oil · 2019. 8. 26. · well uop’s ccr platformers were designed to produce petrochemicals. the...
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eHANDBOOK
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TABLE OF CONTENTSRefinery of the future less focused on fuels 6
Integrated refineries and petrochemical plants get the maximum value out of every drop of
crude oil.
Hot cutover with Foundation fieldbus 10
Multiple transmitters and valves on a single segment raises the stakes.
On the edge in the oilfield 14
Digital wellheads are poised to benefit from new ABB connectivity.
Safety excellence cuts costs 16
At Petronas, doing safety right improves profits by reducing the costs of unreliability.
Use wireless to monitor thief hatches 20
Detecting hatches that are open or not fully closed reduces losses, cuts emissions and eases
compliance.
MRPL wins Plant of the Year 26
Mangalore Refinery and Petrochemicals’ “do things better” culture uses FieldComm Group
technologies.
eHANDBOOK: Oil & Gas 2019 3
www.ControlGlobal.com
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The future may or may not bring flying cars, robot servants and immortality, but it’s bringing excit-ing changes to the business of refining
petroleum. Those changes are opportuni-
ties to earn higher profits for plants that
recognize how to leverage existing tech-
nologies to improve flexibility, integration
and communication.
Integrated refineries and petrochemical
plants are the “Refineries of the Future,”
said Carrie Eppelheimer, vice president of
strategy and marketing, Honeywell UOP,
in her session at Honeywell Users Group
Americas 2019, this week in Dallas. Inte-
grating petrochemical capabilities helps
refineries “Get the maximum value out of
every drop of crude oil, and respond to
market drivers.”
Those drivers include a new regulatory
environment. On January 1, 2020, the Inter-
national Maritime Organization (IMO) will
implement a new regulation for a 0.50%
global sulfur cap for marine fuels. The
industry expects this could drive the price
of high sulfur fuel oil $20 to $40 per barrel
lower than the price of crude oil.
Instead, “High-sulfur bunker fuel is a feed-
stock we can convert to higher value
products,” said Eppelheimer. “Should we
convert it to gasoline or diesel? The answer
is obvious when one price is higher, but
what if both are declining? The best answer
may be to convert it to petrochemicals—
ethylene, propylene, etc.”
INTEGRATION ON THE RISEHowever, the United States lags behind
Refinery of the future less focused on fuelsIntegrated refineries and petrochemical plants get the maximum value out of every drop of crude oil.
By Paul Studebaker
eHANDBOOK: Oil & Gas 2019 6
www.ControlGlobal.com
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other countries in integrating refining and
petrochemical complexes. “Today, refiners
can continue to export higher sulfur, higher
benzene, and higher RVP gasoline to Africa
and Latin America,” Eppelheimer said.
But the export market is always changing
because, as small economies grow, and
fuel demand reaches the level to support a
250,000 bbl/day refinery, the country usu-
ally inves https://www.controlglobal.com/
assets/Uploads/2-2-carrie-eppelheimer-
uop-Art.jpg ts in local fuel refining and
production. Often these plants also pro-
duce petrochemicals.
Integrated refining and petrochemical
plants are expanding in the U.S. as well.
There’s still a demand for exported gas-
oline, and more refineries are adding
production for propylene and ethylene,
as well as and naphtha for export. “We
used to have separate facilities and ship
between them, but now we’re seeing more
integrated plants.” “This trend isn’t just
a paper exercise. The plants are real. Five
years ago for example, only 15% of Honey-
well UOP’s CCR Platformers were designed
to produce petrochemicals. The rest were
designed to produce fuel. In 2018, over
65% were designed for petrochemicals.”
“We use six metrics to drive higher effi-
ciencies in refineries,” Eppelheimer said.
These include:
1. Carbon: “Use every molecule of carbon
processed in the plant.”
2. Hydrogen: “Minimize the number
of times we add or remove it” from
a hydrocarbon.
3. Utilities: “Using less energy saves
money and reduces the CO2 footprint.”
4. Emissions: Greenhouse gases, particu-
late emissions, SOx, NOx, and more.
“The product value goes from $60/ton of coke to $850/ton of petrochemicals. And you reduce water consumption because you don’t need it to cut the coke out.” Honeywell UOP’s Carrie Eppelheimer discussed the new product mix of tomorrow’s refinery, which leans more toward petrochemicals than fuels.
www.ControlGlobal.com
eHANDBOOK: Oil & Gas 2019 7
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5. Water: “It’s a scarce resource. In the
Middle East and India, they often must
desalinate the water, and even in the
U.S., there are shortages due to regional
droughts.”
6. Capital: Maximize return.
FROM REFINERY TO PETROCHEMICAL IN THREE STEPS“We look at the six efficiencies and opti-
mize them for you,” Eppelheimer said of
Honeywell UOP’s work with oil and gas
companies. For example, a typical delayed
coker or FCC refinery may chose a phased
approach to get from gasoline to petro-
chem. The first phase is to replace the
delayed coker with a slurry hydrocracker.
“The product value goes from $60/ton of
coke to $850/ton of petrochemicals. And
you reduce water consumption because
you don’t need it to cut the coke out.”
Next, add an aromatics complex to pro-
duce paraxylene, benzene and toluene.
“Finally, go into propane dehydrogeni-
zation and steam cracking,” Eppelheimer
said. “I like to think of the propane
dehydrogenation unit as a hydrogen
machine that just happens to produce pro-
pylene. This provides hydrogen to feed
back into the hydrocracking processes.”
