve diagnostics for friction, valve seating
force, and air supply problems can also detect incorrect calibration,
incorrect valve packing, or air supply issues. To explore how
Emerson can help you optimize your production, visit
Extending the Intelligent Field
Emerson, Roxar combination
brings new growth areas to
both companies.
he addition of Roxar to the Emerson Process Management family of companies in 2009 brought a new dimension to the exploration and production marketplace. The
combination joined automation provider Emerson Process Management – a U.S. $6.5 billion unit within industrial conglomerate Emerson – with Roxar, a $200 million provider of instrumentation,
software, and modeling technology.
Like Emerson, Roxar is known for its technology innovation and
market leadership. Roxar’s metering and monitoring equipment and
well-optimization software are strong complements to Emerson’s
instrumentation products and PlantWeb digital architecture. The
resulting technological and solutions synergies open new growth
areas for both Emerson and Roxar.
“Subsea is now coming to the upstream,” said Steve Sonnenberg, president of Emerson Process Management. “The acquisition
has been strategic to extending our solutions to help E&P owners meet
the automation challenges of offshore subsea and subsurface. Roxar
is the upstream industry’s largest provider of subsea instrumentation
– a complement to Emerson’s instrumentation and valves that power
the digital PlantWeb architecture.”
Roxar’s customer base includes major multinational independents, small independents, and the majority of national oil companies.
“Joining Emerson Process Management leverages our resources
for increased customer support and response around the globe,”
said Gunnar Hviding, president and chief executive officer of Roxar
ASA. “Our service business joins an organization where service is a
core growth activity and critical to customer satisfaction. Customers
will benefit immensely from being able to go to a single company for
reservoir to refining solutions.”
The move also brings Roxar additional resources and technology
expertise that will help accelerate and drive new product development.
Roxar’s solutions combine real-time data from the company’s multiphase flow instruments with predictive geological and engineering
models to help operators continuously monitor production, observe
and control oil and gas fields from remote locations, process large volumes of vital reservoir data quickly, and use the most up-to-date realtime field information to make critical operational decisions.
“Upstream exploration and production is a very conservative
industry,” Hviding said. “It can be slow to take up new technologies.
This kind of integrated approach is already being used by major oil
companies, but the way is open for an industry player to come in and
offer a configurable industry solution. With a shared passion and focus
on solutions for our customers, together we will be better positioned
to serve current and emerging customer needs.”
Extending predictive intelligence subsea
The use of predictive intelligence in refining, processing, and other
aspects of upstream petroleum production already supplies oil and
gas companies with significant business and competitive advantages. Extension of predictive intelligence to subsea and downhole
metering and monitoring solutions will deliver immediate benefits to
offshore oil and gas operators.
Integrated reservoir-to-transmission solutions
provide increased customer support. | September 2010 | 7
Evolving Subsea Technology Brings Advances
With hydrocarbon exploration and production constantly expanding the drilling locations and understand the production potential. Our goal
into deeper water and more challenging environments, operators need is to build the most accurate reservoir model, characterize it, understand
the best information to determine the most commercially viable, envi- it with multiple scenarios, and plan around it so that when the well is
ronmentally sound, and safest ways to recover the oil and gas from a drilled, we understand its capabilities with respect to reality. That is
what Roxar technology is all about.”
Roxar’s reservoir optimization capabilities and subsea metering technologies are a key part of Emerson‘s vision for the future. Roxar’s two Predictive modeling aids drilling, production process
main product lines – Software Solutions and Flow Measurement – offer Predictive modeling also provides valuable information for drilling
the tools operators need to unlock a potential prospect. With its com- and production. “I can be at my desk in Houston monitoring the realprehensive line of real-time, in-line multiphase measurement instru- time data from the downhole monitors and the tools behind the bit
ments, as well as software for reservoir modeling and simulation, Roxar’s operating out at the rig site in the Gulf of Mexico,” Chelak said. “If the
predicted path of the well bore is moving
knowledge, technology, and services
past a certain horizon and out of the resergenerate continuous information of
voir, I can monitor this with respect to my
value to offshore oil and gas operators.
reservoir model in my office. If the data
“Reservoir modeling has progressed
from the rig starts to vary from the model,
from using big company mainframe
I can run a new model in 10 minutes to
computers to today’s very portable
have a current representation of reality.
technology,” said Robert Chelak, Roxar
“Five years ago, that would have taken
Software Solutions regional services
me a week to do. If it appears the well
manager, Americas. “I used to carry a
bore is going to come out of the reservoir,
big case containing heavy computer
I can call the driller on the rig to stop,
equipment with me to the Middle East
adjust, and change the trajectory of the
to work on projects and perform
well. It’s all about having a good model,
demonstrations. The software was very
understanding the model, and updating it
difficult to run and the scenarios took a
as new information comes in real time.”
long time. Now I use my laptop and can
In the same way, full-field modeling
very easily construct complex reservoir
Downhole monitoring optimizes production
can aid the topside facilities in predicting
models wherever I go.”
and provides critical and timely information
production. “Not only do we need to worry
With these computing changes,
on water breakthrough or gas coning.
about production coming out of the
Chelak said a greater amount of inforground, but we also need to determine
mation is now available for reservoir
modeling. “If you go back just a few years ago, there was no way you what we are going to do with it when we get it to the surface,” Chelak
could load up the amount of data coming from the field into a desk- said. “Can the facilities handle what we produce? If the facility has only
top computer system because the machine power, the memory, and the been built to handle so many barrels of oil daily, and we find out the
graphics just couldn’t handle the volumes of data. Now that’s changed. reservoir will produce more, how are we going to handle that increased
Plus, they are finding new ways of acquiring data at greater depths, capacity? If my model indicates what’s going to happen, then we need
with increased resolution and details.
to be able to slow production down or we need to increase the capac“Ten years ago we were building models with 30 faults. That took ity of the production facility.”
weeks or months to accomplish, and in some cases, it was impossible,
Preserving the integrity of the reservoir also can be accomplished
depending on the complexity. Now, we’re building models with 2,000 with predictive reservoir modeling. “In some cases we know where the
faults in a matter of days with very complex scenarios. To go from that oil is, but the question is how do we get it out of the ground optimally?
scale years ago to the scale and complexity we’re at today is just amaz- In waterflood cases, we can turn on the tap and push water through
ing. And we’re putting more information and more accuracy into these the reservoir, but if we don’t do it right, the water will go in too fast
reservoir models with less effort and time.”
and leave a lot of the oil behind,” Chelak said. “However, if we take
This accuracy will enable better well planning and predictions of our time and inject it at a consistent rate and make adjustments, we
what the reservoir actually contains. “We’re now going into areas that can simulate how the reservoir is going to act and get the majority of
have been difficult to model such as the subsalt areas of Brazil,” the oil from the reservoir. We build models to understand what’s going
Chelak said. “We have high-resolution information coming out of the to happen in the reservoir, and having a good quality model is of
data, and we need to plan very expensive wells carefully to optimize immense importance as a planning tool in reservoir management.”
