bluuebunny/crossref_metadata_2025 huggingface dataset:
New Environmental Friendly Process Aids Improve Bitumen Recovery and Accelerate Tailings Settling of Low Grade Oil Sands
Authors: Mahmoudkhani Amir , Fenderson Thomas , Watson Philip , Wu Yongfu , Nair Mohan
Published: September 2012

Current water management strategies require recycling and reuse of oil sand process affected water (OSPW) to as much as 80%. Continuous recycling and reuse of OSPW degrades water quality as the concentrations of total dissolved solids (TDS) and dissolved organic materials (DOM) accumulate. This results in a net increase in operating and maintenance costs and an impact on the extraction process and bitumen recovery. Remaining water containing fines and suspended clays adds to the mature fine tailings and associated problems for tailings pond treatment and management. Presence of residual bitumen and other organics is known to create difficulties in common practices for flocculation and dewatering of tailings. With the problems stated above, one may consider a pre-treatment approach rather than the common post-treatment remedies.

The ore grade profoundly affects the efficiency of bitumen recovery in the hot water extraction of bitumen, the principal step in the bitumen extraction process. Sodium hydroxide is commonly added to the conditioning step to improve bitumen recovery. As the sodium ions build in concentration, they disperse clays in the ore and create tailings that resist dewatering. This is especially true for low-grade and oxidized ores, which present the greatest challenges in bitumen recovery and produce the major portion of tailings due to high fines content. With current trends for increasing production from mining operations to almost double by 2020, industry has to adopt new technologies to manage tradeoffs between water and energy.

We present a new approach toward total water management by introducing environmentally friendly process aids that can improve bitumen recovery from low-grade oil sands ores. Lab-scale experimental data from a Denver flotation cell and hydrotransport loop were analyzed to evaluate the efficiency on the processability of high and low grade oil sands, water chemistry and tailings management. The results demonstrate that using new process aids during the conditioning stage improves bitumen recovery from low-grade oil sands and can accelerate tailings settling. This pretreatment approach can be incorporated into current oil sands mining processing facilities and delivers environmental and economical benefits. A critical evaluation for use of new process aids versus sodium hydroxide is given in detail.
The Transformation of an E&P Company's Approach to Asset Development
Authors: Mills Tim , Luan Pete
Published: September 2012

This paper tells the story of the steps that an E&P company took in implementing a methodology to plan, deliver and execute capital projects predictably. It addresses the challenges that any organization faces in effecting change, as well as the actions taken to ensure success for the initiative. This story can serve as a blueprint for any organization that wishes to improve capital performance.

The focus of the paper is not so much the solution implemented, but rather the steps the organization took to ensure a successful implementation. In this paper, the terms "project delivery system" and "asset development system" will be used interchangeably.

The company wanted to improve the predictability of its delivery of major capital projects. The company felt that to meet its business objectives, one of many things it needed to do was improve its capital execution or asset development performance.

E&P companies have many paths to growth while achieving sustainability. A traditional approach is to grow via exploration while producing efficiently. Exploration and production are recognized critical competencies for E&P firms. What is often not appreciated is that the path from exploration to production must go through asset development or capital project execution.

The figure below illustrates the three major competencies that an E&P company needs to grow. Often, firms choose the acquisition path in lieu of exploration. Nonetheless, short of acquiring fully mature assets, there is always some exploration work necessary
Reserve Growth an Examination of Infill Drilling and EOR/IOR in Canada
Authors: Baker Richard , Dieva Rous , Sandhu Kerry
Published: September 2012

Growth in reserves from existing reservoirs has been the primary contributor to reserve additions in most mature basins. Historically, infill drilling has been the main driver for reserves growth for the Western Canadian Sedimentary Basin (WCSB) and other parts of the world. This study examines the other why's of reserve growth in WCSB. Examination of historical trends in fields shows that injection processes (Enhanced Oil Recovery, waterflooding) dominate reserves growth in WCSB, and have been the reason for an increasing oil rate in the region.

This paper will examine performance of both legacy production and infill well drilling programs and relate it to drive mechanism. Production trends in Canada will be presented as well as the incremental production and contribution to WCSB seen from the infill programs. Next, EOR development will be analyzed. Again, production trends in Canada will be presented and incremental oil contribution due to each individual EOR method will be shown. A brief look at USA EOR experience will also be analyzed. The influence of technology growth and oil price will be reviewed for both infill and EOR oil pools.
Improving Exploration, Appraisal & Pilot Planning through Better Forecasting of Uncertainty Reduction via Reliability of Information Interviewing and Confidence Plots
Authors: Coopersmith E. M. , Burkholder M. K. , Schulze J. H.
Published: September 2012

A challenge in the oil industry is the ability to forecast uncertainty reduction resulting from new information. This is particularly important in exploration, appraisal and pilot programs, where management weighs the amount of information expenditure needed to make drill or development decisions. Although a key decision criterion for this is often value, another important criterion is uncertainty reduction, or confidence in the interpretation of critical uncertainties.

