Distinction Between Oil Expulsion History and Gas Expulsion History

The process of organic matter transformation into oil and gas is also a balance process of hydrocarbon transformation. This article probes to distinguish the oil expulsion history from gas expulsion history based on the hydrocarbon generation, hydrocarbon residual, and hydrocarbon expulsion processes of the source rocks. In this method, the first step is to study the hydrocarbon expulsion rate by means of hydrocarbon generation potential method; the second step is to study the oil generation rate by means of the heating–pressuring experiment method; the third step is to study the oil residual rate by means of the mathematical method. The difference between the values of oil generation rate and oil residual rate is defined as the oil expulsion rate, while that between the values of hydrocarbon expulsion rate and the gas expulsion rate is defined as the gas expulsion rate. Then, combined with the geological parameters of source rocks, the oil and gas expulsion history can be obtained. This study on Es₁ Source rocks, Nanpu Sag, Bohai Bay Basin, China shows that the primary expulsion period of Es₁ source rocks is Guantao–Minghuazhen period.     

Conditional simulation as a tool for measuring uncertainties in petroleum exploration

A fundamental task for petroleum exploration decision-making is to evaluate the uncertainty of well outcomes. The recent development of geostatistical simulation techniques provides an effective means to the generation of a full uncertainty model for any random variable. Sequential indicator simulation has been used as a tool to generate alternate, equal-probable stochastic models, from which various representations of uncertainties can be created. These results can be used as input for the quantification of various risks associated with a wildcat drilling program or the estimation of petroleum resources. A simple case study is given to demonstrate the use of sequential indicator simulation. The data involves a set of wildcat wells in a gas play. The multiple simulated stochastic models are then post-processed to characterize various uncertainties associated with drilling outcomes.     

A New Reserve Growth Model for United States Oil and Gas Fields

Reserve (or field) growth, which is an appreciation of total ultimate reserves through time, is a well-recognized phenomenon, particularly in mature petroleum provinces. The importance of forecasting reserve growth accurately in a mature petroleum province made it necessary to develop improved growth functions, and a critical review of the original Arrington method was undertaken. During a five-year (1992–1996), the original Arrington method gave 1.03% higher than the actual oil reserve growth, whereas the proposed modified method gave a value within 0.3% of the actual growth, and therefore it was accepted for the development for reserve growth models.During a five-year (1992–1996), the USGS 1995 National Assessment gave 39.3% higher oil and 33.6% lower gas than the actual growths, whereas the new model based on Modified Arrington method gave 11.9% higher oil and 29.8% lower gas than the actual growths. The new models forecast predict reserve growths of 4.2 billion barrels of oil (2.7%) and 30.2 trillion cubic feet of gas (5.4%) for the conterminous U.S. for the next five years (1997–2001).     

Comparison of Methods Used to Estimate Conventional Undiscovered Petroleum Resources: World Examples

Various methods for assessing undiscovered oil, natural gas, and natural gas liquid resources were compared in support of the USGS World Petroleum Assessment 2000. Discovery process, linear fractal, parabolic fractal, engineering estimates, PETRIMES, Delphi, and the USGS 2000 methods were compared. Three comparisons of these methods were made in: (1) the Neuquen Basin province, Argentina (different assessors, same input data); (2) provinces in North Africa, Oman, and Yemen (same assessors, different methods); and (3) the Arabian Peninsula, Arabian (Persian) Gulf, and North Sea (different assessors, different methods). A fourth comparison (same assessors, same assessment methods but different geologic models), between results from structural and stratigraphic assessment units in the North Sea used only the USGS 2000 method, and hence compared the type of assessment unit rather than the method. In comparing methods, differences arise from inherent differences in assumptions regarding: (1) the underlying distribution of the parent field population (all fields, discovered and undiscovered), (2) the population of fields being estimated; that is, the entire parent distribution or the undiscovered resource distribution, (3) inclusion or exclusion of large outlier fields; (4) inclusion or exclusion of field (reserve) growth, (5) deterministic or probabilistic models, (6) data requirements, and (7) scale and time frame of the assessment. Discovery process, Delphi subjective consensus, and the USGS 2000 method yield comparable results because similar procedures are employed. In mature areas such as the Neuquen Basin province in Argentina, the linear and parabolic fractal and engineering methods were conservative compared to the other five methods and relative to new reserve additions there since 1995. The PETRIMES method gave the most optimistic estimates in the Neuquen Basin. In less mature areas, the linear fractal method yielded larger estimates relative to other methods. A geologically based model, such as one using the total petroleum system approach, is preferred in that it combines the elements of petroleum source, reservoir, trap and seal with the tectono-stratigraphic history of basin evolution with petroleum resource potential. Care must be taken to demonstrate that homogeneous populations in terms of geology, geologic risk, exploration, and discovery processes are used in the assessment process. The USGS 2000 method (7th Approximation Model, EMC computational program) is robust; that is, it can be used in both mature and immature areas, and provides comparable results when using different geologic models (e.g. stratigraphic or structural) with differing amounts of subdivisions, assessment units, within the total petroleum system.     