8 | Emerson Intelligent Fields
“It’s a mistake to think of the subsea and topside facilities as two
separate realms,” said David Newman, director, Global Oil and Gas,
Emerson Process Management. “They are not two separate entities in
terms of data. There is a single stream of data that extends from
beneath the earth to the ocean surface.
“As subsea production systems become more complex and move
from basic well control to control of subsea production equipment
such as separators and pumps, PlantWeb’s applicability becomes
even more important,” Newman said. “For example, well production
settings depend on phase separation processing capacity and the
properties of the produced fluid, which are typically accomplished and
derived topside. With predictive intelligence applied across both the
subsea and the facility, a gas slug entering the fluid stream would be
detected, communicated, and dealt with from the topside before it
negatively impacts production on the topside facilities.”
Vincent Vieugue, Roxar Flow Measurement regional manager for
the Americas, said, “As quantities and qualities of the produced fluids become known and communicated through a digital network, you
have more and better inputs for the production system model. The
more rapidly you can update the model, the better its output is.”
Further benefits will come from outfitting Roxar technology
with Emerson’s PlantWeb™ digital architecture and HART Communication Protocol capabilities for condition monitoring and selfdiagnostics.
Wireless digital architecture through
a self-organizing mesh network.
Robert Chelak, Roxar Software Solutions
regional services manager, believes these benefits will give greater impetus to efforts to put
digital communication standards in place,
analogous to the fieldbus standards used in
downstream processing facilities. The most
common protocols today are CANbus, Modbus,
and TCP/IP.
Today, subsea operators are forced to work
with different vendors for the topside control
systems and the subsea control modules.
Industry experts have estimated that 80% to
90% of control system implementation problems are due to this issue. In one instance, a
major operator spent millions of dollars lifting multiple control modules topside once
their inability to communicate with the topside controller was discovered. As a result,
Newman said many operators are basing their
choice of a subsea control provider on the
degree of integration the provider can demon-
Using Big-loop, Little-loop Scenarios
Roxar uses a “big-loop, little-loop” approach to reservoir modeling and
simulation. Traditional workflows focus on the construction of a geological model. First, a model is built using different geological scenarios of
how the reservoir could have been formed millions of years ago. After that,
a single geologic model is run through a history-matching exercise.
“We modify the parameters within this ‘little loop’,” said Robert
Chelak, Roxar Software Solutions regional services manager, Americas.
“We may have different flow rates, different permeabilities, reservoir factors, etc., in the model that we can adjust to get the flow rates to
increase or decrease, depending on what we’re seeing, to get a historymatch to reality. Our software looks at these different parameters, the statistical variation of those parameters, and then adjusts them with the
knowledge given to try to generate a series of probable outcomes with
a good history match. We use this process to get the reservoir simulation
to match actual production history.
“However, in some cases, our simulation tool will come back and tell
us that there is no possible way for you to get a good match because
there’s something inherently wrong with the geological model. We need
go back and alter the original geological model and allow the software
to alter these parameters. This is what we call the ‘big loop.’ In the original geological model, we may have an idea that the channel width of 200
ft [61 m] was appropriate, yet perhaps that isn’t correct and we can’t get
a history match using this scenario. I can allow the software to change that
in the big loop to 300 or 400 ft [91 or 122 m], with respect to this uncertainty in this or other parameters in the model. The workflow will then iterate between the big loop and little loop to get a history match quicker than
I would if I were running the model on only one simulation model.
“Reservoir simulations deal with models that contain thousands of
cells, many wells, and in some cases, more than 20 years of history. If the
history match isn’t right the first time, it could take a long time to change
the parameters and run new cases manually. However, working with the
software allows us to make quick automated scenario models, and check
them with the simulation tool to see which parameters will make the
biggest impact on the simulation, which leads to quicker, and more
accurate reservoir models for predictions and planning.”
Integrated production system models incorporate real-time and historical data from SCADA and historian solutions into an optimization
model. Comparisons of these results with the model’s expectations pinpoint anomalies. Combined with analysis and “what-if” scenarios, comparison of real-time results with optimal parameters derived using
simulations supports better decision making.
A further advancement capitalizes on the intelligence coming from the
well using newer subsea and downhole sensing and metering technologies, allowing the derivation of the key performance indicators that
increase recovery and decrease risk. | September 2010 | 9
Measurement Tools Provide Real-time Data
Roxar Flow Measurement products give operators the answers about what
is happening subsea right now. “We’re taking the real readings of what the
models are modeling and show what’s actually happening,” said Vincent
Vieugue, Flow Measurement regional manager, Americas. “How much
production do you have? What’s the pressure/temperature? Do you have
oil, gas, or water coming through? Those are the questions we are able to
answer, and operators can compare them to what the models from the software group show. If the model says one thing, but our measurements show
something different, the model has to be modified to match what’s really
happening. By closing the loop with our data, the model for the future will
be even better.”
Problems become evident when models and measurements do not correspond. “The main focus for operators is to produce as much oil or gas
as possible, but they need to do it in a safe manner. By monitoring conditions constantly, if you detect an anomaly such as the temperature or pressure going up or down, it could be an indication that something is going
wrong,” Vieugue said. “You don’t want a pipe to burst or a valve to shut
down. That’s why you install monitoring devices all the way from the bottom of the well until you export the production from the platform.”
Vieugue said operators face increasing challenges. “The environments
where we’re drilling now are not easy ones. We’re in deeper water with
deeper wells. High pressure and high temperatures require products with
a higher quality. The need for instrumentation also increases – everything
escalates. The products we supply are proven technologies. We’re way past
the time where we have to prove what our products can do. These are fieldproven technologies, and operators can clearly see the benefits.”