So how can teams understand project uncertainties and the effects of different information or appraisal options on their uncertainty assessments? Through an efficient, multi-discipline reliability of information assessment interview process designed to help the team think clearly and openly about the amount of uncertainty reduction to be gained for different information/appraisal programs.

The product is a series of confidence graphs depicting uncertainty reduction versus information options. The plots are developed using Bayesian mathematics and the reliability of information assessment interviews. They address: (1) the probability of a correct interpretation; (2) the probability the actual outcome will be the low outcome after having forecast a P50 outcome; (3) the probability the actual outcome will be the low outcome after having forecast a high outcome; and (4) the probability of getting a given outcome after having correctly forecast that outcome from the information (e.g., the probability of getting a P50 outcome after forecasting a P50 outcome from a test).

The important aspects of this paper are the set of reliability of interpretation questions used to forecast uncertainty reduction potential, how to conduct those interviews and how to develop the resulting confidence plots. The questions address the drivers of uncertainty reduction potential: information tool accuracy; effect of the environment from which the information is being collected; the tendency of the interpretation to better forecast true low, true P50 or true high states of nature; and the representativeness of the information.
Efficiency of Capital Expenditure of Petroleum Producers: How Investing in Exploration and Development Would Affect Reserves and Production
Authors: Virine Lev
Published: September 2012

Petroleum producers are currently engaged in significant expenditure towards exploration and development in various oil and gas plays in the United States and Canada. Does such expenditure lead to better corporate results, particularly reserves and production, or are there other factors which influence corporate results?

The methodology for analysis of efficiency of capital expenditure was developed, based on the correlation between different types of exploration expenditure, including land, drilling and seismic and producer's reserves and production. A model was developed to quantitatively assess exploration and development expenditure, production, and reserves for various producers for different oil and gas plays. The model employs a number of Key Performance Indicators (KPIs) such as finding and development costs with and without acquisitions, reserves life, reinvestment, and others.

The methodology was applied to a comprehensive study of finding and development expenditure in Western Canada. The study did not find a correlation between exploration and development expenditure and company production and reserves additions for WCSB as a whole. However, a correlation was found between expenditure of the companies belonging to the particular group and production within a particular strategy. The results imply that company results are most sensitive to the high level business decisions rather than overall investment in exploration and development.
Completion Influence On Haynesville Shale Gas Well Performance
Authors: Xie Xueying , Glashan John D. , Holzhauser Shawn P. , Knott Gregory M.
Published: September 2012

Shale gas has becoming an important source of gas production in recent years with the advantage of completion technique development. Completion to generate desired fracture system in the reservoir is critical to shale gas production and the corresponding well performance. The impact of fracture system and completion parameters on the well performance decline curves of Haynesville shale gas wells is investigated by using both simulations and field data.

Applying numerical simulation models on horizontal Haynesville shale gas wells with regularly spaced transverse fractures, we investigated the impact of the fracture half length and total fracture surface area on the performance decline curve. The results show that the total fracture surface area defines the early production behavior during the linear flow period and the half length determines the declining slope of the main production time during the fracture interference period if the reservoir parameters are the same. If the reservoir parameters are different, the early time production behavior depends on kAcm, which is the square root of permeability times fracture surface area.

Using field data of hundreds of Haynesville shale gas wells, we observed the different performance decline curves when compared among different regions and compared among different completions in the same region. The difference of decline curves in different regions when using the same completion practice indicates that the reservoir properties are different and thus impact both generated fracture system and flows in the matrix. The difference of decline curves in different completions in the same region suggests that completion impacts the generated fracture system and thus the decline performance. Based on the study results, we can improve the completion practice to optimize well performance and completion cost.
A Two-Factor Price Process for Modeling Uncertainty in the Oil Prices
Authors: Jafarizadeh Babak , Bratvold Reidar B.
Published: September 2012

The petroleum industry has recognized that a consistent probabilistic approach provides improved understanding and insights into the investment decisions. Yet, although most oil & gas companies appreciate the impact of commodity prices on the value of their potential investments, few are implementing price models at the level of probabilistic sophistication and realism of their, say, subsurface models.

