A Severance Tax Revenue Forecast Model for Louisiana

Most states levy severance taxes on the value of natural resources when they are severed or extracted from the ground or subsurface. In Louisiana, severance tax on oil and gas production contributes to the majority of mineral revenue in the state, and over the last decade, has ranged between $400 million and $1.1 billion, or between 5 and 9% of annual state revenue. The purpose of this article is to develop a forecast model for severance tax revenue to better understand the severance tax regime and to assist in state budgeting and planning purposes. We couple an oil and gas production model with empirical relationships describing historical severance tax receipts to perform the forecast. We demonstrate that oil production correlations are robust, but that in recent years, unconventional gas production from the Haynesville shale has led to a significant departure from historic trends. We estimate that cumulative oil and gas severance tax revenues during 2011–2015 will range from $1.0 to $2.1 billion for oil and $1.3–$1.9 billion for gas. Louisiana is transforming into a gas-producing state, and more attention needs to be paid to tax design and the impact of exemptions on future severance revenue receipts.     

Haynesville Shale Well Performance and Development Potential

Louisiana’s Haynesville Shale is one of several unconventional gas plays that have been discovered in the U.S. in recent years and promise to dramatically change the course of future domestic energy development. The Haynesville Shale is the deepest, hottest, and highest pressured shale among the big four plays in the U.S. with drilling and completion cost ranging between 7 and7 and 10 million per well. The average Haynesville well has an initial production rate of 10 MMcfd and declines rapidly, producing 80% of its expected recovery during the first 2 years of production. The purpose of this article is to describe the productivity characteristics of Haynesville wells, project future production from the inventory of active wells, and assess production potential based on drilling scenarios. We offer statistical analysis of the wells drilled to date and construct type profiles to characterize the play. We estimate that the current inventory of Haynesville wells will produce 3 Tcf over their lifecycles, and within the next 3 years, cumulative build-out in the region will range between 3 and 9 Tcf. To maintain current gas production levels in the state, we estimate that about 550 shale gas wells per year will need to be brought online over the next 3 years.     

A Royalty Revenue Forecast Model for Louisiana

Louisiana receives royalty revenue when minerals are produced on state-owned lands and water bottoms, federal properties within the state, and offshore fields underlying federal and state jurisdiction within 3–6 nautical miles from the coastline. Royalty revenue on oil and gas production has averaged $465 million per year and has contributed 3–7% of the state general revenue over the past decade. The purpose of this article is to develop a royalty revenue forecast model to assist in state budgeting and planning purposes. Producing fields are evaluated within a probabilistic framework to capture the uncertainty associated with future capital outlays and operational changes, and a discovery model is used to generate production from fields expected to be discovered in the future. The forecasts are combined with commodity price scenarios and royalty rate assumptions to generate a royalty revenue outlook for the state. We estimate that cumulative royalty revenue during 2012–2017 will range from $704 million to $1,408 million for oil production and from $286 million to $1,145 million for gas production for commodity prices of 60–120 $/bbl and 2–8 $/Mcf. At $80/bbl and $4/Mcf, cumulative royalty receipts from 2012 to 2017 are estimated at $1,510 million.     

A Review of Louisiana Drilling and Production Activity, 1980–2011

Louisiana plays an important role in domestic oil and natural gas production, and in 2012 ranked sixth in oil production and third in gas production in the United States. Conventional oil and gas production in Louisiana has been declining steadily over the past four decades, while unconventional gas production has seen spectacular growth in recent years, effectively doubling the state’s natural gas output over three years. The structural changes impacting Louisiana’s oil and gas industry are complex and dynamic, and to better understand the relationships between activity drivers, a review of drilling and production data between 1980 and 2011 is performed and correlative relationships are developed. Drilling and completion trends, including completion and success rate statistics and drilled footage, are summarized by region. Correlative relationships are established between measured footage and the number of wells drilled, drilling activity, abandonments, and commodity price. We show that drilling activity in North Louisiana is highly responsive to changing oil prices, whereas in South Louisiana, activity is relatively inelastic. Well abandonments are shown to be negatively related to commodity prices. Horizontal, directional, active, idle, and orphaned well inventories are summarized.     

