bluuebunny/crossref_metadata_2025_split huggingface dataset:
Facilities Selection Impacts Reservoir Performance
Authors: Simpson David A 
Published: June 2014

Abstract
Facilities decisions are often disconnected from anticipated reservoir performance. A frequent result of this disconnect is operating reservoirs in a sub-optimum manner to protect surface facilities that have inadequate strength. This paper will review the facilities decisions that have been made in several Coalbed Methane (CBM) and Coal Seam Gas (CSG) fields around the world and discuss the reasons for and the impact of those decisions on the performance of the reservoirs. The source of the disconnect is that "everyone knows" that CBM and CSG fields "require very low pressures". With that assumption you then apply safety and procurement principles to come to a design. There is a stage in the production life of these fields where very low pressures are required for reasonable recovery levels, but that stage is typically reached 10-15 years after first production. Setting late-life surface facilities at first-production results in choking the reservoir for over a decade, setting compression many years before it is actually required, and less ultimate recovery as a percentage of original gas in place than would otherwise be achieved. These problems can be overcome by understanding the life cycle performance and risks of an unconventional reservoir and accepting that any tradeoff between facilities performance and reservoir performance must be biased in favor of optimizing reservoir performance in order to have acceptable economic results.
Impact of Storage Tax Credit on Economic Viability of CO2 Storage with EOR
Authors: Ettehadtavakkol Amin , Lake Larry W. , Bryant Steven L. 
Published: June 2014

Abstract
A partnership between oilfield operators and the federal government in the coupled CO2 enhanced oil recovery (EOR) and storage projects may bring long-term benefits for both. This paper quantifies the win-win condition for this partnership in terms of an optimum storage tax credit.
We introduce a basic conceptual model for the CO2 market and investigate the market sustainability conditions. We quantitatively show how the storage tax credit affects the optimum economic storage capacity of an oilfield as well as the benefits for the oilfield operator and the government. Two field-scale models for the EOR-storage operation are developed, namely Sandstone and Carbonate. The Sandstone model is tuned according to the top 10% performing West Texas CO2-EOR reservoirs while the Carbonate model is tuned according to the moderately performing reservoirs. The EOR-storage performance of the simulated Sandstone and Carbonate reservoirs is likely to be moderate to optimistic where the oil production performance is between 50 and 100 stbd/well and the CO2 utilization is between 5 and 10 Mscf/stb. Assuming $60/stb oil price and $80/tonne anthropogenic CO2 cost, the storage tax credit should be between 20 and $40/tonne to allow for an economically feasible EOR-storage operation and satisfy market sustainability (win-win) for both the oilfield operators and the federal government. Below this range, EOR-storage is infeasible and neither the operators nor the government gain benefits (lose-lose); above the optimum tax credit range the government spends too much while the operator gains benefits (lose-win). This study, however, does not consider the intangible social, economical, and environmental benefits of anthropogenic CO2 storage.
Design of Fiscal System for Exploration of Shale Gas: How is it Different From Conventional Oil and Gas?
Authors: Amorim LÍvia 
Published: June 2014

Abstract
Due to the success of shale gas developments observed in the US and the absence of domestic legislation specifically for unconventional gas projects in the countries, an arising question is whether replicating the fiscal terms conceptually conceived for conventional oil and gas exploration would be appropriate for the exploitation of unconventional gas deposits. To assess this issue, this study approached the question with a fiscal policy formulation perspective. It was assumed that a desirable fiscal system, able to balance opposed objectives from the Government and private investors would be a flexible, neutral and stable one, favourable to maximize the present value of the project. To address the question, this article makes a comparison between shale gas projects and conventional gas projects to examine if they have structures similar enough to be covered by the same fiscal regime or if the legislation needs to cover issues that are exclusive to shale gas projetcs. The analysis showed that, first, the basis of comparison would be better segmented between oil projects and gas projects – either from conventional or unconventional sources, since this last category has less margin of rent available to be taxed. Besides that, shale gas projects have particularities that should be considered by policy makers when designing a fiscal system to encourage its development. Furthermore, fiscal instruments can be a powerful tool to guide tax payers behavior and hence address other concerns not necessarily related to revenue-raising, bur, for example, environmental and social issues.
Simplified Business Planning - A Business Unit’s Approach to Creating More Realistic, Higher-Return Plans; Faster
Authors: Kirk Graham , Kellogg Christopher 
Published: June 2014