With these additions under Honeywell UOP
guidance, a refinery can move from $20/bbl
to $50/bbl net cash margin, Eppelheimer
said. The facility can become flexible (can
change product mix), integrated (giving
high margins and value), and connected.
Connecting the plant is particularly import-
ant. “Some 50% of skilled workers will
retire within the next seven years,” Eppel-
heimer said. That means fewer skilled
workers even as increasingly integrated
operations become more complex. “Our
answer is to upload your data to a secure
cloud environment and compare actual
operating data to an optimal digital twin of
your plant., This allows 24/7/365 compar-
ison of actual to optimal performance to
identify in real time the changes you can
make to maximize return. This means our
incentives are aligned, so your best day is
also our best day.”
www.ControlGlobal.com
eHANDBOOK: Oil & Gas 2019 8
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Refineries and other process facilities routinely upgrade and even change control systems while the process continues to run, a procedure often called
a hot cutover. But they’re usually done one
loop at a time, minimizing the time each
loop is in manual and the potential for the
process to go out of control. Foundation
Fieldbus (FF) puts multiple transmitters
and valves on a single segment, raising the
stakes when it’s time to change out a field-
bus interface module (FIM).
Marathon Petroleum’s Detroit refinery
successfully upgraded the FF-networked
system on its gas/oil hydrotreater with-
out shutdown recently. The starting point
was two Honeywell C200 controllers and
20 FIM2 Fieldbus interface modules with
220 Foundation Fieldbus devices and
403 measurements and valves; 11 Series A
conventional I/O; heater/compressor SIS
handshaking; and 585 control modules. Hot
cutover was to two Honeywell C300 con-
trollers and 14 FIM4s; Series C conventional
I/O; and SIS communication via Peer Con-
trol Data Interface (PCDI).
“When we went to the existing system from
a Bailey system, we didn’t do everything as
well as we wished we had. We had 220 FF
devices and 403 FF points on two C200
controllers. We had no spare capacity,”
said Ed Bullerdiek, process control engi-
neer at the refinery, to attendees of his
session at Honeywell Users Group Americas
2019, this week in Dallas. The C200s were
designed to be redundant, but they would
no longer failover.
Hot cutover with Foundation fieldbusMultiple transmitters and valves on a single segment raises the stakes.
By Paul Studebaker
eHANDBOOK: Oil & Gas 2019 10
www.ControlGlobal.com
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“Also, programming of the 585 control
modules (CMs) was not up to standards.
Standardized programming improves sup-
port—technicians can understand it quicker
in the middle of the night,” Bullerdiek said.
“It was time for an upgrade.”
Moving FF from one system to another
was not unfamiliar, but they hadn’t done
it on critical controls. And, on this system,
the safeties and e-stops are in the DCS,
“so we had to be very careful,” Bullerdiek
said. “Could we cut over fast enough so
the process doesn’t get away from us?
Also, we had to convince operations that
we weren’t crazy.”
METHODICAL METHODOLOGYTo answer the speed question, “we had por-
table FIMs and C300s in a box, so we could
test our hot cutover procedure,” Bullerdiek
said. With some effort, “we got it down
to 15 to 20 minutes from time out to time
back on for each segment. If we did critical
instruments first, those could be back online
in 10 minutes.”
With speed established, Honeywell and
Bullerdiek built a project schedule spread-
sheet—a plan that described the sequence,
risks and special considerations for all the
segments. Working with the production
team in half-day meetings over several
weeks, “we risk-ranked all the segments,
and documented the specific risks and their
mitigations,” Bullerdiek said. “For example,
one of the bypass valves is undersized. We
had to cut charge rates the day we changed
over that segment.”
Where a control scheme is complex, they
planned to get the entire control done in
one day so they wouldn’t have to revisit it.
“We wrote a script for each segment to be
sure we would do everything, with notes
about cautions and special circumstances,”
Bullerdiek said. “Make sure you have
enough FIM licenses. We didn’t, but were
able to empty the FIMs, harvest the licenses
“Could we cut over fast enough so the process didn’t get away from us? Also, we had to convince operations that we weren’t crazy.” Marathon Petroleum’s Ed Bullerdiek
www.ControlGlobal.com
eHANDBOOK: Oil & Gas 2019 11
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and move them to the next job as we went.
Plan so you don’t get yourself into a corner
where you need another license to get out.”
They also checked the physical condition
of the work. “Can you remove the wiring
covers, or are they rusted on?” Bullerdiek
said. “Is there water in the segment pro-
tectors? Verify that communications are
working—can you ping the box? Check the
diagnostics on all the segments and fix any
problems—replace any bad transmitters. If
you can’t fix them, note them because, after
cutover, you’ll own them.”
HOT CUTOVER BY THE SCRIPT“Honeywell helped us write scripts for all 39
segments that we cut over in three weeks,”
Bullerdiek said. Keep track of which seg-
ments are done and where you are in the
process, so you don’t skip or repeat steps,
he advised. Notify the operator of the risk
level associated with risky segments, so
they can be alert to any problems.
With the integrated safety interlocks, “we
told the operators, ‘Whatever you do, don’t
shut off the heaters,’ because we weren’t
sure we could get them back on,” Bullerdiek
said. “And, we brought in extra operators
from other shifts to do the necessary field
work while we worked on segments.”
When it’s time to cut over, first, inactivate
the devices and unassign them from FF.
Then delete them from the segment and
start the field team moving the wires. While
they do that, move and reload the devices,
and move the CMs. When the wiring shows
up, turn it back on.