Vieugue believes there are many synergies between Emerson and
Roxar. “Emerson products go right in line with technologies Roxar provides subsea,” he said. “By having more monitoring devices and by
being one company, these devices can work better together and supply
even more and better information for the user.”
One area where Vieugue sees new opportunities is in Emerson’s wireless technology. “We can apply that technology to Roxar products and take
the next step in that direction. Is there a possibility that users will suffer
from an information overload? That’s something the operator needs to
think about,” Vieugue said. “Measurement devices are becoming smaller
and faster, and users need to have a system in place to handle this information. However, the more information you get from your wells, the better models we can provide and the better production you can get from
those wells.”
strate having with the topside control system provider.
Wireless technology is another important aspect of Emerson’s
PlantWeb. Already in operation in a variety of downstream facilities,
Emerson’s Smart Wireless technology is a seamless extension of the
wired architecture. Weighing less and having a smaller footprint than
a wired installation, wireless technology can deliver significant cost
savings, especially on offshore platforms.
“People are very familiar with wireless capabilities in their dayto-day life,” Newman said. “From a personal point of view, we have
confidence in it, but the oil and gas industry is very conservative, and
changes are not quickly or easily embraced. However, our experience
has been that once they see the benefits of wireless in the field, and
see how reliable it is, they actively embrace the technology, and look
for more ways to use it.”
Digital architecture signals a step-change
Two important technology trends in upstream oil and gas exploration and production join with the potential for operators to improve
recovery, optimize production, and drive operational efficiencies.
Many oil and gas companies already benefit from the predictive
intelligence capabilities inherent in digital network architectures for
instrumentation, valves, and controls. In offshore platform environments, the result is “intelligent” platforms; floating production, storage, and offloading vessels; and related onshore facilities. Subsea
and downhole metering technologies – the means to capture well temperature, pressure, and flow data – join integrated production system
models to support improved decision making.
10 | Emerson Intelligent Fields
The combination of Emerson Process Management and Roxar
expertise and capabilities brings these two trends together,
providing enhanced insights into automated controls and advanced
optimization to bring oil and gas production closer to a closedloop process.
Immediate benefits include:
n Integration of subsea/subsurface operations with topside facilities, allowing better near real-time modeling
n Insight into actual production, a perennial challenge in oil and
gas fields with complex ownership relationships
n A high level of safety and security for employees, reducing travel
requirements to offsite locations to perform dangerous tasks.
Value-chain benefits
The value chain benefits of having increased insight (i.e., predictive
intelligence) into actual well, reservoir, and field characteristics extend
far beyond the offshore platform:
n Reservoir models – based on seismic, intuitive predictions from
geoscientists and other exploration technologies – play a major
role in determining where wells are placed
n Better production monitoring can deliver an immediate understanding of what is actually being produced
n Knowing what is flowing through the pipelines can help the downstream refineries plan their production and capacity
n Keeping employees and facilities safe from potentially hazardous conditions can result in a flawless health, safety, and environmental record.
To discover how Emerson’s Intelligent Field solutions can enhance
iding the subway system of any major city, you’re likely to
hear a multitude of languages. Often, even though people
are speaking the same basic language, regional differences can be hard to understand, leading to confusion. The same
problem can happen with electronic communication devices. Users
have a wide variety of communication protocol choices.
“This has been a source of angst for offshore operators,” said
David Newman, director, Global Oil and Gas, Emerson Process Management. “They’re looking for integrated seabed-to-topside communication and Emerson is working on building that vision.”
There has been a recent move toward more open communication
structures for the industry. “We have seen a rapid change in mindset
in the last five years or so toward open system architectures,” said
Alistair Birnie, chief executive officer, Subsea UK. “This was driven initially by the IWIS [Intelligent Well Instrumentation Standard] joint
industry project [JIP], which has been ongoing for over 11 years.”
As the first serious attempt to create an open Ethernet standard
based on the point-to-point protocol (PPP), the JIP helped move
things along. “Optical communication has taken major strides in
recent years, and whilst the PPP standard is still viable, we will see this
become obsolete in favor of direct Ethernet connect that is switch-connected subsea and mastered from the surface,” Birnie said.
And, while Ethernet has interesting benefits in some areas, Birnie
believes it isn’t always the best solution. “Another JIP called SIIS [Subsea Instrumentation Interface Standard] uses CANOpen protocol
over a four-wire multidrop connection, and is more suited to lower
level instruments such as pressure and temperature measurement,”
he said. “The point is that it is a common, non-proprietary
standard that allows open connectivity of any subsea sensor to a
control system.
“However, the secret is not just in terms of the open standard –
it is about being able to handle and manage the data throughput, and
doing so in a network that is robust and deterministic.”
In the last few years, Ethernet-based subsea controls have been
introduced in the industry. Still, this has come with a few disappointments, particularly where the network bandwidth is constrained
such as when using copper wire connections – still the most common
methodology for subsea communications by far.
Open system
are poised to
subsea controls.
“The issue is about managing the available bandwidth efficiently,
particularly where there are multiple users of the network and where
data is fragmented,” Birnie said. “Putting IT engineers into a subsea
environment has not been a particularly positive experience for
some, as they have not understood the need for packet management
and optimization, or in network access control, and systems have performed much poorer than expected because of this.”
Birnie believes that as development work opens up the bandwidth using Orthogonal Frequency Division modulation techniques
used in digital television, and as control engineers learn how to get
the best from this technology, the industry will see rapid adoption of
open architecture since it can resolve many issues.
“Using Ethernet-based protocols has taken away one level of proprietary protocol access, but it has introduced new differentiators,”
Birnie said. “Development of subsea controls now hinges on the ability to do packet switching and in having fast routing algorithms to
make the networks robust, flexible, and fault tolerant.”
Network architecture, like that offered by Emerson, also offers
advantages over centralized ones. “Probably the biggest change to the
subsea architecture is the ability to connect data sources directly to
the umbilical via a switch or router,” Birnie said. “This allows much
greater flexibility of the subsea control system without loading up the
SEM [subsea electronic module] process, and then allows the SEM
to use common simple hardware and software, thereby improving its
The long-term benefit to this is that the user can plug in virtually
any industrial network-enabled hardware into the network without
having to know very much about what’s behind the network.
“This has significant benefits where the subsea system is adapted
or extended, using updated or new instruments, and reduces the
reliance on bespoke hardware and software, both of which are major
obsolescence considerations,” Birnie said. “It also allows common
tools and software applications to be used via the network, improving productivity and allowing greater freedom without being constrained by proprietary protocols and software.”
