Even with the experience of delivering nearly forty real time/collaboration centers worldwide for oil companies or for its own offices, there was little sense of the routine as Schlumberger Information Solutions approached the design, construction, and use of its newest center for its Houston headquarters. Completed in 2007, the center promotes real-time and cross-discipline workflows for E&P teams while managing the competing needs of R&D to experiment and create new, more efficient workflows to optimize the search for and recovery of hydrocarbons. This facility meets needs for both intra and inter-company use and is designed with evergreen capabilities and maximum flexibility. Lessons learned as the center moved from initial design to daily use are shared along with the business side of managing one of the world's newest intelligent energy centers.
Whether called centers of excellence, collaboration centers, real time operational rooms, or immersive visualization and interpretation environments, these facilities are designed to help oil companies or oil service companies solve today's oil and gas challenges through the use of innovative technologies and shared views. Several hundred have been built since the late 1990's with varying degrees of impact to oil companies. The facilities range in size and complexity from single rooms with one to two overhead projectors to energy centers with complex display environments and multiple use facilities.
Schlumberger Information Solutions (SIS) has built nearly 40 of the latter around the world either for clients desiring visualization and/or operational centers or for its own use. An existing executive briefing room in Houston was lost as a result of the corporate relocation from New York into the building at 5599 San Felipe. The decision was made to open a new center of enhanced room in 2007 with visualization technology and real time operations capabilities for oil companies and for internal use. While selecting projectors and network configurations would be important, SIS personnel first reviewed challenges and lessons learned from immersive centers built and used by other companies during the previous nine years.
The majority of immersive centers with high-end display and computing technologies were constructed after 1998 with an especially rapid uptake and wide acceptance of their value by 2002. Early debates on design centered on rear versus front projection systems and relative benefits of curved versus flat screens for display of subsurface images. In addition, most centers were designed with a bias for use for peer review/integration of different technical disciplines but some were dedicated interpretation centers for high profile/large seismic volume projects.
While most were successful, of particular interest were the ones that either had been removed because they were underutilized or where teams failed to realize the expected benefits. One such center was built by a large independent in the western United States for over one million USD yet was dismantled in less than two years. In another case, one of the largest multinational oil companies had two teams utilizing the same new center yet one team was twice as effective as the other even though both had identical access and decision support. These were reminders that investing in changing company culture and team alignment remain as important as the spend on technology and furniture.
Other challenges were long term viability of centers and adapting them to changing conditions and business needs. Finally, our review showed that even the best centers had to proactively limit the use of the high end display rooms for large but static slide shows.
WITSML is a key enabler in an increasing number of real-time workflows. This is particularly true for integrated operations within the growing numbers of onshore operations centers. Two years ago WITSML was a technology known by few and actively used by even less. Now the SIG steering the standard has grown to 51 companies.
The starting point for most companies in using WITSML is to bring depth data into their asset databases. For many this has become the norm. Early adopters like Statoil are broadening their use into a wider range of wellsite operations. Within asset teams a standard data delivery mechanism allows integration of new tools and workflows, letting Geologists and Engineers make use of real-time data within their familiar desktop applications. It also enables centrally managed data delivery services letting them focus on their areas of expertise, not data gathering.
New technology and processes in these areas are helping operators make the next big step from real-time remote monitoring to real-time remote control.
For growing numbers it is now not enough to receive a visual representation of the data. They expect data to be delivered in real-time via a standard format.
WITSML also brings operators the opportunity to standardize data delivery workflows, to clarify contractual requirements to providers and to establish and measure realistic data delivery KPIs.
Within Schlumberger WITSML enabled workflows are well established, answer products for drilling optimization and interpretation utilize the standard via a unified WITSML client. This reduces software development cycle time and simplifies data gathering.
WITSML is becoming established, bringing proven advantages to real-time workflows. Continued uptake of the standard will enhance the competitive advantage of service companies and the operators utilizing it. WITSML is here to stay and should be supported more widely within the industry.
Asset performance can often be improved through continuous monitoring and/or through better utilization of information extracted from the high frequency data that are becoming more readily available in today's digital world. ExxonMobil has a long history of applying advanced technologies in asset management. Today, we continue to use new hardware, integrated software, and improved data infrastructure to enhance asset management workflows. ExxonMobil is taking an enterprise-wide approach (Reece et. al. 2008) to implementing digital technology in asset management.
This paper presents four examples where ExxonMobil has taken advantage of high frequency data for timely asset management decisions. These four examples represent implementation at four different operational scales: for reservoir management, for well management, for facility management, and for plant management. The four examples are: (1) For a West African reservoir: Permanent downhole pressure gauge data have added value in reservoir modeling that in turn provided a method for calculating reservoir rates; (2) For South Texas gas wells: Real-time data access and charting capabilities were implemented and advanced data analysis explored to identify well events and manage well work-over activities aided by artificial intelligence; (3) For Norwegian oil fields: An integrated facility model was developed and tuned for surveillance and operation of a network of wells and production facilities that are shared by multiple fields; (4) For an Australian production plant complex: Production from offshore platforms, a gas plant, a crude stabilization plant, a fractionation plant, and a tank farm was optimized with high frequency data and automatic process control.
