oil · 2019. 8. 26. · well uop’s ccr platformers were designed to produce petrochemicals. the...

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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

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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



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.



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.”



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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



“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



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.



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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



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.



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



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.



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.



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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



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.



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.



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.



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.



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 [email protected].



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



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



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



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.



• 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



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.”



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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