PDVSA modernizes controls at the Jusepín oil production complex

Feb. 21, 2000
Petroleos de Venezuela S.A. (PDVSA) is upgrading automatic controls at its Jusepín production complex, serving the Furrial oil field, about 450 miles east of Caracas.

Petroleos de Venezuela S.A. (PDVSA) is upgrading automatic controls at its Jusepín production complex, serving the Furrial oil field, about 450 miles east of Caracas.

The upgrade to integrated automation technology will replace electronically monitored local pneumatic instruments.

The first phase went on line in December 1998 and marked Latin America's first Foundation fieldbus application and its first control system based on Fisher-Rosemount's PlantWeb field-based architecture.

For the initial step in modernizing controls at the Jusepín complex, PDVSA selected the oldest (Separator Module 1) of seven two-phase production separator modules. Each stage has four identical separator vessels operating in parallel, with common inlet and outlet headers. The medium-pressure stage operates at 120 psig and the low-pressure stage operates at 50 psig.

Production complex

The Furrial field has about 56 flowing wells within an area of 22 sq miles in Venezuela's Monagas state. The field produces about 15% of Venezuela's oil. The produced fluid has about a 20% watercut and significant amounts of associated gas.

To minimize disruption of local agriculture by scattered wellhead equipment, PDVSA has concentrated all field production facilities at the Jusepín production complex. The complex contains production and test separation, compressors, storage, and water injection facilities.

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Established in 1986, Jusepín has grown rapidly in step with the field development. The complex (Fig. 1) encompasses 227 acres and handles about 50% of the designed processing capacity of 400,000 bo/d, 95,000 bw/d, and 350 MMscfd of gas. The field produces a 28° API gravity oil.

Separator module

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Separator Module 1 (Figs. 2 and 3) includes a fanned air cooler that lowers the temperature of the 140° F. gas exiting the medium-pressure separators. The gas then passes through a scrubber with a mesh pad that removes any liquid mist before entering the compressors located in another area of the complex.

The two-phase separator module consists of a row of four medium-pressure separators (on the left), a row of four low-pressure separators, and a row with a mist scrubber and gas cooler (Fig. 3).
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The complex also has a mist scrubber, located in another area, for the gas from the low-pressure module.

Typical module throughput is 16,000 bo/d, 4,000 bw/d, and 50 MMscfd of gas, roughly half of the module's full capacity.

The original automation for Separator Module 1 included traditional oil field instrumentation that consisted of local pneumatic level controls on all nine vessels, local pneumatic pressure controllers on the gas outlet, and a backpressure relief valve at the mist scrubber.

PDVSA monitored operations, but did not control them from the central SCADA (supervisory control and data acquisition) station of the Jusepín complex. The central station received signals from electronic analog transmitters that reported temperatures, pressures, fluid levels, flows, and high and low-level alarms.

The expected main benefits of the upgraded separator controls will be improved separation efficiency and less gas flaring. The new controls should allow quicker response to sudden large slugs of liquid or gas and quicker detection and correction of control malfunction.

Either a too-high liquid level that results in excessive liquid carry-over with the gas or a too-low liquid level that prevents gas bubbles from fully evolving from the liquid can cause separator problems. A sudden liquid level rise can cause a spike in gas pressure, which must be relieved to the flare system, resulting in wasted gas and potential environmental issues.

Facilities can also be upset by incorrectly adjusted controllers or controllers that are inadvertently left on manual control and from valves that become sluggish or stick open or closed.

New process control

In the past, operators have replaced pneumatic controls in a facility, such as Jusepín, with either conventional distributed control systems (DCSs), or with SCADA remote terminal units (RTUs) capable of continuous PID (proportional, integral, derivative) control of level and pressure.

For PDVSA, the expected benefits from these systems seemed too slight and the costs too great in terms of money, process interruption, and learning a new system. In 1998, however, a new generation of process control equipment began to appear. The most widely recognized innovation was Foundation fieldbus (see box).

Because of the new fieldbus and a new concept inaugurated in 1998 by Fisher-Rosemount, called PlantWeb field-based architecture, PDVSA decided to overhaul the controls of Separator Module 1.

Fisher-Rosemount de Venezuela handled the systems integration for the project. Local sales representatives are Corporación Vertix SA and Conind de Venezuela.

