Article - Issue 19, May/June 2004

Digital energy – working smart in the oil and gas industry

John Darley

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Working smart in the oil and gas industry

In the past, the technologies used in well engineering have been relatively simple. The well was drilled and the hardware selected, installed down the hole and locked in place. The production then started but the well remained passive. It was essentially just downhole plumbing – albeit on a grand scale. With the oil industry approaching ‘middle age’ – having produced about half of current proved reserves – merging state-of-the-art technologies now available will enable wells and fields to become ‘smart’. This will ensure the oil and gas industry receives a lot more value for input and extends the producing life of its traditional assets.

In a traditional well, components such as valves control the flow of fluids; screens or gravel packs stop sand from entering the well; then there are all the pipe joints and packers needed to ensure the well retains its integrity over its producing life. However, traditional wells do not respond to changing conditions and all the fluids (oil, gas and water) have to be produced together and separated at the surface.

What is ‘smart well’ and ‘smart field’ technology?

Smart wells offer the possibility to respond to changing conditions, and the evolutionary process has begun with smart wells and smart fields already proving their worth. Over the past few years Shell scientists and engineers have played a major role in promoting and developing smart technology. Various sites worldwide – from the USA, to the North Sea, West Africa, the Middle East, Brunei and Australasia – have all successfully installed smart well components.

What makes the wells and fields smart is not the new technology in itself, but rather innovative ways of combining existing state-of-the-art technologies such as wireless technologies, remote sensing capabilities, remote control mechanisms and robotic tools. Remote sensors can immediately show what is going on in the downhole. To get the most out of this measurement feedback, mechanisms can respond to changing conditions. Valves down the hole can be adjusted, controlling flow or shutting off production at one level and increasing it from another. Fluid processing can take place down the hole with gas and liquids being separated by devices such as hydro-cyclones.

Smart wells can be used to take the gas production from one level and re-inject it at another, maintaining the pressure needed for oil production without the need to bring the gas to the surface. The complexity of control mechanisms can vary. Operators at the surface can respond to the downhole information and manually control the devices, or a control room linked to computers can send commands remotely to the sub-surface. Ultimately, at their most complex, the systems can be automated across an entire field so the devices respond directly to changing conditions without manual intervention.

An appropriate parallel can be drawn between the move into the digital age by wells, and oil and gas fields with the automobile engine. In the not too distant past, when a car was serviced, the diagnostics and fine-tuning of systems were performed manually, using a host of meters, strobe lights and plenty of guesswork. In contrast, the modern engine is simply plugged into a digital diagnostic system that interfaces with the car’s on-board computer. The computer is linked to dozens of digital sensors that instantly monitor all systems and inform the mechanic what adjustments are needed. It then makes those adjustments with pinpoint accuracy, eliminating any guesswork. Thereafter, the computer continues to generate an optimal setting of the parameters for the various systems that comprise the engine as a whole. Compared to the old gas guzzlers, modern cars and their control systems maximise economy and minimise emissions.

This information is not just used locally – these settings and adjustments are made available in a central facility that can then be used to optimise and adjust any number of similar installations at remote locations. This is a learning process where knowledge is distributed system-wide. The value of this knowledge from one facility is therefore multiplied dramatically, as facilities throughout the system can benefit from it being adjusted and optimised according to remote data.

Similarly in the oil and gas industry, with smart wells linked together across smart fields, a range of data becomes available remotely to assess reservoir performance or control inflow. With ultimate recovery as the main value driver, this type of real-time operations control has the potential to significantly increase production, save time and money, as well as greatly reduce the risk of injury to personnel and the environment. The higher initial costs are more than offset by the added value of greater production, longer asset life and reduced intervention.

Optimisation opportunities are created in every phase of the resource life cycle by combining data-gathering, integrating modelling, and controlling elements in ‘value loops’. Smart technology is a substantial new development and we are still ‘finding our feet’ and making unexpected discoveries.

One of the major discoveries was that the fundamental impact was in optimising field development and production operations and not in changing the performance of the individual wells.

To capture value from smart fields, we have examined the approach to process optimisation in other industries. It is apparent that there is a marked similarity in the fundamental principles that support all management cycles and optimisation processes. They generally include four entities: physical assets; the data acquired on the asset; the models used to study and understand the data; and the plans and decisions that are created as a result.

In addition to these four entities, there are also four activities: data acquisition; interpretation; option generation; and execution. Data are required to assess the condition of various aspects of the physical asset. After measuring the data we then need people with the skills to interpret it accurately. Once the models are in place it is possible to make future predictions and, from this, to generate a number of options in response to the behaviour of the subsurface asset. Those options can be checked against the required economics to find the best way to optimise value from the reservoir. Once these options have been chosen they are incorporated into executable plans and decisions.

The smart field ‘value loop’

The value loop for smart fields combines the elements measure, model and control to optimise the performance of wells or fields. Modelling of the reservoir is based on geological, seismic, and well information. This is collected from measurements of the wells (such as borehole logging) and the initial production data (such as the flow rates of the wells). Static models are built to describe the reservoir architecture, whilst dynamic models predict the flow of fluids during production. These models determine the initial control settings and the well designs; for example, which well should produce what quantities of hydrocarbons from certain zones. Smart wells can then sense each zone’s actual production form. This information can be used to restart the value loop, adjusting the model to fit the reality, which may change the controls required, the measurements, and so forth.

The value loop shows that an integrated structural approach is a fundamental part of making things smart. Only by integrating these elements and looking at the work processes and skills necessary to make those processes run is it possible to generate maximum business value.

