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Copyright 2010, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Intelligent Energy Conference and Exhibition held in Utrecht, The Netherlands, 23-25 March 2010. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied.
- South America > Brazil > Rio Grande do Norte > South Atlantic Ocean > Potiguar Basin > Estreito Field (0.99)
- North America > United States > California > Salinas Basin > Coalinga Field (0.99)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- (2 more...)
Abstract Few would disagree that the philosophy of intelligent energy permeates through a large proportion of Upstream operators and service companies. Programmes of work to realise this philosophy are now mature. Collaboration, information visualisation, integration of information to aid decision making all feature as commonplace activities. However, the philosophy is largely siloed within parts of the subsurface community and a general intelligent energy culture does not exist throughout the E&P community. This is especially pronounced when we examine the changes, or lack of changes, that have taken place within operational surface teams over the last ten years. This paper investigates the extent to which day to day decision making, aimed at optimising production at an acceptable cost, is fully integrated between sub-surface, drilling and surface operations and examines the value that can be generated through this level of integration. Taking surface equipment as an example, it goes on to examine the pre-requisites and integration points required to make a composite picture that means decisions are made taking into account all production constraints. It contends that reliance on automated data is insufficient and that everyone concerned with production activities, even down to operator and maintenance technicians, need to see themselves as key information providers into the production decisions that constantly need to be taken. Citing specific examples of where this has happened, positive cultural side effects can be seen. The paper concludes by looking at the pros and cons of transparency of information between sub surface, drilling and surface operations, effectively making all personnel information consumers and allowing them to input into optimisation decisions.
Abstract Measurement of the impact of digital energy solutions on asset performance continues to be a challenge. The performance impacts of digital energy solutions is difficult to measure primarily due to the fact that the impact of individual solutions cannot be isolated from the larger performance of the asset. A collaborative work environment (CWE) is a common solution within the accepted portfolio of Digital Oilfield solutions. A CWE is a custom designed facility to support improved field management through the integration of people, process, and technology. CWEs are being embraced in the upstream industry as an effective way if designed well to manage challenges by improving decision-making, achieving higher quality analysis and interpretations, and effectively and efficiently using skilled resources. As part of the CWE implementation, key performance indicators (KPIs) that drive collaborative behaviour were monitored and tracked over the lifecycle of the implementation. These key performance indicators monitored the impact of the CWE on: Operational disruption management Productivity and efficiency gains Reduced operating costs Competency/capability Morale This paper outlines the impact of a CWE implementation on asset performance through comprehensive analysis of identified key performance indicators. In addition, the paper draws round lessons learned and best practice for outlining and tracking KPIs for CWEs.
- Europe > United Kingdom (0.69)
- North America > United States > Texas (0.28)
- Research Report (0.46)
- Overview (0.46)
- Management > Strategic Planning and Management > Benchmarking and performance indicators (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (1.00)
Safety Presentation in Large Screen Displays—A New Approach
Weyer, U.. (Institute for Energy Technology) | Braseth, A. O. (Institute for Energy Technology) | Eikås, M.. (Institute for Energy Technology) | Hurlen, L.. (Institute for Energy Technology) | Kristiansen, P.. (Institute for Energy Technology)
Abstract During the last decades, computerized operator stations and soft controls have replaced hardwired wall panels in the offshore petroleum industry. Aspects such as maintenance problems, increasing cost, and lack of flexibility motivate this move towards a computerized interface design. There is, however, a general consensus that there is a great potential for improvement with regards to how information is being presented in computerized systems. IFE (Institute for Energy Technology) in Halden, Norway has developed and patented graphical symbols using a new design scheme called IRD (Information Rich Design). The displays based on this design scheme are not like traditional Piping and Instrumentation Diagram (P&ID) inspired design, but are based on pattern recognition in addition to use of a new dull color principle where only abnormal situations are highlighted. The new design scheme was initially designed for process interaction, but has become a state of the art standard for Large Screen Displays (LSD) in the Norwegian petroleum industry. Starting with process information, the concept has been further developed during the last years to also include safety information. The aim is to give the operators an overview of the safety state of the plant, and to provide the information needed when an emergency situation occurs. The information content of these safety displays has been specified in cooperation with operator crews through different projects for the Norwegian petroleum industry. The displays are developed using a rapid prototyping method. This paper addresses, describes and discusses this new Information Rich safety display concept, using the dull color scheme. The motivation behind the information content of the displays is also explained. At the end of the paper some specific design examples and symbol explanations are provided.