Applicability of Kinetic Models for In Situ Combustion Processes with Different Oil Types

The in situ combustion (ISC) process is of interest as an enhanced oil recovery method because it is an alternative to traditional steam-based processes for heavy oil and bitumen recovery. ISC is a technique applicable outside the window of reservoir conditions deemed appropriate for steam injection (such as deeper and thinner reservoirs). The process involves complex chemical reactions and physical recovery mechanisms, and predicting the likelihood of successful ISC in field applications remains challenging. This paper describes a numerical investigation of the capability of different ISC kinetic models to predict the combustion behaviors of different types of oils (light oil, heavy oil, and bitumen). Three kinetic models (of Coats, Crookston, and Belgrave) were selected from literature and compared using data from four published combustion-tube experiments. The comparison procedure is as follows: (1) validate the numerical modeling of each kinetic model by matching the selected experimental results or duplicating the numerical results found in published literature; (2) adjust fluid viscosities and densities to match the fluid properties of each experiment;and (3) use each validated kinetic model to predict the performance of the other experiments without further tuning the kinetic parameters. The knowledge derived from the experiments provides guidance for choosing the appropriate kinetic model when no other data are available and for the preliminary design and screening study of a potential ISC project.     

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.     

The Astrakhan Arch of the Pricaspian basin: Geothermal analysis and modelling

The Astrakhan Arch (ASAR) region contains one of the largest sub‐salt carbonate structures of the Pricaspian salt basin (located to the northwest of the Caspian Sea), where prospects for hydrocarbon generation and accumulation in the Devonian to Carboniferous deposits are considered to be high. We evaluate the regional vertical temperature gradient within stratigraphic units based on the analysis of 34 boreholes drilled in the region. To show that the thermal gradient is altered in the vicinity of salt diapirs, we study measured temperatures in six deep boreholes. We develop a three‐dimensional geothermal model of the ASAR region constrained by temperature measurements, seismic stratigraphic and lithological data. The temperatures of the sub‐salt sediments predicted by the geothermal model range from about 100 °C to 200 °C and are consistent with the temperatures obtained from the analysis of vitrinite reflectivity and from previous two‐dimensional geothermal models. Temperature anomalies are positive in the uppermost portions of salt diapirs as well as within the salt‐withdrawal basins at the depth of 3.5 km depth and are negative beneath the diapirs. Two areas of positive temperature anomalies in the sub‐salt sediments are likely to be associated with the deep withdrawal basins above and with the general uplift of salt/sub‐salt interface in the southern part of the study region. This implies an enhancement of thermal maturity of any organically rich source rocks within these areas. The surface heat flux in the model varies laterally from about 40 to 55 mW m^?2. These variations in the heat flux are likely to be associated with structural heterogeneities of the sedimentary rocks and with the presence of salt diapirs. The results of our modelling support the hypothesis of oil and gas condensate generation in the Upper Carboniferous to Middle Devonian sediments of the ASAR region.     

Correlation between assessments of undiscovered oil and gas resources

There is an inbuilt correlation between estimated quantities of oil and gas produced by probabilistic assessments of undiscovered oil and gas resources. Correlation between assessed quantities of oil and gas occurs at every level, whether prospects, plays, basins, continents, or the world. Providing that the oil and gas are assessed in the same run of the computer program, the correlation can be calculated using the paired values of the undiscovered oil and gas volumes calculated in each of the Monte Carlo simulations. It can be seen in the shape and density of a point plot of these paired values. Alternatively, the correlation can be calculated theoretically using an equation written in terms of the data input to the assessment program. These commonly include distributions for the number of accumulations (N), the success rate (s), the accumulation sizes (V), an oil to gas conversion factor, and a proportion of oil to oil plus gas (P _OOG). The cause of the correlation is investigated and explained using point plots and equations for a variety of input distributions. The shape and density of each plot are determined by the pattern of the numbers of oil and gas accumulations, the sizes of the accumulations, and the proportions of oil to oil plus gas. The correlation is caused by the dispersion or spread of the input distributions. It may be positive or negative, tending toward positive as the dispersions ofN, s, andV increase and the dispersion ofP _OOG decreases. The correlation indicates that there is a relationship between the undiscovered oil and gas resources that may be described by fitting a linear regression to a plot of the paired values of the total oil and gas resources. The relationship should be quoted as part of the assessment and might be used to make a better estimate of the value of the undiscovered resources.     