Another benefit is that a common Ethernet stack – one largely
independent of hardware – can be used. “This reduces a considerable
element of bespoke interface software – probably the most unreliable | September 2010 | 11
Fiscal/Custody Transfer and Allocation
Getting accurate and timely measurement data from offshore and
onshore facilities demands solutions with the flexibility to meet a wide
range of applications – from the secure transfer of the measurement
data to the reliability of the measurement systems. Emerson is wellpositioned to offer a wide range of products, systems, and fully integrated services to ensure precise measurement over time, the highest
level of cost-effectiveness, and system reliability while managing the
measurement uncertainty.
Whether ultrasonic, turbine, or differential pressure, Emerson’s
Daniel flow meters are industry standards for oil and gas custody transfer and allocation metering from production to distribution. Daniel
ultrasonic meters integrate with PlantWeb’s predictive capabilities, providing intelligent meters with advanced diagnostics. Measuring and
understanding oil and gas production is critical. Daniel metering systems can predict potential system failures before they happen and sustain key metering equipment throughout its life-cycle, reducing
uncertainties and maximizing the return on the investment of clients’
metering assets.
As a supplier of flow computers, RTUs, and SCADA systems, Emerson’s Remote Automation Solutions inspire confidence that the data
are being seamlessly transmitted from the offshore or onshore field to
the clients’ operating headquarters. Emerson’s Micro Motion Coriolis
meters were the first to provide direct, accurate, and on-line measurement of mass flow, which is critical for controlling many processes.
Since their introduction in the late 1970s, Micro Motion flow and density measurement devices have set the standard for superior measurement technology. Coriolis technology has been expanded to include
highly accurate on-line density, temperature, and viscosity measurements for many applications, including custody transfer. Today’s products include sensors for measuring hazardous and corrosive materials,
high-temperature fluids, and sanitary products, which deliver accurate,
reliable, and representative production data for optimal well production and availability.
METCO specialist measurement services focus on ensuring optimum
production and throughput measurement and compliance. Audit
and consultancy services, field technicians, and office-based engineers
assist oil and gas companies in managing their fiscal, allocation, and
environmental measurement infrastructure, and meeting their commitments to partners and officials while operating in a compliant and
transparent manner.
area of code in any subsea software suite,” Birnie said. “It also can
eliminate the need for mastering of devices subsea, although the
trade-off can be a higher bandwidth requirement on the umbilical,
and if there are multiple host devices on the topside suite, this adds
to communications overhead. However, by using careful design and
efficient data packaging, this issue can be largely negated.”
Birnie added that, depending on the network architecture, using
routers can allow redirection of data packets on fault, and can allow
higher network robustness without having to have a complex communications switching layer in the server processors, again removing code that can cause problems.
New era for subsea systems
Birnie believes the evolution of Ethernet has facilitated a new area of
subsea systems that previously was difficult to achieve – that of subsea processing. “By using open Ethernet-based subsea architectures,
topside and subsea process controls can merge together seamlessly,
making the task of systems integration much easier and reliable,”
he said.
Another substantial growth area in subsea controls is in being able
to deploy data-heavy instrumentation, particularly in areas such as
multiphase flow and downhole distributed temperature measurement,
both of which can be used for production optimization. “I think we
12 | Emerson Intelligent Fields
will see future generations of subsea controls with even higher data
loading, particularly where either environmental or integrity sensors
are routed via a subsea network,” Birnie said.
Subsea UK estimates that in five years, the subsea production market will have grown 40% from 2008 levels, which will require even
more engineers and even higher levels of sophistication in sensing and
data technologies. “With this in mind, we will see an evolution of distributed subsea systems to support plug-and-play type architectures
with more of the data integration happening topside and more Ethernet or CAN-connected devices,” Birnie said. “As all-electric subsea
systems become more accepted and hydraulic components are eliminated, the need for a subsea control module – in its current form –
will be eliminated.
“Whilst it can be easier and more effective to recover a complete
assembly for repair and maintenance, the absolute need for a centralized module is no longer there,” Birnie predicts. “This will change
the dynamics of subsea control towards smarter instruments and
actuators with minimal subsea controls intelligence. Instead, the
smart instrumentation suite will have the power supplies and data
routing. This move will allow faster and more reliable system engineering and configuration at less risk to subsea operations.”
To find out how open communications can help your operations,
New Uses
s offshore operators look for ways to lower operational
expenditure and capital expenditure costs, the possibilities of wireless installations become more attractive. With
less weight, a smaller footprint, and enhanced security and reliability, wireless is changing the industry’s thought patterns.
“The offshore oil and gas industry is very conservative,” said David
Newman, director, Global Oil and Gas, Emerson Process Management.
“Traditionally, it’s been a case of ‘not me first’ when innovative technology has been proposed, yet once people see the benefits in terms of
cost and productivity, they actually end up enhancing that technology.”
Wireless technology has moved into people’s “comfort zone,”
according to Newman. “There’s a classic photo of a person using one
of the first mobile phones. The phone looks like a brick and a car battery was needed to run it. Yet now, we have these tiny phones that have
myriad uses and slip into our pockets. In that same way, as decisionmakers become more familiar with wireless technology applications
offshore, we’ll see greater industry acceptance.”
In the past several years, wireless monitoring instruments have
made their way into remote, hard-to-reach areas on offshore platforms
where high construction costs made wired devices uneconomical.
Newman acknowledges that traditional cabling will continue to be
used in contiguous areas, as well as in safety systems. However, existing facilities are taking greater advantage of wireless benefits, and new
construction projects are being built with wireless in mind.
“Reliable, robust wireless technology should be a key component of all capital projects,” said Bob Karschnia, vice president, Wireless, Emerson Process Management. “Facilities using wireless realize
savings and become smarter through simpler engineering and construction, flexible startup, faster deployment and project completion,
and changing automation needs. Further, customers need proof that
control with wireless is viable.
“We’ve responded with real-world Smart Wireless installations
using one-second updates, enhanced PID, battery management, and
IEC 62591 (WirelessHART®) communications.”
Exploring the potential
of wireless networks
is just beginning.
Emerson’s Smart Wireless enhancements are available with its
DeltaV™ S-series digital automation system. Full redundancy protects
the wireless network from any single point of failure by allowing
primary fail-over to ensure that the data are always delivered even if
there is a malfunction. Other enhancements include redundant wireless I/O, power and communications, and a redundant Smart Wireless Remote Link. The Remote Link easily links the wireless field
network into a DeltaV system.
