Q amplitude compensation is limited by the rapid growth of the exponential function of frequency used to apply the compensation. Signal to noise ratio limits the maximum useful boost on real data.
This paper will discuss how to handle the gain limit in a way consistent with amplitude vs. angle analysis AVA. It will be shown that a fixed maximum gain is not consistent with AVA.
We will also show a solution for another common issue with Q compensation for phase or amplitude in deep water. The problem is removing the travel time in the water column from the total travel time. Propagation of seismic frequencies through water shows almost no attenuation.
Presentation Date: Wednesday, September 27, 2017
Start Time: 1:50 PM
Presentation Type: ORAL
AbstractObjectives/Scope: The paper examines how oil spill Surveillance, Modelling and Visualization capabilities have evolved over the years and how synergies between these technologies aspire to answer some of the pressing questions on "Situational Awareness" for operational decision making during oil spill events.Methods, Procedures, Process: Techniques exist that provide information about a slick's location, and potentially, information can be gathered about characteristics of a slick such as thickness. This is important in order to maximize the encounter rate of spill response tools, since the best equipment will do little if it is not located in or able to be deployed at the location of greatest concentration, whether it is to be collected, burned, or dispersed. Used together, these technologies ensure that resource intensive airborne and ground based spill response tools and personnel can be deployed effectively and timely manner to achieve optimum response performance.Results, Observations, Conclusions: Major oil spills may involve multiple intervention and response strategies. Although much of the focus has been on mechanical containment and recovery, in-situ burn and dispersants, there have been significant developments with respect to sensing technologies that may allow for better discrimination of the details of a surface slick. This is important since effective response relies on the ability to locate the majority of a spill. It is usually the case that most of the slick volume resides in a small area and by identifying the areas of thicker oil, it is possible to deploy response tools in a more effective manner. Therefore, it is important to have good information about the size of a slick, type of spilled material, location and trajectory. Without this it would be difficult to know how much response equipment to plan for and where to position it. In addition, it is expected that the oil will be subject to natural weathering processes such as evaporation, dissolution, dispersion, and emulsification, all of which may diminish response tool effectiveness. Slicks will naturally spread and in locations in the open ocean, currents and winds will serve to spread the oil farther, making it less continuous and thinner.Novel/Additive Information: Technological advancement in oil spill response operations continues to occur constantly, despite a common misconception that there has been little or no change since the first major offshore oil spill happened in the 1960s. Technological advancements will be discussed with a focus on operational readiness level and existing knowledge gaps for future improvements.
Summary In a blended acquisition, source encoding is needed for the separation of the blended source responses. The source ghost introduced by the strong sea surface reflection can be considered as a virtual source located at the mirror position of the actual source. In this abstract, we propose an acquisition concept that includes the source ghost as a natural source encoding such that it can be used for deblending, where the end result is deblended as well as deghosted. This acquisition method is easy to combine with man-made source encoding and also the concept of using the source ghost provides an interesting alternative to deal with the current depth distributed source for the broadband seismic data. Introduction In a blended acquisition source encoding is needed for the separation of the blended sources.
Aliyu, B. (Mobil Producing Nigeria Unltd) | Ben-Edet, A. (Mobil Producing Nigeria Unltd) | Abbah, E. (Mobil Producing Nigeria Unltd) | Jones, S. (Esso Uk Ltd) | Diara, M. (ExxonMobil Corporation) | Buford, D. (ExxonMobil Corporation) | Ngunjiri, S. (Fircroft)
A framework of Company's strategic and calculated preparedness and response to outbreaks with diminished adverse outcomes is presented. It is based on Nigeria Ebola Virus Disease (EVD) outbreak and its potential impact on country oil and gas operations. It describes the model of engaging stakeholders in all stages of an outbreak, culminating in lessons learned.
The EVD outbreak had potential for cataclysmic impact on workers, families and communities in Nigeria. The Company leveraged on a hybrid of outbreak management framework based on a pre-existing infectious disease outbreak management, pandemic planning and stakeholder engagement.
A series of partnerships was established to provide an effective response towards protecting workers and their families; including working partnerships with Ebola Emergency Operations Center (EEOC), International SOS, the US Centers for Disease Control and Prevention, and Baylor College of Medicine. In-house capacity building was enhanced and included training Company healthcare staff in safeguarding their health and safety, while establishing ‘fever assessment’ centers.