边界时刻一致性判别方法在北京市出租车运量生成机制中的实证应用

以北京市出租车运量生成机制研究为例,探索时间基本单元大小对交通时段划分及运量生成机制的影响。基于北京市出租车轨迹数据,按10 min步长,采用10 min至60 min共6种时间基本单元对全天数据在交通小区尺度进行划分得到切片数据,应用系统聚类法将切片聚合得到时段划分,得到6种时段划分结果,进而对具有交集的时段采用边界时刻进行一致性判别。在时段划分基础上,应用地理加权回归模型比较分析了不同时间基本单元在上班时段的出租车运量影响因子的差异。结果显示,时间基本单元小于40 min时,上班时段的起始时刻不具有一致性;如果考虑所有时段的起始和结束时刻,则小于50 min时不具有一致性。上班时段的运量生成机制模型结果与时刻一致性判别类似,当时间基本单元在50 min及以上时,回归得到的解释变量具有一致性,小于50 min后则会有所变化。这些结果说明,基本时间单元的大小会影响交通运量时段划分和生成机制研究的结果;考虑到结果一致性和整点划分习惯,推荐采用60 min为基本划分单元。提出的边界时刻一致性判别方法也可以用到其它交通模式和其他相似的大数据研究。     

Deep Natural Gas Resources

From a geological perspective, deep natural gas resources generally are defined as occurring in reservoirs below 15,000 feet, whereas ultradeep gas occurs below 25,000 feet. From an operational point of view, deep may be thought of in a relative sense based on the geologic and engineering knowledge of gas (and oil) resources in a particular area. Deep gas occurs in either conventionally trapped or unconventional (continuous-type) basin-center accumulations that are essentially large single fields having spatial dimensions often exceeding those of conventional fields.Exploration for deep conventional and continuous-type basin-center natural gas resources deserves special attention because these resources are widespread and occur in diverse geologic environments. In 1995, the U.S. Geological Survey estimated that 939 TCF of technically recoverable natural gas remained to be discovered or was part of reserve appreciation from known fields in the onshore areas and state waters of the United States. Of this USGS resource, nearly 114 trillion cubic feet (Tcf) of technically recoverable gas remains to be discovered from deep sedimentary basins. Worldwide estimates of deep gas also are high. The U.S. Geological Survey World Petroleum Assessment 2000 Project recently estimated a world undiscovered conventional gas resource outside the U.S. of 844 Tcf below 4.5 km (about 15,000 feet).Less is known about the origins of deep gas than about the origins of gas at shallower depths because fewer wells have been drilled into the deeper portions of many basins. Some of the many factors contributing to the origin and accumulation of deep gas include the initial concentration of organic matter, the thermal stability of methane, the role of minerals, water, and nonhydrocarbon gases in natural gas generation, porosity loss with increasing depth and thermal maturity, the kinetics of deep gas generation, thermal cracking of oil to gas, and source rock potential based on thermal maturity and kerogen type. Recent experimental simulations using laboratory pyrolysis methods have provided much information on the origins of deep gas.Technologic problems are among the greatest challenges to deep drilling. Problems associated with overcoming hostile drilling environments (e.g. high temperatures and pressures, and acid gases such as CO₂ and H₂S) for successful well completion, present the greatest obstacles to drilling, evaluating, and developing deep gas fields. Even though the overall success ratio for deep wells (producing below 15,000 feet) is about 25%, a lack of geological and geophysical information continues to be a major barrier to deep gas exploration.Results of recent finding-cost studies by depth interval for the onshore U.S. indicate that, on average, deep wells cost nearly 10 times more to drill than shallow wells, but well costs and gas recoveries differ widely among different gas plays in different basins.Based on an analysis of natural gas assessments, deep gas holds significant promise for future exploration and development. Both basin-center and conventional gas plays could contain significant deep undiscovered technically recoverable gas resources.     

