Fieldbus, advanced technologies reduce Alaska development costs

One such case is ARCO Alaska Inc.'s West Sak project, the world's first implementation, at an oil-production site, of the fieldbus protocol from the Fieldbus Foundation (see box).

In concert with innovative engineering and other new technologies, the fieldbus was instrumental in making West Sak oil production economic. Moreover, as ARCO Alaska expands phased development at West Sak, fieldbus-based systems are expected to help reduce, by as much as 50%, the incremental automation cost.

North slope

To offset declining production at these sites, ARCO and other oil operators have sought to develop new North Slope fields. But new oil production in fields like West Sak was stymied by low-productivity wells and high development and operating costs.

ARCO had to develop innovative new technologies and new tools to produce the elusive crude on the North Slope.

Located in the Greater Kuparuk development area west of Prudhoe Bay, the West Sak field is jointly owned by ARCO, BP Exploration Alaska, and several minor interest owner companies.

It is a large, relatively shallow oil reserve at an average depth of 3,000-3,500 ft. West Sak overlies much of the previously developed Kuparuk field, holds an estimated 15 billion bbl of oil, and is larger than the Prudhoe Bay field.

The West Sak Phase 1 project, which was completed on time and on budget, was the most significant technology advancement for ARCO Alaska in 1997. It demonstrates that the industry is on the verge of true "plug-and-play," fieldbus-based oil field automation.

Planned for completion in 1999, the 50 wells at West Sak are expected to add oil production of nearly 7,000 b/d and help ARCO achieve its North Slope production goal of "No Decline After '99."

Meeting challenges

Another ongoing challenge is the harsh North Slope environment, where winter temperatures can plummet to -65° F. and wind chills reach below -120° F. In this difficult and isolated setting, labor costs rank among the highest in the world.

After conducting a pilot project at West Sak in the mid-1980s, ARCO Alaska concluded that recovery costs were too high to make production economical; however, oil field technology has come a long way since then.

By the mid-1990s, ARCO Alaska recognized that state-of-the-art technologies had changed the game and could make West Sak development both viable and profitable with proven recovery techniques. Smart instrumentation based on Foundation Fieldbus technology, for example, could make surface infrastructure easier to install, operate, and maintain.

The goal for Phase 1 of the West Sak project was to begin economical oil recovery by the end of 1997.

Phase 1 encompassed 50 wells to be added on two existing drill pads (Drill Sites 1C and 1D), with a two-third to one-third split between production and water-injection wells. The long-range plan envisions the drilling of 550 wells at West Sak.

From the onset of development, ARCO Alaska believed that the optimal oil field automation system not only had to reduce upfront capital costs, but it also had to reduce operating and maintenance costs. The system also had to be capable of incremental expansion at minimal cost.

Automation solution

The choice of automation solutions came down to the following factors:

• Need for an open solution
• Life-cycle cost
• Ability to have remote diagnostics
• Using a company as committed to the technology as ARCO.

The fieldbus-based solution also offered the ability to remotely diagnose process and instrumentation problems using smart instrumentation linked to the control room or maintenance shop. The diagnostic information embedded in these instruments would save time and reduce labor costs during commissioning and ongoing oil production.

The final factor in the automation decision was that the fieldbus is truly an open system. Unlike proprietary technologies, it would not limit ARCO Alaska's ability to choose the best available product for future development at West Sak.

Only the fieldbus-based solution proposed by Fisher-Rosemount met all these requirements.

Automation overview

• Rosemount Model 3051 pressure transmitters

• El-O-Matic ELQ actuators

• Fisher-Rosemount Systems' DeltaV process automation systems.

The DeltaV system was a good fit for the West Sak project because it is highly modular and scalable, allowing the installation to grow as additional production wells come on line (Fig. 1 [21,857 bytes]).

In addition to the fieldbus, other technologies and methodologies that helped make oil recovery from the West Sak field economically feasible included:

• Streamlined project engineering and change management-Together with the engineering contractor Alaska Anvil, ARCO developed an approach for completing all infrastructure engineering up front. Drawings used for the first wells can easily be "cloned" and modified for subsequent wells for faster commissioning and lower expansion costs.

• Downhole pump and water injection technologies-Submersible pumps and water injection techniques help lift the viscous oil to the surface. The pumps are controlled by Centrilift variable-speed drives using pressure and temperature measurements from Baker Oil Tools' downhole instrumentation.

The valve that handles the extreme pressure drop between the water injection system's main line and individual wells is equipped with a Fieldvue valve controller that provides diagnostic information to alert technicians when the valve needs maintenance.

• Digital integration at the surface-Process information from various sensors, instruments, and equipment at the wellhead is integrated and brought back to the control room in digital form via the fieldbus. Also, downhole and surface instrumentation from Baker Oil Tools passes information on a Modbus cable to the DeltaV system, which in turn is linked to the Centrilift variable-speed drives via Modbus.