Abstract
In the oil and gas industry, the term "business planning" brings visions of late nights, additional meetings, and countless hours spent collecting and reconciling large amounts of data. This negative connotation has been reinforced over the years as companies struggle to pull together the information they need to create realistic and achievable plans and to forecast future development to guide the growth of their business.
It is unfortunate that business planning has such a bad reputation as it is critical to the success of any company in any industry. In business planning, the goals are simply to select the best projects from a portfolio of opportunities to maximize the return on investment, while being able to effectively communicate the details of how the different scenarios were created to provide confidence in the decision to invest.
This paper describes a case study in which one of Occidental Oil and Gas Corporation (Oxy BU) business units improved a few key elements in their business planning process which helped them create a more realistic, higher return plan, faster.
The Oxy BU saw the potential rewards that improvements to their planning process could generate by improving their planning efficiency, reducing errors, and breaking out of the same painful cycle they had experienced in previous years.
Uncertainty vs. Variability: What’s the Difference and Why is it Important?
Authors: Begg Steve H. , Welsh Matthew B. , Bratvold Reidar B. 
Published: June 2014

Abstract
Technical professionals are often asked to estimate "ranges" for uncertain quantities. It is important that they distinguish whether they are being asked for variability ranges or uncertainty ranges. Likewise, it is important for modelers to know if they are building models of variability or uncertainty, and their relationship, if any.
We discuss and clarify the distinction between uncertainty and variability through strict definition, illustrative analogy and numerical examples. Uncertainty means we do not know the value (or outcome) of some quantity, eg the average porosity of a specific reservoir (or the porosity of a core-sized piece of rock at some point within the reservoir). Variability refers to the multiple values a quantity has at different locations, times or instances – eg the average porosities of a collection of different reservoirs (or the range of core-plugs porosities at different locations within a specific reservoir).
Uncertianty is quantified by a probability distribution which depends upon our state of information about the likelihood of what the single, true value of the uncertain quantity is. Variability is quantified by a distribution of frequencies of multiple instances of the quantity, derived from observed data. That both are represented by ‘distributions’ is a major source of confusion, which can lead to uncritical adoption of frequency distributions to represent uncertainty, and thus to erroneous risk assessments and bad decisions. For example, the variability of natural phenomena is sometimes well-approximated by normal or log-normal distributions, but such distributions may not be appropriate to represent the uncertainty in outcome of a single occurrence.
We show there is no objectively ‘right’ probability distribution for quantifying the uncertainty of an unknown event – it can only be ‘right’ in that it is consistent with the assessor's information. Thus, different people (or teams or companies) can legitimately hold different probabilities for the same event. Only in very restrictive, arguably unrealistic, situations can we choose to use a frequency distribution derived from variability data as a probability distribution to represent our uncertainty in an event's outcome.
Our experience as educators of students and oil & gas industry personnel suggests that significant confusion exists in their understanding of the distinction between variability and uncertainty. This paper thus provides a resource for technical professionals and teachers to clarify the distinction between the two, or to correct it where it has been wrongly taught, and thereby help to improve decision-making.
Transforming Portfolio Optimization through Reengineered Processes and Technologies
Authors: Charles Tashika , Zhakiyanov Berik , Moreland Colin , Back Michael , Bailey Erin 
Published: June 2014

Abstract
The process of upstream planning for the oil and gas industry has historically been a time consuming and inefficient process. The majority of effort is spent collecting data from multiple functional areas and organizational teams within an organization to form a holistic view of a company. By introducing an integrated solution that combines the opportunity catalog, economic analysis, and optimization into a single workflow, planners are experiencing efficiency gains, reduced time spent planning, and more accurate results. Through an analysis of the implementation of such a system at Chevron's Gulf of Mexico Business Unit (GOMBU), the challenges and benefits of implementing an integrated business planning approach as described will be demonstrated.
This paper will reflect on the systems, processes and workflows involved in the planning process at GOMBU both before and after deploying an integrated planning solution consisting of an opportunity catalog and linear optimization tool. This paper will also describe the challenges faced during the implementation and the benefits gained after the solution was deployed.
Method:
Define "Vision" and reason for move to linear optimization Discuss state prior to deployment Evaluate technical challenges with current state Review state after deployment Examine results and gained benefits Proposed model for integrated planning framework
Results & Observations:
Improved efficiency of portfolio optimization was significant, optimization time went from several weeks to days Portfolio optimization process was more fluid and responsive to changing business environments Secondary value generated to the entire organization in data integrity, consistency, management visibility into data, and traceability through opportunity maturation.
Conclusions:
Significant improvement in planning efficiency and accuracy achieved through implementation and execution of proposed architecture Integrated planning saves time, money and leads to significant value realization
Applications:
Learnings are applicable to any mid-to-large sized organization with any aspect of the planning process
Innovations:
Combination of opportunity tracking and planning into a single workflow Combination of Opportunity Catalog, Economics Engine, and Linear Optimizer into a single portfolio analysis package Cross-functional visibility and input into the plan and communication of results
A Management Decision Tool for Ranking Oil Sands Resource Development Opportunities
Authors: Dlugan M. , Pompa A. 
Published: June 2014