Cutover is best done with two people to
allow cross-checks and avoid mistakes.
“We could usually do three segments per
day, sometimes four,” Bullerdiek said. “Use
a field calibrator to verify each segment.
Then, stroking the valves from the control
room verifies that the segment and wiring
are correct.”
After cutover, there will be follow-up work.
“Deleting CMs breaks all the links to other
CMs, the historian and alarm groups,” Bulle-
rdiek said. “I made a spreadsheet to keep
track of these and then came back and
reloaded them.”
The plant held off on the demolition work
until the hot cutover was complete, so no
one could get overzealous and remove
something we might need, Bullerdiek said.
“We’ve done a lot of cutovers,” Bullerdiek
concluded. “Production told us this was the
smoothest one yet,” he said.
www.ControlGlobal.com
eHANDBOOK: Oil & Gas 2019 12
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The future is built on digital. And the tools are already in place to dig-italize your upstream operations, even with conventional wellheads. All you
might need is the right connectivity. The
information value chain starts with mea-
surement and sensor data that is sent to
controllers and on to a SCADA system
for diagnostics and analysis. Wireless
connectivity can then enable analytics in
ABB Ability and the move toward autono-
mous operations.
“The intention of ABB Ability is to create
a digital platform to help you be auton-
omous,” explained Giulia Seikel, ABB
product manager, field-mounted flow
computers and RTUs, who spoke at ABB
Customer World this week in Houston. “We
are ready to do more digitalization of the
wellhead. We just have to ensure that we
have connectivity and the right protocol.
It’s not a huge investment. Everything is
already out there.”
At today’s typical wellhead, you already
have instrumentation and a center point of
control as well as connectivity with SCADA
and enterprise systems, explained Seikel,
“but limitations do exist.” The analytics
available depend on what data is being
collected, and polling protocols mean
new data requests and simulations are not
necessarily supported. “It’s not bad,” said
Seikel. “It’s just that a further level of con-
trol is needed.”
Cloud connectivity and computing promise
to fill in these gaps, Seikel said. ABB’s Mea-
surement & Analysis division, for example,
On the edge in the oilfieldDigital wellheads are poised to benefit from new ABB connectivity.
By Mike Bacidore
eHANDBOOK: Oil & Gas 2019 14
www.ControlGlobal.com
-
is moving to event-driven protocols, noted
Seikel. “And because data access is via a
true API, or application programming inter-
face, every time there are changes, you will
see the information in real time.”
The MQTT protocol in particular is appro-
priate for the digital oilfield because of its
client/broker configuration using a publish/
subscribe pattern and adjustable topics. “On
a well pad, you need to know what’s happen-
ing when it happens,” explained Seikel. “This
is why we are implementing MQTT in our
RTUs. You only transfer data when there are
changes, but you don’t have to wait for the
next polling cycle.” In this configuration, many
systems can subscribe to the same topic, but
not all systems will need the same data.”
“We are ready to do more digitalization of the wellhead. We just have to ensure that we have connectivity and the right protocol.” ABB’s Giulia Seikel explained how equipping the company’s RTUs with the MQTT protocol will allow new levels of wellhead digitalization for the company’s oil and gas customers.
www.ControlGlobal.com
eHANDBOOK: Oil & Gas 2019 15
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Safety is typically viewed as a nec-essary expense. It isn’t free, but doing it right can improve profits when it reduces the costs of unreliability,
as demonstrated by a Petronas refinery in
Malaysia and explained at the EcoStruxure
Triconex User Group meeting this week in
Galveston, Texas.
“Similar to airplane cockpit instrumentation,
the plant instrumentation must be working
perfectly or the plant is not fit and safe to
operate,” said Sharul Rashid, principal engi-
neer, instrument control systems, Petronas.
The safety system is a critical layer of pro-
tection. “When alarms come in, they have to
be attended to, or you get Bhopal.”
Petroliam Nasional Berhad (Petronas)
is Malaysia’s fully integrated oil and gas
multinational, ranked among the largest
Fortune 500 corporations. It has assets
in more than 65 countries, is among the
world’s top five oil and gas companies (in
terms of production), and is the most prof-
itable company in Asia. Rashid’s refinery is
on Malaysia’s east coast. Its total of about
15,000 tags include 1,086 fire & gas, 3,202
safeguarding and 11,918 DCS tags.
At Petronas, “We have been successfully
using structured approach to properly
manage the instrumented protective func-
tion/safety instrumented function (IPF/
SIF) lifecycle.” IPF Classification is divided
into three categories based on the nature
of business process. The plant instrument
team is responsible to:
Safety excellence cuts costsAt Petronas, doing safety right improves profits by reducing the costs of unreliability.
By Paul Studebaker
eHANDBOOK: Oil & Gas 2019 16
www.ControlGlobal.com
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1. Ensure that all IPF in the existing plant
are classified via an IPF study, to be
conducted by GTS (Group Technical
Services).
2. Ensure that data used for the IPF study
are the latest and updated.
3. Be the custodian of the master copy of
the finalized report
The management of change (MOC) project
team is responsible to:
1. Ensure that new IPF tags are classified
via IPF Study to be conducted by GTS.
2. Properly hand over to the instrument
and maintenance teams all the related
IPF documents.
When the plant was new, an instru-
mented protective function (IPF) study
showed using one out of two voting (1oo2)
transmitters resulted in poor availability.
Two out of three (2oo3) was more reli-
able, but 1oo2 was used where it met the
safety requirements.