History matching reservoir models to production data has been a challenge for asset teams since the early days of reservoir simulation. Keeping these models evergreen as production data continues to arrive, knowing when a re-history match is required and being able to re-history match easily and efficiently is also a major challenge which is often not addressed in a timely manner. This need is becoming even more pressing as real-time reservoir performance data is increasingly available. Decisions can now be made with the support of the good quality real-time data from the reservoir usually in the form of pressure data from downhole gauges and rate data from multiphase meters.
With the recent integration of existing technologies, a rapid model updating workflow is now possible. The history matching workflow that was once a discrete process can now be a computer assisted continuous process. Using statistically-based assisted history-matching technology in conjunction with real-time data acquisition, data monitoring, and reservoir simulation software, new production data can be quickly assimilated into the reservoir model. Real-time data from the field measurement devices is filtered for consumption by the reservoir modeling software and compared with the forecasts from the reservoir simulator to determine if re-history matching is required. The new data can be added to the history file and the model (revised if necessary) can be used in operational performance optimization.
This rapid model updating workflow can be run semi-automatically on a continuous basis as new production data is gathered, thereby keeping reservoir models evergreen and providing the most up-to-date basis for the making of important reservoir management decisions.
The full value potential of implementing Integrated Operations on the NCS is estimated to $42 billion. In order to harvest this full potential we argue that a balanced integration of people, technology and organization (PTO) is necessary. Our focus is on the people and organisation aspects; what characterizes teamwork and collaboration in the new IO arenas; and, composition of teams and team performance.
IO represents a set of new work forms, and we argue that collaboration and team work are fundamental aspects in this new reality. Hence, we have used Dr. M. Belbin and his theories on roles and team composition to show how to design and develop good teams.
Our observations and findings indicates that it is important with continuously focus on the people and organizational aspects in order to harvest the full potentials from Integrated Operations. However, this focus must be balanced with technology in order achieve the most optimal work processes, which will give all parties safer and better decisions faster, and contribute to added value.
Background and scope
Based on a report from The Norwegian Oil Industry Association (OLF) published in April 2006, it is estimated that the full value potential of implementing Integrated Operations (IO) on the Norwegian Continental Shelf (NCS) is estimated at $42 billion for the 2005-2015 period. OLF argues that the speed of implementing IO is a key element to harvest the full potential of the NCS, and that a slower pace will reduce the $42 billion potential considerably.
The newly merged company StatoilHydro ASA will operate approximately 80 % of the oil and gas reserves on the NCS. This implies that a full scale development and implementation of IO on the NCS represents a $33 billion value potential for StatoilHydro - this fact alone is a key argument for prioritizing IO. In fact this is the key argument used to create a sense of urgency and opportunity in the company.
We would like to point out that this paper was written before the merger was finalized on October 1st 2007, and therefore references are mainly made to Statoil ASA. However, the paper is presented on behalf of StatoilHydro ASA.
The following definition of IO was used in Statoil, and will also be used in this paper: "Collaboration across disciplines, companies, organizational and geographical boundaries made possible by real time data and new work processes in order to reach safer and better decisions faster.?? (Statoil ASA 2007)
If we take a closer look at this definition we see that there are three goals associated with decision making. Decisions are to be safer, better and faster. In order to achieve these safer, better and faster decisions the IO teams and collaboration arenas need to be optimal. Hence we will focus on the following aspects in the IO context:
In recent years, re-invention and development of electrical wireline mechanical applications, initially for high-angle well-access in conjunction with wireline tractors, has proven able to unlock value potentials by allowing interventions, previously thought impossible or cost prohibitive, even in low angle wells. Common denominators are remote-control, rig-less operations and documented large value-creations.
The most recent advancement in this service category includes milling and drilling on wireline; a breakthrough within intelligent production optimization. With the ability to engage a wide variety of challenges downhole, this technology provides hitherto unseen possibilities to increase production quickly, efficiently and safely. Also representing new capabilities is the technology of transforming constant mechanical force independently of the wireline and depth/deviation of the well. The advantage here is that operations can be performed from a crane or mast unit with electric line and apply a pulling/pushing force capable of manipulating down hole production control devices in a controlled and repeatable manner.
This paper will present innovative areas of recovering production through various case histories.
