oil gas · 2018. 8. 20. · figure 3: oil & gas measurement (ogm) ltd.’s large multiphase...

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eHANDBOOK

TABLE OF CONTENTSHoneywell rises to ExxonMobil challenge 4

Emulation is allowing the company to preserve and bring forward its legacy TDC investments.

Innovation boosts safety at Chevron 8

Chevron Oronite deploys a wireless personnel tracker to increase safety and efficiency.

Oilfield solution streamlines asset integration 12

Rockwell Automation’s ConnectedProduction reduces time to production and lowers costs.

Safety for screens 17

As they multiply on tablet PCs and smart phones and show up in hazardous settings,

HMIs and their controls need intrinsic safety (IS) and other protections.

Water-in-oil analysis uses controlled vortices 24

Improved technology reduces costs of inaccurate measurements.

Save the CSB! 32

The U.S. Chemical Hazard Investigation Board deserves the support of

everyone and every organization in the U.S. process industries.

AD INDEXAcromag • www.acromag.com/sp 3

Krohne • us.krohne.com/optimassmeters 7

Red Lion • www.redlion.net/control 11

Softing • industrial.softing.com 16

Turck • info.turck.us 26, 27, 28

eHANDBOOK: Oil & Gas 2

www.ControlGlobal.com

http://acromag.com/

http://us.krohne.com/optimassmeters

http://www.redlion.net/control

https://industrial.softing.com/en/products/interface-cards-gateways/usb-interface-cards/profibus/mobilink-interface.html

http://info.turck.us

https://www.acromag.com/sp

The state of ExxonMobil’s distributed

control system (DCS) fleet is not

unlike that of the process industries

overall. The oil & gas supermajor still has

in operation a significant number of older

systems installed as far back as the 1980s—

systems that have served the company

well for more than 30 years, but as older

electronic components have been replaced

by more modern alternatives, spare-parts

shortages and looming obsolescence put

ExxonMobil and other owner operators in a

difficult place.

When facing obsolescence, rip-and-replace

is clearly the option of last resort—incur-

ring high costs, protracted downtime and

the loss of all the intellectual property

invested in developing a system’s dis-

plays, databases, control strategies and

Honeywell rises to ExxonMobil challengeEmulation is allowing the company to preserve and bring forward its legacy TDC investments.

By Keith Larson

“It’s the best example of Honeywell’s commitment to continuous evolution that I’ve ever seen.” ExxonMobil’s David Patin discussed how Honeywell had successfully paved the way for the company to preserve and bring for-ward its legacy TDC investments.



third-party interfaces, according to David

Patin, distinguished engineering associate

– control systems, ExxonMobil Research

& Engineering.

The company’s installed base of Honeywell

TDC 3000 systems, in particular, looked to

be facing a critical shortage of spare parts

in the year 2025, Patin explained. “So in 2011

we met with Honeywell regarding the future

of TDC 3000,” Patin began, addressing

a plenary session of the Honeywell Users

Group Americas 2018 conference this week

in San Antonio.

CHALLENGE ISSUEDUnwilling to settle for rip-and-replace, “We

challenged Honeywell to develop and prove

a method to migrate TDC forward,” Patin

said. The two companies established a joint

task team to investigate the problem.

ExxonMobil’s wish list of deliverables

included avoiding wholesale system

replacement (especially the I/O); preserving

the company’s intellectual property invest-

ment; allowing for on-process migration

of system components (meaning without

shutting down the process); enabling new

capabilities not currently possible with TDC;

and unifying TDC with Honeywell’s current

state-of-the-art Experion platform.

This last item encapsulated a desire for a

solution that would “be usable by a younger

workforce, yet stand the test of time,” Patin

said. “I picture a third-grader who’s also a

future TDC engineer,” he said. “They just

don’t know it yet.”

Also implicit in ExxonMobil’s requirements

were continued “rock solid” reliability and

security, Patin added.

SOLUTION IDENTIFIEDSince the technical obstacles to bringing

TDC forward hinged on hardware obsoles-

cence, notably controller microprocessors

and communications chips that would no

longer be available, the team settled on an

emulation approach that would effectively

abstract TDC system functionality from the

specifics of the older hardware.

And in February 2018, seven years after

that first meeting of the minds—and two

years ahead of schedule—Honeywell

answered ExxonMobil’s challenge with

the release of Experion LCN R501.1.

The Experion LCN, or ELCN, effectively

emulates the TDC system as software. “It’s

100% binary compatible and interoperable

with the old system,” Patin explained.

“Current TDC code runs unmodified in this

virtual environment, greatly reducing the

technical risks. Intellectual property such as

application code, databases and displays

are preserved.”

In the end, the Experion Station, Server,

ACE and APP nodes can take the shape

of Windows-based “physical” applications



or virtual machines. Application Modules,

Network Gateway and Network Interface

Module functionality is redeployed on Uni-

versal Embedded Appliances or as virtual

appliances. Only the Enhanced PLC Gate-

way cannot be readily virtualized because

the emulation of serial network connec-

tivity is not well behaved, Patin explained.

“This means you can build an almost 100%

virtualized or 100% physical system—or

somewhere in between.”

With the new solution, LCN and UCN mes-

sages are now encapsulated in standard

Internet Protocol. “All the old networks now

exist as logical constructs on Fault Toler-

ant Ethernet,” Patin said. “We’re no longer

locked into proprietary networks.”

And to address the challenge of on-process

migration, Honeywell has also introduced

several bridge devices that effectively facil-

itate the virtualization of TDC system node

functionality—without the need to interrupt

the process under control.

BENEFITS ACHIEVEDVirtualization of the TDC environment has

come with some added benefits, including

the ability to use Honeywell’s cloud-based

Open Virtual Engineering Platform to engi-

neer TDC solutions; lower cost, smaller

footprint training simulators; peer-to-peer

integration of virtualized HPM controller

nodes with current-generation C300/

ACE nodes; support for OneWireless (ISA

100 and WirelessHART) connectivity; and

integration with ControlEdge and Unit

Operations Controllers.

“It’ll be a game-changer,” said Patin. “We

don’t know all that’s possible as yet.”

Other benefits include a drastic reduction—

or elimination—of spare parts, as well as

reductions in cabinet space requirements.

“We’ve gone from two nodes to six in a

single cabinet,” Patin said. “We’ve not fully

realized unification with Experion, but that

process has begun.”

Overall, Patin gave high marks to the

Honeywell team for its response to Exxon-

Mobil’s needs. “The challenge was met, and

expectations exceeded,” he said. “The need

to replace an entire system is eliminated,

future component issues are virtually elimi-

nated (pun intended), intellectual property

is preserved and on process migration

is supported.

