Perdido ties together Shell digital oilfield technologies

The project is the first Western hemisphere application of an integrated philosophy that shifts from periodic to continuous optimization and from point answers to integrated “big picture” solutions.

Robert K. Perrons, Shell

Located in the Gulf of Mexico in nearly 8,000 ft of water, the Perdido project is the deepest spar application to date in the world and Shell’s first fully integrated application of its in-house digital oilfield technology—called “Smart Field”—in the Western hemisphere. Developed by Shell on behalf of partners BP and Chevron, the spar and the subsea equipment connected to it will eventually capture about an order of magnitude more data than is collected from any other Shell-designed and -managed development operating in the Gulf of Mexico.

This article describes Shell’s digital oilfield design philosophy, briefly explains the five design elements that underpin “smartness” in Shell’s North and South American operations and sheds light on the process by which a highly customized digital oilfield development and management plan was put together for Perdido. Although Perdido is the first instance in North and South America in which these design elements and processes were applied in an integrated way, all of Shell’s future new developments in the Western hemisphere are expected to follow the same overarching design principles. Accordingly, this article uses Perdido as a real-world example to outline the high-level details of Shell’s digital oilfield design philosophy and processes.

THE PERDIDO DEVELOPMENT

The Perdido area is located in the Western Gulf of Mexico about 250 mi south of Houston, Texas, and 8 mi north of Mexican waters. The Perdido development consists of three fields—Great White, Silver Tip and Tobago—whose produced fluids travel to a shared spar, Fig. 1. The spar is equipped with full oil, gas and water processing facilities that are capable of handling production rates up to 100,000 bpd of oil and 200 MMcfd of gas.

Fig. 1. The Perdido spar began production in late March.

The three fields’ subsurface structures are considered to be quite geologically complex, and the difficulty of managing these technical uncertainties is compounded by the fact that Perdido is operating in nearly 8,000 ft of water, deeper than any other spar in the world. Several world records were broken en route to bringing Perdido online, including deepest subsea completion (9,627 ft), deepest drilling and production spar (7,817 ft), and deepest pipeline tie-in (4,520 ft).

Perdido also has the distinction of being Shell’s first fully operational “Smart Field” in the Western hemisphere. Although several digital oilfield technologies have previously been deployed in Shell’s Western hemisphere assets prior to Perdido, this is the first time all of the constituent technologies were applied together in a truly integrated way.

WHAT MAKES A FIELD ‘SMART’?

The total value realized from an asset depends on how well it is managed throughout its lifecycle. The process of developing and producing a field typically creates vast amounts of information and, as both information and E&P technologies continue to improve, the upstream oil and gas sector’s ability to collect this data is steadily increasing. A major challenge facing the industry, therefore, is to use this data to optimize field development, reservoir management and production, and to provide field managers with a degree of control that allows them to translate this knowledge into maximum value.

Smart Fields is Shell’s response to this challenge. In a nutshell, Shell’s integrated digital oilfield philosophy represents the move from periodic to continuous optimization, and a shift in focus from point answers to integrated “big picture” solutions.¹ The concept of the value loop (Fig. 2) underpins Shell’s approach to capturing and using this data insofar as it depicts the basic loop of data-model-decisions-execution that drives value in an asset.²

Fig. 2. Digital oilfield value loop.

Shell has already realized at least $3 billion in value from the implementation of digital oilfield tools and technologies around the world, and expects this figure to continue to rise considerably as these design principles become more thoroughly embedded in the organization. This aggregated figure was delivered in the form of 70,000 boepd of additional production, on a recurring basis, and a reduction of $800 million in capital expenditures.³

Champion West Field in Brunei is a helpful example of how intelligent well and digital oilfield designs can unlock significant value. Champion West consists of several separate pockets of hydrocarbons, and early proposals to develop this field accordingly proved uneconomical because of the number of traditional wells that would have been required. By re-framing the field design with intelligent completions, however, it was possible to make the project viable by connecting several disparate reservoirs together with a common “snake” well. The addition of real-time monitoring and analysis on a zone-by-zone basis also makes it possible to adjust production rates from the various pockets as required, thereby allowing engineers to optimize the field’s overall production. A similar approach was later applied at Brunei’s Seria North Flank Field, in which a so-called “fish hook” well was drilled from the coast, then curved upward into the offshore reservoir.³

These successes were achieved through the use of individual digital oilfield technologies; the Smart Fields concept, on the other hand, is based on the integration of dozens of tools, skills and workflows to improve the performance of core assets in a structural and sustainable way. On a technical level, this overarching objective is achieved by closing a series of value loops in which data is constantly fed back into the system such that real-time optimization is possible.