At hand-off and every five years, IPFs are
studied and reclassified as needed. “Once
you have made the study, don’t put it
on the shelf. Study it, and implement the
changes it suggests as a project,” Rashid
said. “If the current configuration doesn’t
meet the requirements, close the gaps.
But, if the CAPEX is very expensive, we
must apply ALARP (as low as reasonably
practical).”
Projects also can be driven by profitability.
Lost production due to lack of availability
has a cost, and that is considered in the
safety review. “At Petronas, we have to
design to meet both safety and availability
“Allowing a one-hour delay on 100 loops, at $10,000 per loop, can significantly improve profitability.” Petronas’ Sharul Rashid discussed how safety instrumented functions at one of the company’s refineries in Malaysia.
www.ControlGlobal.com
eHANDBOOK: Oil & Gas 2019 17
-
criteria,” Rashid said. The product loss
equation (PLE) changes with the price of
oil, which can change the cost of availabil-
ity and drive a change from less reliable
1oo2 to more reliable 2oo3 if the cost of the
change is not prohibitive.
“Safety standards are many and confus-
ing, and you need to keep up on them,”
Rashid said. “A lot of things change when
the standards change. It’s a constant chal-
lenge.” Being innovative and applying the
latest standards has allowed Petronas
to perform safety system projects that
improve profitability.
For example, NAMUR safety standards
allow up to one hour for response to a
transmitter alarm. Petronas may place a
time-limited, automatic over-ride on 1oo2
systems to allow the plant to respond to a
transmitter malfunction without tripping the
safety system, Rashid said. “Allowing a one-
hour delay on 100 loops, at $10,000 per
loop, can significantly improve profitability.”
In other cases, 1oo2 can be converted to
2oo3 by adding a transmitter. Where wiring
costs are prohibitive, it might be a wireless
transmitter. Where another penetration
is not practical, it may be possible to use
a nearby process transmitter. “When it is
not practical to add a transmitter due to
penetration or wiring costs, we can use a
control transmitter with a barrier,” Rashid
said. “One channel goes to the DCS, and the
other channel from the barrier goes to the
safety system.”
In this case, it’s necessary to provide a pro-
cedure for maintenance to override the
safety system when needed for control
system maintenance.
The refinery also takes full advantage of
valve and transmitter self-diagnostics,
automatic safety system testing, and other
condition-monitoring techniques to improve
reliability. It’s just one way they help keep
Petronas safely near the top of the For-
tune 500.
www.ControlGlobal.com
eHANDBOOK: Oil & Gas 2019 18
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Thief hatches (Figure 1) are installed on the top of low-pressure and atmospheric tanks in the oil and gas, chemical, pharmaceutical, biogas, water
treatment and other industries to allow
access to tanks. They can be used to take
samples of the tank’s contents and deter-
mine the level of the tank, and they protect
the tank from overpressure and exces-
sive vacuum.
The thief hatch acts as a pressure safety
device on the tank. When closed and
latched, two separate, spring-loaded seals
protect against excessive pressure or
vacuum. If excessive pressure builds up in
the tank, the hinged hatch cover will break
its seal, lift up, and allow pressure to escape
to the atmosphere. When the pressure or
vacuum is reduced to the setpoint, the seal
is reseated by either spring, sealing the
tank.
When a thief hatch closes—either from
gravity or from a worker closing it—the
hatch may not seal unless it’s firmly
latched. This allows vapors in the tank to
leak into the atmosphere, which can vio-
late regulations.
To avoid stiff penalties and protect the
environment, Great Western Oil and Gas
Co. (https://gwogco.com) installed wireless
thief hatch monitoring on its oil tanks in the
Denver-Julesburg (DJ) Basin in Colorado.
The DJ Basin is a 70,000-square-mile area
in northeast Colorado, southeast Wyo-
ming and southwest Nebraska. More than
52,000 wells have been drilled in the DJ
Basin. Great Western has more than 600
Use wireless to monitor thief hatchesDetecting hatches that are open or not fully closed reduces losses, cuts emissions and eases compliance.
By Vance Ray
eHANDBOOK: Oil & Gas 2019 20
www.ControlGlobal.com
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operating wells there, producing nearly
13,800 barrels of oil per day.
Great Western is a top-10 driller in Col-
orado, among the top 100 drillers in the
U.S., and makes every effort to meet all
environmental regulations—especially in
Colorado, where penalties for non-compli-
ance are severe.
TOUGH REGULATIONSColorado has some of the oil industry’s
toughest environmental regulations. The
Colorado Dept. of Public Health and Envi-
ronment requires monitoring of thief
hatches on oil and water tanks to prevent
release of methane and volatile organic
compounds (VOCs) to the atmosphere. Its
regulation, XII.E.4.d reads, “For all atmo-
spheric condensate storage tanks, the
owner or operator shall check for and docu-
ment on a weekly basis that the thief hatch
is closed and latched.”
To enforce the regulation, Colorado inspec-
tors regularly check for emissions from
leaks and open thief hatches with ther-
mal scopes and infrared cameras. The
state inspectors document any open thief
hatches, and compare their records to
the producer’s by time and location. If the
producer can confirm the thief hatch was
open—perhaps for maintenance or sam-
pling—at the same time as the inspector
found it open, then there’s no problem and
no penalty. If the producer can’t confirm
from its records why the hatch was open,
penalties and fines are assessed. Penalties
are severe, with fines up to $15,000 per day
per open thief hatch, and many facilities
have scores of thief hatches per site.