Abstract
A management decision-making and planning tool has been developed to provide a quick, high-level resource quality assessment of oil sands assets to enable economics-based ranking of investment opportunities. It is systematic and transparent, largely avoiding the subjectivity and human bias often associated with ranking assets for capital allocation.
The model utilizes the available reservoir characterization information (API gravity and petrophysical analysis including oil saturation, effective porosity, V shale, pay thickness), expected operating conditions (steam injection pressure, horizontal well lengths), and a reservoir risk assessment to predict the key performance metrics for an in situ oil sands project using SAGD (steam assisted gravity drainage) including oil rates, steam-oil ratio and recovery factors. The reservoir risk factor is a quantification of the production impact (lower expectations and/or increased uncertainty) from reservoir impairments based on expert opinions and reservoir simulation. These performance metrics can then be used to estimate expected overall economic potential (IRR) for a given asset. The ranking can be done at various levels: land sections, defined prospects, wellpad drainage areas, or at the individual (delineation) well level.
Predictive analytics techniques, in this case multi-variable linear regression, were used to construct the model. It was initially based on thermal recovery theoretical models for the SAGD process for predicting oil rates and a simple energy balance for predicting steam-oil ratio (SOR). Subsequently it has been updated via industry production data "fitting", or applying the actual performance data of various mature, operating wellpads to improve the confidence level of the model. The result is a hybrid model; science-based but influenced by real operating and production experience.
It has served as a primary tool used for strategic planning, in the setting of high-level performance targets (and probabilistic distributions thereof) for each of the assets. This tool has enabled a resource driven development strategy, allowing the company to focus technical resources on the assets that possess the greatest economic potential. Resulting business decisions include capital allocation (for additional delineation data) and more rigorous technical efforts (reservoir modeling and simulation) on the highest ranking prospects.
Discount Rate Development in Oil and Gas Valuation
Authors: Harden Clarence (Jim) 
Published: June 2014

Abstract
Oil and gas companies typically use discounted cash flow analysis in determination of the value of their oil and gas investments. "PV-10" is often accepted as the present worth of an oil and gas investment, but does a 10% discount rate represent the true cost of capital and include project-specific risk premium, or is it simply a rule-of-thumb? This original paper will discuss the factors that go into and how to calculate the weighted-average cost-of-capital (WACC) as the starting point to calculate the appropriate discount rate for their investment.
A Model Approach to the Emergency Preparedness and Response Process
Authors: Jensen Peter A. 
Published: June 2014

Abstract
Emergency Preparedness and Response and Business Continuity Planning are integrated into ExxonMobil’s structured approach to managing safety, security, health and the environment commonly referred to as"Operations Integrity Management System". This paper describes ExxonMobil’s Emergency Preparedness and Response Model and Process, with emphasis on its ongoing application. ExxonMobil strives to prevent emergencies from occurring. However, when emergencies do occur, the Model and Process defines ExxonMobil’s approach to preparing for and responding to the event(s). Our philosophy remains the same for an emergency that directly impacts us or one indirectly impacting our industry: establishing objectives that minimize impact on people, the environment, assets, and reputation (PEAR).
Our philosophy, objectives, tools, and processes are internal to the Model and Process, and integrate a tactical and strategic response. Internal and external resources ensure that our response is effective and scalable, on a 24/7 basis. Engaging these resources in training and exercises enhances response capability if a real emergency occurs. ExxonMobil’s Corporate Headquarters and Upstream, Downstream, and Chemical Companies have Emergency Support Groups (ESG) for each business unit. The ESG is focused on strategic support. Tactical support is derived from: Tier III Regional Response Teams (global coverage), U.S. based Tier II Strike Teams (personnel and equipment based), and numerous Tier I- Facility/Site Teams. ExxonMobil also contract with oil spill response organizations (e.g., Oil Spill Response, Marine Spill Response Corporation, and Marine Well Containment Company) for additional personnel and equipment. In the United States, use of the National Incident Management System’s Incident Command System (ICS) is required at the tactical level. ExxonMobil is in the process of implementing ICS, on a global basis, to improve preparedness and response.
ExxonMobil has benefited from the Model, Process, Teams, and Resources. Benefits include: Networking; Lessons learned and applied; and Increased personal knowledge. Team synergy and immediacy of effective response activities during emergencies have also validated training and exercises.
Emergency Preparedness and Response planning is essential for any organization. International and national laws and regulations mandate oil and gas companies to have emergency preparedness and response plans, resources, training, and exercises. The ExxonMobil Model and Process, which integrates strategy and tactics, provides an invaluable framework for preparing for and responding to emergencies.
Possible Mechanisms for Oil Recovery from Chalk and Sandstone Rocks by Low Salinity Water (LSW)
Authors: Hamouda A. A. , Valderhaug O. M. , Munaev R. , Stangeland H. 
Published: June 2014