Information gain in prospect assessment by using basin modeling

To enhance the quality of oil- and gas-resource assessments and to reduce the risks in oil and gas exploration, a number of assessment techniques have been developed. Unfortunately, these techniques have not always been effective in the timely transfer of information. The amount of time that is required for preparing assessments does not always allow for the necessary high-quality data to be generated. To overcome this problem, a method based on an analysis of the phase state of oil and the dynamics of fluids in secondary migration of hydrocarbons is proposed. The phase state of the oil and fluid potential for secondary migration is estimated initially for each prospect together with the extent of the drainage area. On the basis of these estimates, statistical calculations can be made for the generation and expulsion of hydrocarbons. As a result, more reliable data are available for prospect assessment. The application of this method has a practical significance in that it brings the role of basin modeling in prospect assessment into full play, increases the reliability of petroleum-resource assessments, and reduces the risks in exploration. A case study from the Beitang region in eastern China is presented.     

Utility Efficient Frontier: An Application in the Oil and Gas Industry

Current practice shows that the use of portfolio and utility theory is very low among petroleum companies. This article advocates the use of both portfolio theory and utility theory as decision-making tools to improve performance of oil and gas companies. We introduce a model that can be practically used and applied in the oil and gas industry. This model generates an optimized, efficient portfolio and, at the same time, enables the decision maker to incorporate his risk attitude and policy. This can only be done by combining both the portfolio theory and utility theory through an approach called the utility mean-variance model. A typical oil portfolio optimization problem is investigated by applying both portfolio and utility theories. Through the utility mean-variance model, an efficient frontier that captures decision maker risk attitude is achieved.     

A Bootstrap Approach to Computing Uncertainty in Inferred Oil and Gas Reserve Estimates

This study develops confidence intervals for estimates of inferred oil and gas reserves based on bootstrap procedures. Inferred reserves are expected additions to proved reserves in previously discovered conventional oil and gas fields. Estimates of inferred reserves accounted for 65% of the total oil and 34% of the total gas assessed in the U.S. Geological Survey's 1995 National Assessment of oil and gas in US onshore and State offshore areas. When the same computational methods used in the 1995 Assessment are applied to more recent data, the 80-year (from 1997 through 2076) inferred reserve estimates for pre-1997 discoveries located in the lower 48 onshore and state offshore areas amounted to a total of 39.7 billion barrels of oil (BBO) and 293 trillion cubic feet (TCF) of gas. The 90% confidence interval about the oil estimate derived from the bootstrap approach is 22.4 BBO to 69.5 BBO. The comparable 90% confidence interval for the inferred gas reserve estimate is 217 TCF to 413 TCF. The 90% confidence interval describes the uncertainty that should be attached to the estimates. It also provides a basis for developing scenarios to explore the implications for energy policy analysis.     

Improved Minimum Miscibility Pressure Prediction for Gas Injection Process in Petroleum Reservoir

Determination of gas–oil minimum miscibility conditions is one of the important design parameters to improve the displacement efficiency of the hydrocarbon reservoir during enhanced oil recovery with gas injection. In this work, a support vector regression (SVR) model is developed using experimental data to estimate the minimum miscibility pressure (MMP) for various reservoir fluids and injection gases. Experimental MMP data taken from the reliable literature were used as input. Each data point input includes methane and intermediate components mole percent, plus fraction properties and reservoir temperature related to reservoir fluid and CO₂, H₂S, N₂ and intermediate mole fractions, and intermediate properties of the injected gas. Experimental MMP is regarded as the model output. The database contains 135 datasets, from which 125 datasets were used for model development, and the rest were used for model evaluation. Genetic algorithm was implemented to optimize the SVR model parameters. The proposed data-driven model was verified by statistical validation data. The model results illustrate a correlation coefficient (R²) of 0.999. In addition, the SVR results demonstrate the proposed model to be a fast tool and a robust approach to map input space to output features. The SVR model was compared to popular data-driven MMP estimation models as well. This comparison presents an acceptable accuracy relative to this estimation model. Finally, the presented model was evaluated against a comprehensive theoretical model of slim tube compositional simulation on a trusted literature dataset.     