Oil producers nationwide fear the U.S. EPA
will soon adopt a similar regulation, and are
searching for ways to cost-effectively moni-
tor their thief hatches.
INSIDE A THIEF HATCHA thief hatch is a rugged device designed
for harsh environments and handling by
“less than gentle” users. Made from cast
TAKEN FROM THE TOPFigure 1: Thief hatches on the tops of tanks at Great Western Oil & Gas Co. in Colorado allow access to the tank and protect the tank from overpressure. If left open, huge fines can result.
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eHANDBOOK: Oil & Gas 2019 21
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aluminum, thief hatches are
used on fiberglass and steel
tanks in the oil and gas,
chemical, pharmaceutical,
biogas, water treatment and
other industries. Most tanks
used in these heavy indus-
try applications come with a
thief hatch (Figure 2).
The thief hatch has a latch
that locks the lid closed.
If an operator opens the
hatch to check tank level
or take a sample, he or she
lifts the latch, raises the
lid, performs the necessary
function, and closes and
latches the hatch. If the lid
isn’t properly latched, the
tank will not be sealed and
will vent to atmosphere.
(Figure 3) This is what Col-
orado wants to eliminate
from production facilities:
the unnecessary release
of methane and volatile
organic chemicals (VOC)
into the atmosphere.
MONITORING THIEF HATCHESR3 Automation (http://
r3automation.com), an
automation services com-
pany in Windsor, Colo.,
has been working with
Emerson Process Automa-
tion and several upstream
oil and gas companies to
develop a thief hatch mon-
itoring system. Rosemount
702 discrete WirelessHART
transmitters (Figure 4)
LatchLatch pin
Tank vapor space
Thief hatch lid
Tank vapor space
LatchLatch pin
Tank vapor space
Thief hatch lid
Tank vapor space
HATCH SECUREDFigure 2: A thief hatch has a lid that can be opened manually. The latch (upper left) keeps the lid closed and the tank sealed.
POTENTIAL VIOLATIONFigure 3: An unlatched thief hatch allows volatile gases to es-cape, and if detected by the State of Colorado, fines of up to $15,000 per day, per open hatch.
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eHANDBOOK: Oil & Gas 2019 22
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can be installed on exist-
ing thief hatches and
tank batteries to ensure
the hatches are closed
and latched.
The concept is fairly
simple: a switch at the
latch (Figure 5) detects
when the latch is closed.
The switch is non-pow-
ered, has no magnets, is
easy to install on new or
existing thief hatches, and
no hot work is required.
The switch is wired to an
intrinsically-safe, wire-
less transmitter. The
battery-powered transmit-
ter is also easy to install. It
requires no power wiring
and no signal wiring, so
it can be mounted in any
convenient location on top
of the tank. To conserve
battery life, the scan rate
is once per minute—more
than sufficient for this mon-
itoring application.
The estimated cost for
installing a WirelessHART
thief hatch monitoring
system on one tank battery
(eight tanks) was calcu-
lated to be about $8,300,
FITTED FOR DETECTIONFigure 4: This thief hatch at Great Western Oil and Gas is fitted with a WirelessHART monitoring system developed by R3 Au-tomation. When the latch is not closed, the wireless transmitter sends a signal to the facility’s controller so that it can be logged or an alert can be sent out.
SIMPLY INSTALLED SWITCHFigure 5: A simple switch (yellow) detects if the latch is open or closed. The switch is non-powered, has no magnets, is easy to in-stall on new or existing thief hatches, and no hot work is required.
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eHANDBOOK: Oil & Gas 2019 23
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including switches, wire, terminations, trans-
mitters and labor.
The per tank cost can be substantially
reduced if latches on a tank battery are
wired in series to a single transmitter. This
type of installation will indicate if one of the
hatches in the bank is open, but not which
one. In practice, an operator would be sent
to site to determine which one needs to
be fully closed and latched. This method
of monitoring complies with regulations, is
the most practical, and allows very quick
response to any open hatch conditions.
If a tank farm doesn’t already have a Wire-
lessHART infrastructure, the cost of a
WirelessHART gateway must be added.
To date, R3 Automation has installed
WirelessHART thief hatch monitoring
systems on more than 100 tanks at five dif-
ferent oil producers in the DJ Basin.
WORKING WIRELESSLYAt Great Western’s tank farm near Brighton,
Colo., WirelessHART thief tank monitors
were installed on two water and 12 oil tanks.
The tank monitoring system is arranged
in banks as shown in Figure 6. At the top
of the figure, oil tanks 2, 4 and 6 are wired
in series to channel 1 of the WirelessHART
transmitter. Water (H2O) tank 1 and oil tanks
1, 3 and 5 are wired in series to channel 2 of
the WirelessHART transmitter.
At the bottom of the figure, oil tanks 7, 8,
10 and 12 are wired in series to channel 1 of
the WirelessHART transmitter. Water tank
H20 2 12 11 10 9 78
H20 1
CH1
CH2
CH1
CH2
1 2 3 4 5 6
WIRED TO WIRELESSFigure 6: Great Western’s tank farm has WirelessHART thief hatch monitors on two water and 12 oil tanks. At the top, oil tanks 2, 4 and 6 are wired in series to channel 1 of the WirelessHART trans-mitter. Water (H2O) tank 1 and oil tanks 1, 3 and 5 are wired in series to channel 2 of the Wire-lessHART transmitter.
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eHANDBOOK: Oil & Gas 2019 24
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2 and oil tanks 9 and 11 are wired in series
to channel 2 of the transmitter. The wireless
transmitters send their data to a gateway
mounted on a DIN rail in the production
facility’s main control room.
