The primary aim of the digital oil field is to optimize the production of existing wells in the context of an overall reservoir performance plan that is tied to business drivers.

Remote supervisory control and data acquisition (SCADA) systems that utilize low-cost sensors and controls for well and borehole monitoring allow reservoir engineers to monitor well and field performance in near real time.

Exploration and production (E&P) enterprises can embed agility by adopting solutions that rely on standardized, configurable components, open-source technologies, and fault-tolerant devices and networks. Beyond the basics, to fully uncover value, agile enterprises must embrace event-enabled processes and integrate business intelligence systems.

Value

Extracting value from existing oilfield assets through digital "virtualization" offers tremendous promise. The "digital oilfield" concept generally strives to create visibility into the performance of those assets from the well to the pipeline, across the value chain.

However, this model continues to face challenges, as Cambridge Energy Research Associates' (CERA's) 2003 report, "The E&P Virtual Enterprise Evolves," notes. The primary obstacles continue to be managing the loss of direct control and supervision of work, establishing suitable technical infrastructure, and integrating far-flung workers into an effective team.

The CERA report suggests that we look for examples of success of virtualization in other industries as leverageable models for the E&P industry.

EDS had the privilege of helping one of its clients, Detroit Water and Sewerage Department (DWSD), eliminate metering disputes, improve system reliability and streamline operations. The solution was built around a remote automatic meter reading (AMR)/SCADA system that relies on highway addressable remote transducer (HART) communications technology. The DWSD plant was recognized as the 2003 HART Plant of the Year.

DWSD's situation is, in many ways, quite similar to the environmental conditions experienced by oilfield operators. DWSD's services extend far beyond Detroit's city limits to an area of more than 1,000 sq miles (2,590 sq km). Water flow and pressure are controlled and measured through instruments housed in nearly 300 underground metering pits throughout the system.

Prior to implementation of the AMR/SCADA project, data was recorded via chart recorders and similar paper-producing methods. Disputes arose between the DWSD and its municipal customers over consumption data due to multiple metering systems in use.

Working with the service company, DWSD established some goals for its solution:

• The system had to be dependable - failure of any single component could not disrupt system performance;
• The integrity of metering data had to be preserved;
• Equipment and control of software versions would be standardized;
• Reliance on paper documents should be minimal; and
• Software aids should be incorporated into the SCADA system for maintenance, calibration, performance monitoring and other functions.

DWSD was particularly keen to adopt a digital means of measuring and transmitting data that would work with the variety of measurement technologies already in place.

The solution that the team devised, based on the HART protocol with its stable performance history and cost-effective adaptability, integrates a vast array of diverse field devices and technologies on a single networked system. The result is a common odometer total display that can be read via the LCDs on the HART meters, just like the odometers of the mechanical meters, while the remote transmission unit (RTU) collects total and instantaneous rates-of-flow readings to control switching between the large and small venture meters using standard and extended HART commands.

In addition to stemming billing disputes with DWSD's customers, the AMR/SCADA system provides some other benefits to which oilfield producers also aspire. Among them are:

• An increased ability to quickly detect and repair troubles in the distribution system;
• Improved safety through HART-enabled remote monitoring, calibration and validation, thus reducing the need for field crews to enter potentially hazardous meter pits;
• Greatly enhanced value from existing instrumentation without having to rely on communications technologies that are not as field-proven or that require steep investment and risk;
• The ability to drive computational functions (e.g., totalization) to the field device, which frees the higher-level PLC/RTU for tasks such as monitoring equipment health; and
• Fault tolerance through the ability of HART instruments to retain a history of their readings and through the packet radio network's ability to reroute signals in case of node failure.

The multidrop configuration capability of HART technology works well in the E&P environment. In a Venezuela gas-lift project, HART was used for remote operation of offshore gas-lift production wells at considerable savings, including:

• A 30% decrease in installation costs;
• 16:1 reduction of input modules;
• Remote reranging; and
• Remote access to the transmitter status for improved process uptime.

While we think HART is an appropriate technology for the oilfield environment, it's certainly not the only solution. There are a growing number of open communications protocols available to instrument engineers today. All digital fieldbus technologies such as Profibus have matured considerably and can certainly take their place in the operating environment. Similarly, where TCP/IP-enabled Internet devices are appropriate, the industry's own XML-based Wellsite Information Transfer Standard Markup Language (WITSML) can offer compelling benefits.

The emphasis should be on finding the appropriate mix of open-source and proprietary technologies that support reliable, configurable solutions at the optimal price point in the risk-versus-reward equation. The design principles for an agile E&P operation should include:
• Open plug-in architecture with well-defined interfaces;
• Resilience to changes over time;
• Industry and de facto standards compliance;
• Event-oriented digital nervous system;
• Service-oriented interface bus with Web services;
• Utility-based resource provisioning and billing control; and
• Self-executing predictive monitoring and control.

Self-prediction is a key point in unlocking the full value of the digital oil field. The integration of business intelligence tools such as data mining into the remote SCADA systems can help the oilfield operator spot trends or patterns in exploration and production that can be exploited near real-time, instead of after the fact, for maximum benefit. As with every technology application, the digital oil field is a constantly evolving environment. And evolution favors the agile who combine leverage and speed to transform their operations through digital solutions.

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