Unconventional Energy Resources: 2011 Review

This report contains nine unconventional energy resource commodity summaries prepared by committees of the Energy Minerals Division (EMD) of the American Association of Petroleum Geologists. Unconventional energy resources, as used in this report, are those energy resources that do not occur in discrete oil or gas reservoirs held in structural or stratigraphic traps in sedimentary basins. These resources include coal, coalbed methane, gas hydrates, tight gas sands, gas shale and shale oil, geothermal resources, oil sands, oil shale, and uranium resources. Current U.S. and global research and development activities are summarized for each unconventional energy commodity in the topical sections of this report. Coal and uranium are expected to supply a significant portion of the world’s energy mix in coming years. Coalbed methane continues to supply about 9% of the U.S. gas production and exploration is expanding in other countries. Recently, natural gas produced from shale and low-permeability (tight) sandstone has made a significant contribution to the energy supply of the United States and is an increasing target for exploration around the world. In addition, oil from shale and heavy oil from sandstone are a new exploration focus in many areas (including the Green River area of Wyoming and northern Alberta). In recent years, research in the areas of geothermal energy sources and gas hydrates has continued to advance. Reviews of the current research and the stages of development of these unconventional energy resources are described in the various sections of this report.     

Unconventional Energy Resources: 2013 Review

This report contains nine unconventional energy resource commodity summaries and an analysis of energy economics prepared by committees of the Energy Minerals Division of the American Association of Petroleum Geologists. Unconventional energy resources, as used in this report, are those energy resources that do not occur in discrete oil or gas reservoirs held in structural or stratigraphic traps in sedimentary basins. These resources include coal, coalbed methane, gas hydrates, tight-gas sands, gas shale and shale oil, geothermal resources, oil sands, oil shale, and U and Th resources and associated rare earth elements of industrial interest. Current U.S. and global research and development activities are summarized for each unconventional energy commodity in the topical sections of this report.     

Unconventional Energy Resources: 2007–2008 Review

This paper summarizes five 2007–2008 resource commodity committee reports prepared by the Energy Minerals Division (EMD) of the American Association of Petroleum Geologists. Current United States and global research and development activities related to gas hydrates, gas shales, geothermal resources, oil sands, and uranium resources are included in this review. These commodity reports were written to advise EMD leadership and membership of the current status of research and development of unconventional energy resources. Unconventional energy resources are defined as those resources other than conventional oil and natural gas that typically occur in sandstone and carbonate rocks. Gas hydrate resources are potentially enormous; however, production technologies are still under development. Gas shale, geothermal, oil sand, and uranium resources are now increasing targets of exploration and development, and are rapidly becoming important energy resources that will continue to be developed in the future.

---

     

Empirical Methods for Detecting Regional Trends and Other Spatial Expressions in Antrim Shale Gas Productivity, with Implications for Improving Resource Projections Using Local Nonparametric Estimation Techniques

The primary objectives of this research were to (1) investigate empirical methods for establishing regional trends in unconventional gas resources as exhibited by historical production data and (2) determine whether or not incorporating additional knowledge of a regional trend in a suite of previously established local nonparametric resource prediction algorithms influences assessment results. Three different trend detection methods were applied to publicly available production data (well EUR aggregated to 80-acre cells) from the Devonian Antrim Shale gas play in the Michigan Basin. This effort led to the identification of a southeast–northwest trend in cell EUR values across the play that, in a very general sense, conforms to the primary fracture and structural orientations of the province. However, including this trend in the resource prediction algorithms did not lead to improved results. Further analysis indicated the existence of clustering among cell EUR values that likely dampens the contribution of the regional trend. The reason for the clustering, a somewhat unexpected result, is not completely understood, although the geological literature provides some possible explanations. With appropriate data, a better understanding of this clustering phenomenon may lead to important information about the factors and their interactions that control Antrim Shale gas production, which may, in turn, help establish a more general protocol for better estimating resources in this and other shale gas plays.     