In addition to the thief hatch monitors,
the tank farm has 30 more Rosemount
WirelessHART level switches, temperature
transmitters and pressure transmitters
mounted on the tanks to create a compre-
hensive tank monitoring system. The data
from all transmitters goes to the Wire-
lessHART gateway, which is hardwired to a
TotalFlow RTU. The system is programmed
to monitor the thief hatch signals and report
any open hatches to the operators.
Because the tanks are wired in four banks,
operators can narrow down an open hatch
condition to, at most, four tanks, making
it quick and easy for field technicians
to locate the offending hatch and latch
it closed.
NO MORE FINESThe monitoring system alerts operators to
open hatch conditions within one minute,
allowing quick resolution of any problems.
Field technicians no longer need to peri-
odically monitor and document the status
of thief hatches manually, but instead only
need to respond to an open hatch alert.
This reduces manpower requirements for
monitoring thief hatches, and demon-
strates Great Western is employing the
best available technology to protect the
environment and comply with regulations.
Great Western is not only reducing emis-
sions for the benefit of its neighboring
communities, it’s containing gases that can
be recovered and sold.
In addition to the 14 tanks in Brighton, R3
Automation has installed WirelessHART
thief hatch monitors at two other Great
Western tank farms. To date, none of
those thief hatches have been detected
open by the State of Colorado because
the facility can now react very quickly to
any open hatch conditions.
Although Colorado is the only state so far
to issue tough regulations for monitoring
thief hatches, such regulations are prob-
ably coming from the U.S. EPA or from
individual states. WirelessHART thief hatch
monitoring is a cost-effective solution to
avoid fines, reduce product loss to the
atmosphere, and cut emissions.
Vance Ray, founder, R3 Automation, can be reached
at vray@r3automation.com.
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eHANDBOOK: Oil & Gas 2019 25
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Brave poker players go “all in” to show their confidence in their cards. Equally bold process engineers demonstrate similar commitment when
they implement steadily increasing ratios of
advanced digital communication protocols
like HART, WirelessHART and FOUNDA-
TION Fieldbus. However, only an elite few
go on to claim the FieldComm Group’s
annual Plant of the Year Award, and earn
the much-deserved recognition that goes
with being a leading adopter of FieldComm
protocols and technologies.
This year’s winner, Mangalore Refinery and
Petrochemicals Ltd. (https://mrpl.co.in),
exhibits all these qualities, but it’s also
noteworthy because it’s the first recipient
from India, and represents the nation’s bur-
geoning oil, gas and petrochemical sector
that’s been rapidly securing a preeminent
place on the worldwide stage. MRPL’s
staff reports its “do things better” culture
inspires it to be a pioneer and frontrunner
in hydrocarbon processing, adopt digital
communications for process control, and
continuously strive for more effective utili-
zation of its resources and facilities. MRPL
jumps wholeheartedly into everything it
does, including implementing FieldComm
Group solutions.
Established in 1995, MRPL is a 15 million
tonnes per annum (MMTPA) oil and gas
refinery located on 1,550 acres in Mangalore,
Karnataka state, on the west coast of India.
It’s part of India’s state-owned Oil and Nat-
ural Gas Corp. (ONGC), a Navaratna (Nine
Precious Gems) company, and its full range
of products include liquid petroleum gas,
MRPL wins Plant of the YearMangalore Refinery and Petrochemicals’ “do things better” culture uses FieldComm Group technologies.
By FieldComm Group
eHANDBOOK: Oil & Gas 2019 26
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Motor Spirit (gasoline), High Speed diesel
gas and oil, kerosene, aviation turbine fuel,
naphtha, coke, polypropylene, fuel oil, bitu-
men, sulfur and others. It also supplies raw
materials such as naphtha and mixed xylenes
to ONCG Mangalore Petrochemicals Ltd.
(OMPL), which is a 0.9-MMTPA joint-ven-
ture petrochemical facility by ONGC and
MRPL that started operations in 2014. OMPL
is completely built on digital technology
including FOUNDATION Fieldbus for process
control, and HART for emergency shutdown
(ESD) and fire and gas (F&G) systems.
STRIDING INTO FIELDBUS MRPL started its journey into FieldComm
Group technologies in 2005, when it installed
all-digital communications on its isomeriza-
tion unit. This project included implementing
all process control loops with FOUNDATION
Fieldbus with control in the field (CIF) func-
tions, as well as HART transmitters used in
its safety instrumented systems (SIS). On
the strength of this success, MRPL raised the
stakes in 2012 by also commissioning more
than 10 process units, cogeneration plant and
utilities at its 3-MMTPA refinery with FOUN-
DATION Fieldbus, HART and WirelessHART.
They’re also MRPL’s default process control
protocols for future upgrades and added
capacity projects.
“We had experience with digital protocols
such as DE, Brain and HART since MRPL’s
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inception in 1995, and also used TRL/2
bus for tank gauging since then,” says
Basavarajappa Sudarshan, chief general
manager for electrical and instrumenta-
tion at MRPL and project team leader. “We
learned about FOUNDATION Fieldbus on
the Internet and from suppliers. Its advan-
tages included less cabling needed and a
smaller footprint in the plant’s Yokogawa
DCS in terms of I/O, panels and rack
space required.
