bluuebunny/crossref_metadata_2025_split huggingface dataset:
Transforming Operations with Real Time Production Optimization and Reservoir Management: Case History Offshore Angola
Authors: Paulo Jeronimo , Taylor Deidre A. , Isichei Obi , King Marty , Singh Gagan 
Published: September 2011

Abstract
The subject field is located 50 miles offshore Angola in ∼1200' of water. The compliant piled tower that supports this development in Block 14 is one of the largest manmade structures in the world. The 46-well development plan includes both wet and dry trees. The multi-layered reservoirs are heterogeneous in nature. To extract the most value from this development, Chevron has developed and deployed an integrated solution that uses people, processes and technology to improve performance. In 2002 Chevron began exploring how integrated digital solutions could help better manage the reservoirs, wells and facilities. Since that time, a fully fledged i-field™ program was developed with a vision for transforming operations through technology. It's about making sure the right people have the right information at the desired frequency in a usable format at the right time to make the best decision. It's about teamwork and collaboration across function and distance. It's about providing people the time and space to develop creative alternatives and solutions to effectively manage the daily and longer term challenges.
The Production Optimization Solution for the subject field was successfully deployed in September 2010. The solution is designed to improve production engineering productivity, increase production and recovery by optimizing overall field management, and decrease response time through early problem detection. Two initial engineering workflows were deployed along with an asset overview dashboard that displays key information, trends and results. After a rigorous evaluation process, a project team was created to develop the engineering workflows that make use of nodal analysis and pressure transient analysis tools for field and model management. A 3rd party vendor was selected to design and manage the data and application integration required to successfully implement the solution.
This paper will detail the development and deployment of this integrated solution that is allowing the engineers to spend more time on technical work, respond quicker to anomalies, and make better, faster decisions. It will also discuss the requirements for success that include change management, training, support and organizational capability.
Modified Mathematical Model for Fines Migration in Oilfields
Authors: Zeinijahromi A.. , Machado F.. , Bedrikovetsky P.. 
Published: September 2011

Abstract
Permeability decline during corefloods with varying water composition, especially with low salinity water, has been widely reported in the literature. It has often been explained by the lifting, migration and subsequent plugging of pores by fine particles, which has been observed in numerous core flood tests with altered water composition. In the present paper, we derive a new system of governing equations describing fines mobilisation, migration and subsequent permeability decline for 1-phase and 2-phase flows. In large scale approximation, the mathematical model for 2-phase flow with induced fines migration is equivalent to polymer flooding model. It allows taking advantage of the polymer flooding option for the Eclipse black oil simulator in order to model waterflood with low salinity water, where the induced fines migration and permeability damage can be considered to provide a relatively simple method for mobility control during waterflooding. The modelling showed that permeability decline in the water swept zone, caused by the alteration of the injected water composition and induced fines migration, may be able to improve waterflood performance by delaying water breakthrough and reducing the water cut.
Barriers to the Implementation of Real-Time Drilling Operations Strategy
Authors: Crawley C.. , Rizvi A.. 
Published: September 2011

Abstract
Many industry insiders and analysts believe that the creation of real-time operating centers to achieve drilling optimization is the key to solving numerous challenges encountered by the industry. Even with a significant investment and the development of state-of-the-art facilities by major operators, however, the incorporation of real-time center operations in the field has occurred more slowly than anticipated.
In 2009, the SPE Real-Time Optimization Technical Interest Group (RTO TIG) surveyed the drilling community, including oil companies, operators, and consultants, to assess the progress of the industry toward drilling optimization through the use of real-time operating centers. This survey identifies barriers to real-time center use and adoption, and assesses the use of technical and business tools at each stage of the real-time process, ranging from data collection to decision making and field action.
This paper summarizes the results of the survey and analyzes its findings. The survey covers the entire value chain in oilfield drilling services, from preliminary modeling and planning to actual drilling. With data collected from more than 150 respondents, the survey findings indicate that the industry perceives that few substantial obstacles remain in the adoption of real-time centers and that progress in real-time drilling optimization is being made. Although many respondents predict that the remaining barriers will eventually be overcome, the RTO TIG believes that by identifying and highlighting these barriers, and by exploring the most persistent barriers to adoption, we can illuminate methods by which the industry can achieve faster gains in real-time adoption and performance.
The survey finds that many companies have acquired the technology necessary for real-time operations, yet have failed to achieve real-time performance in the implementation of this technology. This paper assesses implementation roadblocks by examining the real-time process, including modeling and planning, data acquisition, analysis, decision, field action, and process improvement.
Latest Developments in Acoustic Subsea Control and Monitoring for the Drilling Industry
Authors: MacDonald L.. 
Published: September 2011