Oil and gas resource assessment: The linkage between geological analysis and discovery process model results

Two widely-used techniques to estimate the volume of remaining oil and gas resources are discovery process modeling and geologic assessment. Both were used in a recent national assessment of oil and gas resources of the United States. Parallel estimates were obtained for 27 provinces. Geological-based estimates can typically see into areas not available to discovery process models (that is areas with little or no exploration history) and thus, on average, yield higher estimates. However, a linear relation does exist between the mean estimates obtained from these two methods. In addition, other variables were found in a multiple regression model that explained much of the difference. Thus, it is possible to perform discovery process modeling and adjust the estimates to yield results that might be expected from geological-based assessments.     

Uncertainty analysis and the relative contributions of geological factors for the Qingshankou source rocks in the North Songliao Basin, northeastern China

Source rock evaluation is a critical factor in resource assessment of oil and gas. Models for evaluating source rocks are dependent on established geomathematical principles, the calculation of source-rock parameters, and geological data. The sensitivities and uncertainties associated with these models are a matter of concern. In this paper, the effects and relative contributions of 13 major geological factors, as well as their variations and distribution probabilities, have been analyzed for the source rocks in the North Songliao Basin in northeastern China. The geological factors include the time of formation of the regional caprock, composition of the regional caprock, the phases of hydrocarbons in migration, and those factors associated with the generation, retention, and expulsion of hydrocarbons and their effects on source-rock efficiency. Of the 13 factors analyzed, the most important are the source-rock depth, sedimentation rate, total organic content, and kerogen-type index; the relative contributions to the uncertainty of efficient gas/oil migration amounts for the most important factors are 37, 25, 19, and 1% for oil and 32, 17, 20, and 15% for gas, respectively. These most reflect the changes that have occurred in the Qingshankou source rocks.     

On the Use of the Beta Distribution in Probabilistic Resource Assessments

The triangular distribution is a popular choice when it comes to modeling bounded continuous random variables. Its wide acceptance derives mostly from its simple analytic properties and the ease with which modelers can specify its three parameters through the extremes and the mode. On the negative side, hardly any real process follows a triangular distribution, which from the outset puts at a disadvantage any model employing triangular distributions. At a time when numerical techniques such as the Monte Carlo method are displacing analytic approaches in stochastic resource assessments, easy specification remains the most attractive characteristic of the triangular distribution. The beta distribution is another continuous distribution defined within a finite interval offering wider flexibility in style of variation, thus allowing consideration of models in which the random variables closely follow the observed or expected styles of variation. Despite its more complex definition, generation of values following a beta distribution is as straightforward as generating values following a triangular distribution, leaving the selection of parameters as the main impediment to practically considering beta distributions. This contribution intends to promote the acceptance of the beta distribution by explaining its properties and offering several suggestions to facilitate the specification of its two shape parameters. In general, given the same distributional parameters, use of the beta distributions in stochastic modeling may yield significantly different results, yet better estimates, than the triangular distribution.     

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.     

Burial,Maturation, and Petroleum Generation History of the Arkoma Basin and Ouachita Foldbelt,Oklahoma and Arkansas

Removed overburden, burial, maturation, and petroleum generation analysis indicates that maturity in the Arkoma Basin and the Ouachita Foldbelt is explained effectively using simple burial models that account for the significant surface erosion that has occurred and assuming geothermal gradients similar to present-day gradients have been approximately constant through geologic time. Regional models, based on analysis at 115 well locations, indicate that from 5,000 to 15,000 ft (1.5–4.5 km) of section, differing with location from north to south and west to east, has been removed from the Arkoma Basin region, and as much as 25,000–40,000 ft (7.5–12 km) have been removed from areas of the Ouachita Foldbelt. Based on burial and thermal history reconstruction, increasing maturation from west to east across the basin is primarily the result of increasing overburden and subsequent surface erosion from west to east. The models predict most publicly available vitrinite reflectance data within a factor of 1.5 at two standard deviations. Comparison of model and measured reflectance-depth trends in six wells indicates that hydrothermal fluid movement should not have modified reflectance by more than approximately 20% in the center of the basin. Analysis indicates that most of the basin is overmature for oil production from intervals below the Spiro Sandstone, except to the north and northwest. Although thermal maturities are high, methane is stable throughout the basin. Except for the basal Arbuckle Group, all formations were thermally immature for oil generation prior to burial by the Mississippian and Morrowan in the Ouachita Foldbelt of Oklahoma and by the Atokan and Desmoinesian over most of the basin and study area. In the deeper part of the present basin, all strata entered and passed through the oil window during or within 10 My after Atokan time. Because no additional major quantities of hydrocarbons were generated after Atokan time, the hydrocarbons must have been emplaced and trapped during this brief time interval.