“ELCN technology essentially resets the

odometer on your TDC 3000 investment,”

Patin added. “It’s the best example of

Honeywell’s commitment to continuous

evolution that I’ve ever seen. And if it were

a final exam, I’d give Honeywell an A on

this one.”



http://us.krohne.com/optimassmeters

Chevron Oronite manufactures hun-

dreds of additive packages for

engines, gears and hydraulic fluids

in seven plants around the world. “Our facil-

ity has expanded over the years, becoming

larger and more complex. As part of an

overall Chevron effort, we want to improve

safety, and we started by looking at access

control,” said Tom Madilao, regional man-

ager, special projects, Chevron Oronite, in

his presentation, “Using analytics and sens-

ing technology to improve safety, energy

efficiency, and productivity at a chemical

plant” at the 2017 Emerson User Group

Exchange, this week in Minneapolis.

“It’s easy to have employees and contrac-

tors in the wrong place at the wrong time,

especially during startups and shutdowns.

And during an incident, we need to be able

Innovation boosts safety at ChevronChevron Oronite deploys a wireless personnel tracker to increase safety and efficiency.

By Paul Studebaker

“As a former operations manager, I ask myself what operators will be doing in the future. Is it the right thing to have them go out and check, or instead, to have the system check for them?” Chevron Oronite’s Tom Madilao dis-cussed the use of digital technolo-gies to keep track of employees and contractors when in the plant, and to reduce the need for them to enter the plant in the first place.



to find and account for everyone,” Madilao

said. “We don’t want everyone having to go

to the control room to sign in and out, and

even then, we weren’t certain about their

location. We wanted to go from ‘I think…’ to

‘I know…’”

The solution is a real-time locating

system, and Emerson provided a practical

approach. “We now have RFID tags for

employees and contractors, so we know

where they are. If they get into trouble,

they can press a button on the tag and

we’ll respond to a ‘man down’ alert,”

Madilao said. They added a WiFi and

WirelessHART “traffic light” system, so if

a person goes to an area and the light is

green, they can go on in. If it’s red, don’t

go in, and if it’s amber, they should be

careful and look for instructions.

The system has been in operation for about

a year, including during a major turnaround

about six weeks ago. “Knowing exactly

where people are, especially at night, helps

us keep them safe,” Madilao said, “And

when contractors have to take a trip to the

control room every time they move to sign

in and out, they lose efficiency. Now they

don’t have to.”

A RELIABLE PLANT IS A SAFE PLANTMadilao is now embarking on other

opportunities. One of them is steam-trap

monitoring, and the plant has thousands of

them. Instead of checking them manually,

he said, “We have a trial of acoustic

sensors installed on 30 of them, with

built-in analytics to tell us which ones

need service.”

The plant is further exploring reliability with

wireless vibration monitors on large rotat-

ing equipment, a program that is also taking

place in Chevron refineries. It’s also using

wireless for production monitoring and for

loss of containment.

“Non-intrusive wireless is a process control

playground,” said Madilao. “We’re trying

wireless sensor devices for temperature,

pressure, etc. to learn where we need them

to improve operations.”

He’s also experimenting with mobility. “As

a former operations manager, I ask myself

what operators will be doing in the future,”

Madilao said. “Is it the right thing to have

them go out and check, or instead, to have

the system check for them?”

A current trial gives operators tablets

with wireless connectivity. “They have

information at their fingertips, at any

time,” Madilao said. “If a pump doesn’t

sound right, they can take a video, press

a button and create a work order then

and there. They don’t have to go back to

the control room, write it up, then try to

answer a lot of maintenance questions

about it.”



DIGITAL INNOVATION DRIVES RESULTSMadilao said each program has shown

quantitative success. The access control

and monitoring program was the first

such implementation at Chevron, and has

resulted in faster mustering tally, more

effective and efficient access control,

and enhanced emergency response

capability. Steam-trap monitoring allows

immediate detection of failures, which

has avoided steam loss, hammering and

process upsets. Vibration monitoring

has accurately predicted pump failures,

avoiding loss of control and safety

incidents. The mobile worker program

has increased the effectiveness of field

surveillance and allowed faster response to

abnormal conditions.

“People who want to digitally innovate

often need help answering the ques-

tion, ‘What are the right tools to pick up

and apply?’” Madilao said. “I suggest you

partner with Emerson and make a plan

to improve business results. Manage the

change—we needed to teach those oper-

ators how to use those tablets. And make

sure the technologies you choose will drive

business performance.”



http://www.redlion.net/control

I had to wonder what a full-sized oilfield

pump jack was doing in a Rockwell Auto-

mation trade show exhibit focused on

networking and software. I mean, I hear

Texans will drill anywhere, but in the middle

of the George R. Brown convention center?

“ConnectedProduction is to local equip-

ment installations what The Connected

Enterprise is to the overall business: a

system for gathering data, analyzing it, and

turning it into actionable information where

and when it’s needed,” explained Marcus

Toffolo, global business manager, oil and

gas, Rockwell Automation. I chewed on that

bite of word salad as Toffolo began our tour

of the section of The Connected Enterprise

(TCE) Industries Pavilion devoted to pro-

cess industries at Automation Fair this week

in Houston.

Oilfield solution streamlines asset integrationRockwell Automation’s ConnectedProduction reduces time to production and lowers costs.

By Paul Studebaker

“Imagine that quality of data across hundreds of assets, thousands of times, with no need for data cleaning.” Rockwell Automation’s Marcus Toffolo discussed how the company’s Con-nectedProduction solution dramatical-ly streamlines the integration of data flows among smart field assets.



“Food and beverage, chemical, and oil and

gas industries must meet demand, quality

and safety requirements,” Toffolo said. “Oil

and gas prices have driven the need to be

more competitive, to lower total cost of

ownership (TCO). Then there’s the aging

workforce, so it’s not all about cost, we also

need to do more with fewer people.”

For ConnectedProduction, Rockwell Auto-

mation brings many systems and solutions

together. The equipment may be disparate

in type and location, and a mix of new and

brownfield. “We have the organizational

strength, from intelligent power and Plant-

PAx (DCS) to motor control centers and

OEM skids, to bring information from equip-

ment together and reduce costs in any size

plant or installation,” Toffolo said. “This

capability is scalable from a single smart

drive to an entire production facility.”