Abstract
This presentation will review the case for secure, high reliability acoustic signalling through water, with applicability to communication, monitoring and control requirements. Illustrations will be drawn from NASBOP to provide an example of critical data being transmitted and received acoustically in the deepwater Oil and Gas arena today.
Advances in Digital Acoustic Technology and the specific inception of spread spectrum communication technology have resulted in high integrity, high reliability transmission and reception of critical command and control data from Subsea BOP to surface vessels. These systems have unique ability to operate reliably in deep water, high multipath environments with greater than 99% reliability.
The foundation of Nautronix signalling is ADS2 (Acoustic Digital Spread Spectrum) technology. Proven ADS2 technology allows high integrity data transmission and excellent immunity to interference. Its long range capability (in excess of 5km dependent on environmental conditions) as well as reduced battery consumption, makes this technology the ideal solution as primary or secondary data management and communication. Ultimately, this technology will provide options for a wide range of life of field applications in the future.
NASeBOP, using ADS2 technology, provides the solution from a subsea control perspective without the traditional umbilical to remotely monitor other subsea equipment and retrieve data such as pressure/temperature wirelessly. NASeBOP provides 16 critical functions with feedback for the Subsea Isolation Device and allows for read-back of 8 analogue sensors to monitor critical subsea pressure and temperature readings. The system also allows the ability to activate an Emergency Disconnect Sequence (EDS) and to monitor the BOP status after disconnect.
The next evolution of BOP control is NASMUX; using 128 channels to fully control and monitor the BOP with acoustics. This technology will revolutionise BOP operations by addressing many of the current issues by providing a reduction of umbilical's and reels, elimination of downtime caused by umbilical damage and increased safety by reduction of moon-pool activity in handling of umbilical's. The system would provide full BOP functionality in the event of umbilical failure, in order to allow the operator to safely shut in a well before recovery for umbilical repair.
Planning the Combined Revitalization of Two Carbonate Reservoirs in The Campos Basin
Authors: Pires P.. , Furuie R.. , Sarturi J.. , Benac P.. , Pereira J.. 
Published: September 2011

Abstract
This paper presents the revitalization plan of two long producing fields located in the Campos Basin, offshore Brazil. Both produce from high OOIP, complex albian carbonate reservoirs. The fields started producing in the early 1980's and their exploitation strategies were mainly based on vertical and deviated wells. No secondary recovery process was initially adopted. Both reservoirs exhibit low average permeabilities (less than 10 millidarcies) and high heterogeneity. In Albian-B, vertical heterogeneity has led to uneven reservoir depletion. From the drilling of recent wells, stratigraphic layers with better properties have been found to be severely depleted. Albian-E exhibits remarkable areal contrasts. The northern part of the reservoir is extremely tight while the southern is naturally fractured.
Currently, the production performance of both reservoirs creates the opportunity of increasing their ultimate recovery factor. In 2009, a pilot project aimed at appraising water injection toke place. The project scope was defined by a pair producer-injector, both horizontal multi-fractured. Through the monitoring of the two wells the displacement efficiency has being characterized in Albian-B reservoir. This information has guided the revitalization plan of the reservoirs. New drainage strategies were defined with help of assisted optimization. The studies pointed out attractive revitalization scenarios with a new platform to produce both reservoirs.
An Innovative Approach for Laboratory Evaluation of Defoamers for Oilfield Cementing Applications
Authors: Mahmoudkhani A.. , Bava L.. , Wilson B.. 
Published: September 2011

Abstract
Defoamers and antifoams are crucial components in many processes of the oil and gas industry. In particular, they play a vital role in well cementing where many additives would otherwise contribute to foam formation and air entrapment during the mixing of the cement slurry. If not controlled, foam can cause serious problems such as pump cavitation, undesired slurry densities, inadequate mixing and gas permeability issues. Quest for high performance defoaming agents has been intensified in recent years due to the challenging industry standards and new environmental regulations such as those for offshore drilling and completion operations. The major task is to find suitable additives that pose little to no risk to the environment without compromising the performance and system integrity.
Quantification of defoaming performance is critical to achieve success in cementing operations as well as in the development of new and environmentally friendly defoamers. Most commonly, defoamers for cementing operations are appraised by non-standard or traditional test methods such as blender and sparge tests. While these methods are simple to perform, they often show poor reproducibility, lack of objectivity, and do not accurately replicate field conditions. This paper presents a unique test method using a dynamic foam analyzer which is capable of characterizing defoamer performance based on fluid density during simulated mixing operations. The dynamic foam analyzer generates objective data that shows initial and persistent defoamer effectiveness. This enables more accurate dosage comparisons in the lab resulting in more controllable operations in the field.
In addition, non-silicone based defoamers are desirable due to increasingly strict environmental regulations. The current challenge is to develop green alternatives while maintaining or improving the current performance levels of the defoamers used. This paper presents an innovative approach for evaluations of cement defoamers using a unique laboratory setup and a modified blender foam test method that provide more insights into cement foaming and defoaming processes. A mechanism is proposed for action of common cement additives as foam stabilizing agents. Performance of a green non-silicone based cement defoamer was evlauted to elucidate viability of the dynamic foam analyzer in comparison to the new blender foam test method.
Holistic Workflow for Autonomous History Matching using Intelligent Agents: A Conceptual Approach
Authors: Zangl G. , Al-Kinani A. , Stundner M. 
Published: September 2011