The integrated digital oilfield approach is not a one-size-fits-all solution; each asset has its own unique features and challenges, and the appropriate level of “smartness” to apply will therefore vary from situation to situation. In greenfields like Perdido, elements of “smartness” can be built in from the start, and can accordingly deliver maximum value right from the beginning of the asset’s life. In brownfields, on the other hand, “smart” capabilities are applied selectively according to their economic viability, and any digital oilfield implementation plan balances investment costs with the expected remaining field life.

The deployment strategy for disseminating digital oilfield tools, technologies and workflows throughout Shell’s North and South American assets consists of five separate capabilities and design elements that, when brought together, deliver “smartness.” Perdido is the first asset in the Western hemisphere that is designed to leverage all five of these elements, but all of Shell’s future new developments in North and South America are expected to follow these same overarching design principles. Specifically, these are remote-assisted operations (RAO); exception-based surveillance (EBS); collaborative work environments (CWEs); hydrocarbon development tools and workflows; and IT infrastructure and applications.

Remote-assisted operations. By gathering more and better data from assets, it is possible to offload many offshore/on-location operation tasks to a remote location where these functions can be handled more efficiently and safely. RAO achieves this objective by having an office-based operator working with the asset operations team to provide immediate situational awareness of field operations, and to reduce the amount of time required for making decisions.

By having a clear point of contact for operations in the office environment, it will be easier for supporting organizations—such as engineering teams, for example—to interact with the offshore operations team. Also, transferring some tasks away from the production environment will almost certainly reduce the team’s exposure to HSE incidents by minimizing the number of hours that employees spend in transit or at an operations site.

Each of the dedicated asset-specific remote control rooms, located in New Orleans, offers most of the same real-time information and resources that would be available to the respective offshore operations teams, Fig. 3. The two-way audio and videoconferencing links between the offshore and onshore team members for each asset are always left on, so team members are able share information with ease.

Fig. 3. A remote control room in New Orleans.

Exception-based surveillance. A centralized facility called “the Bridge,” also in New Orleans, is equipped to provide exception-based surveillance (EBS) by observing selected real-time production data using graphical trends of key technical parameters for all of the wells in Shell’s Gulf of Mexico fields and selected assets in Brazil. The facility is equipped with software tools that can spot exceptions and unanticipated changes appearing in the incoming data that seem to be outside of the expected norms and usual operating envelopes, Fig. 4. When these deviations are discovered, they are brought to the attention of the relevant people within the operations and engineering communities.

Fig. 4. Surveillance data being reviewed at the EBS facility in New Orleans.

Support provided to asset operations teams is customized according to the needs of each asset, and may include proactively monitoring particular wells, subsea facilities and surface equipment; surveillance reporting; and supplemental operations monitoring for assets that do not have around-the-clock personnel coverage in their control rooms. EBS supports engineering organizations by shifting the burden of routine monitoring and optimization tasks—such as those tasks for which specific procedures can be defined by an engineer and then replicated automatically—to the Bridge so the company can keep its engineering resources focused on more complex issues. Although this facility is only staffed on a half-time basis at present (12 hours a day, seven days a week), an initiative is afoot to aggressively expand the scope and scale of its activities.

Collaborative work environments. CWEs play an important role in Shell’s digital oilfield strategy by helping to coalesce disparate groups of people into a highly cohesive virtual asset team (VAT), Fig. 5. Broadly speaking, a CWE is an environment designed to facilitate better and faster decisions through multidisciplinary teamwork in an asset or operating unit, or at a regional level, to improve business performance.^4,5

Fig. 5. A typical collaborative work environment.

A CWE typically contains videoconferencing facilities and a broad array of IT tools that allow teams to share images and ideas seamlessly, and to analyze data and graphical representations together in real time. Moreover, because additional participants can easily be brought into a conversation from outside the asset team, this capability can also be used to tap into regional and/or global expertise when and where required. In this way, improved asset performance can be achieved by creating an environment where the right quality and quantity of people are physically and virtually brought together with the right information at the right time, and with the right technology, tools, skills and work processes.

Hydrocarbon development tools and workflows. Interviews with members of Shell’s E&P community in the formative days of the company’s digital oilfield efforts revealed that many subsurface and production engineers have historically had to invest as much as 20–30% of their time hunting for data. Calculations and information that were used to make important decisions about an asset years ago are sometimes lost on a team’s shared hard drive, or lend themselves too readily to misunderstanding after a pivotal team member retires or moves on to a new job. Also, it’s not uncommon for many of the assumptions underpinning earlier decisions to be forgotten by the team over the years, making it hard to update complex subsurface models.

To solve these types of problems, Shell’s hydrocarbon development (HD) knowledge management and workflow framework offers development teams a collection of software tools and capabilities that are focused on improving the quality of development decisions and reducing the cycle time of activities within the HD domain.