- North America > United States (0.68)
- Europe > Norway (0.49)
- Health, Safety, Environment & Sustainability > Safety (1.00)
- Facilities Design, Construction and Operation (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (0.34)
- Health, Safety, Environment & Sustainability > HSSE & Social Responsibility Management > Contingency planning and emergency response (0.34)
Integrating Data Mining and Expert Knowledge for an Artificial Lift Advisory System
Vega, E. De (PEMEX AIB) | Sandoval, G.. (PEMEX AIB) | Garcia, M.. (PEMEX AIB) | Nunez, G.. (Schlumberger) | Al-Kinani, A.. (Schlumberger) | Holy, R. W. (Schlumberger) | Escalona, H.. (Schlumberger) | Mota, M.. (Schlumberger)
Abstract This paper describes a new workflow to accelerate and improve decisions regarding where and when to apply an artificial lift system in fields with a considerable number of active wells. The workflow deploys a hybrid combination of a user-driven expert system and a data-driven knowledge-capturing system calibrated with historic data. Both systems interact to determine the right point in time to support a particular well with an artificial lift system. In the case presented, the mature gas field has a large number of operating wells, with predominantly manual operating data entry and a long processing time for newly acquired data. Due to the rapid decline rate in many wells, however, quick decisions are needed to improve productivity and hence the economics of each individual well. During the first two phases of the project, the asset team focused on data collection and workflow automation to speed up well production surveillance operations (e.g., gas rate calculation, estimation of critical velocity, etc.) (Mota, 2007). This paper documents the third phase, which addresses the knowledge-capturing and advisory components of the solution. Mature fields typically have significant field and asset expertise and a huge amount of historic data. Both information sources—the expert documentation and historic data—can be integrated to investigate past decisions and identify an optimum approach to field interventions. This paper describes the setup and implementation of a hybrid model that combines expert knowledge from asset engineers with the new knowledge discovered through the latest data-mining technology. The resulting system is then implemented in a fully automated workflow that identifies which wells require artificial lift. The results from a case study in a North Mexico gas field are presented. The reservoir is highly compartmentalized and requires fracturing as a way to increment well productivity. The data-mining approach used in this study is a special visualization technique, the self-organizing map (SOM), and a clustering algorithm (Zangl, 2003). The model was trained with historic production data, well test data, and information about historic well intervention decisions. In addition, expert knowledge from the asset engineers was introduced. The combination of data and expert knowledge enabled fast and reliable identification of the optimal time to install an artificial lift system to increase production while also effectively managing costs. This system reduces the typical decision time from several days to a matter of hours. The automated workflow runs immediately after the data is acquired and provides a continuous, up-to-date, and ranked list of proposed wells for artificial lift analysis. When new decisions are taken, the model can be updated for future use. The rapid analysis and decision cycle reduces lost production and improves overall field and asset value.