We illustrate the implementation and calibration of the two-factor stochastic price model (Schwartz and Smith, 2000) that allows mean-reversion in short-term price deviations and uncertainty in the long-term equilibrium level. It provides advantages over more basic methods but is still simple enough to be communicated to corporate decision makers. The balance between realism and ease of communication of the model has led us to choose this model in favor of one-factor models, which assume that only one source of uncertainty contributes to the uncertainty in prices, or other multi-factor models where two or more factors contributes to the uncertainty in prices.

Previously, a Kalman filter was used to estimate the model parameters based on historical spot and futures prices. We illustrate how current market information (such as futures prices and options on futures observed in commodity futures exchanges) can be utilized to assess the parameters of the two-factor price model. As opposed to the Kalman filter technique, the implied approach to parameter estimation is easy and intuitive, and it will generate estimates that are good enough for most valuation assessments.
The Optimization of Natural Gas Transportation
Authors: Economides Michael J. , Wang Xiuli , Tomaselli Vanni Neri
Published: September 2012

More than 2,600 trillion cubic feet (Tcf) of natural gas reserves are considered as stranded internationally, outside of North America (i.e., not connected to production). This figure is essentially equal to the 2,800 Tcf currently connected to production. The total world reserves, including North America, are around 7,000 Tcf. Confusing the situation and putting impediments to smooth development, in contrast to oil, is the enormous disparity among natural gas prices in various parts of the world: $1/MMBTU in Russia, $2.5 in the US, $8 in Europe, $16 in the Far East. Lack of adequate and diversified transportation is the reason.

It has been repeated often that oil is "fungible" and hence easy to transport with pipelines or easy to load and unload tankers, whereas natural gas is not. Natural gas can be transported with on-land pipelines but it gets rather expensive with underwater pipelines. Traditionally, the cost per length of offshore pipelines has been considered ten times the onshore cost. The main alternative has been liquefied natural gas (LNG) but other options have been offered such as compressed natural gas (CNG) and the chemical conversion of gas to transportable fuels, collectively called gas-to-liquids (GTL). The latter has changed over the years with alcohols getting new prominence.

This work presents new information from recent experiences and attempts to provide a methodology of optimization for the transportation options for natural gas. Emphasis is given to new CNG technologies. Guidelines and new limits are presented to provide the appropriate means of transportation and reduce the volume of stranded gas currently in place. Worldwide demand for natural gas is expected to force the issue because of massive new needs, headed by China.
Price Projection Model for New Explorations after the Lost Control of Majors
Authors: Al-Farisi O. , Fan K. , Belhaj H. A. , Fahmy F. A.
Published: September 2012

Oil price prediction is one of the vital processes in every oil producing and operating company for current running projects and future new explorations, the whole different segments of industries and commodities would be also interested in knowing the future of oil prices, and we shall not ignore the interest that each country by itself shows to know the effect of future prices on their development plans. The oil price today is somehow far away from the control of any of the world powers, not under the control of the major consumers like the United States, Europe, Japan, Russia & China, nor the Super Majors like BP, Total, Exxon, Shell and Chevron, and not even OPEC majors like Saudi, Iraq, Iran, Kuwait and UAE for several reasons. The Consumers are not any more controlling the tap of oil as it was before the 1960's. While the Super majors are not any more having the major reserves as it was before the 1970's, while for OPEC the Excess Capacity of oil production that they have during 1970's, 80's, and 90's has diminished with maturing fields and failing to find new reserves. Therefore, the oil price control become mainly in the hand of supply and demand trends, hence the ability to capture the supply and demand trend model and anticipate the future of them, the oil price shall be known with reasonable confidence. Therefore, several attempts have been conducted throughout the years to estimate the oil prices as early as 1960's. In this paper, a new oil price projection modeling is built and called POMVSD (Price of Oil Modeling with Variables of Supply and Demand). A model reflects the new economic changes happening worldwide. The details of this model will be described in this paper in addition to a review and analysis of historical and modern literature that support this new model structure.
More Confidence in NCF through Comprehensive Oil Price Model
Authors: Belhaj Hadi , Yaslam Maged M. , Patwary Fakhurddin , Olayiwola Saheed O.
Published: September 2012

Since the early days of the petroleum industry, prediction of oil prices has been a real challenge. The puzzling question we need to answer when evaluating project's NCF is: how much is the price of a barrel during the life-span of the project? Accordingly, oil price modeling became a vital tool to predict both short- term and long-term prices. Unfortunately, there are many uncertainties associated with the available models and none of them can predict oil prices with acceptable accuracy. Only limited controlling parameters are captured by these models. These parameters are basic and derived from simple assumptions of supply and demand dependency. Nowadays, the need for a reliable oil price model became more critical as a change of oil price is experiencing dramatic fluctuations that affect economic decision parameters a great deal.