We found that it was possible to extend this model over the life cycle of the field by analysing a number of our core business processes at Shell. Most noticeably, at each stage of field development and field life cycles, opportunities for further smaller scale optimisation can be identified. For example, in the exploration and appraisal phase there are decisions taken that potentially impact subsequent value generation. An overview is, therefore, required to look at optimisation in time and at each stage, as well as analyse the complete life cycle of the asset to ensure the organisation of capabilities and data optimises asset value. This is the real challenge of the EP industry.

Projects using smart field technology

South Furious field – Malaysia

The South Furious field in Malaysia is an example of a smart field in action. It is an extension to an existing field – a slim-lined unmanned design with four wells, three of which are smart twozone completions with downhole pressure gauges. This smart technology delivers 350,000 data points per day to the operators and technologists, giving them the ability to make real-time decisions and carry out tasks remotely, such as opening and closing valves and adjusting gas lift.

Smart technology wells – Brunei

In Brunei, another project shows the difference that smart completions can make to an individual well. It is the closest to state-of-the-art technology currently available with a Well Dynamics completion, with five separate valves controlled by three control lines.

The reserves are located in a very thin oil rim comprising several zones or regions, each with different geological characteristics. They are not substantial enough to justify the drilling of a dedicated well for each zone. The ideal situation is to combine the field in a single well; however, without smart technology, the behaviour of any of the different areas can compromise, or even destroy, the performance of the well. Inflow control valves need to be installed and then each treated as a single well. By managing the opening and closing of these valves, it is possible to optimise the behaviour of the well and regulate the flow of gas, water and oil.

To do this ‘smartly’ it is necessary to model the reservoir behaviour and determine how to control the valves in such a way as to optimise well performance. By adjusting the valves correctly it is possible to increase ultimate recovery by as much as 15 per cent.

Another example of a successful Brunei smart completion involved fitting smart completions to a three-year-old well where it was possible to change the role of the well in field development. The well now doubles as a gas injector and gas producer. This means it is no longer necessary to drill dedicated gas or oil wells, but to drill oil wells that produce gas half the time.

Na Kika deepwater development – Gulf of Mexico

The Na Kika deepwater development in the Gulf of Mexico is an example of a project that would not have been possible to develop economically without smart wells.

There are two pivotal issues. First, the individual field discoveries (six in total) are small- to medium-sized, making them uneconomical as standalone projects. Second, the deepwater, turbidite reservoirs of the Gulf of Mexico have a serious sand production problem. One of the major operational issues is the necessity to re-enter the wells from time to time to deal with this. A key control mechanism is the ability to choke individual zones. One of the primary justifications in Na Kika for smartness is to eliminate the re-entry problem. Each re-entry in the Gulf of Mexico costs about US$5–7 million. The smart well itself requires an additional investment of some US$3 million above the cost of a conventional installation.

The real value of smart well technology

Improved economic ultimate recovery remains the key goal. Reservoir simulation studies have shown that zonal injection and production control in water injection schemes can add significant value.

We have studied the value of smart wells and found that most of the value of smart completions is at the asset level, not the production system level – smart wells are about asset value, not well cost.

Based on these numbers we have set ourselves some targets. Our smart wells studies programme aims to generate US$250 million per annum, while our smart fields programme aims to add another US$100–150 million once fully implemented. We aim to arrive at this point within the next few years and believe it is possible to improve field life cycle value by more than 25 per cent.

Today’s smart wells may not have reached the peak of development yet, but in the near future, advances in capability and technology will enable the use of very complex well architecture. It will also become part of the production facility and possibly take measurements at any inflow point. The well will also act as an active sensor within the reservoir. Most importantly it will allow sophisticated field optimisation and development in real time.

One of the areas where most development is expected in the next few years is the application of in-situ and passive seismic data acquisition. Possibly within the next two years, seismic in the smart fields will move into the production arena. It will no longer be just a well appraisal tool but it will also be used for reservoir monitoring and optimisation.

Effective knowledge management and information sharing using digital technology is an important element in the potential success of smart fields. As an industry we are only at the beginning of the ‘smart’ revolution. It is a brave new world, with a lot to look forward to. As existing fields mature it is clear that we must move to more and more demanding locations and be prepared to work in harsher, more difficult conditions.

The industry needs a new paradigm. In order to survive, old dogs are going to have to learn new tricks. The digital age is here to stay and those who do not, at least in part, embrace it will fall by the wayside. To really make the most of these new capabilities, the industry needs to start fundamentally thinking about how to change the way in which we innovate and think. The industry also needs to look outside itself and its traditional partners to find new skill sets and capabilities – to consider partnerships and knowledge sharing with new and unrelated industries.

Finally, it is important to remember that our growing involvement in the world of digital technology is a vital conduit to a new generation of engineers and technologists. Our challenge is not just in producing the oil and gas, but also in ensuring that society’s expectations of minimal environmental impact are achieved. Good global neighbour relations and sensitivity to the diverse needs of the different regions in which we work, and people with whom we work, are fundamental to global success.

John Darley

Director, Shell Technology E&P

John Darley is the Director of Shell Technology EP with global responsibility for Shell’s upstream technical organisation. This remit includes the provision of technical support and services to Shell’s E&P sector, including technology applications and research, subsurface development solutions, major project delivery, well engineering, commercial technology ventures, and skills and competence development. John is also a member of the Executive Committee for Shell’s EP business. A graduate of Imperial College in Mathematics and in Petroleum Reservoir Engineering, John has worked for Shell since 1971 in a range of international postings. Assignments as a reservoir engineer in the Middle East, Europe and Latin America were followed by positions in business coordination and in strategic and business planning. He has held the position of General Manager of Shell’s Joint Venture production company in Syria, and in 1997 became Managing Director of Brunei Shell Petroleum and Chief Executive of Brunei LNG, a post he held to the end of 2000. John and his Canadian wife Lois have a son and two daughters. His interests include sports and reading modern history.

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