CONNECTEDPRODUCTION IN THE FIELDFor example, a wellhead or oilfield compres-

sor can be a smart asset. With intelligence

at the edge, operators can control a motor,

reduce energy consumption, or limit a tem-

perature rise. They can control locally, and

the asset can connect to the enterprise so

operations can be monitored and optimized

at higher levels.

The asset may not be on a SCADA system

or even have a cellular connection, so local

and edge analytics are important. Then data

can be contextualized, and the critical infor-

mation can be sent on up.

“Here, we have a typical piece of oilfield

equipment, a pump jack,” said Toffolo,

gesturing at the aforementioned hulk of

steel. “See the QR code on the pump arm?

A mobile technician can drive into Blue-

tooth range, scan that code and download

the operating data from the jack. It may

be minus 30 degrees outside—he doesn’t

have to get out of the truck. There may be

maintenance to be done, or a work order

associated with that code. He can download

that, as well as the instructions. “

The data will have information about the

well productivity, which goes up to the

enterprise system and to a subject matter

expert (SME) where it will be combined

with information from the other 50 wells

in the field and used to determine water/

oil ratios, choke settings, strokes, and injec-

tions to optimize the group.

Moving on, we come to an OptiLift NF

natural gas flow controller, a package

solution that can be connected, but is also

self-sufficient, with an HMI for local con-

trol. If communications are unavailable

or go down, it stores time-stamped data,

then backfills the records on reconnection.

“Automatic data collection replaces chart

recorders and clipboards,” Toffolo said. “It

can upload to mobile devices that move the

data up when they return to a cellular or



https://www.rockwellautomation.com/global/industries/oil-gas/overview.page?pagetitle=ConnectedProduction&docid=75a5da7631c0c016304f5f54de4f4587?utm_source=Control&utm_medium=Advertising&utm_content=AFDay2&utm_campaign=EventsAF_NA_UnitedStates_EN_CMP-01335-G1J5V9

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https://www.rockwellautomation.com/global/industries/oil-gas/overview.page?pagetitle=OptiLift-Systems&docid=2c44db43ed444b2b116893f7e9a5adf1?utm_source=Control&utm_medium=Advertising&utm_content=AFDay2&utm_campaign=EventsAF_NA_UnitedStates_EN_CMP-01335-G1J5V9

WiFi network—complete data, with no tran-

scription errors.

“Imagine that quality of data across hun-

dreds of assets, thousands of times, with no

need for data cleaning.”

Next, we visit an OptiLift RPC rod pump

controller. This is a “self-declaring asset,”

said Toffolo. On connection and power-up,

it auto-identifies, asks to be connected

to the production system, and offers its

setpoints, ranges and variables. “You just

give it a name, and it’s on the system, auto-

matically connected to ERP and SAP asset

management systems, ready for mainte-

nance and work order generation, and to

accept optimization instructions.”

Then we stopped by an FW Murphy com-

pressor control panel, “another smart asset,”

Toffolo said. We can monitor it, see how it’s

operating—temperatures, pressures, incipi-

ent surge—and if indicated, modify the well

behavior remotely to prevent a problem. “If

needed, we might slow production a bit to

avoid a trip,” Toffolo said.

A nearby UMC lease automatic custody

transfer (LACT) metering skid monitors

flows, temperatures, pressures and compo-

sitions to determine dollar values based on

quality. “This information also flows back

through ConnectedProduction, where the

company can allocate production to par-

ticular wells, know sand and gas ratios, and

optimize the reservoir at the cloud level,”

Toffolo said.

FIVE MINUTES, SEVEN CLICKSFinally, we see a configuration, monitoring

and control demonstration, where Srikanth

Mashetty, engineering manager, Digital

Oilfield Solutions, Rockwell Automation,

showed how SMEs, operators and techni-

cians can collaborate across responsibilities.

As he talks, a new smart asset is powered

on and pops up on the screen. It could

be anything, and this time it’s a wellhead.

Mashetty acknowledges it with a click,

and it describes itself as a data model in

AssetPoint. Whether there are 50 or 800,

it knows its tags, as well as its location,

both physically and in the control hierarchy.

Mashetty gives it its name, and it’s auto-

matically in the ERP, analytics and asset

management systems, giving trending, dis-

plays and alarms. Five minutes, seven clicks,

and one data entry.

“In the past, that would have taken at least

half an hour, and as long as several weeks,”

said Toffolo.

On a nearby screen, Schlumberger software

shows the new well automatically added to

a map of an existing field, where Riku Vilkki,

BDMS solution champion, Schlumberger

Information Solutions, describes how he can

schedule it and use its trending and history

for field performance optimization.



The tour has shown just one example, in

one industry, of how ConnectedProduction

and The Connected Enterprise draw on the

depth of Rockwell Automation and partner

technologies to enable OEMs and end users

to “collect data, perform analytics where

they’re needed, and present the results to

the right person,” said Elizabeth Parkinson,

director, market development, The Con-

nected Enterprise, Rockwell Automation.

Alongside the data flows, collaboration

tools like the FactoryTalk TeamOne app

allow operators and technicians to “phone

a friend”—an SME—to work together, share

information and solve problems quickly

and efficiently.



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https://industrial.softing.com/en/products/interface-cards-gateways/usb-interface-cards/profibus/mobilink-interface.html

Going out in bad weather? You may

need a sweater or coat. Working in

a harsh or hazardous environment?

You and your coworkers will need the right

protective and safety gear.

The same goes for tools and accessories,

especially all the human-machine interfaces

(HMI) on tablet PCs and smart phones

that are flooding onto plant floors and

field applications—sometimes authorized,

but often unauthorized due to their sheer

prevalence on the consumer side. Despite

their numbers, they must also comply with

the same intrinsic safety (IS) and other

standards as earlier electronic handheld

devices by limiting operating voltages, and

getting sheathed in just as much rubber

and plastic.

Of course, today’s increasingly chip-based,

Ethernet-aided and wireless systems mean

users don’t need to go into hazardous areas

as often as in the past, and can monitor

and manage applications from safer dis-

tances. However, there are still many times

when technicians and operators must rou-

tinely journey out to pipelines and tanks,

up to columns, or out in the field to other

equipment—even if they can interact with

many process applications and equipment

via a tablet PC and wireless link when they

get there.

“It depends on each facility’s policies and

the specific level of the hazardous area

whether tablet PCs, smart phones and

other devices can be brought in “ says

Jeff Morton, sales manager at Cross Co.’s

Safety for screensAs they multiply on tablet PCs and smart phones and show up in hazardous settings, HMIs and their controls need intrinsic safety (IS) and other protections.