“When operators are planning for the platforms of the future,
they’re now thinking about a combination of fieldbus, electronic marshalling, and wireless,” Newman said. “And they’re finding that wireless can be cost effective, economical, and quickly installed. It’s going
to prompt a mindset change about the design process with greater
awareness of what customers need and what they don’t really need.”
Evolution of the technology
For years, 4-20 mA analog instrumentation was the industry standard.
Beginning in the mid-1990s, the search began for a digital replacement, and FOUNDATION™ fieldbus was developed. It is now widely
used throughout the industry, especially for controls.
The first wireless networks were limited by a “line of sight” requirement – a drawback that was especially cumbersome on offshore platforms. Today, Emerson’s Smart Wireless solution uses a self-organizing
mesh technology that overcomes this obstacle. Self-organizing mesh networks continuously monitor transmissions from a variety of | September 2010 | 13
Industry decision-makers are becoming
more comfortable with wireless technology applications.
deck space of up to 4,556 sq. ft. in cabling, cable
trays, junction boxes, and cabinets.
When another study compared wireless to
the traditional hardwired 4-20 mA/HART
design, the savings were even more significant.
“They found 44% of the total points can be
wireless, which would result in a savings of
36%,” Newman said.
ment devices that keep track of pressure, temperature, flow, and vibration. The network automatically finds the best communication route
back to the network gateway. If a connection is temporarily blocked, signals are rerouted to adjacent wireless devices, and connectivity is maintained. This mesh technology is the basis for the internationally accepted
IEC 62591 standard. It enables users to quickly and easily gain the benefits of wireless technology while maintaining compatibility with existing devices, tools, and systems.
“With this technology, as you add more devices to the network, the
entire network continues to get stronger and stronger with more potential communication paths for each device to use,” Newman said. “This
is very important when you think about the ever-changing environments
your instrumentation faces every day – pumps, motors, and fans cycling
on and off, scaffolding being erected and torn down, welders, and a whole
host of other things happening all the time. With the network’s ability
to automatically reroute data, we see data reliabilities of more than 99%,
regardless of process environment or application.”
Impacting the bottom line
When Smart Wireless technology is used for 25% to 45% of total I/O on
both small and large capital projects, significant savings can result. “An
Emerson study of an actual offshore platform with about 4,000 I/O
proves wireless technology can be broadly used in process applications,” Newman said. “It is unnecessary to restrict wireless to those applications where deploying wired instruments would be too expensive or
Examination of various combinations of wired HART, fieldbus,
and wireless devices, and the projected installed costs showed wireless
to be cost-effective in comparison with the other communications
means. For the platform studied, approximately 17% of signals were economically and reliably transmitted via wireless devices. In this case,
installing wireless along with other technologies in the process control
system can realize savings of up to 7%, or more than U.S.
$1 million. An additional saving is seen in eliminating 800 wired points,
which results in weight saving of up to 35 tons, and reduces required
14 | Emerson Intelligent Fields
Scalable solutions fit a variety of needs
Emerson’s Smart Wireless can be adapted
seamlessly to cover anything from a small field
network to a full facility complex. “Smart Wireless is neither a top-down nor bottom-up
model,” Newman said. “You can begin at the plant network level
and work down to the field, or at the field network and work up. You
can start anywhere based on what your highest priority needs are.
You’re not required to invest in an expensive wireless infrastructure
throughout your facility to try out a simple monitoring application.”
Field and facility networks have different technical considerations.
Wireless field networks use lower bandwidth for short, high-priority
communications. Operating from batteries that last from five to 10
years, the field networks (usually many devices distributed in harsh
environments) have low power demands and are secure and reliable.
Emerson offers field devices that monitor pressure, flow, level, temperature, vibration, pH, and position. For facilities, Smart Wireless
brings the high bandwidth, flexibility, and expansion capabilities
required for business and operational applications. Open standards
such as 802.11 (Wi-Fi) are used to provide these solutions. Top applications for facility networks include:
n Field data backhaul
n Mobile workers
n Video
n Safety mustering and asset tracking.
Field data backhaul is the most common wireless application. If
a number of wireless field devices are in a remote area of the facility
and there is no distributed control system (DCS) rack room, a communications link (or backhaul) is installed to bring the information
back to the DCS. The other three applications affect personnel and
security. “The business driver for the mobile worker application is
worker productivity,” Newman said. “Improvements are realized
when operations and maintenance workers are able to take the control room console with them or have access to asset management tools
or procedures for troubleshooting problems.”
Video surveillance is widely implemented as part of facility
process safety and security systems. The traditional wired system is
costly and takes a long time to deploy. Using wireless networks, video
feeds can be delivered to the control room and office buildings with
flexibility not possible with a wired solution. “Video has many prac-
tical uses offshore,” Newman said. “One operator faced corrosion
issues in its FPSO [floating production, storage, and offloading] storage tanks. When they tried to determine how they were going to
monitor it, wireless video cameras were the obvious answer. Also,
using video conferencing with personnel on the platform has limited
the travel and location risks.”
Safety mustering and asset tracking improve personnel safety,
enhance facility security, and optimize the use of critical assets in a
harsh environment. “People’s safety is the highest priority,” Newman
said. “Providing full visibility to people’s locations in hazardous
areas or mustering stations is extremely critical to an efficient evacuation in case of emergency.”
Technology designed with the customer in mind
“‘Make it easy to use’ was a mantra during our entire product development process,” according to Newman. “Customers today do not
have the resources or the time to learn new technologies and buy special interfaces and software. Plus, with Smart Wireless, you don’t have
to run cables to every device, making installation much simpler than
for wired networks. In fact, the major attraction of this technology is that
you don’t have to deal with the complexity of all those wires.”
Because the Smart Wireless devices have the same process connections as traditional wired HART devices, existing procedures can be used
to complete the installation. Sensors for Smart Wireless can be calibrated
using the same configuration tools as for traditional HART devices.
Sophisticated planning and costly site surveys are not necessary for
field networks. As long as each device or gateway is within range of at
least one other, it can communicate with the network. “Site surveys are
a must to define line-of-sight communication paths in traditional
point-to-point wireless solutions or those where network reliability is
a concern,” Newman said. “These surveys can be time-consuming,
especially if equipment or other obstacles limit available communication paths.”
