Off the coast of Summerland, California, they didn’t drill the first-ever offshore oil well. They hammered it. “Engineers” used a pile driver to pound a pipe 455ft into the seabed in about 30ft of water. Yield was moderate; the site shut down after several years; and they left a gooey, black mess on the beach with broken-down, wooden piers in the shallow waters up to 1000ft off the coast of the town.
Oil production technology advanced from land to shallow water to deep water and by the late 1980s, nearly a hundred years after Summerland, geologists were better able to recognize the lay of the underwater land that would yield fat flow rates of crude.
Along with such seismic, geological, and drilling- technique developments came the concept of asset management applied to engineering, infrastructure, and certain practices relating to physical assets.
Asset management’s objective? To provide a level of service in the most cost-effective manner and which includes the management of the whole lifecycle of an oil producing structure. This encompasses the design, construction, commissioning, operating, maintaining, repairing, modifying, replacing, and decommissioning/disposal of the physical and infrastructure assets.
Asset management adapted to the microprocessing advances of the late 1990s and 2000s, and inserted itself into the automation scheme that is integral to the advanced functioning of 21st century offshore oil collection. It seems simple; through the use of automation technology the end user can quickly comprehend what assets are doing at all times. That means there is a higher potential for greater productivity, which leads to higher profitability.
Control Center
There are critical aspects that drive automation asset management of oil production platforms. One is the control system and the networking of small-and-large, new-and-old, production systems. That ends up being a software and hardware modification undertaking and includes handling control systems that may be geographically and functionally distributed. In addition, there are applications using IT networks linking resource planning, manufacturing systems, and control, throughout the enterprise.
The control system on a platform is the heart and soul of the beast. Devices, communications, temperatures, pressures, levels, chemistry, speeds, content, analysis, on-off switching, and other information, run through the control system.
All aspects of production assets, safety, device status, maintenance, and the business management components, take from the control network the data they need to perform their functions.
Indeed, oil companies use multiple vendors in the staging of their operations. While platform and oil production instrumentation and automation is not an exclusive club, it does encompass exacting technologies that demand understanding what every device is doing at all times.
Until the 1970s, control of the process on a platform used panel-mounted, loop controllers. A single operator would watch one or several gauges, which were reporting a parameter like temperature, pressure, or the sulfur content, of downhole oil passing through a conduit.
This level of expertise – the single-loop controller – is to modern platform operational control what that pile driver was to modern drilling techniques.
Innovations to operation on oil rigs have come a long way since the age of panel-mounted loop controllers.
With the introduction of distributed control systems (DCS), operators’ methodology changed drastically. Operators could now grasp the platform-wide operation by monitoring from a central control room.
“If you look at some of the phenomenal technology they have deployed in the seismic and downhole areas, they are not risk averse,” says David Bleackley, senior director global accounts at AspenTech. “The production side has sometimes lagged the others by 20 years. That culture is changing. The first wave was MES (manufacturing execution system) technologies and having the ability to move from SCADA (supervisory control and data acquisition) systems to fully-fledged MES systems to enable visualization through the whole enterprise. I think that wave is ongoing. I think the control space is the next challenge. If the users are confident the technology is robust and sustainable, then it will take off.”
A DCS typically uses custom- designed computer processors as controllers with proprietary interconnections and communications protocols to talk to process assets spread over large expanses of territory.
These assets include input and output modules that form the component parts of the DCS. They also include all the instruments – switches, pumps, valves, meters – in the process (or platform). As well, the assets are the computer buses and or electrical buses that connect the processor and modules. Buses also connect the distributed controllers with the central controller and finally to the human-machine interface (HMI) or control consoles.
Asset makeover It’s not uncommon to have a makeover from one vendor system to another as transpired at BP’s Bruce offshore platform in the North Sea. Bruce is one of the largest fields in the UK North Sea and contains estimated reserves of 2.6Tcf of gas and 250MM bbl of condensate, NGLs, and oil.
“This project is the largest system replacement to date in the UK North Sea,” says Steve Barber, BP’s project manager of the Bruce changeover. “The past two years have seen exemplary performance with not a single integrity issue or production loss attributed to the system from initial commissioning until today.”
“The previous system was causing production losses from time to time.