This paper presents an oil-price model to project the price behavior in the next 20 years. Different scenarios were examined out of which "Economic-Scenario" was found to be the best suitable predictor. This model takes into account multiple effects of fourteen parameters that are believed to have the highest impacts on oil price. These factors have been further classified into key categories such as supply, demand, reserve and externalities (political/environmental/social) which is regionally based. Other parameters such as population growth and technology are embedded within these key factors. According to this model, oil price has been found to have strong reliance on the US Dollar and inflation, which has been incorporate into the model to ensure a more reliable outcome.

Market behavior modeling is a continuous process which is planned to be integrated into the proposed model in the near future once consistent data become available. The major obstacle in modeling market behavior is the lack of futuristic behavior that is primarily dependent on accurate historical data. This data should reflect the performance of short-term effects such as lifestyle, human behavior, politics, conflicts, wars, natural disasters, environmental issues and other economies’ behaviors. The ultimate goal of this modeling effort is to assist in economic and risk analysis evaluation of petroleum projects.
Creating Analogs, Fact and Fiction
Authors: Freeborn Randy , Russell Boyd , Keinick Wayne
Published: September 2012

Executive Summary

The increasing attention and development of unconventional resources has many in the industry searching for suitable analogs to supplement their evaluation. A common approach is the use of type wells. Type wells are created by averaging the rate of several analogous wells. This type well rate and corresponding volume is used as a benchmark for evaluating and guiding forecasts for similar wells. The concept of type wells is not new but there are aspects that can be refined to improve results.

The current industry practice has a flaw that when combined with development practices will provide inaccurate results. When creating a type well from historical data only, forecasts are implicitly calculated for wells that do not have enough production to reach the end of the type well time interval. Adding to this is the fact that operators will optimize profit by drilling their best wells first. In this instance the type wells will have a greater rate profile and expected ultimate recovery (EUR) than the underlying data will support. This is because the implicit forecasts for the newer, less productive wells are created from the older, better wells. Conversely, type wells will under-predict rate and EUR in technical plays where performance improves with experience. This paper proposes an approach to address the flaw.

When historical production data is merged with reliable production forecasts to build a type well, the resulting type well is the best available representation of the underlying data. Measures to ensure accurate forecasts on individual wells are recommended.

As an extension to predicting a single rate for similar wells, type wells are also employed to predict different percentile outcomes for similar wells. A common method considers all of the data and calculates a percentile at each time step (Time Slice approach). This approach does not produce consistently reliable results. This paper will propose an alternative approach to creating Type Wells at varying percentiles by analyzing actual wells whose outcome is close in value to the desired percentile.
How to Apply Stretched Exponential Equations to Reserve Evaluation
Authors: Freeborn Randy , Russell Boyd
Published: September 2012

The advent of unconventional resources has radically changed the gas and oil supply landscape in North America. To a great extent, investment decisions with respect to development of unconventional resources depend on the ability to accurately forecast future recovery. Conventional forecasting methods have serious shortcomings. A class of empirical decline equations, termed stretched exponentials, was meant to address these forecasting weaknesses. These equations targeted unconventional gas and held great promise for predicting reserves from wells that were previously forecast using linked super-hyperbolic/exponential equations. Unfortunately, stretched exponentials have been underutilized, possibly because the equations are difficult to solve.

This paper will present solution algorithms for the three most popular equations proposed by Ilk (SPE116731), Valko (SPE 134231) and Duong (SPE 137748). Methods will be presented to identify which data should be rejected and which production trend should be solved when operational or reservoir changes result in multiple trends. Conditions will be described that prevent finding a solution or that will result in an inaccurate solution.

Stretched exponential equations are complex and, unlike the Arps’ equations, they cannot be readily manipulated. For example, it is not possible to use Ilk's equation to determine when a well's recovery will reach a specified amount. A formulation will be presented to make stretched exponentials calculator friendly. Regulators require that the decline factor not exceed a specified minimum and the new formulation honors this requirement.

Case studies will be shown to verify the solutions, compare the expected recovery from the three equations and demonstrate why they sometimes fail.
Perceived Value and Popularity of Decision Analysis Tools in Upstream Asset Valuations
Authors: Karakaya Erkan
Published: September 2012

Oil & Gas (O&G) projects are inherently risky. Increasing economic volatility has compounded the complexity of decisions that O&G companies must make in selecting and investing in projects. Consequently, managerial toolkits to support decisions on economic viability of investments under uncertainty have proliferated, from established traditional models such as Discounted Cashflow Analysis (DCA), to more contemporary ones such as Real Options Valuation (ROV).