By Jim Montague



Process Control Integration Group (www.

crossco.com/process-controls) in Knoxville,

Tenn. The group is a certified member of

the Control System Integrators Associa-

tion (CSIA, www.controlsys.org). “We see

a lot of interest in remote, wireless opera-

tor panels implemented as thin clients or

virtual clients in food and beverage and

chemical applications, as we don’t work in

oil and gas. Usually, iPads are employed in

non-hazardous areas, but we did have one

client that needed a tablet PC in a Class

I, Div. 2, non-explosive area, so its opera-

tors could walk in and start a pump for its

chemical extrusion process. This is a volatile

environment and the user previously had a

pushbutton in an appropriate panel. Instead

of yelling back and forth, we brought in an

industrially hardened tablet PC with Class I,

Div 2 certification.”

ARMOR UP INTERFACESBecause the most obvious way to protect

interfaces that must go into hazardous

areas is shielding them, many suppliers

have been putting them in purpose-built

cases or manufacturing them with built-in

protections that comply with IS and

other standrds.

For instance, RAG Deutsche Steinkohle AG

(www.rag.de) in Herne, Germany, oper-

ates six anthracite coal mines, and recently

replaced its hardwired, non-portable voice,

data and video communications with a

wireless, computer-based system that

includes Bluetooth headsets, wireless LAN

access points (AP) and cameras, and i.roc

Ci70-Ex handheld PCs with barcode mod-

ules from ecom instruments GmbH (www.

ecom-ex.com), a division of Pepperl+Fuchs.

The i.rocs run RAG’s proprietary software,

so the mines’ above-ground staff can send

requested data such as technical docu-

ments to below-ground APs that relay them

to the IP65-rated handhelds, which are cer-

tified for use in potentially explosive mining

environments (Figure 1).

RAG reports that immediately available

data and advice via the i-rocs and its

computer-based communications greatly

enhance mine operations and maintenance,

UNDERGROUND PC COMMUNICATIONSFigure 1: For data, voice and video communications, Germany-based coal mine operator RAG adopted a wireless, computer-based system with Blue-tooth headsets, wireless LAN access points (AP) and cameras, and i.roc Ci70-Ex handheld PCs, which are IP65 rated and certified for use in poten-tially explosive mining environments. Source: RAG and ecom



which make its products more competitive

internationally. Also, the company is saving

on downtime and damage because its engi-

neering experts no longer need to be onsite

to instruct miners, but can instead save time

by guiding them through inspection and

repair tasks remotely from above ground.

“Handhelds have been used in IS areas for a

long time, but now they’re making a logical

progression into more hazardous settings,

and developers like Imtech are embedding

Android apps in them, while suppliers like

Pepperl+Fuchs’ ecom are adding loca-

tion-aware capabilities and Bluetooth,” says

Grant LeSueur, senior director for control

and safety software at Schneider Elec-

tric (www.schneider-electric.us). “These

GPS-based technologies can also help

with cybersecurity because they can be

set to only allow data access with a loca-

tion-based prerequisite.”

DEVICE-LEVEL AND I/O SHIELDINGBeyond armoring interfaces brought into

IS and hazardous areas, several end users

and system integrators are taking a closer

look at better protecting I/O and device-

level components in IS and hazardous

areas, especially as they gain new network-

ing connections.

For example, to maximize capacity at its

3-million-cubic-meter Kalmaz underground

natural gas storage facility in Hajigabul, the

State Oil Co. of the Azerbaijan Republic

(www.SOCAR.az) recently updated the

core instrumentation and controls of its

surface applications with help from Inkoel

(www.inkoel.az), an automation engineer-

ing contractor in Baku, Azerbaijan. These

above-ground processes include two-stage

separation of solids and condensate; gas

flow measurement at wells; gas compres-

sion, preheating and pressure control; and

drying and treatment (Figure 2).

SOCAR and Inkoel implemented a PlantPAx

process automation system (PAS) from

Rockwell Automation (www.rockwellau-

tomation.com) for about 1,000 I/O points

handling monitoring, control and gas-flow

calculations. This client-server architecture

I/O SAFE IN THE FIELD Figure 2: State Oil Company of the Azerbaijan Republic's 3-billion-cubic meter Kalmaz underground natural gas storage facility uses Ex Interface relay modules to establish intrinsically safe signal circuits for 1,000 I/O points that handle its above-ground processing applications, which are controlled by Rockwell Automation's PlantPAx PAS and Prosoft Technology's MVI56-AFC gas and liquid flow computer. Source: SOCAR and Rockwell Automation



includes Operator Work System (OWS);

Process Automation Supervisory Server

(PASS); EtherNet/IP networking; Prosoft

Technology’s in-rack MVI56-AFC gas and

liquid flow computer for running dedicated

gas flow and calculation algorithms follow-

ing ISO-5167 measurement standards; and

522 Endress+Hauser overload-resistant

There's a dizzying array of suppliers offering

tablet PCs, smart phones, handheld comput-

ing devices or cases that are reported to be

intrinsically safe (IS) or at least offer a range of

protections for use in hazardous environments.

Here are some of the main players:

• Aegex Technologies (http://aegex.com)

provides IS Industrial Internet of Things (IIoT)

and mobile solutions for hazardous applica-

tions, such as Windows 10 tablets, sensors

and partner monitoring systems, which are

tested in its AegexLabs R&D facility.

• Azonix Corp. (www.azonix.com) is a member

of MTL Instruments Group, which is part of

Eaton's Crouse-Hinds division. It designs

and manufactures intrinsically safe commu-

nication and data acquisition products for

hazardous-classified Zone 1 (Class I, Div. 2)

and Zone 2 areas.

• Bartec Enterprise Mobility (https://bartec-

mobility.com) brings more than 40 years of

explosion protection experience to its cameras,

tablet PCs, smart phones and other devices.

• Beijing Dorland System Control Technol-

ogy Co. (www.dorland-tech.com) makes

phones, smart phones, PDAs, RFID and bar-

code devices, laptops, tablet PCs and digital

cameras, which it reports are all intrinsi-

cally safe.

• ecom (www.ecom-ex.com) is a Pepperl+-

Fuchs brand that concentrates on mobile

computing, communications, measuring and

calibration, and handlamps.

• Exloc Instruments (www.exloc.com) supplies

IS tablet PCs, as well as industrial commu-

nications, notification products, process

instrumentation, indicators and displays, plant

maintenance and tracking solutions, engi-

neered solutions and enclosures, and cooling

and pressurization devices.

