In today's economic environment, oil and gas companies are continuously challenged by a combination of ma-turing fields (yielding less while requiring more attention), coupled with increasing human resource scarcity.
This situation is creating higher costs per barrel and changing economic viabilities for development projects around the world. One way to improve economics is to introduce new efficiency gains that reduce non produc-tive time (NPT), reduce well construction times, and, therefore, minimize costs.
The Factory Drilling* approach for field development has demonstrated significant benefits when applied to a well-known field that has consistent well programs and reduced uncertainties. This new way of conducting drill-ing operations is enabled by real-time data, seamless integration of services, application of suitable technology specific to mature fields, remote operations, multi-tasking of personnel, and fit-for-project rigs. The concept has been successfully piloted in Mexico, on the above-mentioned field, and deployed in twelve land rigs simultane-ously during 2009 and 2010.
This paper describes what was done, how it was done and summarizes key results. Since then, other projects have implemented the same model (with some variations) in other parts of the world.
The Cooper Basin, located in central Australia, is an extremely remote, harsh and technically challenging environment in which to operate an oil field. Immense distances and poor artificial lift pump reliability has led to high operating costs. Santos, on behalf of a number of Cooper Basin Joint Ventures operates over 400 oil wells spread over approximately 30,000 sq km, most of which are located in areas that can be inaccessible for large parts of the year. Through the implementation of best in class automation technology, Santos has overseen a step change in the way that the oil business in the Cooper Basin is operated.
In 2007 Santos introduced a program to install variable speed drives on existing and new beam pump completions. Coupled with an upgraded communications infrastructure and remote monitoring software we realised significant improvement in both mean time between failures (failure frequency) and consequently a 75% reduction in operating cost for our beam pump wells (and a 3% reduction in downtime). The ability to remotely monitor and optimise production from wells using variable speed drives has also resulted in a marked improvement in the level of production from those fields with high levels of automation. Oil production improvement of 18 to 30% has been observed across our automated fields.
This paper will address the key learnings and challenges faced in implementing this automation program. It will review how organisational change and resistance to change was managed from an operating perspective as well as the development of systems and standards to govern the safe and efficient operation of variable speed technology and remote monitoring software. The paper will also showcase several early life successes and the benefits delivered to the Cooper Basin Joint Ventures.
The intent of this is to document some of the scenarios plaguing Rockies Gas' wireless network; i.e. network outages, equipment failures, performance degradation, and power related issues. The most prevalent of all the problems entails the sporadic communication associated with the VoIP (Voice Over IP) network. For example, users have reported frequent problems with telephone calls being dropped and/or the inability to make telephone calls from a wireless handset. There is general consensus these issues are directly related to the hardware's inability to support the current architecture, which is based on an older Layer 2 bridging technology. Cisco, the current telecommunication vendor is questioning the rationale behind the deployment of this architecture and whether there were any extenuating circumstances for not implementing routable Layer 3 (TCP/IP) network.
Killian, Keith Edward (ExxonMobil Production Co.) | Jones, Chris G. (ExxonMobil Global Services Company) | Nye, Johan B. (ExxonMobil Research and Engineering) | Wiemers, Suzan (Exxon Mobil Corporation)
Implementing digital technology in the oilfield introduces non-traditional technology, equipment and applications to our oil & gas operations. The long term success and sustainability requires the ability to support this technology effectively and efficiently. ExxonMobil* has a global, standard IT infrastructure. ExxonMobil's downstream has implemented a global, standard advanced control architecture and deployed a suite of applications to optimize various aspects of these operations. Leveraging this experience, infrastructure design and support structure has been recognized as a significant opportunity in the upstream to facilitate quicker deployment and benefits realization, and leverage proven support models. This paper shares ExxonMobil's approach with leveraging our existing corporate IT and advanced control technology foundation, experience and support models for upstream deployment of advanced digital technology.
In the oil & gas industry sporadic studies are developed to analyse the flow conditions and operations procedures through the life of the field. The objective of those studies is to understand the environment, boundary conditions and properties changes along the fluid journey. For characterization of the production behavior, engineers use model-based multiphase flow simulation via various applications available on the market.
A constant understanding of the fluid flow conditions is valuable for the decision process on the execution of operational procedures. A robust flow assurance strategy is dependent on the level of awareness of the real production conditions prior to a fluid flow interruption event. Fiber optics distributed sensor system has been recently used mainly for integrity monitoring purposes; the proposed methodology unlocks the additional values for interfacing disciplines as flow assurance by the provided simultaneous distributed measurements of temperature, strain, and vibration.
The model-based multiphase flow simulations represent flowlines and production networks and as output of those simulations operating profiles are used to evaluate the risk of solids precipitation and deposition along the flow path. A regular update of simulation models by real-time data from field sensor results in a more reliable representation of the production system operating profile that can support the flow assurance strategy by the detection, monitoring, and location of events.