Abstract
Low salinity water flooding is gaining much of attention for its potential in increasing oil recovery, in spite of the debatable working mechanism for both sandstone (SS) and chalk. Various mechanisms have been suggested in literature.
The objective of this work is to address oil/brine/rock (COBR) interaction and deduce thermodynamically possible product of the interaction, then verify with the experimental results. The experiments were designed to have most of the flooding with LSW as a secondary recovery method following seawater (SSW). This is to mimic the situation in most oil fields, which gone through seawater flooding and to contribute to the debatable discussion on the rule of LSW to enhance oil recovery as secondary or primary fluid.
From previous work in our laboratory, sulfate and magnesium have been identified as active ions in the seawater in altering chalk wettability to more water wet; hence they were also tested as single ions water flooding and imbibing fluids for both SS and chalk. This approach has contributed to our understanding of the possible reactions that occurs due to COBR.
From the SS part of the experiments, the results show indications of ion exchange, mineral dissolution processes and rock weakening causing fine migration. Mineral dissolution and ion exchange are not unexpected in presence of mineral such as, in general, kaolinite. The experimental results confirmed the simulated reaction between LSW and kaolinite from the increase of the pH and the resulted ions. In addition, the increase of the pressure drop detected during the flooding, could be related to the fine migration in addition to visual observation.
From the work performed on chalk, the results indicate fine detachment, which was enhanced in presence of Mg2+ ions as imbibing fluid at elevated temperature (70°C) for chalk. An increase of the pH was also observed for all flooding and spontaneous imbibition tests, especially with SO42- (for SS and chalk). In contrast to SS, chalk flooded with LSW showed reduction of pressure drop across the cores.
Assessment of Oil Recovery by Low Salinity Waterflooding from Laboratory Tests
Authors: Winoto Winoto , Loahardjo Nina , Morrow Norman R. 
Published: June 2014

Abstract
Increased secondary and tertiary oil recovery by low salinity water flooding has attracted widespread interest as a low cost improved oil recovery method. Field applications that give increased recovery by over about 2% OOIP are considered economically viable. Although the number of reported laboratory and field investigations is now approaching 200, no consistent conclusions have been reached as to the circumstances under which recovery is improved. Laboratory core floods provide a practical approach to investigation of necessary conditions for improved recovery. In seeking responsive rocks for investigation of recovery mechanisms, 19 sandstones were screened for low salinity effect (LSE) through decrease in residual oil after injection of dilute brine (LSE @Sor). The highest recovery given by a definitive bump in recovery, as opposed to small increase in oil cut, was 5% OOIP. Three rock types, Castle Gate, Berea Stripe, and Briar Hill, were selected for further study because of relatively high response. After the originally tested core plugs were cleaned and restored, two of the plugs gave robust residuals to high salinity flooding and no LSE @Sor; the third gave very high recovery by high salinity flooding but much reduced response to LS brine. Reproducibility of recovery behavior was tested for pairs of sister plugs. For all three core types, average LSE @Sor, if any, was much lower than the recoveries that led to their selection. The best performing sandstone, Briar Hill, was then tested further with sets of cores being taken from two additional quarried blocks, each weighing about 10 tons. None of the cores cut from these blocks gave significant tertiary response. The average recovery for outcrop rocks is much lower than the average for reservoir rocks. An unexpected conclusion from the study is that, because of the generally low response, outcrop rocks provide numerous examples of very little or no LSE @Sor.
Evaluation of Frictional Properties for Methane-Hydrate-Well Completion and Production
Authors: Yoneda Jun , Kakumoto Masayo , Miyazaki Kuniyuki , Katagiri Jun , Aoki Kazuo , Tenma Norio 
Published: June 2014

Summary
During methane-hydrate production in offshore deepwater seabeds, there are concerns about the settlement of the seabed and the possibility that negative friction will occur along the production well. However, frictional properties of a deepwater well structure are not investigated. Here, friction tests were conducted on interfacial boundaries among a steel rod and sand and a steel rod and cement under high confining pressure. Three types of steel rods with different surface roughness, two types of silica sand with different particle sizes, and cement were used. A steel rod confined by compacted sand or hardened cement was pushed out at a constant displacement rate. The tests show that frictional strength of two kinds of interfacial boundaries increased linearly with confining pressure. In addition, the results confirmed the effective friction angle of the interface between a steel rod and sand and the cohesion of the interface between the steel rod and cement increases with the surface roughness of the steel rod.