A comprehensive literature review of the Decision Analysis tools used in upstream asset valuations was performed, and identified tools were mapped to a conceptual decision analysis framework. Perceived value and popularity of these tools were established by conducting a broad survey which attracted 308 respondents over a two-month period.

The survey results indicate that the tools can be grouped into three broad categories: tools with universal acceptance; tools that are not embraced by the O&G industry; and tools with partial acceptance. The survey also included several demographics dimensions. Several tools exhibited an increasing trend in utilization with increasing company size, while others indicated a functional silo effect where tools’ acceptance levels varied considerably across job functions. Geographical impacts were not analyzed in detail as the sample space was skewed towards Europe and North America.

Utilization and satisfaction levels are generally well correlated; however, a cross-analysis of these two dimensions indicates that discrepancies do exist. Hydrocarbon price forecasting and cost estimation tools provide a lower satisfaction relative to their utilization frequency, while some of the well-established tools appear to be struggling to gain acceptance despite being valued by their practitioners.
Reporting Reserves Under Modern Fiscal Agreements
Authors: Young Elliott D.
Published: September 2012

This paper examines the wide variety of international agreements that are currently used by host governments when granting rights to explore for, develop, produce and market hydrocarbons. The variation in fiscal terms found in these agreements covers a broad spectrum. In addition, their structures are often very complex making comparison of alternative project opportunities difficult. The key differences in the agreements and approaches that are commonly used to compare different fiscal regimes are discussed. Case examples are used to illustrate the techniques used to model and perform economic evaluations of specific agreement types and terms. Commonly used definitions and accepted practice for the determination and classification of hydrocarbon volumes are presented. Host and home government regulations that govern and establish the criteria for external reporting of reserves and related financial information are also discussed in contrast with internal reporting needs for technical and business planning purposes.
An Integrated Portfolio Management Approach for More Effective Business Planning
Authors: Back Michael , Kirk Graham
Published: September 2012

Portfolio management has become an important aspect of oil and gas business planning to support the efficient allocation of capital. As oil and gas becomes more difficult and expensive to find, petroleum companies are looking to portfolio management for providing both a more streamlined business planning process and an advantage over the competition in the industry. However, portfolio management has traditionally been deployed at a corporate planning level and has often missed the opportunity to consider the operational reality at the asset team or regional level. Each capital investment decision must be consistently evaluated for its ability to contribute to the corporate strategy while maximizing the usage of available resources. The aim of this study is to show how an integrated portfolio management solution can provide benefits when used at every stage in the asset development life cycle (from exploration through to production and abandonment) as well as at different levels in the corporation (asset teams through business units to corporate planning) to drive more efficient and effective business planning.

This robust, integrated approach to portfolio management will drive more efficient investment across the corporation. The methodology can be applied to business planning processes at the asset team, the business unit, and at the corporate level within any petroleum company.

The first section provides the best practices in maturing opportunities as producing, development, and exploration properties are evaluated consistently in the context of the company portfolio. The second section of the study covers some specific examples in which the asset development plan is put together to create typical drilling and rig schedules with operational issues such as dependencies between assets and facilities resource constraints. The third section looks at various portfolio management techniques to define the long-term corporate strategy and bridge it with short-term operational constraints to determine an optimized portfolio.

The study concludes with specific recommendations on integrated portfolio management practices at every level in the organization to ensure that the corporate strategy is aligned with available resources. This integrated approach to portfolio management will allow corporate planners to balance long-term strategic goals with operational constraints from the business unit down to the asset team. It will result in a more balanced and diversified portfolio and drive better decisions in the capital allocation process.
The Role of Stranded Gas from Central Asia, Russia, Southeast Asia, and Australia in Meeting Asia's Future Demand for Gas Imports
Authors: Attanasi Emil D. , Freeman Philip A.
Published: September 2012

Demand for natural gas is increasing more rapidly than anticipated in Far East markets because (1) China has modified its policies in order to increase reliance on gas, in part to mitigate the growth in its coal consumption (which now stand at almost half of world coal production), (2) Japan has announced its intention to eventually shutdown its nuclear power industry, and (3) India, which currently has more than 400 million people without electricity, desires to accelerate electrification. This analysis investigates the potential role of stranded gas from Central Asia, Russia, Southeast Asia, and Australia in meeting Asia's future demand for gas imports. It initially surveys the discovered or known gas in stranded gas accumulations in Central Asia, Russia, Australia, Indonesia, and Malaysia. It then examines the primary gas import markets of China, India, Japan, and South Korea by describing energy use, gas demand trends, and domestic gas supplies to establish boundaries that encompass the wide variation in gas import demands in these markets during the two decades following 2020.