Classic or traditional I/O was used only when a digital solution was not available or when dictated by a process safety assessment. This added up to less than 3% of the total I/O for the project.

• Elimination of oil and gas separators for production testing-New gas/liquid production test meters from Accuflow are smaller and less expensive than traditional, three-phase test separators, thus reducing space and cost.

These production test skids also include Micro Motion Coriolis mass flow meters for liquid rates, Rosemount vortex flow meters for gas rates, and Fisher Fieldvue valve controllers to control liquid level.

• Remote diagnostics-Remote diagnostic capabilities enable smart field instruments to be located at the well. Diagnostic information is communicated back to the control room via fieldbus, allowing technicians to view field device status or perform troubleshooting in a warm office rather than spending additional time out in the cold; inspecting field instruments.

Diagnostic information for the Baker Oil Tools instruments and Centrilift drive is carried by the Modbus links between those devices and the DeltaV system.

Team approach

Alaska Anvil, the primary engineering contractor, was responsible for designing the solution and APC (Alaska Petroleum Contractors), performed installation, and checkout. PCE Pacific assembled the instrument panels and provided project coordination, and Fisher-Rosemount Industry Solutions provided implementation support services for all fieldbus products.

Project funding was approved in February 1997. Implementation began in June with a kick-off meeting in Austin, Tex., involving engineers from ARCO Alaska, Alaska Anvil, PCE, and Fisher-Rosemount.

At that time, the challenge ahead seemed tremendous. It encompassed everything from how fieldbus was going to be implemented to what the control network topology and configuration would look like and how many workstations were required.

Over a 3-month period, ARCO Alaska worked with the suppliers on the project team to provide integrated solutions for the Centrilift drives, Baker Oil Tool equipment, El-O-Matic actuators, the DeltaV system, and Rosemount fieldbus instrumentation. Staging and troubleshooting for the entire automation system, including third-party equipment, began in Austin in November 1997.

Some suppliers enhanced product capabilities to meet project requirements. For example, El-O-Matic modified its actuator design so that switches from the surface safety valve (SSV) at the wellhead could be wired directly into the actuator. This allowed the SSV signals to be sent back to the control room on the same fieldbus cable used to communicate with the valve.

This project enhancement contributed to a 98% reduction in wire between the wellhead and the control room when compared to hard-wiring these instruments using the conventional approach.

While the fieldbus is sometimes thought to address only continuous, analog control, more than half the function blocks of the fieldbus implemented at West Sak are designed for the discrete world.

The El-O-Matic actuators contain some of those discrete blocks to control on-off divert valves. Activation of these on-off valves is now handled through the fieldbus by the DeltaV control system.

Smooth FCO, start-up

Installation of each fieldbus transmitter took about 20 min rather than the 3-4 hr needed with non-fieldbus technology.

FCO for an entire well, which included three transmitters, two remotely operated valves (ROVs), two pressure switches, and SSVs, took only 3 hr. Ordinarily, it would have taken an entire day to verify all well equipment in the field.

The fieldbus start-up was fast and uneventful, perhaps one of the smoothest in ARCO history. The commissioning crew was one-fourth the size expected for a project of this magnitude.

The fieldbus instruments and host system started and ran flawlessly, handling more than 1.5 million fieldbus communication transactions in the first day without a single error. The automation system was up and running for first oil, and commercial oil production from the West Sak field began Dec. 26, 1997.

Less is more

With the automation solution on line, ARCO Alaska is now seeing the positive results and benefits of implementing the fieldbus. The fieldbus has meant lower capital expenditure from labor costs, reduced piping, less wiring, fewer terminations, smaller controller cabinets, easier maintenance enabled by remote diagnostics, and streamlined engineering and configuration, as well as a cost-effective incremental expansion.

In fact, incremental facilities costs (piping, home runs, engineering drawings, FCO, etc.) for adding a well at West Sak are expected to drop to about half of the historical cost of adding a well (Tables 2 and 3).

Wiring, I/O, terminations

Instead, the instrument wires run a short distance in the field to a junction box. From that box, a single fieldbus cable runs to another junction box outside the control room and from there directly into a panel inside the control room.

For every four wells, there is one fieldbus "home-run" wire pair between the field instruments at the well and the control room. This results in a 98% reduction in home-run wiring and makes it easy and inexpensive to add new wells and home runs.

Fig. 2 [26,804 bytes] shows the layout of the H1 segments.

Some of the wiring reduction also resulted from efficient design. For example, the El-O-Matic actuators have an auxiliary discrete output and two auxiliary discrete inputs. These are used to control a solenoid valve and to monitor two pressure signals from the well head area and send the data back to the DeltaV system along a single fieldbus connection.