The strategic preparedness and response is described with the successful partnerships and enhanced alignment of key objectives, between in-country management, internal and external stakeholders. Communication and coordination with Company headquarters and external experts resulted in extensive training of health care providers and development of risk-based educational material for workers and dependents. In total about 1400 employees and healthcare providers were trained. The Company also achieved 100% worksite screening procedures which were implemented throughout the duration of outbreak resulting in no loss time recorded due to the outbreak.
Provision of support to Nigerian government including efforts on contact tracing, led to the national recognition of Company for her community investments. Positive and proactive influence by partnering with the oil and gas industry and government to respond to the outbreak, ensuring robust business continuity planning and testing, showed the company's dedication to honoring commitment to our partners and stakeholders whilst protecting the workers and families.
The experiences and lessons learned are important to share widely. They will assist others in the industry as preparations are made to attain readiness to deal with future public health challenges (not just EVD). An effective response requires the establishment of several partnerships across a wide range of stakeholders
Protecting human study subjects from risk or harm is a long-recognized imperative of ethical research. Title 45 CFR Part 46 of the US Code of Federal Regulations, known as The Common Rule, regulates research ethics for most federally-funded human research, but does not apply to research that is privately funded.
Private entities also benefit from instituting formal ethical procedures to guide the conduct of human research that they sponsor or conduct. The primary reason for undertaking such efforts is to protect study subjects from undue risk or harm, while maintaining scientific rigor. An additional benefit may be the enhanced credibility such a program may confer to the validity of industry sponsored/conductedresearch.
This paper describes a program establisihed in 2002. The ExxonMobil Health Research Ethics Program consists of five key elements that include: (1) A Health Research Ethics Committee (HREC) and (2) Formal written Guidelines; (3) A three-tiered review (4) Annual training of both HREC members and potential study investigators (5) Annual Program
(1) A Health Research Ethics Committee (HREC)
In addition to managing the program, HREC conducts reviews of research proposals. Its membership draws upon a variety of professional disciplines and cultural and geographic backgrounds to provide a comprehensive review of the proposals. In addition, HREC includes two external, highly regarded experts in bioethics. Inclusion of these experts ensures that HREC's processes and deliberations are informed by current thinking in the field of bioethics.
(2) Formal written Guidelines
HREC has adopted and developed guidelines outlining standard of conduct and communication of research studies that it reviews. For the convenience of the investigators and to assure consistent quality, study protocol and informed consent templates have been developed.
(3) A tiered review process
All health research studies involving human subjects that are conducted by or on behalf of the corporation are subject to a three tiered ethics review process (See figure 1). The Level 1 review is designed to determine whether an activity is within the scope of the Health Research Ethics Program and thus subject to Level 2 review.
Level 2 review requires submission of a Level 2 Review Form, a study protocol, a copy of the informed consent (if applicable) and any survey tools that may be used. Level 2 Review is modeled on reviews conducted by Institutional Review Boards (IRB). Where risk to subjects is minimal and the study does not involve intentional exposure, the HREC chair may approve a study based on an expedited review. In all other cases, HREC meets, typically by phone, to review the study.
The most complex studies require a third party IRB's review, termed Level 3 review. Studies that involve researchers from academic institutions, are obligated to submit the study to their institution's IRB, but does not obviate the need for full HREC review.
Studies submitted to an IRB prior to HREC review, were invariably approved without comment from the IRB, while HREC issued either contingencies or recommendations. Ivestigators generally report that the study received more thorough review by HREC and that the contingencies or recommendations enhanced the study. HREC's third party consultants confirm that HREC reviews meet or exceed the rigor of IRB review. This is likely due to the lower volume of reviews that HREC performs, allowing more time than is devoted to a study by a typical IRB. In addition, most IRBs see mostly clinical trials and thus are not as experienced in evaluating epidemiology studies, which are the majority of the studies that are submitted to HREC. Thus, Level 3 review is generally performed when required, either based on collaboration with investigators from academic institutions or by institutions releasing data for the purpose of a research study.