Then the cost of developing and delivering gas through overland pipelines from selected stranded gas fields in Central Asia and Russia to China is examined. Analysis shows that for the Shanghai market in China, the costs of developing and delivering Russia's stranded gas from the petroleum provinces of eastern Siberia are competitive with costs estimated for stranded gas from Central Asia. However, for the Western Siberian Basin, delivered gas costs are at least 3 US dollars per thousand cubic feet (USD/Mcf) higher than delivered gas from Central Asia.

The extraction and transport costs to a liquefaction plant for gas from stranded gas fields located in Australia, Indonesia, Malaysia, and the basins of eastern Siberia are then evaluated. The resource cost functions presented show development and extraction costs as a function of the volume of stranded gas developed for each country. The analysis demonstrates that, although the Russian fields in areas of eastern Siberia are large with relatively low extraction costs, distances to a potential liquefaction plant at Vladivostok make them initially the high cost suppliers of the liquefied natural gas (LNG) market. For the LNG markets examined, Australia and Malaysia are initially the lowest cost suppliers. For the Shanghai market, a comparison of the cost of supplying gas by pipeline with the cost of supplying LNG shows that the pipeline costs from areas of eastern Siberia and Central Asia are generally lower than delivered cost of gas as LNG from the LNG supply sources considered.
Integrating the Subsurface and the Commercial: A New Look at Monte Carlo and Decision Tree Analysis
Authors: Schulze J. H. , Walker J. N. , Burkholder M. K.
Published: September 2012

The petroleum industry has always struggled with the "disconnect" between modeling subsurface uncertainties and integrating them into full robust economic analysis. Why? Because there is inconsistent use of probabilistic analysis within asset teams and functions, using disparate software tools, few of which can communicate with each other. Depending upon the project and the company, commercial analysts may use single cases, scenarios, decision trees, best estimates or risk weighted analysis combined into a composite case. Few, if any, have moved their project analysis to a fully integrated stochastic approach. Again, why? Because an "all singing all dancing" subsurface through commercial model does not exist. Different functions in an asset team use different software tools, few of which communicate with each other. In addition, there are few software applications which support fully stochastic analyses, which further complicates the task.

As a result, many subsurface uncertainty characterizations get reduced to a few cases which are passed to the commercial analyst. Wouldn't it be best to integrate both workflows? This would allow the subsurface teams to preserve their characterizations while the commercial analysts interact with the reservoir distributions in their native states. Have the commercial analysts run their calculations using their models and their decision making tools so they can clearly see when, where and how decisions may change based upon all uncertainties. It is more than modeling with precision; it is about knowing when we should be changing our minds.

This paper is designed to stir some thoughts in this area and showcase an example where stochastic analysis and decision trees are combined in three different ways within a single case to provide proof to the adage "the whole is greater than the sum of the parts". A live working example will demonstrate how correlations, full economic analysis and value of information can best be achieved by combining forces. The aim is to demonstrate the power of new ideas and workflows which can be implemented and used today in a practical way.
Fiscal System Modeling Framework
Authors: Coddou Ginny , Hammond Robert , Laaveg Marius , Ogunyomi Babafemi , Raeder Asbjørn , Svensson Malin , Xu Peng
Published: September 2012

Fiscal systems used by various governments in the oil and gas industry are integral to the economic analysis of projects. Complete economic models which aid decision making should incorporate the terms of these fiscal systems. The terms vary by country and frequently by the resource location; onshore, offshore or deepwater, and by resource type; gas, oil, conventional, or unconventional. Despite the variability of these specifics, consistencies exist within the main types of contractual structures. Our work has focused on developing these consistencies into a modeling framework addressing royalty and tax regimes, leasing contracts and production sharing agreements with sufficient flexibility to account for system-specific terms, easily, quickly, and with a high degree of customizability.

We describe an approach to modeling fiscal systems implemented with a modular framework based on the 3 main types of resource development contracts. The framework has 5 design goals: 1. decrease modeling time by an order of magnitude, 2. increase model transparency to enable understanding, 3. provide an auditable environment that can easily be used by both modelers and users, 4. make models adaptable to global changes by implementing modules common to all models, 5. make models accessible and extensible by users without significant programming knowledge.

In addition to these design goals, the framework must satisfy the requirements of its ultimate purpose: to support and inform effective decision making in contractual negotiations and reveal with accuracy the economic impact of the controlling fiscal regime. It is designed to simplify constructing the structure of the model, and to be individually customizable to specific terms. This approach has been attempted by a number of companies with some success, and this is the first time of which we are aware that work is being published on the subject.