With today's high operating cost it is important to identify areas where new technology can be used to reduce rig time and improve production efficiency. Mechanical interventions such as manipulating valves and sliding side door devices, setting/retrieving mechanical plugs and gas lift valve retrieval/deployment, has historically been the domain of Slick Line techniques in vertical wells and Coiled Tubing in horizontal wells. These methods are difficult to execute in the intelligent completion environment because of the complexity in passing downhole jewelry without consequences such as damaging or shifing the sleeve devices unintentionally. With the introduction of the Well Stroker (Figure 1), in conjunction with the Well Tractor (Figure 2), to the Gulf of Mexico, North Sea and West Africa markets, there has been a marked reduction in time and costs for operators carrying out mechanical interventions with standard electric wireline in intelligent completions whether in high or low hole angle holes. As tractor technology evolved and confidence was gained during the past several years, another application of electric wireline methods was developed and field proven; this time for milling of specific downhole hardware (i.e. valves, plugs etc.) as an alternative to existing methods (rig/CT). This technology is specifically needed on offshore installations where the logistical limitations for this kind of operation are high.
In this paper we will discuss the results of a prototype software application to view the rig schedule generated by a reservoir simulator. Visualization of simulation rig schedules and comparing with planned rig schedule would help in identifying opportunities to improve operations. With the help of the schedule chart and rig movement data, we better the schedule generated by trying to reduce the net distance traveled by the rig and reduce the number of rigs utilized. We ensure that the overall field oil production is not affected for all the cases.
Using reservoir simulation as a tool to assist in the rig planning and scheduling process has the potential to foster team collaboration between reservoir engineering, planning and operations team and facilitate better Integrated field management. The teams would appreciate the challenges associated with planning and scheduling activities for the field.
Foreseeing near future opportunities for oil and gas fields, Petrobras created a corporate program dedicated to study, develop, and implement Digital Integrated Field Management (GeDIg) among its production assets.
Over the last three years, Petrobras has been developing a pilot strategy based on multiple scenarios to evaluate the technology level of digital oilfields. Six assets were chosen, taking into account the diversity of production processes (heavy oil, offshore, onshore, brown, and green fields) found all over the Brazilian fields. Two different approaches were implemented: in-house development and partnership with integrated companies.
Petrobras program is supported by three fundamental elements: people, process, and technology. Humanware, workflow processes, and change management are the key factors for new technologies implementation such as collaboration centers, intelligent completion, and fast loop artificial lift optimization.
After the pilots first year of operation, lessons learned will be gathered to guide the expansion of the digital oilfield concept for other Petrobras assets. The objective of this work is to describe the methodology applied in the six pilots and how Petrobras is going to improve its digital way of work and add value to its assets with Digital Integrated Oil and Gas Field Management.
We live in a fast moving consumer world where pocket PCs are common place and auto-identification technology is everywhere - mainly barcoding but increasingly Radio Frequency Identification (RFID). So why isn't Upstream Oil and Gas adopting these technologies at a faster rate to improve business performance? "If Tesco can do it, why can't we???
This paper examines the major applications for the use of hand held devices (HHDs) and auto-identification within supply chain, maintenance and operations. It describes the benefits in terms of the ability to link offshore and onshore operations more effectively and accurately pass real-time or near real-time information between assets, support organisations and supply chain partners, to allow earlier and improved decision quality, as well as the traditional efficiency gains. Upon detailed analysis, moderate investment yields high potential returns.
One of the fundamental differences between the supermarket chains and the Oil and Gas industry in this area is the lack of agreed technical standards in terms of RFID hardware and data transfer standards, acting as a barrier for supply chain integration. This paper touches on the work that is underway to address this issue, but goes on to explain how an appropriate application of technologies and attention to process and change management considerations can deliver robust solutions for operations and maintenance today.
Optimal well placement is crucial step in oil filed development but it is a very sophisticated process on account of different engineering and geological variables affect reservoir performance and they are often nonlinearly correlated. This study presents an approach where a hybrid optimization technique based on genetic algorithm (GA) and a Neuro-Fuzzy system as proxy was created and used to determine the optimal well locations regarding net present value (NPV) maximization as the objective. Neuro-Fuzzy system was used as proxy to decrease the numbers of costly and time consuming-simulations. Such a system has supplanted a conventional technology in some scientific applications and engineering systems, especially in modeling nonlinear systems. Neuro-Fuzzy modeling is a flexible framework, in which different paradigms can be combined, providing, on the one hand, a transparent interface with the designer and, on the other hand, a tool for accurate nonlinear modeling. The rule-based character of Neuro-Fuzzy models allows for the analysis and interpretation of the result.
Within Hybrid Genetic Algorithm (HGA), a database of the completed simulations is made. This database is used to construct of Neuro-Fuzzy network. Then this network is used to estimate the fitness function at points that no simulations have not been done. This proxy is also able to get better during the optimization each time a new point is verified and visited points database is updated.
A synthetic reservoir was tested and comparisons made among HGA, simple GA and non-proxy using approaches. Results showed that Neuro-Fuzzy system is very reliable proxy to estimate fitness function so the HGA will have a good chance to obtain the optimal place for the well in minimum possible duration.