• Getac (http://us.getac.com) provides rugged

notebook PCs, tablets, handhelds and video

equipment.

• Handheld Group (www.handheldgroup.com)

manufactures rugged mobile computers,

PDAs and tablets, and recently launched its

first rugged IS computer.

• Panasonic (https://na.panasonic.com) makes

a variety of industrially hardened labtops,

notebook and tablet PCs, and other handhelds.

• Xciel Inc. (www.xciel.com) builds IS porta-

ble devices like smartphones and tablet PCs,

ruggedizes and certifies commercial-grade

products, and certifies industri-

al-grade products.

Protected interfaces



pressure and differential pressure/tempera-

ture smart transmitters.

MVI56-AFC calculates flow rates, accu-

mulated volumes, accumulated mass and

accumulated energy for up to 16 meter

runs, provides data directly to PlantPAx,

and transfers results back to processor

memory for control, or sends them to serv-

ers or the OWS supervisory layer. To make

the gas storage application’s I/O consistent

and intrinsically safe, SOCAR and Inkoel

implemented Ex Interface relay modules,

enabling IS signal circuits that are electri-

cally isolated from the overall system, while

its process values are accurately transmit-

ted to the process control system.

Likewise, Manoel Feliciano da Silva, techni-

cal advisor at Petrobras (www.petrobras.

com.br/en), reports it’s developed a mud-

gas separator for its under-balanced drilling

(UBD) method, which uses hydrodynamic

pressure of the drilling mud and fluids in the

well bore that’s lower than the well forma-

tion. Because surface pressure is lower than

well pressure, UBD applications can bring

hydrocarbons to the surface at controlled

rates, and eliminate or reduce the need for

fracturing after a well is completed, which

allows it to reach full production sooner.

However, UBD requires specialized sur-

face equipment for continuous separation

of the mud and hydrocarbons, so Petro-

bras also developed its Aleph HMI/SCADA

application based on LabVIEW software

from National Instruments (www.ni.com). “A

microcomputer runs the LabVIEW applica-

tion, drivers for integration with other PLCs,

and screens for operator control of the

UBD operation,” explains da Silva. “Aleph

and LabVIEW provide process diagram

visualization, separator measurements, and

real-time control loops for the continuous

separation. The data acquisition system

measures: drill bit position through an elec-

tromagnetic measurement while drilling (EM

MWD) function; gas and liquid flow rates;

liquid height and pressure in the separator;

downhole pressure measurements; and con-

trol valve positions through IS sensors and

4-20 mA transmitters.”

LabVIEW also provides connectivity to

the drilling control PLC through an RS-232

serial drive and connectivity to a remote

system through a DataSocket server. This

system meets all design requirements

including: safety with IS sensors and a sepa-

rate UBD control PLC; flexible software and

modular hardware for additional I/O; inte-

gration via open protocols and LabVIEW

software with a range of connectivity; and

ease-of-use with LabVIEW graphical devel-

opment environment.

“By deploying UBD technology based on

NI LabVIEW, we save between $500,000

and $2 million, depending on the size of the

well and the cost of a fracturing job,” adds

da Silva.



HAZARDS SHIFT; SO DOES SAFETYJust as advancing technologies and capabil-

ities are pushing HMIs into more challenging

settings, similar forces are altering many

hazardous environments, and impacting

choices about the right safety levels for

solutions that should be deployed in them.

“Many manufacturers support bring-your-

own-device (BYOD) for maintenance and

other tasks, and some hazardous areas

could support BYOD. However, we’re not

seeing it because our customers’ approach

is to limit access to hazardous areas alto-

gether. Recently, they’re limiting access

even further by leveraging technology to

access hazardous areas remotely from

safe areas,” says John Tertin, sales and

marketing director at ESE Inc. (https://

eseautomation.com), a CISA-certified

system integrator in Marshfield, Wis. “We

deploy rugged HMIs, but not usually due to

class requirements.”

Nonetheless, Tertin reports there’s more

attention to overall process safety in the

past two years, and ESE’s approach and

available technical responses have shifted,

too. “Previously, we’d use several safety

monitoring relays going back to a central

controller, but as more attention was given

to process safety and both the number and

complexity of safety circuits has grown, we’ve

transitioned to safety PLCs and distributed

safety I/O, such as Rockwell Automation’s

Point Guard I/O, which let the safety circuits

signal via Ethernet and allow visibility down

to individual points. Even in complex safety

circuits, engineers can determine the exact

device that caused a safety trip and where it’s

located. Safety I/O is also very economical

and cost-effective to design and implement

compared to the complexity of using safety

control relays for larger systems.”

Tertin adds that users want visibility into

their processes, but they also want to see

into them without having to go into haz-

ardous areas. “We’re not trying to replace

clipboard with iPads. We’re trying to skip

that step entirely, and not go into hazardous

locations and stand in front of equipment

unless we have to,” he explains. “Not only do

our customers want to limit people in class/

div areas, but they also want to limit the

components in them, too. While we do use IS

power supplies, I/O and field devices, we still

prefer to install them outside of rated areas,

and wire them in via sealed conduits.

“Field components must be in hazardous

areas, but using sealed rigid conduit and

terminating them in a safe area lets us

add another layer of safety and security

by keeping controls and support devices

outside of the rated area. For example, a

flowmeter in a hazardous setting needs

to be IS, but the IS I/O and power supply

that it’s terminated to can be outside and

removed from a hazardous setting. The

devices are then wired through sealed con-

duit, further limiting exposure.”



PROTECTION WITH VIRTUALIZATIONOnce the prejudice that only hardware

can offer protection begins to dissipate,

developers and users report that software,

servers, networks and other forms of digita-

lization and virtualization can also improve

safety—though their simpler, combined

solutions are often in a box as well.

“We see plenty of manufacturers making

thin clients that are hazardous-rated, mini-

PCs with Ethernet, power, screens and

keyboards. However, virtual components

make IS panels even easier to design and

build,” says Will Aja, customer operations

VP at Panacea Technologies Inc. (www.

panaceatech.com), a CSIA-member system

integrator in Montgomeryville, Pa. “We

recently did a pharma industry project for a

chemical system with panels in a hazardous

area, which needed to modernize its HMIs

from physical touchscreens to panels with

hazardous-rated touchscreens on the front.

So, we went virtual with ACP Thin Manager

(https://thinmanager.com) software on a

couple of Class I, Div. 2 screens in the haz-

ardous area.”

Aja explains that protection in a situation like

this traditionally requires costly IS barriers

or nitrogen purging/ventilation. However,

“virtualizing” is far less expensive because

it distributes some formerly non-distributed

HMI components, and uses standard display

libraries and a common server architecture

to serve screens to thin clients.