PlantWeb architecture replaces the classic centralized DCS layout with a network of intelligent field devices, automation systems, and software applications. The open, scalable architecture can be configured to handle a wide range of control requirements, from a few instruments to many. Control algorithms, for the system, can execute in the automation system or at intelligent field devices.

One of the more important software modules is the asset management solutions (AMS) package for advanced instrument configuration, calibration, diagnostics, and preventive maintenance.

Another key component is Fisher-Rosemount Systems DeltaV automation system, which uses an operator interface based on Windows NT instead of a proprietary type.

Conversion process

The upgrade replaces all 35 pneumatic and conventional analog transmitters (level, pressure, flow, and temperature) with 33 intelligent units. It equips all 11 control valves with Fieldvue digital valve controllers.

The temperature transmitters are Rosemount Model 3244, each handling two RTD (resistance temperature detector) elements. Rosemount Model 3051 differential pressure transmitters sense both gauge pressures and fluid levels.

Foundation fieldbus capability is not yet available for the three compensated orifice meters on gas flow. Instead, these units are Rosemount Model 3095, capable of HART (highway addressable remote transducer) multivariable digital communication, superimposed on standard 4-20 ma signal lines. Similarly, the scrubber temperature transmitter is HART compatible. Except for these, all field instruments use Foundation fieldbus H1.

PDVSA left the 18 existing (legacy) high and low-level switches and their signal lines in place because Foundation fieldbus currently does not have any economical, off-the-shelf method for multiplexing discrete signals.

Separator Module 1 is classified as a Class I, Division 2, Group C hazardous area.

The upgrade migrated a field junction box with analog signal lines (left terminal block) to the Foundation fieldbus (right terminal block). The installation uses only one cable of the bundle to link to the SCADA marshaling cabinet (Fig. 4).
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The upgrade does not require any new conduits or signal wires except for the additional sensor line for each of the new dual-temperature transmitters. The existing (legacy) wires leading from field instruments terminate in a small explosion-proof junction box close to each pair of separators (Fig. 4). Analog and discrete lines terminate in separate boxes located side by side.

Similar junction boxes are at the gas cooler and at the medium-pressure mist scrubber.

A conduit from each junction box carries the signal lines to a SCADA marshaling cabinet for the entire module. Foundation fieldbus uses only six pairs of the existing wires and the HART-communicating flow transmitters use three pairs. The rest of the existing lines are disconnected.

The automation system controller is mounted in a new cabinet next to the SCADA marshaling cabinet and connected to it with four H1 foundation fieldbus segments. Two divide into two branches at the SCADA cabinet. At the controller, the field lines terminate at two dual H1 modules, one eight-channel HART analog input module, and three eight-channel, 24 v DC discrete input modules.

The control algorithm for each of the control valves could be executed equally well at any of three locations: controller, smart transmitter, or digital valve controller. Running the algorithm in either field location would allow control to continue despite interruption of communication with the DeltaV controller. The digital valve controller location was selected.

The automation system can readily be networked with other systems and devises in the field-based architecture. It currently includes an operator station in the central SCADA control room, connected by 10-Base-T Ethernet on an optical fiber link. This station uses a Pentium II desktop computer running Windows NT.

The operator's PC uses Windows NT and is networked via Ethernet and TCP/IP (Fig. 5).
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Fig. 5 shows the PC operator station, running Windows NT and being networked via Ethernet and TCP/IP (transmission control protocol/internet protocol).

Field instruments installed for the initial project phase consisted of 10 of the 13 pressure transmitters, all six temperature transmitters, transmitters and digital valve controllers for five of the nine level-control loops, and all three HART-communicating flow transmitters. Connected to the system were also 6 of the 18 existing level switches.

The installations work was made on a "live" basis, without shutting down any part of the separator module.

Work schedule

Based on prior experience with instrument overhauls of this scale involving totally unfamiliar systems, PDVSA personnel expected the initial installation to take 5-6 months. Instead, the work for installing, calibrating, and commissioning all components lasted only 15 days, reducing installation time by factor of at least 10.

One reason for this surprising efficiency was the familiarity of the operators with the Windows interface. Nearly everyone involved felt at home in that environment and needed only minimal training.