“Operator acceptance of the system was exceptional and resulted in increased awareness and ability to handle process upsets, easier process fault diagnosis, and more expedient restarts,” he says.
Some of the assets swapped in were:
ESD/F&G (emergency shutdown/fire and gas) scheme that has 24 subsea controls systems. Oil companies connect not only producing platforms in fields, but fields themselves spread over vast areas of ocean and even the company’s land operations.
Indian multinational oil and gas company ONGC (Oil & Natural Gas Corporation), completed a project in the Arabian Sea that monitors, controls, and provides real-time data about its offshore and onshore production and processing facilities.
That project incorporated 11 of fshore processing complexes, 157 offshore wellhead platforms, 74 drilling rigs, 7000 wells, 247 onshore production facilities, and 250 centers for local, regional, and mobile control.
A SCADA system designed for the oil and gas industry was selected for the project. It employs three-tiered technology, which provides field personnel, control room operators, and senior management, with immediate information on the performance of production assets dispersed over large geographic areas.
The solution integrates directly with ONGC’s two existing business information systems – Exploration & Production Information Network (Tier 2) and Enterprise Resource Planning system (Tier 3).
This is the complete asset connectivity oil companies need, so they can get the most out of their assets. “The solution enables us to collect information from all our various locations and installations, so that we know what is happening moment by moment anywhere in our business, just by logging into a laptop,” says ONGC’s SCADA installation project leader NK Barat. From such systems, asset-and-production reporting rises from live data, from all connected assets at the enterprise level. Business managers can make decisions that are more accurate if they have access to real-time information from across the board. This leads to improvements in fiscal and production decision-making.
Asset Control, Managment
For some time now, offshore platforms have had to have safety-instrumented-systems (SIS) that work in concert with all device asset systems, control systems, and business systems. The safety system must conform to the IEC 61508 international safety standard and be able to serve in SIL 3 (safety-integrity-level 3) applications. IEC 61508 Functional Safety of Electrical/ Electronic/Programmable Electronic Safety-related Systems is an international standard of rules applied in industry.
The safety integrity level (SIL) derives from the assessment of three factors. Higher-level safety integrity levels require greater compliance in three areas: improved reliability, failure to safety, and management, systematic techniques, verification, and validation. SIL 3 is the next to highest level of stringency of safety. SIL 2 occurs in refineries, while SIL 3 occurs in offshore platforms and some nuclear facilities. SIL 4 is the highest risk and occurs only in the nuclear industry.
“Safety is the most important consideration in plant operations,” says Takashi Nishijima, a director, senior vice president, and head of the industrial automation platform at Yokogawa. “The tighter connection, not only with Yokogawa’s DCSs, but also other vendors’ systems, makes it easier for companies to adopt our safety-instrumented- system.”
The absence of safety, an asset, leads to far grander economic consequences than a generation of revenues can cover.
That is why the integrated control and safety system (ICSS) on the Qatar Petroleum, ExxonMobil, and Italian energy company Edison’s offshore regasification platform off the coast of Porto Levante, Italy, is all about asset control and management.
The Adriatic LNG Terminal (ALT) is a huge state-of-the-art, gravity-based structure (a platform that sits on the seabed and which stays in place by gravity) with facilities for the mooring and unloading of LNG vessels, two 125,000 cu m LNG storage tanks, and an LNG regasification plant. Pumps move natural gas from the platform through a 30in. pipe, 15km to the mainland where the pipeline connects to the national gas distribution network.
The individual components of this ICSS are its distributed control system, a safety-instrumented system, and an additional network-based control system for pipeline monitoring and leak detection at the block valve and metering stations. In addition, there’s an operator training system.
As well, there are systems from disparate vendors like the LNG unloading system, tank gauging system, pipeline-monitoring system, metering system, and gas turbine system. They all integrate via a Modbus interface with the ALT’s main control system.
“LNG carrier scheduling, unloading, tank storage, and vaporizing, are all procedure-based operations, and need to take place flawlessly,” says Russell Golson, operations manager at ALT. “Our availability is about 99.5%. All process and device asset data is clearly visualized for optimum operation, maintaining a clear gas business plan and creating optimal LNG supply chain scenarios.”
ALT’s ability to visualize process data from throughout the terminal allows the preparation of production reports, calculation of plant efficiency, and performance analysis of individual processes.