El-bakry, Amr (ExxonMobil Production Company) | Romer, Michael Christopher (Exxon Mobil Corporation) | Xu, Peng (ExxonMobil Corporation) | Sundaram, Anantha (ExxonMobil Research and Engineering Company) | Usadi, Adam K. (ExxonMobil CSR) | Morehead, Hubert Lane (ExxonMobil Upstream Research Co.) | Crawford, Mark L. (ExxonMobil Technical Computing Company) | Holloway, Bryce (ExxonMobil Information Technology) | Knight, Charles (ExxonMobil Information Technology)
Asset management teams face many challenges with increasing asset complexity, increasing data volumes, and staff in high demand while optimal asset performance remains paramount. More effective development and management of hydrocarbon assets may be achieved through an increased level of automation of work processes and decision-support technologies across the upstream value chain. Asset management workflow automation poses special challenges as such workflows are multi-disciplinary, cross-functional, and human expertise-intensive. Advancements in the fields of artificial intelligence, software engineering, and decision sciences have led to the development of Multi-Agent Systems (MAS) which have been the cornerstone of achieving higher levels of system and work process automation and autonomy. Here, the human expertise, obtained via knowledge elicitation of domain experts, is encoded into the software in an extensible and sustainable way. Each agent functions as an entity of a distributed computing system, performing a broad range of tasks which may include advanced analytics, data quality checks, and oversight of other agents. Although agents may have competing priorities, they can convey information to one another to broker a feasible decision through collaborative and coordinated decision making. This approach is useful for distributed real-time monitoring and capable of providing technical recommendations under open-loop environments and process control in closed-loop environments. This paper provides insights into a multi-agent development process for hydrocarbon asset management workflow automation and decision support.
Kheshgi, Haroon S. (ExxonMobil Research and Engineeing Company) | Bhore, Nazeer A. (ExxonMobil Corporation) | Hirsch, Robert (ExxonMobil Gas & Power Marketing) | Parker, Michael Edward (ExxonMobil Production Co.) | Teletzke, Gary F. (ExxonMobil Upstream Research) | Thomann, Hans (Exxon Research & Engrg. Co.)
Focus on Carbon Capture and Storage (CCS) has grown over the past decade with recognition of CCS's potential to make deep CO2 emission reductions and that fossil fuels will continue to be needed to supply much of the world's energy demands for decades to come. How CCS will compare to other options in the future depends critically on the cost of CCS (the focus of this paper) and resolution of barriers to CCS deployment, as well as costs and barriers for other emission reduction options.
This paper provides a comparison of the cost of electricity of five power generation options - coal and gas Combined Cycle Gas Turbine (CCGT,) with and without CCS and nuclear - and shows regions of carbon price and fuel prices where each can be economically viable.
Current cost estimates for coal CCS for Nth-of-a-kind power generation plant are in the 60-100 $/ton of CO2 avoided - higher than some of the earlier CCS estimates, and higher than the generally accepted range of expected carbon prices in the next two decades. The high cost of coal CCS suggests that:
• Gas based power generation is much more economical than coal CCS at carbon prices below 60-100 $/ton CO2.
• Even after carbon prices reach 60-100 $/ton CO2, gas CCS produces lower cost electricity than coal CCS as long as natural gas prices remain below 9 $/MBTU.
• Nuclear has a lower cost of electricity than coal CCS.
Although Coal or Gas CCS is unlikely to be economical in power generation over the next two decades, subsidized demonstrations of CCS are likely to occur. In addition, components of CCS technologies will continue to be economically practiced in early use segments such as natural gas processing and Enhanced Oil Recovery (EOR) operations. In this paper, we share ExxonMobil's experience at LaBarge in using CO2 from a natural gas facility for EOR use - the single largest CO2 capture site for sub-surface injection in the world today. In the natural gas processing industry, CO2 separation cost is a fraction of the cost of CO2 capture in power generation due to its higher gas pressure, and the CO2 separation is typically necessary to monetize the natural gas resource.
In contrast, CCS for most refinery and industrial emissions is expected to be significantly more costly than power generation because the CO2 streams are typically smaller scale and more distributed than those from large power plants.
Realistic estimates of cost for CCS, as well as for other greenhouse gas (GHG) mitigation options, are an important input for focusing research, development and demonstration (RD&D) addressing barriers to applications that show the greatest promise, and development of sound policy.
CCS has the potential to provide significant reductions in CO2 emissions from large stationary sources, particularly in electricity generation. How and when CCS will compete with other GHG mitigation options depends on a clear understanding of CCS costs and drivers, as well as resolution of barriers to CCS deployment.
The cost of CCS is influenced by the size of the CO2 source, CO2 concentration, CO2 pressure, the maturity of technology, and the proximity and quality of storage (CERA 2010). Furthermore, added costs may be incurred by the resolution of issues associated with impurities, permitting, and long-term responsibility for stored CO2.