- North America > Mexico (0.48)
- North America > United States > Texas > Coleman County (0.24)
- Information Technology > Data Science > Data Mining (1.00)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Rule-Based Reasoning (0.97)
- Information Technology > Artificial Intelligence > Machine Learning > Learning Graphical Models > Directed Networks > Bayesian Learning (0.69)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Uncertainty > Bayesian Inference (0.47)
Abstract The major challenges for future oil and gas installations are to create and increase business value in addition to improve HSE (Health, Safety and the Environment). The oil and gas industry has recognised the potential of operations and maintenance in ‘normally unmanned areas’ where access to the entire process is based on utilisation of new robotics-based technologies from remote onshore locations. This paper concerns remote integrated operations by deploying teleoperation and telepresence of oil and gas installations. The challenges involve more than the technology of transferring data and performing operations. A teleoperator or a telerobot is a ‘machine’ which extends a human operator’s sensing and manipulation capability to a remote environment. An essential issue of telepresence is to keep the human operators in the control loop to enable them to use their high levels of skill to complement the power of remote manipulators. Teleoperation within oil and gas differs from other known applications as offshore installations represent large, complex and dynamic processes located hundreds of miles away, often in very harsh environments where failures may result in major consequences for the environment and process equipment. The challenges of offshore teleoperation are to enhance the operator’s perception of the current situation so that the operator has a complete understanding of the state of the process and operates the process as if he was offshore without hundreds of miles and complex technology in between. This paper outlines the challenges and opportunities of deploying robotics in integrated remote operations with a description of laboratory and early field tests as part of a joint project between ABB and Statoil. Without any doubt, safe and efficient remote operation is critical for operating profitable new fields which may be completely unmanned in the future.
- Europe (1.00)
- North America > United States (0.94)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.68)
Abstract In fulfillment of the Saudi Aramco Intelligent Field development initiative, more than 15,000 Permanent Measurement Systems (PMS) have been installed and are transmitting real-time data from both surface and subsurface to the corporate database. However, the full benefits of this investment can only be realized if systems and workflows are put in place to transform the massive amounts of data into actionable information to improve field development and performance. This paper presents a holistic approach to the utilization of data from PMS to enable real-time field management and optimization. We show how Saudi Aramco is integrating this data into the current practices and workflows of well testing and reservoir characterization. Examples of real-time well testing workflows are presented. The workflows take advantage of unplanned shut-ins to characterize the well and reservoir under dynamic conditions. The implementation encountered several challenges in the PMS data transmission, availability, sampling, standardization, storage, and retrieval, which are discussed. We also share our experience in resolving change management issues that arose from our attempt to synchronize the activities of various entities involved in the capture, transmission and transformation of PMS data. The paper demonstrates how a major oil and gas company is leveraging high frequency data from Intelligent Fields to enable field management and optimization in real-time. Application of the workflows presented could result in significant cost savings, due to a reduction in the number of planned shut-ins for pressure buildup tests. In addition, the use of long production history data captured by PMS, enables the determination of not only reservoir boundaries and hydrocarbons in place, but also permeability and skin damage, which normally would require well shut-in, and consequently, loss of production from a few days to a few weeks.
- Asia > Middle East > Saudi Arabia (1.00)
- North America > United States > Mississippi > Marion County (0.24)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Saudi Arabia > Eastern Province > Arabian Basin > Widyan Basin > Qatif Field (0.99)
- North America > United States > Arkansas > Smart Field (0.98)
Copyright 2010, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Intelligent Energy Conference and Exhibition held in Utrecht, The Netherlands, 23-25 March 2010. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Petrom operates offshore oil and gas fields on the continental shelf in the Black Sea in Romania. These mature fields were discovered in the late 1970s and early 1980s in sandstone reservoirs with average well depths of 5500ft to 7200 ft (1700m to 2200m). Until recently, production has been with both free flow and gas lift. Over the past three years, ESPs have been installed in five wells resulting in production increases. The paper reviews the ESP completion designs and focuses on the impact of real-time data on the run lives and uptimes achieved over the past 3 years. To analyze the well performance, a new technique based on the ESP torque equilibrium equation between the pump and motor was utilized to reconstruct a continuous rate versus time profile using real-time data. This provided greater resolution in rate measurement than that provided by traditional surface well testing, which proved instrumental in understanding the ESP behavior in these wells which exhibited low flowrates (typically less than 100 Sm3/d, i.e., 600 bbl/d) and high GORs. The authors explain how the technique is valid in both transient and steady state conditions and therefore calculates the instantaneous flowrate at any time when real-time data are available. This continuous "rate log" as opposed to episodic rate data from well testing enabled superposition technique to be used to monitor drainage area average reservoir pressure, to confirm the relationship between motor temperature and well rate, and to observe the effect of high GVF (Gas Void Fraction) through the ESP.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-209-P > Stag Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-15-L > Stag Field (0.99)