Fiscal regimes are a key feature of the international petroleum business, and an objective, transparent, and trusted model is integral to quickly generating insight. A good implementation of such a framework can drastically reduce model development time and highlight critical terms for profitable outcomes, freeing stakeholders to focus on decision making and implementation strategies rather than building models.
The Economics of Gas in North America: Portfolio vs. Performance under Cyclical Prices
Authors: Ziff Paul
Published: September 2012

This paper examines corporate economic and financial performance in the natural gas producing industry and assesses whether performance is a function of portfolio (types and location of gas supplies) or efficiencies in execution in capital spending and operations.

This issue is relevant for North American gas producers, related service companies, and government fiscal policy that are all trying to deal with the current low gas price environment, and the future.

North American gas producing companies assemble their portfolios from 2 categories of gas supply: Conventional and Unconventional (including Tight Gas, Coal Bed Methane, and Shale Gas). Producers economic performance is very different depending on the level of gas prices, so 2 price cases will be examined - ‘normal’ price ($5+/Mcf), and ‘depressed’ price (<$3/Mcf), comparing Conventional & Unconventional gas. In the Normal Price case, full cycle costs are the most relevant performance measure. The largest component, Capital Spending Efficiency, drives full cycle economic results and the return available to the producer. We show the wide range of company performance, such as Finding & Development Cost for gas only by company, and examples of full cycle cost for Unconventional vs. Conventional plays. Some play types are more economic (portfolio selection) and some companies are more efficient than others (Execution). The Depressed Price (current) world is characterized by a gas price well below Full Cycle Economics - there is no return, though some cash is generated. Operating Costs are most important. The range of average Operating Costs between types of gas fields in Western Canada and the Gulf of Mexico Shelf is shown. There is a large variation in operating cost among similar fields.

Both portfolio and execution are critical to surviving today's gas markets. It is important to know full cycle costs by strategy (and gas basin analysis) to achieve a target portfolio and strong performance in CapEx and Operations is critical. Other key factors to enhance revenue are: the impact of natural gas liquids on gas economics and the effect of hedging on the price achieved.

Natural gas prices have plummeted to decade lows, threatening gas activity. An understanding of industry economics is critical to forecasting and maybe even surviving!
Long-Term Economic Viability of Production from Unconventional Liquids-Rich Reservoirs: The Case of Bakken Field
Authors: Ozkan Sarp , Kurtoglu Basak , Ozkan Erdal
Published: September 2012

Long-term economic viability of unconventional reservoirs is evaluated from the profit-maximizing perspective of a producing company. The case of the liquids-rich production from the Bakken field is considered as a representative of unconventional resources. A profit-margin optimization model is constructed for a company to meet the demand it faces from a stock of conventional and unconventional resources given different sets of exogenously determined prices. The model is parameterized using the different production-decline rates of the two sources, physical and economic exhaustibility of the resources, and the ever-increasing marginal cost of adding conventional resources into the company portfolio. The optimal extraction path of oil from the conventional and unconventional reservoirs is assessed and the long-term economic consequence of keeping the unconventional resource in the ground for different oil-price scenarios is predicted. The model reveals the appropriate composition of a portfolio of conventional and unconventional resources. In the case of a high-price scenario, the optimal efficient extraction path is the pursuit of additional conventional resources before utilizing unconventionals to meet the demand. For the reference-price scenario, the decline of the conventional reserves should be substituted with unconventionals from the beginning. The profitability of the EOR applications in unconventional reservoirs and when they should be implemented are also determined. Contrary to common expectation, it is shown that the EOR technology is more justifiable in the case of a lower price forecast.
Basic Petroleum Accounting for Petroleum Engineers
Authors: Olds Dan
Published: September 2012

Oil and gas reserves are the assets that create value for oil and gas companies. While engineers are generally aware of the importance of reserve calculations, many do not know exactly how their work impacts the financial results. Oil and gas reserves, along with the book value, determine the depletion rate which impacts the net income of the company. This paper describes the general accounting process as it relates to reserves, the depletion, depreciation, and amortization (DD&A) process under Full Cost and Successful Efforts accounting methods, and its impact on net income.
An Efficient Decision Framework for Optimizing Tight and Unconventional Resources
Authors: Wehunt C. D. , Hrachovy M. J. , Walker S. C. , Padmakar A. S.
Published: September 2012

Making an efficient and wise concept selection decision—quickly selecting the right project—is often of equal or greater importance than later design and execution tasks for determining project success. Value lost from a suboptimal concept selection decision or from a needlessly prolonged decision process is independent of value generation opportunities during design and execution, and cannot be recouped during later project phases. This paper presents decision framework and production forecasting processes that complement one another, and promote an efficient and high-quality concept selection decision for tight or unconventional resources. The method is for both oil and gas resources, and is especially useful for assessing and developing large contiguous tracts.