Probabilistic methodology for estimation of undiscovered petroleum resources in play analysis of the United States

A geostochastic system called FASPF was developed by the U.S. Geological Survey for their 1989 assessment of undiscovered petroleum resources in the United States. FASPF is a fast appraisal system for petroleum play analysis using a field-size geological model and an analytic probabilistic methodology. The geological model is a particular type of probability model whereby the volumes of oil and gas accumulations are modeled as statistical distributions in the form of probability histograms, and the risk structure is bilevel (play and accumulation) in terms of conditional probability. The probabilistic methodology is an analytic method derived from probability theory rather than Monte Carlo simulation. The resource estimates of crude oil and natural gas are calculated and expressed in terms of probability distributions. The probabilistic methodology developed by the author is explained.The analytic system resulted in a probabilistic methodology for play analysis, subplay analysis, economic analysis, and aggregation analysis. Subplay analysis included the estimation of petroleum resources on non-Federal offshore areas. Economic analysis involved the truncation of the field size with a minimum economic cutoff value. Aggregation analysis was needed to aggregate individual play and subplay estimates of oil and gas, respectively, at the provincial, regional, and national levels.     

A petroleum discovery-rate forecast revisited—The problem of field growth

A forecast of the future rates of discovery of crude oil and natural gas for the 123,027-km² Miocene/Pliocene trend in the Gulf of Mexico was made in 1980. This forecast was evaluated in 1988 by comparing two sets of data: (1) the actual versus the forecasted number of fields discovered, and (2) the actual versus the forecasted volumes of crude oil and natural gas discovered with the drilling of 1,820 wildcat wells along the trend between January 1, 1977, and December 31, 1985. The forecast specified that this level of drilling would result in the discovery of 217 fields containing 1.78 billion barrels of oil equivalent; however, 238 fields containing 3.57 billion barrels of oil equivalent were actually discovered. This underestimation is attributed to biases introduced by field growth and, to a lesser degree, the artificially low, pre-1970's price of natural gas that prevented many smaller gas fields from being brought into production at the time of their discovery; most of these fields contained less than 50 billion cubic feet of producible natural gas.     

Guiding Principles of USGS Methodology for Assessment of Undiscovered Conventional Oil and Gas Resources

During the last 30 years, the methodology for assessment of undiscovered conventional oil and gas resources used by the Geological Survey has undergone considerable change. This evolution has been based on five major principles. First, the U.S. Geological Survey has responsibility for a wide range of U.S. and world assessments and requires a robust methodology suitable for immaturely explored as well as maturely explored areas. Second, the assessments should be based on as comprehensive a set of geological and exploration history data as possible. Third, the perils of methods that solely use statistical methods without geological analysis are recognized. Fourth, the methodology and course of the assessment should be documented as transparently as possible, within the limits imposed by the inevitable use of subjective judgement. Fifth, the multiple uses of the assessments require a continuing effort to provide the documentation in such ways as to increase utility to the many types of users. Undiscovered conventional oil and gas resources are those recoverable volumes in undiscovered, discrete, conventional structural or stratigraphic traps. The USGS 2000 methodology for these resources is based on a framework of assessing numbers and sizes of undiscovered oil and gas accumulations and the associated risks. The input is standardized on a form termed the Seventh Approximation Data Form for Conventional Assessment Units. Volumes of resource are then calculated using a Monte Carlo program named Emc2, but an alternative analytic (non-Monte Carlo) program named ASSESS also can be used. The resource assessment methodology continues to change. Accumulation-size distributions are being examined to determine how sensitive the results are to size-distribution assumptions. The resource assessment output is changing to provide better applicability for economic analysis. The separate methodology for assessing continuous (unconventional) resources also has been evolving. Further studies of the relationship between geologic models of conventional and continuous resources will likely impact the respective resource assessment methodologies.     

The space-time structure of oil and gas field growth in a complex depositional system

Shortly after the discovery of an oil and gas field, an initial estimate is usually made of the ultimate recovery of the field. With the passage of time, this initial estimate is almost always revised upward. The phenomenon of the growth of the expected ultimate recovery of a field, which is known as field growth, is important to resource assessment analysts for several reasons. First, field growth is the source of a large part of future additions to the inventory of proved reserves of crude oil and natural gas in most petroliferous areas of the world. Second, field growth introduces a large negative bias in the forecast of the future rates of discovery of oil and gas fields made by discovery process models. In this study, the growth in estimated ultimate recovery of oil and gas in fields made up of sandstone reservoirs formed in a complex depositional environment (Frio strand plain exploration play) is examined. The results presented here show how the growth of oil and gas fields is tied directly to the architectural element of the shoreline processes and tectonics that caused the deposition of the individual sand bodies hosting the producible hydrocarbon.     