The capture step dominates CCS cost from electricity generation. CCS cost estimates are primarily derived from consideration of equipment requirements and operating costs. However, issues associated with impurities, permitting, and long-term responsibility for CO2 storage are not fully resolved. Resolution of these issues may require changes in design and operation that could entail additional costs. Construction costs for the capture step are likely to be higher than common basis assumptions, especially for a first-of-a-kind plant.
Effective acid stimulation can be critical to achieving the desired long-term production rates from targeted reservoir layers. ExxonMobil has developed an integrated, multi-disciplinary methodology for carbonate matrix stimulation of long completion intervals.1 The methodology is a continuous process which includes geological characterization, reservoir objectives, completion strategy, stimulation design with the necessary experimental testing, implementation, and evaluation. The methodology has recently been customized in collaboration with RasGas to achieve objectives for K1-K32 and K1-K43 completions in the North Field, the world's largest, non-associated gas field.
Building upon this success, ExxonMobil continues to study the fundamentals of carbonate stimulation and its impact on long-term productivity to enhance the process and apply it to a wider range of reservoirs and well types. This paper presents preliminary results from three areas of ongoing research: (a) improved understanding of 3-D wormhole growth through large-scale experiments and visualization techniques, (b) integrated wormhole modeling and complex fluid flow during stimulation of long horizontal wells, and (c) enhanced post-stimulation evaluation method that integrates stimulation physics, well test analyses, and long-term reservoir performance predictions. Integration of these technological advancements with existing knowledge provides an enhanced methodology for the stimulation of carbonate reservoirs with an increased focus on long-term productivity.
In December 2009, Esso Highlands Limited, a subsidiary of Exxon Mobil Corporation, and its partners made the decision to sanction the PNG LNG Project to develop resources in the Southern Highlands and Western Province of the Papuan fold belt. This project will develop four gas fields and blow down the gas caps of four currently producing oil fields. Resource assessments in the project area are only poorly characterized by the integration of 2D seismic, surface geology, well data, synthetic aperture radar (SAR) and aeromagnetic data. Integration of dynamic data has been critical in the development of the resource assessment, with approximately 80% of total resource supported by production and pressure data.
The Hides Field with five reservoir penetrations is the key asset for the PNG LNG Project, supplying approximately 2/3 of the total project resource. Integrated structural mapping and comprehensive reservoir analysis in conjunction with pressure data sourced from existing wells defines the Hides volumes. Full field dynamic simulation models have been used to test the match to production history and determine the range of in-place and recoverable volumes. Comprehensive sensitivity analysis confirmed the validity of small amounts of production data to constrain the range volumes and demonstrated the resource robustness. A similar approach was applied at the Kutubu Main Block Toro (MBT) Field which has extensive well penetrations, production history and pressure data. Results of this work significantly narrowed the range of uncertainty in the Hides and Kutubu MBT resource and built confidence in the total resource base for the PNG LNG Project.
PNG LNG Project Overview
The PNG LNG project will commercialize the Hides, Angore, Juha and SE Hedinia non-associated gas fields and the associated natural gas resources in the currently operating oil fields of Kutubu, Agogo, Gobe and Moran in Papua New Guinea. The gas will be treated at a gas conditioning plant located at the southern plunge of the Hides Field and then transported via pipeline to a 6.6 million tonne per annum LNG liquefaction and storage facility to be located 20km north-west of Port Moresby on the Gulf of Papua (Figure 1). Over its 30-year life, the project is expected to produce over nine trillion cubic feet of gas, with first LNG production to begin in 2014. Long term LNG Sales Purchasing Agreements were signed with international customers from China, Japan and Taiwan.
Participating interests in PNG LNG include affiliates of ExxonMobil (including Esso Highlands Limited as operator, 33.2%), Oil Search Limited (29.0%), Independent Public Business Corporation (PNG Government, 16.6%), Santos Limited (13.5%), Nippon Oil Exploration (4.7%), Minerals Resources Development Company (PNG landowners, 2.8%) and Petromin PNG Holdings Limited (0.2%).
This major LNG development is comprised of the following main components (Figure 1):
- Producing and preparing the gas - facilities at Hides and Juha will process raw gas from several production wells in the Southern Highlands and Western Provinces.
- Transporting the gas - via a pipeline overland from Hides, Kutubu and Gobe to the Omati River fluvial plain and then subsea to the LNG plant north-west of Port Moresby.
- Liquefying the gas - a 6.6 million tonnes per annum capacity LNG plant near Port Moresby.
- Shipping the gas - specially built LNG tankers transport the liquefied gas to international customers.