“With virtualization, we can pull out

everything that was causing problems—in this

case, terminal blocks, controls and a nitrogen

purge panel—so all that’s left in the hazardous

area is a Class I. Div. 2 box housing the HMI,

touchscreen and thin client, running software

such as Rockwell Automation’s FactoryTalk

(FT) View SE,” explains Aja. “Also, instead

of dealing with HMIs that are islands and

patchworks of visualization with all kinds

of different programming, we’re taking

anywhere from 11 to 50 separate screens,

finding commonalities, and pushing them into

one project with a uniform HMI library. This

can mean huge gains as a result of stocking

fewer displays; eliminating parts by using

one type of thin client and touchscreen; and

decoupling the hardware and software layers.

“As a result, instead of being stuck in the

usual two – and three-year obsolescence

cycles for hardware and traditional

software, we just replace the commodity

tablet PCs, smart phones or other interfaces

serving our screens as needed. These

devices can be intrinsically safe if required,

but future plants aren’t going to have as

many HMIs in the field. Instead, they’ll have

engineering stations that will interact with

IS tablets, and use geo-fencing that will only

allow users to securely control the boiler or

other equipment when they’re close to it.”



For many years, end users and their

engineering contractors have been

installing quality measurement

systems (QMS) such as a sampling,

mixing and analyzer systems (SMAS) for

immiscible liquids, including oil and water.

It’s a tenet of process measurement that

any analyzer or sensor is very capable of

measuring only a single-phase sample. In

fact, most practitioners assume that using

two analyzers on one stream for immiscible

liquids will solve the measurement

problem. It doesn’t—it just requires a

double SMAS, each with its own level

of uncertainty.

This article describes a new SMAS, with

the registered trademark SmartMix, that

uses a novel approach to improve multi-

phase measurement.

Crude oil sample conditioning systems must

comply with international quality measure-

ment standards such as ISO 3171 and API

8.2 if they’re used in the delivery and sale

(custody transfer) of crude oil. Almost all

crude oils contain basic sediment and water

(BS&W), with the water usually having a

high concentration of salt and the basic

sediment composed of various impurities.

The question is, how much BS&W is pass-

ing unmeasured?

A more critical question is, “Are the cur-

rent quality measurement systems in use

today fit-for-purpose?” A QMS that is not

fit-for-purpose is a double-edged sword.

First, if the measurement is inaccurate, salty

water will be bought or sold at the price of

crude oil, resulting in a potentially signifi-

cant financial exposure. Second, the amount

Water-in-oil analysis uses controlled vorticesImproved technology reduces costs of inaccurate measurements.

By Wes Maru, Gary Rathwell and Robert E. Sherman



and composition of these salty waters and

complex impurities have detrimental effects

on the process operation due to corrosion,

fouling and upsetting the mass and energy

balance of the system.

As many of us in the hydrocarbon and

chemical processing industries know,

SMAS—particularly mixing—requires atten-

tion to every detail if we’re to minimize

lost revenue.

MIXING DIFFICULTIESMany of the technologies involved in mixing

are not well understood. In the hydrocarbon

industry, mixing is a critical component for

liquid custody transfer of crude oil. Poor

mixing practices can lead to inaccurate

measurements with high levels of uncer-

tainty, resulting in losses totaling millions of

dollars per year for typical petroleum refin-

ery or pipeline operations.

Significant loss reductions are available for

plants that mix well. Consider a 250-million-

barrel-streaming-per-day (MBSD), or about

1,500 m3/hr, petroleum refinery receiving

crude oil with a nominal 2% by volume water

content for a crude price of $65/barrel.

Compared to 100% mixing efficiency (ME):

• 90.0% ME leads to losses of about US

$10 million per year (current ISO/API

requirements),


$5 million per year (upper limit of cur-

rent technologies),

• 97.0% ME leads to losses of about US $3

million per year (standard capability of

SmartMix), and


$213,000 per year (optimized capability

of SmartMix).

GENESIS OF A NEW TECHNOLOGYSome existing SMAS didn’t seem to provide

a homogeneous mixture for truly represen-

tative sampling of two-phase immiscible

liquid streams. We thought it should be

possible to do better.

Current industry practice is to use vertical

pipe runs for mixing and sampling immis-

cible liquids, especially when the stream

velocity is less than 0.5 m/s. It’s sometimes

assumed that stream turbulence induced by

pipe elbows and globe or check valves will

provide homogeneous mixing. Such mixing,

though significant at high velocities, is far

from satisfactory.

ISO 3171 states that a ratio of the water con-

centration at the top of a pipe (C1) to water

concentration at the bottom of the pipe

(C2), or C1/C2, greater than 0.9 is indicative

of good dispersion of immiscible liquids: 0.9

< C1/C2 < 1.0.

To ensure representative samples, we

believe the mixing system must maintain a

C1/C2 ratio as near as possible to 1.0 under

all flow conditions. To do this, the sampling

system must provide efficient mixing based



on optimized real-time feedback control using its ana-

lyzer sensors.

With that in mind, the R&D Group at Oil & Gas Measurement

(OGM) Ltd. (www.oilandgasmeasurement.com), under the

direction of co-author Wes Maru, CEng, built multiphase

flow loops at its facility in Ely, Cambridgeshire, U.K., to test

and optimize mixing and other technologies.

The flow testing and calibration laboratory (Figure 1) inte-

grates a small multiphase flow loop (SMPFL) and large

multiphase flow loop (LMPFL) for oil-water testing, a liquid

meter calibration loop (LMCL), and a high-performance

computing (HPC) capability.

R&D LOOP SCHEMATICFigure 1: Oil & Gas Measurement (OGM) Ltd.’s inte-grated flow testing and calibration laboratory includes a small multiphase flow loop (SMPFL) and large mul-tiphase flow loop (LMPFL) for oil-water testing, sup-ported by a liquid meter calibration loop (LMCL) and high-performance computing (HPC) capability.

Verification datafor scaling

Calibratedmeter

Calibratedmeter

High-performance computing (HPC)NAFEMS (Calibrated CFD models)

Validationdata

Validationdata

Optimization Optimiza

tion

Generic scaling

Large multiphase flow loop (LMPFL)ISO 17025 (Testing)

Small multiphase flow loop (SMPL)ISO 17025 (Testing)

Liquid meter calibration loop (LMCL)ISO 17025 (Calibration)



http://info.turck.us/sensors/?utm_source=Control&utm_medium=ebook&utm_campaign=2018_div1&utm_content=uprox3

The SMPFL (Figure 2), with a 2.5-in. nominal pipe diameter,

was used with magnetic resonance imaging (MRI) to char-

acterize the prototype.