Adapting legacy systems for wireless use
Emerson Process Management’s Smart Wireless THUM™ Adapter
helps free up diagnostics and process information from existing
HART field instruments that were previously inaccessible in wired
legacy system installations. “Most HART instruments have rich diagnostics and process data, yet this valuable information goes unused
because older legacy systems are not equipped to receive HART communications,” Newman said. “Since it is often too expensive and
complicated to access this data through traditional wired means,
upgrading transmitters with the THUM Adapter is an easy and costeffective way to ‘see’ the valuable diagnostic and process information.”
The THUM Adapter is a WirelessHART device that can retrofit
onto almost any two- or four-wire HART device without special
power requirements to enable wireless transmission of measurement and diagnostic information. Devices with the THUM Adapter
operate as components of Emerson’s Smart Wireless self-organizing
Pilot Project Leads
to Greater Acceptance
Wiring constraints led to the successful installation of Smart Wireless at
Western Europe’s largest onshore oil field.
BP wanted to increase the available information, improve worker efficiency, and remove the need for operator rounds at its Wytch Farm oil field
in Dorset, UK. Wired transmitters were too expensive due to the wiring infrastructure need, so wireless became the best technology for this application.
The Smart Wireless network installed on one of the well sites included
40 wireless Rosemount® pressure transmitters. Two transmitters were
mounted on each wellhead and a single Smart Wireless gateway mounted
outside the process area, connected the transmitters to the control system.
Data are collated in a PI historian database with the information used for
regular maintenance and safety reports.
It took less than eight hours total to complete installation, which
included removing the old gauges, replacing them with the Rosemount wireless transmitters, and performing a three-point manual calibration check on
every device. All devices were online within 30 minutes.
“The wireless instruments have performed without losing any data
since they were installed,” Chris Geen, BP manager, said.
Wireless installation made easy. (Image courtesy of BP)
field networks.
As a result, predictive intelligence can be expanded into key areas
throughout the facility by:
n Tapping the power of in-situ meter verification for magnetic
flowmeters and Coriolis meters, enabling significant operational
n Enabling enhanced valve capabilities with in-service valve testing, alert monitoring, and valve position trending
n Remotely managing devices and monitoring health by allowing
customers to troubleshoot HART devices from their own desks
n Making any HART device wireless and eliminating the high cost
of loop wiring due to remote locations or physical obstructions | September 2010 | 15
Statoil Gullfaks Platform Sees Increased Production
Emerson Process Management’s Smart Wireless network is regarded by
one oil company as a viable and necessary solution for its operations in
the harsh environment of the Norwegian North Sea.
“We are currently in a process of qualifying wireless as a standard for
monitoring,” said Anders Røyrøy, production facilities researcher at Statoil’s Research Center in Bergen, Norway. “It also is one possible solution
in several upcoming projects.”
Statoil was occasionally losing flow from the producing wells at its Gullfaks A, B, and C platforms because of a loss of wellhead pressure. Detecting
flow loss early enables operators to flow the well through the test separator
and thus re-establish flow by reducing pressure. Bringing flow back quickly
improves throughput and, over time, significantly increases production.
The loss of flow was difficult to detect since no existing flow-metering
devices had been installed within the well pipes. “The installation on Gullfaks would not have been done with traditional instruments due to the
installation cost,” Røyrøy said. “In order to install such devices, a complete
Gullfaks A is used for storage and shipment of stable crude oil.
(Photo by Øyvind Hagen, courtesy of Statoil)
shutdown of production would have been necessary – far too expensive
in terms of lost production.”
Lack of available space complicated the situation. The wellhead was
already a crowded area and, for safety reasons, had to be kept as clear as
possible. New sensors would have to be connected back to the control
room, yet the introduction of additional equipment such as new cabling,
cable trays, and junction boxes was not possible.
Another challenge was a time difference between first occurrence of
flow loss and first detection of the loss. Platform personnel routinely
went to the wellhead – a potentially hazardous area – where they placed
their hand on the pipe to feel whether there was a temperature difference
between the pipe and ambient. Typically, well fluid is 140ºF (60°C), so the
pipe feels warm. However, if flow is interrupted, it slowly drops to ambient temperature. Temperature readings were taken only at the start and
the end of a shift, so a loss of flow could easily go undetected for long periods of time and production would be lost.
Emerson’s solution was to install Rosemount® 648 wireless temperature transmitters to indirectly indicate flow on lines at each of 40 wells on
the Gullfaks A, B, and C platforms. The wireless devices transmit data from
clamp-on temperature sensors mounted on the surface of the flow pipes.
Personnel have not seen any drop-off in performance. “Because there
is daily radio communication within the well area, it is essential that the
wireless field network can coexist without any reduction in performance,” Røyrøy said. “We have found that Emerson’s Smart Wireless mitigates the impact of interference, and the data reliability is 100%.”
Emerson’s wireless devices transmit readings back to the Smart Wireless Gateway every 30 seconds. This gateway is hardwired into the existing control system, providing operators with the real-time information they
need to react quickly to any change in flow. “The operators are not seeing any difference between wired and wireless instruments; they now know
when they are starting to lose production from their wells and can prevent
that,” Røyrøy said.
n Efficiently gathering data from multivariable devices.
Looking toward the future
Planning for future technological advances can pay off now. “In anticipating the life-cycle needs of an upcoming project, one customer
made the decision to put in 300 points of wireless from the beginning,” Newman said. “They wanted the wireless infrastructure in
place to give them the flexibility and nimbleness to address things that
they can not anticipate right now.”
Because wireless requires minimal engineering, less well-defined
areas can be specified for wireless later in the project without reworking all of the conduit and electrical work. The long-term operational
benefits come from the fact that the hurdle for incremental measurements to improve facility performance is much lower.
“The next step for offshore newbuilds is to go with wireless,” New-
16 | Emerson Intelligent Fields
man said. “Think of all the weight and cost of cable going in on an offshore platform. Those are tremendous issues and wireless can help
solve those problems. People say, ‘Why should I put wireless in? I still
have to run a cable anyways.’ It’s a fair comment, and yes, at this time,
you do have to do that for controls. But when you get things like
electronic marshalling in the field, then you don’t have to run that
multicore cable anymore.”