Development of an Improved Methodology to Assess Potential Unconventional Gas Resources

Considering the important role played today by unconventional gas resources in North America and their enormous potential for the future around the world, it is vital to both policy makers and industry that the volumes of these resources and the impact of technology on these resources be assessed. To provide for optimal decision making regarding energy policy, research funding, and resource development, it is necessary to reliably quantify the uncertainty in these resource assessments. Since the 1970s, studies to assess potential unconventional gas resources have been conducted by various private and governmental agencies, the most rigorous of which was by the United States Geological Survey (USGS). The USGS employed a cell-based, probabilistic methodology which used analytical equations to calculate distributions of the resources assessed. USGS assessments have generally produced distributions for potential unconventional gas resources that, in our judgment, are unrealistically narrow for what are essentially undiscovered, untested resources. In this article, we present an improved methodology to assess potential unconventional gas resources. Our methodology is a stochastic approach that includes Monte Carlo simulation and correlation between input variables. Application of the improved methodology to the Uinta–Piceance province of Utah and Colorado with USGS data validates the means and standard deviations of resource distributions produced by the USGS methodology, but reveals that these distributions are not right skewed, as expected for a natural resource. Our investigation indicates that the unrealistic shape and width of the gas resource distributions are caused by the use of narrow triangular input parameter distributions. The stochastic methodology proposed here is more versatile and robust than the USGS analytic methodology. Adoption of the methodology, along with a careful examination and revision of input distributions, should allow a more realistic assessment of the uncertainty surrounding potential unconventional gas resources.     

Oil- and gas-resource assessment in certain South American Basins—An application of ARDS (Ver. 5.0) to complex exploration and discovery histories

The modified Arps-Roberts Discovery Process Modeling System [ARDS (Ver. 4.01)] has recently been upgraded [ARDS (Ver. 5.0)] and applied to a wide variety of field discovery and wildcat drilling data with differing characteristics. ARDS is designed to forecast the number and sizes of undiscovered fields in an exploration play or basin by using historical drilling and discovery data. Fields used as input may be grown or ungrown. Two models for field growth—one offshore and the other onshore—have been implemented (Schuenemeyer and Drew, 1996). Uncertainty attributable to field growth is estimated via simulation. This upgrade of ARDS has been designed to handle situations when the data cannot be partitioned into homogeneous regions, but where estimation of the number of remaining oil and gas fields is still meaningful. In this upgrade of ARDS, many restrictions, which include those on the number of fields and wildcat wells required to forecast the size distribution of the oil and gas fields that remain to be discovered in an exploration play, a basin, or other target area, have been removed. In addition, flexibility has been gained by reforming the criteria for convergence of the model. In all, 32 basins and subbasins in South America were examined, 18 of which had sufficient data to be amenable to forecasting the field-size distribution of undiscovered oil and gas resources directly by using the Petroconsultants Inc. (1993) field discovery and wildcat drilling data. Overall, ARDS (Ver. 5.0) performed well in estimating the field-size distribution of undiscovered oil and gas resources in the 18 basins and subbasins. The aggregate volume of undiscovered petroleum resources was characterized by using histograms of the distribution of resources and the following five statistics: the mean, the 80% trimmed mean, and the 10,50 (median), and 90 quantiles. More than 38 billion barrels of oil equivalent (BOE) in fields that contain more than one million BOE individually were forecast as remaining to be discovered. The largest basin, the Campos (Brazil), is forecast to contain nearly 10 billion BOE undiscovered resources. The East Venezuela Basin (excluding the Furrial Trend) is forecast to contain about 8 billion BOE; the Austral-Magallanes Basin (Argentina and Chile), about 7 billion BOE; and the Napo (Colombia and Ecuador) and the Neuquen (Argentina) Basins, between 3 billion and 4 billion BOE. A subset of these basins that illustrate the increased flexibility of ARDS are discussed.     