The LMPFL (Figure 3) has a 10-in. nominal pipe diameter,

110-diameter straight pipe section and 6-in. return flow. It

was used to characterize and validate the SmartMix entrain-

ment atomization (EA) mixing device using an advanced

multiprobe profiling (MPP) system according to ISO 3171

and API 8.2.

At the start of this technology development program, OGM

set the following goals:

• Produce technologies and products that not only meet

the current industry standards, but that essentially exceed

them all.

• Accelerate design and testing activities through the use

of synergistic fluid mechanics (physical experiment and

computer simulation).

• Develop and employ turbulent multiphase flow models

to understand the intricate issues involved in mixing

of immiscible fluids in general, and oil-water flows in

MRI PEERS INTO PIPEFigure 2: Two views of Oil & Gas Measurement (OGM) Ltd.’s small multiphase flow loop (SMPFL) at the Uni-versity of Cambridge Magnetic Resonance Research Centre show the nominal 2.5-in. pipe passing through the magnetic resonance imaging (MRI) unit used to characterize the prototype SmartMix device.



http://info.turck.us/sensors/?utm_source=Control&utm_medium=ebook&utm_campaign=2018_div1&utm_content=QR24

particular, in an effort to bring about a paradigm shift

from current technologies.

• Improve the mixing efficiency (C1/C2 ratio) as defined in

ISO 3171, beyond what is currently achievable.

• Obtain significant cost savings in lifecycle and energy use

compared to currently available technologies.

In 2014, a research award to Dr. Maru by the U.K.’s Tech-

nology Strategy Board allowed collaboration with the

University of Cambridge, which:

• Provided a process-size, research-quality MRI to charac-

terize the prototype SmartMix,

• Developed interest and resources to extend the research

program into process industry technologies,

• Provided guidance on how to extract a new MRI sequence

used to characterize the SmartMix device and validate

OGM’s in-house-developed advanced multiphase compu-

tational fluid dynamics (MCFD) modeling tools, and

PROFILING PER ISO AND APIFigure 3: Oil & Gas Measurement (OGM) Ltd.’s large multiphase flow loop has a 10-in. nominal pipe diame-ter, 110-diameter straight pipe section and 6-in. return flow, where entrainment atomization (EA) was charac-terized and validated using an advanced multi-probe profiling system per ISO 3171 and API 8.2.

Zanker plate Oil tank Coalescer Smart mixing

Water tank

Oil pump

Water injection

110D-plus straight pipe section



http://info.turck.us/connectivity/?utm_source=Control&utm_medium=ebook&utm_campaign=2018_div2&utm_content=m8%20ethernet

• Provided critical review on the vali-

dation of the MCFD according to the

International Association for Engineer-

ing Modelling, Analysis and Simulation

Community (NAFEMS) test protocols for

scale-up of the 2.5-in. SMPFL data to the

a 10-in. LMPFL.

EA MIXING TECHNOLOGY IN ACTIONInstead of physical agitation, the EA mixing

system uses a controllable, turbulent vortex

to achieve more representative sampling of

immiscible liquids. The EA mixing relies on

a weak jet/strong jet interaction supplied

in a controlled way using proprietary (pat-

ents pending) mixing nozzles. This results

in a more uniform droplet size and a more

homogeneous flow profile than conven-

tional sampling systems.

These claims have been experimentally

proven using Cambridge University’s MRI

facility as well as highly sensitive electrical

capacitance tomography (ECT) and a high-

speed video camera that allowed imaging

via an optically-transparent Perspex (PPX)

pipe (Figure 4). The experimental validation

together with the MCFD simulations show

that the EA mixing system can control the

droplet sizes and their distribution across

the pipe diameter, creating fully homoge-

neous flow for improved representative

sampling. Unlike other SMAS, SmartMix also

eliminates occurrence of undesirable oil-wa-

ter emulsion.

In operation, a continuous stream sample

is extracted from the process piping by an

isokinetic sample extraction probe, circu-

lated via a pump, and reintroduced to the

process stream through twin nozzles that

create weak jet/strong jet interaction within

the process fluid.

This operation is constantly adjusted by a

stochastic model-based feedback control

system, which automatically responds to

changes in the process flow rate and com-

position to achieve uniform droplet size and

homogeneous oil-water mixture without

producing any emulsion. The model-based

feedback control uniformly adjusts to the

measured fluid temperature, pressure, vis-

cosity, water cut, density and salinity from

its sensor systems.

SMARTMIX DEVELOPMENT SYSTEMFigure 4: In addition to the Cambridge University MRI facility, characterization was done using electrical capacitance tomography (ECT) and a high-speed video camera that allowed imaging via an optically-transparent Perspex (PPX) pipe.

Cell sampler Twin

nozzle Scoopsampler

Water cut Electrical

meter (WCM)

capacitance

tomography (ECT)Perspex pipe (PPX)

Out

In



The system achieves greater than 97% mixing

efficiency, resulting in potential savings of

millions of dollars per year (see earlier fig-

ures). This is accomplished in horizontal

process stream piping, even at very low flow

velocities. This eliminates the need for ver-

tical piping, and avoids pressure drops due

to elbows or bends. Installation can be done

with minimal cost for process piping rework.

The high accuracy and continuous nature

of the system may allow reduced manual

sampling, minimizing or eliminating the

common, laborious, expensive and less

accurate five-stage sampling protocol. It’s

also energy-efficient, reducing pump power

requirements by up to 50% compared to

existing technologies.

EXISTING APPLICATIONSAfter extensive testing and further industry

– and peer-reviewed demonstrations in

the LMPFL at Ely, a major oil operator in

the North Sea oil fields has ordered three

SmartMix systems for one of its challenging

applications (Figure 5), including the

complete replacement of an existing

alternative system that failed to function

as desired.

In summary, a new proprietary (patent

pending) SMAS has been demonstrated to

improve the accuracy required for ISO 3171

measurements by more than 7%, where 1%

improvement equates to a saving of US $1

million for a typical 250 MBSD (1,500 m3/hr)

process flow. It promises to:

SKID-BASED SYSTEMFigure 5: A major oil operator in the North Sea has ordered three SmartMix systems for challenging applications, including complete replacement of an existing alterna-tive system that failed to function as desired.