Another key to finishing so quickly was that the automation system controller and operator station interact with the intelligent field instruments on a highly automated, plug-and-play basis. This occurs in the same fashion as Windows NT (or Windows 95 or 98) interacts with the various components of a desktop computer or network. In fact, displays of the control system's hardware and software components look and work like Windows Explorer screens, showing labeled icons in a hierarchy diagram.

As soon as a new instrument is connected "hot" to a Foundation fieldbus segment, it pops up fully identified on the configuration display, and the configuring engineer is prompted to incorporate it into the system.

With the AMS software, a transmitter or valve is configured in a familiar drag-and-drop fashion, taking only a few seconds. Similar quick automation applies to field calibration of transmitters and actuators from the operator station without the need to send a technician to the field.

Therefore, it is easy to see why commissioning did not require laborious point-to-point tests and loop-by-loop configuration and tuning.

Success

Field-based architecture is making many jobs much easier. A reasonable expectation is for a doubling of human-resource effectiveness. For instance, when a valve or transmitter malfunctions, the maintenance crew can be directed to the specific instrument rather than searching among many possible causes of detected symptoms.

Rather than inspecting, calibrating, and servicing field instruments on a calendar basis, the work can be concentrated on the equipment that actually needs it according to indicators such as the total number of strokes or hysteresis trend of a valve.

The architecture has a corresponding savings in maintenance administration and parts stocking. Rather than sending someone out to the field when an abnormal condition is detected, the control-room operator can often deal with it remotely.

PDVSA has realized gains in terms of reduced fluctuations in liquid level and shutdowns of various units or the whole module due to the surging nature of the flow and to instrument problems. Thus, less gas is flared and more liquid is recovered, with savings from an economic standpoint and in terms of environmental regulations.

Further improvements may be realized by coordinating level controls among the multiple separators and using algorithms that adapt to high and low flow. PDVSA appreciates the deterministic character of Foundation fieldbus, which unlike a DCS, does not experience delays in control response caused by occasional heavy maintenance traffic.

From a broader view, the project's significance for PDVSA is that the company has experienced a successful introduction to the latest process-control technology in terms of Foundation fieldbus and an open, decentralized, field-based architecture that can economically encompass an entire plant and integrate with management systems.

For the future, the field-based architecture is entirely open and thus can be integrated with other control systems at the Jusepín complex. Because of the diversity of control equipment at the complex, this capability was a major factor in PDVSA choosing it. Furthermore, this architecture will allow PDVSA to expand and extend the system almost without limit, and without having to change some of the existing equipment.

To date, problems with the upgrade have been few and minor. If the upgrade achieves its expected long-term savings, PDVSA could standardize or implement similar systems in this and other facilities.

The Author

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Victor Yi Hung is a process automation and control advisor for Petroleos de Venezuela SA. He has been involved with a wide range of onshore and offshore oil and gas production and process facilities, most recently with fieldbus for process control and state-of-the-art techniques for downhole monitoring and control.

Yi has an MS in electrical engineering with a degree in electronic engineering.

Foundation fieldbus

A CONSORTIUM OF LEADING MANUFACTURERS CALLED THE Fieldbus Foundation developed the Foundation fieldbus. The first version of this fieldbus, called H1, appeared in commercial products in 1997.

A major impediment to extensive electronic control was that every field instrument had to have its own pair of signal wires in a conduit. This made installation of electronic controls expensive and cumbersome.

With Foundation fieldbus H1, a single twisted pair of wires as long as 6,000 ft, can handle central and peer-to-peer communication for up to 16 transmitters (pressure, temperature, etc.) and control valves at speeds of 31,250 baud. The valve-mounted interface units are known as digital valve controllers (DVCs).

Besides saving on wiring, the fieldbus allows one pair of wires to carry a much wider variety of information than simply process variables and valve commands. The fieldbus line enables computers built into field instruments to be integrated with the control system and each other. Thus, it unleashes the information-processing power that can be packed into the relatively inexpensive silicon circuitry of field instruments.

Advanced algorithms can be performed in transmitters or at control valves. These field instruments can also monitor and report on their own operation for improved reliability and economy.

Also, digital field communication enables use of friendly software interfaces that ease the chore of instrument configuration, calibration, and documentation.