Abstract
The current practices of assisted and automated history matching refer only to specific methods to address the optimization problem in history matching, but never span over the complete workflow. Computational power and the development of sophisticated software should allow us today to capture the whole workflow and automate it rather than just a piece of it (usually the regression method). The approach presented in this paper is based on the principle of domain decomposition. The reservoir history matching (HM) problem is decomposed into smaller and smaller pieces (from reservoir to region, from region to layer) to allow a refinement of the final result and hence the HM quality. The decomposition of the problem can be commenced by introducing time dependent well influence areas. These areas are sub-divisions of previous decomposition processes, as there are lithofacies types, clusters, flow units and vintage intervals. For the time dependent "influence areas", the success of the optimization can be tracked over the sequential iterations as well as across the different realizations. The progress of the most sensitive parameters can be tracked and successful strategies can be applied to other, similar areas of each realization. Finally, the interference of the influence areas has to be accounted for in the selection of the parameter values in each of the regression loops. A smart expert system that includes machine-learning techniques (cognitive agents) is used to drive the global history matching process, control the sub-domains and find the best parameter combination amongst all influence areas. The approach presented in this paper allows an automated history matching process, which is scalable for very large reservoir models. Relying on smart run selection and cluster technology even large models (many hundreds to thousands of wells) can be successfully matched in a reasonable amount of time. As the system is reservoir independent and learning from human experts, less and less user input is necessary over time leading to an autonomous history-matching agent.
Cross-Industry Innovations in Artificial Intelligence
Authors: Piovesan C. , Kozman J. 
Published: September 2011

Abstract
Artificial intelligence (AI) has been applied in various digital oilfield applications, but primarily for subsurface analysis in areas such as artificial lift optimization or production process integration (Sandoval et. al., 2010). While oil and gas continues to be one of the primary producers and consumers of digital data (Heggelund, 2009), other similarly data and operationally intense industries use advanced predictive analytic technologies that could be applied across industries to reduce downtime on offshore platforms. Such proven capabilities are now being applied to data from rotating and reciprocating equipment on the topsides of offshore assets to develop predictive models that can be used to prompt preemptive actions before a critical and economically expensive downtime event.
Gulf of Thailand Information Super Highway, A Business Case on the Foundation of Integrated Operations
Authors: Senivongse Chulatep , Lecksiwilai Naruepon , Kiatrabile Thitiya , Mehrabian AJ 
Published: September 2011

Abstract
Today's offshore oil & gas production environment must maximize recovery for the on-going and future projects to be economically viable. Newly discovered reservoirs must be designed to address issues such as HSE, greater water depths, and other well related gradients.
To undertake the above, in 2010, PTT Exploration & Production Plc., PTTEP, a Thai National Oil & Gas E&P Company, had endorsed the service contract of having Submarine Fiber Optic cable to interconnect its offshore main operating complexes. This initiative is seen as the initial breakthrough in order to step closer to the PTTEP Integrated Operations program, PINTO. It's a foundation of the Digital Oil Field maturity model that could transform the whole operating processes and concepts for PTTEP.
This case study reviews the business case for the Submarine Fiber Optic Cable initiative, and how it was utilized to get support of PTTEP management to realize the benefits and transform of the "Business As Usual" for PTTEP aligned with long term corporate vision.
Assessment of Yet-To-Find Oil in the Brazilian Pre-Salt Region
Authors: Jones Cleveland M. , Chaves Hernani Aquini 
Published: September 2011