“This led us to seek acceptance from MRPL
management for an upgrade including
interoperability of field devices. We vis-
ited with major DCS suppliers, and did
many interoperability tests during four to
six weeks in 2004 to resolve concerns and
anxiety about such a new installation. This
is how we introduced FOUNDATION Field-
bus in our new isomerization plant in 2005,
which made MRPL the first company in
India to construct a hydrocarbon process
unit using entirely FOUNDATION Fieldbus
for closed-loop process control.”
CONVINCING COWORKERSBeyond determining the technical advan-
tages of FOUNDATION Fieldbus and other
FieldComm Group technologies, Sudarshan
reports that he and his team had to con-
vince colleagues, including operators and
managers at MRPL, that migrating to dig-
ital communications would be worthwhile
and wouldn’t hinder operations. Other core
team members included: Suryanarayana,
chief project manager; Ganesh Bhat, chief
instrumentation manager; Allen John, senior
instrumentation manager; Muralidhara
Karanth, instrumentation manager, and
Deepthi K.M., assistant instrumentation
manager, who added to the discussion
about MRPL’s successful use of FieldComm
Group technologies.
“We ensured participation of everyone
concerned like C&I, projects and process
operations in discussions and technical pre-
sentations,” explains Sudarshan. “In 2005,
technicians with experience with conven-
tional DCS and field devices took some time
to understand the new digital technology.
However, with guidance from our field
device and other suppliers, they were trained
on the job, and quickly streamlined use of
FOUNDATION Fieldbus, which was initiated
during pre-commissioning. The team had no
issues in adopting the technology.”
Sudarshan also credits MRPL management
with giving his team and other staffers the
crucial support they needed to evaluate,
design, test and implement HART, Wire-
lessHART and FOUNDATION Fieldbus into
their process applications. “Management gave
us a lot of freedom, which enabled our excel-
lent people on the forefront of these projects
to be open to FOUNDATION Fieldbus,” says
Sudarshan. “Many were skeptical about these
digital technologies, so they were first teased
and tried on non-critical, open loops before
being used on closed loops. Once users and
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eHANDBOOK: Oil & Gas 2019 28
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managers got more confident, we were able
to take everything forward.”
BIG MOVES = BIG REWARDS Consequently, MRPL reports that adopting
FieldComm Group and other digital tech-
nologies on entire process units allowed its
installed equipment to achieve versatility
and performance gains faster than if it had
implemented them in small increments. So
far, the refinery has tested and installed
digital devices and functions for almost all
of its various applications, from simple DP
measurement to complex analyzers and
nucleonic level measurement. At present,
digital device deployments at MRPL include:
• More than 3,000 FOUNDATION fieldbus
segments using several concepts, includ-
ing FISCO, FNICO, FISCO ic and HPT.
Many applicable FOUNDATION Field-
bus interfaces, diagnostics components
and junction boxes were supplied by
Pepperl+Fuchs, which also furnishes tem-
perature multiplexers.
• More than 35,000 total devices, including
more than 9,000 FOUNDATION Fieldbus
and 5,000 HART components.
• Developing its CIF potential, more than
75% of valve positioners at MRPL employ
FOUNDATION Fieldbus. These include
1,500 with FOUNDATION Fieldbus and
450 with HART. Primary positioner suppli-
ers are Metso and Emerson.
• Nearly 70% of the refinery’s more than
10,000 other transmitters for pressure,
radar level and Coriolis mass flow use
FOUNDATION Fieldbus, while the rest use
HART. Emerson, Honeywell, and Yokogawa
are the primary suppliers of these devices.
• More than 215 motor-operated valves
(MOV) and controls at MRPL’s Phase 3
cogeneration power plant also employ
FOUNDATION Fieldbus. They’re supplied
by Rotork, and deliver as many as seven
parameters each, which reduced I/O,
cabling and footprint requirements by
80% and saved $415,000.
Sudarshan reports that FieldComm Group
technologies generate savings for MRPL in
a variety of ways. “We achieved an average
savings of 50% on I/O, cabling and installa-
tion costs for new projects,” he says. “There’s
an average savings of 15 minutes per month
per valve in terms of preventive mainte-
nance, which results in an average savings
of 55 man days per month in applications
with digital valve positioners. In addition, we
get early detection of failures in devices that
had no preventive maintenance plans before
diagnostic-enabled devices were available.
Though these particular benefits can’t be
quantified in terms of cost savings, they’ve
nonetheless improved refinery uptime.
Thanks to all these gains, we’ve saved
approximately $6.6 million compared to
project costs that take into account added
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eHANDBOOK: Oil & Gas 2019 29
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costs of conventional I/O and cabling com-
pared to FOUNDATION Fieldbus.”
LESS DOWNTIME, MORE EFFICIENCYMuralidhara Karanth says there have been
several other specific instances where Field-
Comm Group technology has improved
operations, prevented downtime, or
enabled other gains. These events include:
• Avoided shutting down a sour water strip-
ping unit during a DCS upgrade in 2016
by using FOUNDATION Fieldbus, which
allowed MPL to take the DCS controller
offline while the unit continued running. Key
parameters were monitored through local
indicators, controllers were left in normal
mode, and the unit ran normally without dis-
turbances until the upgrade was done.
• Using HART pass-through I/O modules
in DCS and safety systems delivers the
added advantage of mapping critical
secondary and tertiary parameters from
HART devices to the DCS for better oper-
ation and maintenance. Critical inputs
from HART devices like control valve
position feedback from valve positioners,
density from Coriolis mass flowmeters,
and cell temperature from pressure trans-
mitters can be mapped to the DCS.