Archived reports on the accumulated running time of rotating equipment such as LNG pumps and compressors enable operators to determine the optimum timing for equipment maintenance and replacement. The visualization of asset data throughout the terminal puts the right data in front of the right person, enabling the right decision, at the right time.
Real-time Knowledge
Using real-time, plant-instrument management tools, oil companies administer instrumentation calibration, device diagnostics, and maintenance records, on their platforms.
As well, increased regulatory oversight of the industry demands more data to prove or ensure compliance with safety laws and environmental oversight. This is merely a software chore now. Moreover, since this is real-time information, if a problem develops, like a sticking valve, maintenance can be immediately aware of the situation and stop possible deterioration into a costly or unsafe event.
A critical component of this digital device networking is the compatibility and inter-operability of instruments from different vendors. After years of proprietary systems followed by serious conniption and negotiation, users today are able to enjoy “open” systems thanks to technologies and protocols like Windows, OPC, Foundation fieldbus, Profibus, HART, and others.
This open environment is in contrast to the classic “proprietary DCS controlroom centric” interface topology. Today, the oil industry can select the instruments it considers best and not fear they can’t talk with other, older, different vendors’ instruments. “The non-proprietary, Foundation fieldbus digital- control technology has ushered in a new era, so that we can install ‘best-in-class’ host and field devices with confidence [that] these products will work seamlessly on the same control network,” Shell principal process control & instrumentation engineer Dick Wismeijer said, after Shell selected an open system for its Malampaya development, a deepwater gas-to-power project in Southeast Asia that supplies natural gas to power plants in the Philippines.
“We can integrate information from comprehensive plant-wide process and equipment monitoring and control areas with the SIS, the gas pipeline monitoring systems, and the telecommunications systems,” Wismeijer says.
The network on this job included five subsea wellheads, an offshore gas-processing platform, a 500km long, 24in. gas pipeline to the island of Luzon, and an onshore gas treatment plant with dispatch center.
The power of these fieldbus-connected, intelligent instruments includes the ability to perform predictive maintenance and diagnostics on the devices from afar. The data flowing from the instrument provides information as to instrument health. With that, Shell can schedule calibration as needed, as well as predictive maintenance.
Scheduling calibration only as needed instead of on a periodic basis saves money. If the device is working within its bounds, there is no need for action. However, if there’s a more critical instrument, Wismeijer says Shell might have to calibrate more often to improve performance, or calibrate as it starts to drift out of range. Both strategies are possible.
Predictive maintenance is perhaps the most important benefit an end user can receive via a fieldbus system. Using the data delivered by fieldbus, the user can predict problems before they occur. Maintenance can take place on a planned basis as opposed to reacting to a difficulty, which saves money, improves safety, and can eliminate unplanned downtime. If a field device is failing, it is possible to repair or replace the device before it brings down the entire process. “We expect the diagnostic information from our intelligent fieldbus devices to insure high overall production system delivery availability, and we expect unprecedented uptime at the Malampaya development,” Wismeijer says. Device asset systems also handle commissioning tasks such as valve tuning, loop checking, device configuration, and creative troubleshooting. In addition, for valves retrofitted with new positioners, many of these systems can ascertain valve signatures.
For all devices on the platform, the system provides maintenance personnel quick access to all related instrument documents like loop drawings, manuals, and hook-up drawings registered on the system.
The Way Forward
This we know: with the decline in available resources on land, the move to offshore exploration is inexorable. There have been huge deepwater discoveries in a wide variety of places including Brazil, Gulf of Mexico, West Africa, and the Asia Pacific region.
Technology advancements are promoting increased activity in deep and ultra-deep waters.
As shallow-water resources decrease, these deep and ultra-deep, subsalt areas will play an increasingly significant role in offshore oil and gas production.
The rewards are huge. The amount of energy to produce is staggering. It’s clear producers will be collecting oil offshore through the end of this century. Possibly more oil lies offshore than exists as known reserves now.
The days of pile driving wells are long gone and the oil industry has the means – the assetmanagement automation umbrella – to safely deliver the goods thanks to the prime assets – control, safety, and devices – that have emerged from over 100 years of trial, development, and high technological advancements. OE
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