The oil and gas industry has embraced the digital oil field concept that has resulted in advances in information and communication technologies. Fiber-optic networks, advanced sensors, processing power enhancements, massive improvements in data storage, and visualization techniques have created a new vision for how oil fields function.

The challenge has been to apply these advances to manage the high cost of deepwater completions, replace reserves, optimize production, reduce cost, and accommodate changes in how people work.

The benefits of success, however, are huge: Cambridge Energy Research Associates estimates that the digital oil field could add 2% to 8% to production and 1% to 6% in additional recovery across the industry.

Remote performance management — gathering, conditioning, automatically analyzing, and communicating surveillance information — is one of the three principles of BP’s Field of the Future program. (Images courtesy of BP)

Experience is showing that change is taking place. Seamless workflows, innovative data handling tools, real-time information, and high levels of automation increasingly are part of the plans companies implement to build and operate their global assets.

Implementing digital solutions

BP’s Field of the Future program is aimed at improving decision support by applying real-time data capabilities in production and reservoir management. The program provides a suite of technology-based solutions focused on the goal of making better decisions faster.

The Field of the Future program has three principal components:

• Digital infrastructure and IT architecture: providing the essential equipment and standards to enable implementation solutions;

• Remote Performance Management: gathering, conditioning, automatically analyzing. and communicating surveillance information; and

• System Optimization: making the best use of real-time information using model-based and advanced analytical techniques to reach optimal production and recovery for the asset or system.

The program, initiated in 2005, has a strong and growing track record of implementation, which has advanced significantly in the past two years. Technology has been deployed in high-rate offshore oil and gas fields, where the risks and rewards are largest and most clearly defined. BP operations in the Gulf of Mexico (GoM); Azerbaijan; Angola; Trinidad; the North Sea; and the Tangguh LNG development in West Papua, Indonesia; all have seen the introduction of elements of the digital toolkit. Around 80% of BP’s top-producing wells are operating with the support of real-time information. In short, digital developments are becoming part of routine operations.

How the digital oil field works

Integrating a portfolio of individual capabilities to assist assets in how they operate and manage resources is an important aspect of the Field of the Future program. Advances in remote monitoring in the GoM, for example, only could have happened on the back of the successful installation of an 808-mile (1,300-km) fiber-optic communications network.

BP’s proprietary ISIS software provides alerts about well conditions, cleans and conditions data, and includes analytical functionality that helps the production team understand performance.

Remote performance management fundamentally is about giving asset operators the necessary information to allow them to react to events quickly and at the right time. This includes providing predictive tools that enable optimal performance to be achieved.

Access to real-time data sources and the analytic and visualization tools that exploit them supports remote operations, engineering, and HSSE performance. It enables monitoring, alerting, and predicting flowline and pipeline integrity and provides equipment monitoring and alerts. This covers aspects of operating such as run times, safety valve performance, vibration monitoring, and chemical inventories. Real-time information supports condition-based maintenance – saving time and cost by ensuring maintenance is carried out only when necessary and convenient.

Real-time data from well sensors and associated parts of the facility also are making it possible to monitor the state and performance of the well stock. This is assisting with well integrity monitoring and alerting, well upset (sand production and stability) monitoring and alerting, well performance monitoring (rates, phase, well test performance), production allocation, distributed temperature measurement, and automated data transfer to analytic tools and automated analyses.

A BP proprietary software package – ISIS (integrated surveillance information system) – provides alerts about well conditions, cleans and conditions data, and includes analytical functionality that helps the production team understand performance. Well modeling tasks previously carried out manually on a case-by-case basis now are conducted automatically and continuously.

The intelligent field

An example of some of these tools in operation is the application of equipment monitoring capabilities in the Azerbaijan export terminal at Sangachal, which processes oil and gas from fields in the Caspian Sea. Important features of this implementation have been monitoring of key rotating equipment run time and critical blowdown and safety valve performance.

Enhanced monitoring capability introduced at Sangachal has enabled performance characteristics, maintenance requirements, and failure modes to be identified, allowing maintenance efforts to be focused on problem areas and appropriate mitigations to be identified. In some cases, it was demonstrated that more efficient maintenance practices could be identified, reducing or eliminating unnecessary maintenance intervention. In particular, this has reduced or eliminated preventive maintenance tasks for equipment with good performance history.

Monitoring also facilitated early warning of deteriorating performance and improved the assessment of the reliability of equipment with low utilization. This has helped maintain plant integrity and reduced risk by decreasing the frequency of unnecessary, intrusive checks. Significant cost savings have been identified from this and other steps.

Applying well monitoring capabilities in the subsurface and wells has had substantial impact on operations, delivering:

• Increased production – typically 1% to 2% of the original base production;

• Supporting reserves pull-through via improved data (e.g. production allocation) feeding models and reservoir management decisions;

• Reduced costs through better targeted interventions and infill drilling decisions; and

• Improvements in staff efficiency – up to 25% observed.

Benefits also have been achieved in new field startups. On Thunder Horse in the GoM, for example, the provision of high-quality monitoring information in real time, relating to well rates and production stability, has enabled early assessment of well startup performance. The delivery of essential information about reservoir behavior and response allowed the wells to be operated with confidence. Reservoir performance uncertainties were reduced, resulting in an immediate impact on execution of the depletion plan.

The GoM “Advanced Collaborative Environment,” where drilling, reservoir, and process engineers co-located onshore analyze real-time data from fields offshore, has enabled onshore control loop tuning to be performed (saving an offshore trip as well as engineering time). Problems bringing on new wells and subsea equipment have been diagnosed – increasing production rates, avoiding loss, and saving cost. And swift responses to events have avoided entire production shutdowns.

A further example of remote performance management has been the application of Distributed Temperature Sensing (DTS). BP has installed DTS in 26 sand-controlled completions in the past four years, improving reservoir management and delivering greater operations efficiency. Implementation has improved understanding of inflow profiles along the well bore with benefits for how wells are operated and offtake managed.

These examples illustrate the intelligence in action that the Field of the Future program was designed to deliver and that has resulted in production benefits. Lessons have been learned, such as understanding impacts on business processes and workflows and helping people adapt to changes in roles, accountabilities, and behavior. And more benefits are emerging.

Digital technologies are creating the future intelligent energy environment now.