Newman said there are companies that, by 2015, will have offshore
platforms that are 70% wireless. He noted that wireless installations
have become an accepted part of offshore facilities within the last
three years. “Widespread use of wireless isn’t going to happen
overnight, but as the technology brings proven results in terms of costs
and productivity, the industry will see a culture change.”
To explore how Emerson’s Smart Wireless solutions can enhance
The Future
A Look into the
Predictive intelligence
will increasingly affect
how people work.
hile no one can accurately predict what tomorrow’s digital oil field will look like, several experts
shared their vision for the oil and gas industry
within the next 10 years.
The UK’s National Subsea Research Institute foresees autonomous
subsea fields as one of the future technological challenges facing the
subsea industry. Yet Emerson’s David Newman, director, Global Oil
and Gas, believes that hurdle will be overcome within the next 10
years, and processing that now takes place topside will be relocated
to the seabed. “All the processing today that you have on the platform
– the compressors, separators, and boosters – will be sitting on the
seabed,” Newman said. “We’ll be taking technology that’s currently
in use topside, ‘marinizing’ [adapting the technology for marine
use] it, and moving it subsea. We’ll have buoys on the surface that send
and receive data from an onshore control center and, possibly, a loading buoy where a tanker will come to the site, load up, and go.”
Newman also believes that autonomous underwater drones
(AUVs) that can perform simple functions will be used. “They’ll be
able to have a look and see what’s happening subsea, and will be able
to adjust or gather data. This sort of technology is continuously
evolving and growing.”
Alistair Birnie, chief executive officer, Subsea UK, an industry
group that is the focal point for the British subsea industry, concurs.
“Subsea, overall, has the greatest potential for predictive intelligent
technology,” Birnie said. “At the forefront of this is the massive innovation in autonomous underwater vehicles that can now think for
themselves and work out what to do based on what they see, and
change their missions based on higher level objectives set
by the pre-mission configure. | September 2010 | 17
The Future
Human Centered Design:
Process tasks made easy.
pressors, separators, and boosting, as
well as temperature and pressure
measurement,” Newman said. “Also,
there will be advances in subsea separator and compressor control, subsea
storage tank level and radar measurement, and subsea wireless.”
Beyond the 10-year time-frame,
instrumentation will take on the challenges of control buoy data gathering
systems and communications, and the
previously mentioned AUV control,
according to Newman.
“We also have an opportunity to use technologies that have been
applied to topside processes, and we can expect to see, in time,
autonomous production optimization technologies being deployed.
However, reservoir mechanics also would come into the skill set
required to close the loop, so it will be a while before we see this level
of integration.”
With exploration technology such as 4-D seismic becoming better refined, reservoir optimization technology is also an area where
operators are seeking more answers. Current recovery rates in the
North Sea’s Norwegian sector are averaging 45%, compared to 30%
globally, but Statoil is targeting 70% ultimate recovery rates from its
offshore fields. Integrated Operations (IO) are seen as a way to
increase recovery and improve uptime.
“Higher resolution is being seen with 4-D seismic. In order to
build a more correct model, we have to understand the reservoir
better,” said Robert Chelak of Emerson’s Roxar division. “Uncertainty
is the big thing we have to deal with, but advanced reservoir optimization technology is being delivered to expand our understanding
and people are embracing it.”
He looks forward to combining Roxar software and subsea capabilities with Emerson’s topside process control management. “Emerson saw Roxar technology and software solutions as a good way to
expand their own technology. There are a lot of good ideas and innovations under consideration so that operators can optimize their
reservoirs in smarter and quicker ways,” Chelak said.
Additional instrumentation opportunities will become available
as more complex projects require involvement from several different
partners. “In less than five years – and as processing moves to the
seabed – we’ll see technology focus on such items as subsea com18 | Emerson Intelligent Fields
Technology changes
the way people work
Intelligent Field technology not only
brings changes that speed up the
amount and quality of information
available to operators, it also will
change the way people work. Companies that integrate advances in
information and communication technology and processes with
workforce-related solutions will be on the cutting edge of the industry’s “quiet revolution.”
“The movement to use real-time data and information technology is changing the way we work,” said Tony Edwards, chief executive officer, StepChange Global, a leader in the application of digital
oilfields and integrated operations. “However, you cannot regard
technological changes as strictly IT projects. If you treat them as
such, this transformation doesn’t go very well. Technology is an
enabler, but it should enable changes to our way of working.”
Edwards noted that connecting people to real-time information
brings basic alterations to an organization by:
n Speeding up work process
n Providing data and information that crosses traditional historical boundaries
n Enabling moves to geographically remote locations
n Allowing teams with different backgrounds to collaborate on the
same assets.
“One of the drivers for these changes includes the fact that many
companies have moved out of the heartland of oil and gas production
– the Gulf of Mexico, North Sea, or Alaska – into more remote geographic areas,” Edwards said. “As a result, there’s a lot of geographic
dislocation and separation from traditional areas.” Also, with offshore
projects moving to greater depths and more remote locations, these
technologically challenging areas may not have the same infrastructure available.
“Finally, the demographics of our industry have changed. Fifty
percent of our personnel are due to retire within the next 10 years,
The Future
Technology Serving People
In 2009 Emerson formed the Human Centered Design Institute to
make process control easier to use.
Following more than five years of customer work-practice
analysis, new product development re-engineering, and organizational training, the goal of the institute is simple: make products
that are not only reliable, compatible, and cost-effective, but also
bring about a significant improvement in ease-of-use and work
force productivity.
“Process control technologies have come a long way in the past
40 years,” Peter Zornio, chief strategic officer at Emerson, said, “but
the industry has invested almost exclusively in feature and technology enhancement instead of designing around how people
actually use this technology. We believe it is time technology
began serving people, instead of the other way around.”
The primary goal of Emerson’s Human Centered Design Institute is to ensure that user work practices and improved task completion (usability or work force productivity) are at the heart of
every new product that Emerson introduces.
“There is a demographic paradox facing the industry,” Zornio
said. “In mature markets, knowledgeable workers are retiring. In
emerging markets, finding knowledgeable and skilled workers is
very difficult. By putting increased emphasis on ease of use, we can
meet this demographic challenge head-on and simply make it
easier to extract value from technology investments.”
Emerson’s DeltaV™ S-series digital automation system hardware and more than 50 new field Device Dashboards are the
first applications of this philosophy of human-centered design
(HCD). Customers and engineering contractors can have unprecedented flexibility in I/O engineering thanks to electronic marshalling. Hard-wiring each device as a unique connection from field
taking 80% of the knowledge with them. The historical model of
staffing up a project is no longer feasible. You can’t pick up 300 people and take them to a remote location anymore. They don’t want to
go there.”