The solution set covers the areas of information management, collaborative working, uncertainty management, and knowledge capture and re-use. Each solution consists of changes to work practices, improved workflows and new software tool sets. These HD solutions do not consist of a single tool or technology; instead, they are an integrated set of tools and new workflows that are linked together by the common theme of improved use of information for faster and better decision making.

Some teams using this new approach have reported a reduction of over 30% in dynamic model testing cycle times; running 40 subsurface model scenarios in less time than was required to run only five using previous methods; cutting weekly meeting times by 50%; and allowing team members to work together more efficiently.

IT infrastructure and applications. While each asset has its own unique features and challenges, there are also elements of Shell’s digital oilfield design philosophy that will probably be beneficial to almost every asset. Moreover, some aspects of “smartness”—like IT network security, for example—are infrastructural in nature, and can only be truly effective if they are applied broadly throughout all of the company’s assets. Therefore, these baseline technologies were collected into a suite of tools called the “Foundation,” consisting of the following:

IPM/IFM. This integrated production modeling software from Petroleum Experts, a third-party vendor, facilitates the integration of appropriate flow path models—specifically, the reservoir, wells and surface systems—in different time steps to assist with production system optimization and forecasting activities.

FieldWare Production Universe (PU). This is a Shell-developed tool that uses well test data to establish a correlation between flowrates and any one of a host of well measurements such as tubing-head pressures and temperatures, flowline pressures and temperatures, downhole pressures and temperatures, choke positions, gas lift rates, electrical submersible pump frequencies and currents, and power fluid rates. Thus, PU is a rich source of well-by-well production data that can be used to make a field “smart.”^6,7

Energy Components (EC) hydrocarbon allocation. This third-party software package stores production data and well parameters, then automatically processes this information into daily or monthly allocation figures that are instantly attributed to the appropriate wells, reservoirs or companies. The software makes it quick and easy to generate production status and deferment reports that can then be used as sources of production history data for field management, hydrocarbon allocation and compliance with Sarbanes-Oxley reporting protocols.

Plant Information (PI) data historian. Shell’s E&P operations produce copious amounts of real-time data—temperatures, pressures, flowrates, gas quality, etc.—from a wide variety of sources throughout an asset. Asset managers and engineers need to have access to this information in a meaningful and practical format so they can make informed decisions and conduct effective business planning. Information aggregation from a multitude of sources manually or through custom programing can be costly and slow to deliver business value.

Therein lies the basic function of PI in a digital oilfield context: to unify the streams of information from many sources into a single, comprehensive system that allows managers and engineers to capture and store this data efficiently. Simply put, PI is a third-party software package that is being used as a data historian.

Data Acquisition and Control Architecture (DACA) security. DACA can best be described as a Shell-developed “deep defense” strategy that consists of several layers of protection and barriers to external threats. This defense system makes it possible to set up real-time information streams and controls from the field in such a way that they are segregated from what happens in the office. The DACA design platform will allow Shell to achieve this in a consistent manner for each operating unit around the world, thereby putting enough controls and security barriers in place to keep hackers out of the offshore or field domains.

The above software elements do not work in a “smart” way when used one at a time in isolation. Each of these constituent parts has been integrated in the Smart Fields design such that they work together and share data from one part of the system to the next, Fig. 6.

Fig. 6. Foundation suite system architecture.

APPLICATION AT PERDIDO

As noted earlier, it is mandatory for every greenfield development within Shell to adhere to the Smart Fields design philosophy. At the same time, Shell recognizes that not everyone in the company is intimately aware of these ideas and principles. To help weave these design principles into the company’s existing E&P design practices, specialized consultants, technical screening workshops and support activities have been put in place so that development teams like Perdido’s are given the tools and resources they need to make sure that their designs and workflows are “smart.”

An initial screening takes place early in the development cycle to identify opportunities where digital oilfield technologies could help the design team reduce risk and manage uncertainties of which they may already be aware. One specific uncertainty the Perdido team had to address was reservoir compartmentalization.

The team’s reservoir engineers were faced with a small handful of equally plausible scenarios as to how much compartmentalization they could expect from one of the reservoirs; therefore, it was decided at the initial screening that additional downhole pressure sensors and flow monitoring capability would be installed in order to shed light as soon as possible on which compartmentalization scenario the engineers were facing.

A targeted evaluation of reservoir surveillance technologies for secondary and tertiary recovery processes is conducted to facilitate improved reservoir surveillance and management. Permanently installed ocean-bottom cables were initially considered for Perdido as a way to understand how the reservoirs will change and evolve once they are in full production, but the team eventually decided that periodic seismic “snapshots” captured by streamers will provide adequate information in a more cost-effective way.