This paper proposes the use of real-time data acquisition from an optical-fiber distributed sensor for the assurance of fluid flow along the production system. It outlines a methodology to perform flow assurance automated surveillance based on multiphase flow simulation models constantly fed with real-time field measurements to estimate fluid flow conditions throughout the system to avoid potential problems, such as flow restrictions due to solids deposition.
Introduction to Flow Assurance
Flow assurance is a broad discipline dealing most notably with the solids deposition issues of hydrate, wax and asphaltene. In fact it can be considered to encompass fluid-equipment interactions from sandface to receiving facility and beyond to export. Thus it can be considered to also include challenges such as: multiphase flows (especially slug flow), internal corrosion, emulsions and scale.
Some success has been realized in the past through a combination of limited flow assurance analyses and over-design to compensate for the attendant uncertainties. Operational difficulties and excessive operating costs as a result of poor system design (or as a result of over-zealous capital cost control) have also been quite common. However, the current state of the art is to try to reduce both over-design and short-sighted design, and work towards a production system truly optimized from first oil through to abandonment.
Description: Industrial Capital Project Engineering Design solutions are heavily dependent on large scale custom integration services efforts to hand over key information to the Operations and Maintenance application environment. Individual Owner/Operators must each redundantly bear the development and sustaining costs for these efforts. Large engineering design suppliers offer proprietary ecosystems making their own rules for technology enablement often setting high costs and onerous technology prerequisites. Often these artificial rules require owner operators to choose systems based on suboptimal criteria or worse require them to rip and replace existing systems. These barriers and artificial guidelines lock owner / operators into proprietary applications with very high initial costs and high ongoing costs. A new engineering data handover and ongoing operations and maintenance sustaining model is proposed in this paper advocating an Open Standard "system-of-systems?? approach for engineering, operations and maintenance information. This Open Standards approach recommends an Interoperability Solution rather then custom service delivered "point-to-point?? integration strategies for the general industry engineering eco-system. The Open Standards Approach is based on open, supplier neutral standards, enabling initial loading and incremental update of participating systems eliminating custom service based integration.
Application: IBM has been collaborating with industry standard bodies and key standards based suppliers like Assetricity LLC bringing proven Interoperability functionality. This approach enables enterprise service bus integration neutral exchange of information leveraging a standards-based common engineering register coupled with a reference semantic information abstraction model that provides a safe, reliable and replicable roadmap for interoperability. The solution has been adopted by several oil and gas companies as a basis for enterprise information exchange.
Conclusions: An IT design framework is offered for integrated operations and maintenance for oil and gas companies that is architecture centric, product neutral, operating platform neutral, enterprise service bus neutral, enabled by standards at all levels, supported with a practical implementation approach.
Significance of Subject Matter: The creation of a reference semantic information model and an Engineering Register based on in-depth understanding of industry standards coupled with Open Operations and Maintenance Web Services provides the establishment of a safe roadmap for interoperability that enables a industry paradigm change that significantly reduces the cost of initial information handover and sustained information change management for the Engineering, Operations and Maintenance environment for both the Upstream and Downstream and Process Unit Operations in general.
At the SPE conference in 2006 BP announced the Field of the Future Integrated Surveillance Information System (ISIS) project. Since then the ISIS system has been developed, delivered, tested and verified. Deployment to BP assets has been at the scale and pace proposed in the conference papers published at that time. This paper describes a core module, the Rate&Phase virtual flow meter, and also gives reasons why deployment has been achieved so successfully.
BP's Rate&Phase system automatically estimates production rates from individual wells and other well performance and reservoir information at least once per hour. The approach has been to automate a proven Petroleum Engineering methodology using models of well hydraulics and flow though chokes. The system takes advantage of the instrumentation typically installed on new wells and the transmission of those data for analysis at technical centres often remote from the production sites. Rate&Phase is integrated in ISIS along with routines to automatically reconcile production across entire fields, monitor issues of erosion and sand production and estimate reservoir pressure at shut-ins.
The Rate&Phase system has been deployed widely across BP-operated assets including many major oil and gas fields. Benefits have been realised from the ability to efficiently monitor well stock, manage fields better and allocate production more accurately. The effort to determine monthly production allocation is significantly reduced. Production gains have been realised through assets operating closer to constraints because of the assurance of flow rates in critical pipework.
Developments are being introduced to reduce maintenance effort through tools to assist model re-calibration and to complement the hydraulic models with models derived entirely from measured data.
Rate&Phase exploits commonly-used modelling tools and is designed to be easy to deploy/configure. Acceptance of the system has been hastened because it is not regarded as a black box and all results can be reproduced manually offline. Current production and performance information is readily available and changes over time can be trended though existing data interfaces.