Shale-Gas Assessment: Comparison of Gas-In-Place Versus Performance-Based Approaches

The recent interest in exploration for shale gas increases the demand for a reliable, compatible resource assessment. Many different assessment methods are used, commonly depending on types and quantity of data available, which may lead to significantly divergent results for the same shale-gas play. This study compares results obtained using performance-based and gas-in-place methodologies to assess a well-developed and active shale-gas play (Woodford Shale, Arkoma Basin, USA) and two untested, hypothetical shale-gas plays (Shublik and Brookian, Alaska North Slope, USA). Results show that the two assessment methods produce comparable results when assessment units are identically defined and similar geological constraints are used as input parameters. Inherent uncertainties are associated with both assessment methods, and these are related to aspects of shale-gas production that are not well understood. The performance-based method relies on decline trend analysis to generate distributions of estimated ultimate recovery (EUR), and uncertainty increases in cases of short production history. The gas-in-place method requires the application of a recovery factor to estimate technically recoverable resources, and both absolute values of recovery factors and their spatial variability are poorly documented, and therefore a source of uncertainty.     

Study on Phase Behavior of CO2/Hydrocarbons in Shale Reservoirs Considering Sieving Effect and Capillary Pressure

The phase behavior of fluid is essential for predicting ultimate oil recovery and determining optimal production parameters. The pore size in shale porous media is nanopore, which causes different phase behaviors of fluid in unconventional reservoirs. Nanopores in shale media can be regard as semipermeable membrane to filter heavy components (sieving effect) in shale oil, which leads to the different distributions of fluid components and different phase behaviors. In addition, the phase behavior of fluid in nanopores can be significantly altered by large capillary pressure. In this paper, the phase behavior of fluid in shale reservoirs is investigated by a new two-phase flash algorithm considering sieving effect and capillary pressure. Firstly, membrane efficiency and capillary pressure are introduced to establish a thermodynamic equilibrium model that is solved by Rachford–Rice flash calculation and Newton–Raphson method. The capillary pressures in different pore sizes are calculated by the Young–Laplace equation. Then, the influences of sieving effect and capillary pressure on phase behavior are analyzed. The results indicate that capillary pressure can suppress the bubble point pressure of fluid in nanopores. The distributions of fluid components are different in various parts of shale media. In the unfiltered part, density and viscosity of fluid are higher. Finally, it is found that the membrane efficiency can be improved by CO₂ injection. The minimum miscibility pressure for shale oil–CO₂ system is also studied. The developed model provides a better understanding of the phase behavior of fluid in shale oil reservoirs.

     

Conventional and Unconventional Hydrocarbon Resource Potential Evaluation of Source Rocks and Reservoirs: A Case Study of the Upper Xiaganchaigou Formation,Western Qaidam Basin,Northwest China

The Paleogene upper Xiaganchaigou Formation (E₃²) is the most important source rock and reservoir in the Qaidam Basin. However, there are few studies on the processes of hydrocarbon accumulation in this formation; therefore, its hydrocarbon resource potential has not been estimated reasonably. This paper evaluates the hydrocarbon generation properties in light of an improved hydrocarbon generation and expulsion potential model. According to the geochemical characteristics of source rocks and the petrological features of reservoirs, the potentials of different resource types, including conventional oil, tight oil and shale oil, are quantified by combining the buoyancy-driven hydrocarbon accumulation depth (BHAD) and the lower limit for movable resource abundance. The results show that the source rocks are characterized by a large thickness (more than 1000 m), moderate organic matter content, high marginal maturity and a high conversion rate (50% hydrocarbons have been discharged before R_o?=?1%), which provide sufficient oil sources for reservoir formation. Moreover, the reservoirs in the Qaidam Basin consist mainly of low-porosity and low-permeability tight carbonates (porosity of 4.7% and permeability less than 1 mD). The maximum hydrocarbon generation, expulsion, retention and movable retention intensities at present are 350?×?10⁴ t/km², 250?×?10⁴ t/km², 130?×?10⁴ t/km² and 125?×?10⁴ t/km², respectively. The thresholds of hydrocarbon generation, expulsion and BHAD were 0.46% R_o, 0.67% R_o and 0.7% R_o, respectively. Moreover, the dynamic evolution process of hydrocarbon accumulation was divided into three evolution stages, namely, (a) initial hydrocarbon accumulation, (b) conventional hydrocarbon reservoir and shale oil accumulation and (c) unconventional tight oil accumulation. The conventional oil, tight oil and movable shale oil resource potentials were 10.44?×?10⁸ t, 51.9?×?10⁸ t and 390?×?10⁸ t, respectively. This study demonstrates the good resource prospects of E₃² in the Qaidam Basin. A comprehensive workflow for unconventional petroleum resource potential evaluation is provided, and it has certain reference significance for other petroliferous basins, especially those in the early unconventional hydrocarbon exploration stage.