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eHANDBOOK: Oil & Gas 2019 30
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• Wireless DP transmitters are cost-effec-
tively achieving required backup tank
level measurements and better process
visibility in the shortest possible time
by installing HART gateways and signal
repeaters in the tank farm. This solution is
also used for control valve leak detection
via acoustic transmitters, and MRPL has
made it mandatory to use WirelessHART
in upcoming refinery units for applications
like pump seal monitoring, control valve
leak detection, etc.
• More intelligent field devices and the Yok-
ogawa PRM asset management system
(AMS) have redefined the preventive
maintenance techniques and enabled
advanced diagnostics. For example, criti-
cal control valves are monitored regularly
by the AMS, valve signatures are captured
during turnarounds and corrective actions
are taken. In addition, valve position
feedback is integrated to valve control
function blocks, which allows better tuning
of control loops and diagnostics. FOUN-
DATION Fieldbus physical layer health is
tested regularly with DTM-based diagnos-
tic tools and corrections are performed.
Also, MRPL is in the process of making a
preventive maintenance template based
on the NAMUR NE107 standard.
• Because FCC reactor instrument nozzles
in slurry service are prone to choking with
catalyst, critical delta pressure transmitters
are used for actuating shutdown on low
pressure. To better detect plugged impulse
lines, Emerson supplied 3051S transmitters
with Advanced Diagnostics Suite software.
MRPL tested this solution in sample appli-
cations, and is in the process of extending
them throughout the unit.
• Available valve position feedback indi-
cation improved unit operation. In 2017,
a failing actuator in a PSA purge gas
valve was identified by valve positioner
diagnostics, which averted a potential
hydrogen unit shutdown. Breakdown
of this valve would have brought down
MRPL’s diesel hydrotreater unit for 72
hours. Fuel and energy loss for startup
and shutdown of the hydrogen unit alone
would have cost $60,000.
“Using open standards lets us integrate
smart instruments throughout the entire
plant, including extensive use of HART in
our safety systems that enable capabilities
like partial stroke testing, as well as CIF
from FOUNDATION Fieldbus that lets us
operate even with the loss of critical hard-
ware—giving our team peace of mind,”
says Suryanarayana. “In 2016, we were
able to keep the refinery process running
during that DCS upgrade, which would have
resulted in a production loss conservatively
estimated at $800,000 without CIF.”
Suryanarayana adds that MRPL benefited
greatly from adopting digital technol-
ogy during its early stage, and achieved
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eHANDBOOK: Oil & Gas 2019 31
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considerable savings in commissioning
time, improved process visibility, reduced
DCS footprint, and simple, effective
maintenance practices thanks to better
utilization of device diagnostics. “FOUN-
DATION fieldbus physical layer diagnostic
tools have simplified our diagnostic pro-
cedures and improved the uptime of the
process units,” he explains. “Innovative
techniques, like carrying out FOUNDA-
TION Fieldbus loop checking using device
display, segment-wise device commission-
ing, etc., reduced pre-commissioning time
and required resources.” Likewise, avail-
ability of multiple parameters from single
instruments and getting the values to the
operators has improved quality of process
operations and ease of maintenance.
Ganesh Bhat, who worked for OMPL from
its conceptualization stage in 2007 until its
construction stage in 2011 on deputation
from MRPL, reports that OMPL’s Aromatic
complex that produces paraxylene and
benzene has also completely adopted
FieldComm Group technology. “This green-
field petrochemical (aromatics) complex
of OMPL didn’t face any difficulty in plant
commissioning with FOUNDATION Fieldbus
and HART,” says Bhat. “They use all FOUN-
DATION Fieldbus and HART features for
predictive and preventive maintenance, and
these technologies also make their mainte-
nance tasks easier and simpler.”
Sudarshan adds, “Overall, there’s been
a paradigm shift in how instrumentation
maintenance has been carried out ever
since MRPL introduced FOUNDATION
Fieldbus into its process units in 2005.
For instance, breakdown maintenance
calls are converted to predictive main-
tenance, and preventive maintenance
activity has been shifted to the control
room from former routine, manpower-in-
tensive field visits. The biggest advantage
of smart devices is the self diagnostics
of the devices. They’ve been tapped to
avert breakdowns due to instrumentation
failure, and this increased on-stream avail-
ability of the whole refinery.”
OTHER USERS CATCH ONSudarshan adds that many of India’s other
major industrial manufacturers have been
observing and joining its digitalization initia-
tive movement in increasing numbers.
“Once it became known that we’d imple-
mented FOUNDATION Fieldbus, HART
and WirelessHART, and were reaping con-
siderable benefits, representatives from
other Indian refineries approached us, and
since then, many of them have started
using FieldComm Group technologies,
too,” adds Sudarshan. “In fact, anyone
who reads our story is welcome to visit
MRPL for a detailed discussion on using
FieldComm technologies.”
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eHANDBOOK: Oil & Gas 2019 32
CoverRedlion AdTable of ContentsAcromag AdAd IndexPepperl+Fuchs Ad1Refinery of the future less focused on fuelsAmetek AdHot cutover with Foundation fieldbusSierra Instruments AdOn the edge in the oilfieldSafety excellence cuts costsKrohne AdUse wireless to monitor thief hatchesMRPL wins Plant of the YearPepperl+Fuchs Ad2
Button 2: Button 3: Button 4: Button 5: Button 6: Button 7: Button 8: Button 10: Button 12: Button 14: Button 16: Button 18: Button 19: Button 17: Button 15: Button 13: Button 11: Button 9:
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