• Bring rapid return on investment

(ROI) in process crude stream qual-

ity measurement,

• Give accurate and efficient performance

over very large process flow turndowns,

• Cause no system pressure drop, and

• Provide accurate, single-pass sampling

through its compact fast-loop design, elim-

inating current sample recycle practices.

The system may also help optimize crude

de-salter operation in refineries by improv-

ing droplet size and its distribution across

the electrostatic field (energy saving), and

by improving the operation of water wash

injection and heat transfer via efficient

mixing. The flow through the fast loop and

its advanced control may also be able to

replace current emulsifier valves.

SmartMix may also provide data for predic-

tion of corrosion levels due to free water

in refinery piping and vessels. This allows

reduction of expensive additives worth up to

hundreds of thousands of dollars per year.

Wes Maru, Ph.D., R&D manager, OGM corporate oper-

ations world-wide and principal technical contact for

SmartMix technologies, resides in Cambridge, U.K., and

can be reached at [email protected]. Gary Rath-

well, principal, Enterprise Consultants International, is

near Houston, and can be reached at gary.rathwell@

entercon.biz. Robert E. Sherman, ISA Life Fellow and

principal technologist, Enterprise Consultants Interna-

tional, is near Chicago and can be reached at robert.

[email protected].

REFERENCES1. Lakshmanan, S., Holland, D.J., Maru,

W., Gurevich, M., and Sederman,

A.J., “Multiphase flow quantification

using computational fluid dynamics

and Magnetic Resonance imaging,”

33rd International North Sea Flow

Measurement Workshop, Tønsberg,

Norway, 2015.

2. Lakshmanan, S., Maru, W., Holland, D. J.,

Mantle, M. D., and Sederman, A. J., “Mea-

surement of a multiphase flow process

using magnetic resonance imaging,” J.

Flow Measurement and Instrumentation,

53 pp. 161-171 (2016).

3. Huang, J., Lakshmanan, S., Maru, W.,

Thomas, A., “(SmartMix®) Validation

of OpenFOAM Models with Mag-

netic Resonance Imaging and Nuclear

Gamma Densitometer Measurements”,

12th International OpenFOAM Work-

shop, University of Exeter, 24th – 27th

July, 2017.

4. Maru, W., Sherman, Robert E., “Opti-

mized Hydrocarbon Sampling

Methodology and Equipment in the

presence of Basic Sediment and Water,”

63rd Annual ISA-Analysis Division Sym-

posium, April 22-26, 2018, Galveston,

TX, USA.

5. Maru, W-A., Holland, D., Huang, H.,

Lakshmanan, L., Sederman, A., Thomas,

A., “Multiphase Flow and Mixing Quan-

tification using CFD and MRI,” Invited

Topical Review, J. Flow Measurement

and Instrumentation, (2018), in press.



I’ve been plowing though the usual fall

harvest of user group conferences with

all their interesting sessions, but one

really stuck out from the rest for me. It was

by Manuel “Manny” Ehrlich, board member

of the U.S. Chemical Hazard Investigation

Board (www.csb.gov), who mentioned that

CSB was able to get some added funding

to investigate root causes following the fire,

explosion and sinking of the Deepwater

Horizon platform on April 20, 2010, which

killed 11 people and fouled much of the Gulf

of Mexico with a record-breaking, subsea

oil leak.

“When Deepwater Horizon happened

in 2010, then-U.S. Rep. Henry Waxman

(D-Calif.) was able to add $2 million to our

budget over six years to help us conduct

our investigation, but he eventually left

Congress, and our funding was gone, too,”

said Ehrlich. “We’ve asked the current Con-

gress to support us, but we were cut out of

the 2018 budget.”

Unbelievable, but these days, maybe not

so unbelievable.

I’ve been covering the CSB on and off for a

lot of years, and like many other individuals

in and around the process field, I’ve appre-

ciated its cool, computer-animated videos

illustrating the root causes of hundreds

of process safety accidents, as well as its

reports and safety recommendations about

how to avoid similar events in the future.

I can’t think of a more useful and valuable

service to the operators, technicians, engi-

neers and managers in these industries,

or one that does more to show how they

Save the CSB!The U.S. Chemical Hazard Investigation Board deserves the support of everyone and every organization in the U.S. process industries.

By Jim Montague, Executive Editor



can make sure they and their coworkers

“go home in same condition as when they

showed up for work.”

Ehrlich reported that CSB has conducted

800 root-cause analysis investigations since

it was founded in 1998, and it’s achieved a

remarkable 78.8% compliance rate along

the way. CSB’s small, 40-member staff in

Washington, D.C., and Denver provide a

uniquely valuable service to all the pro-

fessionals and employers in the process

industries, and one that should be sup-

ported and preserved by everyone in them.

Consistently supporting and funding CSB’s

comparatively tiny budget would be worth

every penny given what process profession-

als get in return. So, call the offices of your

elected representatives in Congress, and tell

them to put CSB back in the budget. Be the

squeaky wheel that gets CSB some grease.

This is my hope, but truthfully I haven’t

heard a lot of outrage or other voices raised

in support of CSB yet. And sadly, I don’t

expect to hear many as time goes by. Just

as with so many other inexpensive and tak-

en-for-granted services, everyone enjoys

CSB’s videos and reports, but few if any are

likely to go out of their way to advocate

for it.

I think CSB is unlikely to get the lifesav-

ing help it must have because too many

individuals in the process industries view

it is an irritant and unwelcome reminder

about the process safety tasks they should

be performing but aren’t. I’m afraid they

really don’t want to bother, and think they

can get away without doing them—even if

it puts their people and assets at risk and

in harm’s way. They talk process safety

because it’s expected and easy, but they

aren’t really interested in practicing or

genuinely protecting their people, families

and communities.

What’s the word for someone who hurts

people and communities for personal gain

or malice? Criminal or negligent, or both.

If the injuries and deaths that happen

like clockwork in the process industries

occurred in a regular community setting

or municipality, the officers in the police

departments I used to cover as a gen-

eral assignment/police reporter would be

searching for and dragging in a serial killer.

Tragically, industrial injuries and fatalities

carry little if any serious penalties because,

in the U.S. at least, they’re still expected and

accepted, and because the perpetrators are

too well insulated from justice.

Please don’t let these forces of inertia and

neglect keep on winning. Push for the CSB

to get the assistance and funding it needs

to keep on investigating and reporting.

Who knows? You might even help prevent

yourself or someone you know from being

hurt or killed.



oil gas · 2018. 8. 20. · figure 3: oil & gas measurement (ogm) ltd.’s large multiphase...

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