     

The Evolution of Giant Oil Field Production Behavior

The giant oil fields of the world are only a small fraction of the total number of fields, but their importance is huge. Over 50% of the world’s oil production came from giants by 2005 and more than half of the world’s ultimate reserves are found in giants. Based on this, it is reasonable to assume that the future development of the giant oil fields will have a significant impact on the world oil supply. In order to better understand the giant fields and their future behavior, one must first understand their history. This study has used a comprehensive database on giant oil fields in order to determine their typical parameters, such as the average decline rate and life-times of giants. The evolution of giant oil field behavior has been investigated to better understand future behavior. One conclusion is that new technology and production methods have generally led to high depletion rates and rapid decline. The historical trend points towards high decline rates of fields currently on plateau production. The peak production generally occurs before half the ultimate reserves have been produced in giant oil fields. A strong correlation between depletion-at-peak and average decline rate is also found, verifying that high depletion rate leads to rapid decline. Our result also implies that depletion analysis can be used to rule out unrealistic production expectations from a known reserve, or to connect an estimated production level to a needed reserve base.     

Oil resources for the next century: What's ahead?

Proven reserves of liquid hydrocarbons are now assessed at between 950 and 1,000 billion barrels, depending on the source. Their life expectancy at the current rate of world production is about 41 to 45 years. This lifetime is much longer than what was predicted in both 1970 and 1980. However, this wealth of resources does not necessarily mean that the security of oil supplies is guaranteed for all countries. Oil reserves are unequally distributed from a geopolitical standpoint. Reserves and output are mainly due to big fields (with more than 500 million barrels of initial reserves).Though oil supplies seem to be ensured for the coming 30 to 40 years, what does the picture look like beyond 2020–20307 The increased lifetime of proven oil reserves has been apparent only in the last 10 to 20 years. The considerable increase in proven oil reserves reported after 1986 is, in fact, mainly due to revisions and extensions, rather than to new sources of oil: conventional oil (with the price per barrel of oil on the order of $20 and recovery rate around 30 percent) remaining to be discovered today; oil resources stemming from an improvement in recovery rate; oil resources resulting from exploitation of new zones, such as deep sea zones; and unconventional types of oil, such as extra-heavy crudes, tar sands, shale oils, and liquid hydrocarbons from chemical-enhanced oil recovery methods.     

An assessment of oil supply and its implications for future prices

This paper examines three issues related to both the U.S. and world oil supply: (1) the nature of the long-term, postpeak production profile for the U.S. and, by inference, other regions (the Hubbert curve is used as a “strawman” model); (2) implications on U.S. energy security of using a modified Hubbert-type conceptual model of prepeak production, testing the adequacy of Latin America to be the primary source of U.S. oil imports; and (3) the cyclic behavior of oil prices. it shows that U.S. production will exhibit a more attenuated decline than that simulated by the Hubbert curve and not decline to zero. it asserts that U.S. production is better predicted by past reserves than past production, but that this argument does not apply to nations that keep a much larger proportion of reserves in the ground. Such nations could considerably expand production without any growth in reserves. The paper concedes that the potential total production for these nations could be examined with a Hubbert curve model linked to reserves, but with great uncertainty. Such an uncertain optimistic forecast predicts that the cumulative production of Latin America could far exceed that of the United States. Nevertheless, a statistical model of oil prices since 1870 implies that real wellhead oil prices in the United States are on a long-term upward path, underlying a much more “noisy” cyclical pattern estimated to include 22- and 27-year cycles. The statistical model predicts a severe oil shock within a few years (of 1998) but also predicts that through 2030, real oil prices will not reach 1981 levels again. The paper examines U.S. and world trends in seismic exploration, drilling locations and depths, drilling costs, oil/gas reserves, oil/gas use rates, and oil demand. After taking these factors into consideration, it concludes that the statistical model of oil prices cannot be disputed, despite its lack of basis in economic theory.