A field management plan is compiled to explain explicitly how the selected “smart” design will support decision-making over the full lifecycle of the asset. Using the value loop as a framework, the plan outlines each of the technical issues and uncertainties that need to be managed, and then describes the hardware and instrumentation that will be used to collect data to manage this issue, the models in which this data will be used, and who will be responsible for making a decision based on the outcomes of the model.

A customized value-loop solution was formulated in this way for each of the many dozens of technical uncertainties and issues facing the Perdido team throughout the asset’s entire life, from start-up to long-term maintenance and monitoring.

A CWE assessment study is completed several months before first oil to arrive at a collaborative work environment plan that meets the anticipated needs of the relevant operations and engineering teams.

Dedicated CWE facilities were set up in the three locations where most of the Perdido team members would be located: New Orleans, Houston and the spar itself. The interviews conducted as part of the CWE customization process offered valuable insight into how the team’s members work together, and the CWE facilities were subsequently designed in a way that aided these workflows.

One specific insight emerging from the interviews was that Perdido’s completion and well design team members were split between New Orleans and Houston, and they would frequently need a way to quickly sketch rough concept-level drawings to work through design issues collaboratively. Accordingly, high-fidelity cameras and digital “doodling” tools were set up at both locations to make it easier to share these kinds of design ideas efficiently in real time, thereby reducing travel requirements.

By the end of these workshops and processes, the company’s digital oilfield group and the Perdido asset team had a shared understanding of the right kind and amount of digital oilfield technologies and workflows to apply to Perdido. A schedule and work plan was then put in place to make the asset “smart.”

It is important to note that Perdido’s journey toward becoming an integrated digital oilfield would not have yielded the highly positive outcomes that it did without strong support within the Perdido team, the relevant Shell E&P communities, and both BP and Chevron. The adoption of “smartness” in Perdido’s technical designs and workflows happened more completely and quickly than expected because of the emergence of champions who understood the value of these technologies. The Perdido team’s enthusiasm and commitment to the company’s digital oilfield design philosophy was the “invisible element” that made the other five capabilities and design elements come together in a way that works. 

ACKNOWLEDGMENTS

Parts of this article were prepared from SPE 127858 presented at the SPE Intelligent Energy Conference held in Utrecht, the Netherlands, March 23–25, 2010. The author thanks Shell International E&P for its support, and the Perdido team for its assistance and contributions toward putting together this article. Within these large communities, special thanks are due to Bill Townsley, Chris Smith, Susan Lajeunesse, Gill Purdy, Amanda Lee, Chris Weiss and Richard Smith.

LITERATURE CITED

 ¹ de Best, L. and F. Van den Berg, F. “Smart Fields: Making the most of our assets,” SPE 103575 presented at the SPE Russian Oil & Gas Technical Conference and Exhibition, Moscow, Oct. 3–6, 2006.
 ² Potters, H. and P. Kapteijn, “Reservoir surveillance and Smart Fields,” IPTC 11039 presented at the International Petroleum Technology Conference (IPTC), Doha, Qatar, Nov. 21–23, 2005.
 ³ Van den Berg, F., Perrons, R. K., Moore, I., Schut, G. and T. Fürstenberg, “Business value from intelligent fields,” SPE 128245 presented at the SPE Intelligent Energy Conference and Exhibition, Utrecht, the Netherlands, March 23–25, 2010.
 ⁴ Edwards, T., Saunders, M. and K. Moore-Cernoch, “Advanced collaborative environments in BP,” SPE 100113 presented at the SPE Intelligent Energy Conference and Exhibition, Amsterdam, April 11–13, 2006.
 ⁵ Vendasius, J., “The integrated collaboration environment as a platform for new ways of working: Lesson learned from recent projects,” SPE 112218 presented at the SPE Intelligent Energy Conference and Exhibition, Amsterdam, Feb. 25–27, 2008.
 ⁶ Goh, K.-C., Moncur, C.E., Van Overschee, P. and J. Briers, “Production surveillance and optimization with data driven models,”  IPTC 11647 presented at the IPTC, Dubai, Dec. 4–6, 2007.
 ⁷ Poulisse, H., Van Overschee, P., Briers, J., Moncur, C. and K.-C. Goh, “Continuous well production flow monitoring and surveillance,” SPE 99963 presented at the SPE Intelligent Energy Conference and Exhibition, Amsterdam, April 11–13, 2006.

THE AUTHORS
	Robert K. Perrons joined Shell in 1997, and has worked in various production engineering and technology strategy roles within the company. He is also an Adjunct Professor of technology management and strategy at the Queensland University of Technology. He has a bachelor’s degree in mechanical engineering from McMaster University in Canada, an MS degree in technology and policy from MIT, and a PhD in engineering from the University of Cambridge. Contact Dr. Perrons and see his related work by visiting www.perrons.net.