Combining these discrete signals into the actuators has saved an average of 800 ft/well of power-supply wire.

Because there is no longer any need to connect a pair of wires for each instrument to a specific set of terminals on the I/O card, the fieldbus does not require wire tags for individual wires to each instrument but rather a cable tag per fieldbus cable.

The ability of a single fieldbus cable to handle multiple signals also led to a major reduction in the number of I/O cards. Because the fieldbus allows fewer wires and terminals, labor costs for installation were much lower, resulting in an estimated 80% savings in overall termination costs.

Much of the termination reduction came from inside the control room. Here, one of the primary savings resulted from the relatively few terminations required to handle the Centrilift variable-speed drives (VSDs), which typically have 275 terminals/drive.

The VSDs now connect to the DeltaV system via Modbus with nearly one-sixth the number of terminations. Normally, the VSDs for 32 wells would have required 1,150 terminations. With Modbus, that requirement dropped to less than 200 terminations.

Fewer terminations also freed up two-thirds of the cabinet space that would be required with traditional technology. The cabinets are not only smaller, they also handle more wells.

For example, a cabinet at West Sak can now handle about 64 wells and yet is one-third the size of a conventional cabinet designed for only 16 wells.

The overall savings in reduced terminations enabled by the fieldbus and Modbus was an astonishing $500,000 for drill sites 1C and 1D.

Piping, manifold buildings

This approach complements a trunk-and-lateral piping design that eliminates the need for manifold buildings. These structures and the extra piping they contain pose a major capital cost of up to $2 million for the delivered module before installation.

The streamlined piping design will also help reduce incremental costs associated with adding wells or changing a well from a producer to an injector.

Previously, putting all the extra pipes into place added months to a project schedule, with pipe runs costing up to $25,000/100 ft.

Drawings

Now the engineer simply "clones" the drawing for an existing well, changes a few labels, and the work is done.

Similarly, the DeltaV system's Windows NT-based configuration tools and object-oriented capabilities enable engineers to create templates that simplify reproduction of repetitive objects or processes using easy "cut and paste" programming techniques.

In the past, the entire engineering process for a single well could last from 8 to 16 weeks. Now, an inexperienced technician can perform the job in a couple of days, and a more skilled engineer might complete the work in 3-4 hr.

Well testing

With the DeltaV system, test procedures can be handled automatically, and the required operator time has been reduced to less than 1 hr/week for a 32-well pad.

Maintenance, diagnostics

Although it is still too early in the West Sak project life cycle to report conclusive savings in maintenance because of remote diagnostics, it is safe to say that future maintenance tasks will be greatly simplified.

The impact of reduced maintenance costs is expected to be significant. According to some studies, maintenance represents 60% of a project's 10-year, life-cycle costs.

Fig. 3 [30,794 bytes] shows a typical display that includes the diagnostic information about the well.

Future

For that reason, it is anticipated that much of ARCO Alaska's future North Slope projects will be built on the technology platforms pioneered at West Sak. In fact, West Sak is already serving as a prototype for new satellite fields.

Key technologies used at West Sak, such as the fieldbus, will enable these fields to become fully automated much more quickly than with traditional approaches.

The upcoming Tarn project, for example, is expected to be the world's fastest remote oil field development, advancing from inception to production in only 14 months, including new drill sites.

Ultimately, streamlined infrastructure, operations, and maintenance enabled by the fieldbus will benefit ARCO Alaska, its contractors, and the entire industry.

The world is rapidly going digital, and West Sak proves that the oil patch can be on the leading edge of that digital wave.

The Authors

Duane Toavs is staff engineer, Kuparuk projects E&I technical coordinator, for ARCO Alaska Inc. in Anchorage. He has worked for ARCO, primarily in Alaska, since 1983. Toavs has a BS in electrical engineering from the University of Idaho.

Mel Olson is system sales manager for PCE Pacific Inc. in Anchorage. He has been involved with the control system aplications for 20 years. Olson has an MS in chemical engineering from Oregon State University and is a registered professional engineer.

What Is the Fieldbus Foundation?

Its fieldbus is a subset of the ISA S50 fieldbus standard and the emerging IEC 1158 fieldbus standard. The protocol is an open, industry-accepted technology that enables use of "best of breed" field devices from multiple suppliers, without locking users into the proprietary offerings of a single supplier. Other benefits include:

• Easier and less costly installations
• New levels of performance
• Solutions for discrete and process applications
• Reduced instrument wiring and terminations
• Enhanced field-level control
• Accurate and reliable diagnostic data
• Reduced process errors
• Easier predictive maintenance

Copyright 1998 Oil & Gas Journal. All Rights Reserved.