Abstract
The Brazilian Pre-Salt region has garnered much attention since the first major discoveries were announced by Petrobras, in 2006. Since then, discoveries in the region have ranked among the largest in the world in the last ten years, including Lula (former Tupi), Iara, and Libra. This led to various estimates, from within and outside the government, that mentioned extremely large total possible accumulations, ranging from 50 to over 300 billion barrels of recoverable oil in the "Picanha Azul" region, an area of approximately 150 thousand square kilometers. Since none of these estimates was accompanied by technical data, or a description of the methodology used, an assessment of the potential for yet-to-find oil was carried out using a software tool which models the exploration process, making Monte Carlo simulations based on the information available regarding wells drilled, discoveries made, respective dates, and the areas involved. The assessment methodology used has been successfully applied by the authors in evaluating the potential of other areas, such as the shallow waters of the Campos Basin. While the present Pre-Salt region assessment does not have as many information points available as in those prior assessments, the intense exploration activity has resulted in enough information being available about the region so as to be able conduct an assessment over the entire area. Applying the concepts of discovery sequence and field size distribution, and making geological estimates for parameters of the number and size of accumulations, the current assessment furnished a probability distribution for the number and expected size of individual accumulations (fields) yet to be discovered, as well as for the total accumulation of yet-to-find recoverable oil in the region. The relatively large range of possible values of the results reflects the lack of more exploratory experience (discoveries or dry wells), which will only come about with time, despite the intense exploratory efforts currently under way. Even so, it was possible to suggest that within probabilistic confidence levels of 95% and 5%, field sizes expected will range from 165 million barrels to eight billion barrels, and total accumulations will range from 115 billion barrels to over 288 billion barrels.
Virtual Metering System Application in the Ceiba Field, Offshore Equatorial Guinea
Authors: Petukov Anton , Saputelli Luigi , Hermann Jeffrey , Traxler Alex , Boles Kim , Nnaji Obiageli , Vrielynck Bruno , Venugopal Deepak 
Published: September 2011

Abstract
Well rate surveillance is essential for reservoir characterization and selecting potential activities to enhance and optimize production. However, such variables usually lack consistent or direct field measurements, which is related to technology availability, equipment reliability, and cost control. As a result, many technologies have been developed to estimate well rates from indirect measurements (e.g., virtual metering or soft sensors).
The well rate estimation requires consistent pressure-volume-temperature (PVT) data, fit-for-purpose production well tests, and reliable sensors. In most cases, field data are used to ‘tune’ data-driven models. Missing, biased, or failing sensors may break the rate estimation, and a new calibration would be required. In addition, sensor input uncertainty and rate estimation confidence were commonly overlooked in previous approaches.
This paper discusses the implementation of a data validation and reconciliation pilot study in the Ceiba Field to estimate well rates. In this case, data, uncertainty, and models are combined to minimize a global error function. Rigorous statistics are used to calculate new sensor estimates. Unlike previous well rate estimation approaches, field-collected data are validated and corrected using physical models.
The pilot technical scope included calculating oil, water, and gas rates for each well; calculating the tolerance of rate measurements and gauge readings; and identifying sources of unreliable measurements. Although the approach is not new in the petrochemical industry, the application is ‘young’ in the upstream.
Project benefits included less downtime due to well testing and early problem detection, 65% less time expended on validating well tests and allocating individual well rates, and improved cost control due to calculating well-produced volumes hourly. These findings provide a better understanding of reservoir and well performance, which facilitates production optimization management. This paper presents a summary of current project status, the lessons learned during pilot implementation, and the procedure for further progression.
Project success criteria, application key performance indicators (KPIs), and expected benefits are reviewed and analyzed. As far as they can be evaluated at this stage, they were all achieved successfully.
Data Mining For Safety
Authors: Tuzin Bill 
Published: September 2011

Abstract
"There are a million ways to lose a work day, but not even a single way to get one back."~Tom DeMarco and Timothy Lister
The old saying "What gets measured gets done" has been put into use to reduce the hazards of the workplace. Virtually every company involved in the exploration and refinement of hydrocarbons has installed procedures and systems to measure workplace hazards and incidents. Monitoring incidents and hazards and performing timely analysis leads to effective remediation efforts. Many of these hazard identification systems and procedures are ineffective because they may be paper based, may be cumbersome for part-time computer users, and are often unavailable at the job site. In addition, event and hazard detail records are often difficult to comprehend, fail to fit into neat categories, and rely heavily on the personal skills of individuals assigned to review these records. All of these conditions impede the value and quality of information entered into the system, resulting in additional challenges to maintaining a safe workplace. Every impediment to the full use of the systems increases the risk that events and hazards will go unidentified and un-remediated.
This paper identifies new technologies that have been implemented in other industries that could improve the performance and outcomes of safety systems used in the energy industry. The principle benefit is the ability to overcome the many obstacles that prevent identification and reduction of risk. By enabling easier data collection from virtually anywhere, with assurances that automated processes will consistently and correctly interpret the data collected, the outcome will be a process of prompt and accurate risk mitigation.