With the upcoming shortage of skilled manpower resources and
the so-called “gray shift change” occurring in the energy industry, the
utilization of technology is important, but it’s how we use it that’s
more relevant. Moving to multidisciplinary work teams can bring sustainable value-added capability to the process.
“Many companies have production optimization teams that
include the reservoir people, the petroleum engineers, operations
and facilities engineers, and the commercial people,” Edwards said.
“Having the information flow allows functions to be moved anywhere around your company or even external to your company. It
enables a lot of options in the way you do things.”
However, companies need to update their processes. “You need to
address the people-change aspect of it. For example, if you have engi-
to controller, and every contact in between, is eliminated. This
means less engineering up front and fewer change orders later in
the project.
Also, by focusing on the repetitive tasks operators and maintenance staff perform and how they interface with field devices,
Emerson was able to overhaul its Device Dashboard. “We evaluated device interfaces across the industry and found a common
problem,” Zornio said. “Routine steps – which operators and
maintenance personnel perform frequently – were cumbersome,
confusing, and illogically laid out. It’s an endemic problem in the
industry. Based on user input, we believe the changes we’ve made
to the Device Dashboard will improve speed and accuracy of confidently performing these tasks.”
This innovative approach likely will impact design costs and
time. “We observed that customer project engineering and
design processes across the industry put too much emphasis on
locking down designs very early in the project, often before the
process design was complete,” Zornio noted. “Not only does this
increase FEED [front-end engineering and design] and detailed
design cost and time, but it also exposes the project to increased
labor and potentially significant change-order costs during construction. Additionally, the existing wiring processes were time consuming and laborious.”
Partnering with Carnegie Mellon University, a recognized leader
in human interface and interaction with technology, Emerson
began incubating the HCD process during the early days of its
Smart Wireless designs. “The products Emerson will introduce
based on this and ongoing research will make a profound difference in how people accomplish their tasks,” Duane Toavs, director
of Emerson’s Human Centered Design Institute, said.
neers who have worked one particular way for 20 years and now
you’re asking them to work in a very different way, how do you overcome that resistance to change? You have to make innovations in the
organization, the way people work, and the organizational processes.”
Luckily, much of today’s intelligent field technology enables operators to accomplish remote tasks they couldn’t do previously. “Many
of the technologies we need are already developed and are being
integrated in the industry including high bandwidth communication,
low cost of data storage, video-based technology, and sensor technology,” Edwards said.
Looking beyond technological applications used strictly in the oil
and gas industry also can be beneficial. “The oil and gas industry is
pretty risk aversive,” Edwards said. “Many times there will be a ‘no new
technology’ statement for a project, yet that is a barrier to taking lessons
from areas closely related to us. What’s been learned in a refinery can
be used here. For instance, Emerson’s FOUNDATION™ fieldbus technology is absolutely routine in refineries, yet in the upstream oil and gas | September 2010 | 19
The Future
industry, you routinely hear that this type of technology is ‘not proven.’
“If you look at many platform and facilities’ designs, they’re still
based on early 1980s or 1990s technology. However, we’re finding that
many brownfield projects are incorporating needed technological
changes more quickly than greenfield projects.”
Both Edwards and Birnie agree that one significant challenge
facing the industry today is the lack of personnel familiar with both
digital IT technologies and the needs of the industry. “Data management is a big and hot topic in the industry,” Edwards said. “Assuring good quality data and incubating new functions can be a
challenge. Finding dedicated data managers or digital engineers –
someone who understands not only the engineering, but also the data
and IT sides of a project – can be difficult. Engineers have to know
what kind of data they want. The digital oil field can help capture the
‘brain drain’ that’s occurring in the industry.”
“In recent years, there has been a growing skills shortage, not just
in development of controls technologies, but also in delivering projects,” Birnie added. “The use of IT technologies helps change the skill
set in some areas, particularly where the data systems are more complex, and this has certainly improved the software delivery process.
“However, subsea control is about understanding the entire subsea system and its behavior, including its interaction with the
extended production process. These attributes make it a much tougher
challenge to develop the broad competency needed to engineer subsea systems solutions, particularly as the growth in subsea in recent
years has been immense – 20% per year.
“When we can get to the point where subsea controls become a
logical extension of topside facilities controls, then we will start to
make some significant progress,” Birnie said. “I think we are starting to win on this front, but there are still too few competent systems engineers around.”
Birnie believes Emerson is well positioned for the
growth in the subsea industry. “Considering
Emerson as a whole, they have a
wide portfolio of topside control and data acquisition
capability, and this can
be extended to subsea through the use
of open data architecture,” he said.
“As the market
grows and systems
become more open, we
will see an increased drive
toward integrated topside and
Intelligent Fields provide
greater visualization of
your reservoir.
20 | Emerson Intelligent Fields
subsea systems, with the aim of reducing the hardware complexity and
increasing the flexibility of the overall process control.”
According to Birnie, Emerson’s acquisition of Roxar is conducive
to new subsea advances. “Having now a subsea sensor capability
such as Roxar, integration between subsea instrumentation can be
tightly managed using common topside and subsea software, and in
some cases, common hardware, to create a flexible and robust solution that is seamless between subsea and topside environments.
“Emerson also has the strength, through its portfolio of capabilities, to manage the evolution of automation and control for the
future – a challenge that is becoming increasingly difficult through
the increased complexity and short life cycle of commercially available components. Combined with the buying power of Emerson, this
will lead to stability of product lines and proven solutions that should
improve the availability of systems for the future,” Birnie said.
The pace of development of Intelligent Field technologies continues to accelerate as operators push into deeper, more remote environments while trying to cope with a growing shortage of people who
understand and can solve the challenges they face.
“The future for the subsea sector is very bright indeed, with both a
continued strong growth in the market and a growing desire for higher
levels of instrumentation and redundancy, particularly in ultra-deep
water,” Birnie said. “With this growth, we will see a rapid change
toward control and automation companies, such as Emerson, participating in this market. We will see from this new ideas being brought to
bear, changing the way we think about subsea controls forever.”
To see the vision of your technology future today, visit
Was this manual useful for you? yes no
Thank you for your participation!

* Your assessment is very important for improving the work of artificial intelligence, which forms the content of this project

Download PDF