Well segmentation and instrumentation have been used to improve steam injection and production conformance in a completions strategy for a thermal-enhanced oil recovery (EOR) project by using intelligent well technology and interval control valves (ICVs). The initial field trial is ongoing in the injector of a Northern Alberta steam-assisted gravity drainage (SAGD) well pair. The development of the completion technology suitable for thermal conditions, initial field trial results and the plans for further development are described in this paper. The application modeling shows that, depending on the level of heterogeneity present in the reservoir, a 45% reduction in the steam-oil ratio and an almost 70% increase in recovery can be achieved in a SAGD process when both improved injection conformance and producer differential steam-trap control can be applied in a segmented horizontal well pair. A cost-effective, intelligent-well completion solution to achieve this
segmentation and control has the potential to add substantial value to field developments through improved steam conformance. This will result in increased energy efficiency and oil recovery. The method under development is also applicable to a wide range of other thermal EOR processes such as cyclic steam stimulation (CSS), steam drive, and variations, including, for example, those involving solvent additives.
The initial field deployment in the injector well was initiated to prove the technology, to demonstrate the feasibility of modifying the steam distribution, and to obtain best practices for future developments. A successful installation and commissioning of the intelligent completion has validated the technology. Lessons learned are highlighted. Early injection test results and data show a significant increase in the understanding of the injection and production behavior in the well pair. A test program to optimize the distribution of the steam injection in the well is underway, and the results are discussed. The intelligent completion technology under trial and proposed further developments should enable more extensive use of downhole measurement and control in thermal EOR projects than has been possible to date.
Chevron has applied digital oilfield principles to enhance workforce safety in emergency situations. An older emergency management process was transformed into a centrally coordinated workflow to guide decisive action and timely evacuation during tropical cyclones.
The Chevron operated Gorgon Project will develop the Gorgon and Jansz-Io gas fields, located within the Greater Gorgon area, about 130 kilometres off the north-west coast of Western Australia. The Project is being constructed on Barrow Island, a Class A Nature Reserve located approximately 60 km off the north west coast of Australia. The environment on Barrow Island is unique. It is home to flora and fauna, some of which are not found anywhere else in the world.
Chevron has operated Australia's largest onshore oilfield on the island for more than 40 years, demonstrating that industry and the environment can successfully coexist.
The Gorgon Project is driving significant activity on and around Barrow Island. The construction phase workforce has expanded to undertake offshore drilling and marine operations, plant site preparation, accommodation facilities and aviation support as well as continuing oilfield operations.
The northern coast of Australia, including Barrow Island, is prone to severe tropical storms each season, from November through April. The safety threat is real and unpredictable.
Growth in Chevron's workforce drove a requirement for a well-coordinated storm evacuation process, with unified accountability across the island and offshore vessels. This need was met by developing an i-field decision environment that unites all affected groups, tracks all personnel, coordinates critical data like storm projections and aircraft availability and conserves the safety margin through data-guided decisions, as a cyclone develops and moves.
This transformed evacuation process informs the decisive action that is needed, balancing the paramount need for safety with environmental responsibility and operational goals. This paper describes the results of improved efficiency in demanning safely during storm threats and remanning quickly once the storm threat passes.
(Note: i-field™, the short form of "integrated field??, is Chevron's Digital Oilfield program.)
BP has had an active digital oilfield programme for over 10 years with our Field of the Future technology flagship. This paper identifies some key learnings from both our own experience and comparison with activity across the industry. We then examine the implications for the future of the digital oilfield concept.
In retrospect, we characterize BP's activities into two distinct phases. We believe the characteristics of these phases also apply more generally in the industry.
Phase 1 (2000-05) dealt with communicating a compelling vision and demonstrating the validity and potential of the digital oilfield concept. This phase dealt with engaging asset and major project teams in understanding the potential value in new ways of working by accessing real time operational information. In an R&D sense, Phase 1 was about developing and integrating a diverse set of tools to support technology trials and prove up the concept.
In Phase 2 (2005-11) we started to implement at pace and scale. For BP, the focus was on delivery of discrete real-time remote monitoring solutions and target driven value realization for well monitoring, surveillance by exception (i.e event driven rather than by routine scheduling), equipment reliability, and production optimization. We have documented value delivery of over 70 mboed net cumulative production impacts, plus other benefits. The choice of specific technologies was less important than the drive for sustainable implementation and solid business cases.
The range of industry experience raises an interesting question about options for the next phase of activity. These range from a focus on embedding the success to date as "business as usual??, through to targeting the next class of difficult problems or operational risk reduction. Using the skills and experience from Phase 2 could unlock even greater value and further transform the work of energy companies.
• Digital oilfield programmes appear to be progressing through a sequence of 5 year phases.
• A number of Key Success Factors have been identified:
o Achieving effective organizational engagement;
o Developing productised solutions and standards supporting rapid deployment of common tools across a significant number of assets;
o Deploying for sustained change to ways of working;
o Driving value delivery.
• A range of options and requirements for future direction and success now exist, including:
o Embedding digital oilfields as the way the industry does things;
o Addressing the next set of tough business and operational risk problems;
o Integrating the next generation of technology developments.
o Designing systems and interfaces that the ‘next generation' of engineers and geoscientists will want to work in and with.