High quality production forecasting is very important during concept selection. Better quality concept selection decisions will also result if the alternative conceptual plans are equally optimized when the decision is made, and our assessment process facilitates both accurate forecasting and equal optimization of the various development alternatives. Our method includes symmetry element reservoir simulation models and an efficient economic spreadsheet model with an optimizer. The sector simulation models run fast and can evaluate many cases, but they still explicitly address the physical effects relevant to flow in porous media with vertical, transverse, hydraulic fractures intersecting horizontal wells. The decision framework is structured so that some decisions are independent of the simulation model, and those decisions are rapidly optimized within the economic model. We introduce a fracture efficiency factor which may be important for modeling the diminished performance observed as the number of stages increase in multi-fractured horizontal wells. This fracture efficiency factor may also be an important discriminator of performance between wells fractured using aqueous vs. non-aqueous fracturing fluids. We also show how to use meaningful constraints with a symmetry element model to ensure that the economic forecasts are both realistic and achievable.
Exploration Assets Evaluation: A Practical Way of Conforming Deterministic to Stochastic Mindsets
Authors: Surovtsev Dmitry , Hole Per Audun , Meulengracht Chresten
Published: September 2012

Many integrated evaluation teams use stochastic simulation only to estimate cumulative probability resource curves for exploration assets. Three deterministic cases are then anchored to P90-P50-P10 points of the curve and serve as the basis for in-depth engineering and exploration economics modelling. As illustrated by Delta prospect, discrepancies between resulting NPV approximations and true prospect NPV may be material.

Since it may take another generation to break the wall between deterministic and stochastic ways of exploration project assessment, this paper suggests an interim workflow method to reconcile both mindsets. The method builds on the ability of modern software to pre-estimate the shape of NPV probability distribution curve. Once the shape is available, a discretization shortcut is applied to obtain relevant NPV distribution fractiles and weights. Equivalent resource fractiles are then ‘reverse-fitted’ using the stochastic value cloud. Finally, discrete cases reflecting such calculated resource fractiles are handed over for deterministic engineering and valuation. With the illustrative Delta prospect, application of the method resulted in picking P70-P32-P16 resource fractiles to ensure the best fit to true (stochastic) NPV.

The proposed method provides a practical way to commingle the strongest features of simulation, discretization and in-depth engineering approaches. It is supported by Full Cycle tools embedded in industry standard software for probabilistic risk, resource and value assessments.
Coalbed Methane Resources Evaluation Methodology: An Integrated Case Study in Former Coal Mining Basins in France
Authors: Lefebvre Ch. , Alvis Mariana , De Groen V. , Delamarre S. , Roy G.
Published: September 2012

This paper presents the methodology and technical solutions used to perform an evaluation of Gas Resources for two coalbed methane (CBM) projects in former coal mining basins in the North and East of France. These assessed gas volumes constitute one of Europe's important reported coal bed methane's resources. Successful gas flow rates were also obtained from a horizontal well drilled in coal strata. CBM resources classification principles as described in the Guidelines for Application of the Petroleum Resources Management System (PRMS - November 2011) were applied. The main issues encountered were the allocation and categorization of the 1C/2C/3C Contingent Resources and Low/Best/High Prospective Resources. Dealing rigorously with uncertainties inherent to the type of data used was an essential part of the study.

A fully integrated workflow was used to undertake the resources evaluation. The Gas Initially in Place (GIIP) estimation is based on 3D geological models. Project specific criteria were applied to derive the final volume estimation in the context of CBM resources in the vicinity of former coal mines. Potential recovery factor calculations followed 3 different approaches: Langmuir isotherm curves, material balance based on mining data and 3-D dynamic simulation based on pilot horizontal well results. Due to large uncertainties existing on various parameters, a sensitivity analysis was performed to evaluate their relative impact on production during the dynamic simulation, using experimental design techniques. The final resources calculations and their respective categorization were based on a probabilistic methodology using Monte Carlo simulations with specific distributions for all parameters used at each stage of the workflow (net coal, gas content, coal density, level of coal undersaturation, permeability and recovery factor distributions).

Key parameters were identified as critical with a large impact on the final assessment (gas content, level of undersaturation, shape of Langmuir isotherm curve, abandonment pressure). The elaborated workflow allowed the classification in Contingent and Prospective resources as well as evaluating their respective range of uncertainty which was required to complete the evaluation.