- Europe > Romania > Black Sea > Babadag Basin (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (1.00)
Installation and Implementation of "Smart Fields Foundation" on a Brown Field Asset, Adding Value without Major Capital Investment
Gerrard, Carl A. (Shell Exploration and Production in Europe) | McCabe, Heather (Shell Exploration and Production in Europe) | Beck, Andrew D. (Shell Exploration and Production in Europe)
Abstract Within the Exploration and Production (E&P) industry much focus has been on the application of "Smart" technologies. Deployment of these technologies has frequently focused on new field developments, where costs of installation and training of users are included in the overall field development cost. However within the Royal Dutch Shell group of Companies ("Shell") a significant volume of hydrocarbon production comes from mature assets, where the business case for such large investment is not always clear. The level of installed instrumentation and it’s condition on these platforms, whilst not impacting on the integrity of the asset, is not always optimal for the implementation of "Smart" technologies. Globally within Shell two programs, Well and Reservoir Management (WRM) and Smart Fields Foundation Mark I ("Mark I"), are being deployed to a number of assets. These programs focus on "fixing the basics" and deploying a minimum "foundation" level of smartness to support field management best practices. The successful implementation of Mark I requires new ways of working for all members of the asset; from offshore operators through to onshore petroleum engineering staff. Using a set of integrated applications and processes, it is only when these changes are fully embedded that the production and other benefits expected by the project are realised. The authors describe both the technical installation and subsequent implementation of Mark I on the Nelson platform in the central UK sector of the North Sea. The topics covered include; challenges in the installation project, changes to the way operations are executed in the asset, organisational changes and the development of a support structure to ensure the Mark I applications remain sustainable. The paper documents the benefits realised from an implementation that is focused on changes in peoples working practices with minimal capital investment.
- North America > United States > Texas > Terry County (0.40)
- North America > United States > Texas > Gaines County (0.40)
- Europe > United Kingdom > North Sea > Southern North Sea (0.40)
- North America > United States > Texas > Coleman County (0.24)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Silver Pit Basin > Block 49/30c > Davy Fields > Brown Field > Rotliegend Formation (0.99)
- North America > United States > Arkansas > Smart Field (0.98)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/7 > Nelson Field > Forties Formation (0.98)
- (3 more...)
Combining Distributed Temperature Sensing with Inflow Control Devices – Provides Improved Injection Profile with Real-Time Measurement in Power Water Injector Wells
Hembling, Drew (Saudi Aramco) | Berberian, Garo (Saudi Aramco) | Watson, Mark (Tendeka) | Simonian, Sam (Tendeka) | Naldrett, Garth (Tendeka)
Abstract Passive ICDs (Inflow Control Devices) have been used in the past to enhance performance of producing horizontal wells in unfavorable environments such as non-uniform permeability and/or pressure variations along horizontal sections. This is the first ever attempt, to the best of our knowledge, at using ICDs combined with a fiber-optic DTS (Distributed Temperature Sensor) to manage the water injection profile across a horizontal reservoir horizon. The cost of the permanent monitoring installation is comparable to a single coiled tubing deployed PLT intervention. This paper addresses how a passive ICD completion, utilizing DTS technology, was used to optimize and monitor well performance. In addition, the operational aspects of permanent vs. intervention monitoring are addressed while highlighting the opportunity for additional value creation using real-time monitoring combined with ICD technology. This field trial demonstrates the effectiveness of the ICD system when used in an injection well for injection profiling and fluid diversion during acid stimulation. In addition, the DTS proved to be an effective alternative to production logging in this horizontal water injection well. The key factor in the success of this project was the use of the 3-1/2" ICD completion along with a DTS system to monitor and passively control the injection sweep across the entire reservoir section. DTS data were also obtained during pre-injection and acid stimulation operations. This was the first occasion in which an operator was able to evaluate stimulation efficiency of an ICD completion using permanent real-time monitoring methods.
- Asia > Middle East > Saudi Arabia (0.49)
- North America > United States > Texas (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.31)