Petroleum Resource Assessment Research Articles

Hydrocarbon Generation and Residue Features of Ediacaran High-Maturity Source Rocks and Their Significance in Gas Exploration in Sichuan Basin

Evaluating residual hydrocarbons is crucial for assessing shale oil and gas reservoirs, significantly impacting resource evaluation and exploration prospects. Previously regarded as lacking hydrocarbon generation potential, the Ediacaran Dengying Formation (Fm) microbial dolomite in the Sichuan Basin has been re-evaluated for its hydrocarbon generation capabilities. While understanding source rock characteristics is vital for petroleum resource assessment, a comprehensive analysis of the dolomite’s source rocks, encompassing hydrocarbon generation and residual features, remains undocumented. In this study, we thoroughly analyze the total organic carbon and vitrinite reflectance and extensively utilize pyrolysis analysis, gas chromatography and isotopic analysis of the organic kerogen from the Ediacaran Dengying Fm dolomite samples. The findings affirm that the Ediacaran Dengying Fm dolomite indeed serves as a source rock with moderate hydrocarbon generation and residue capabilities. This microbial dolomite was formed in a reducing marine environment with high salinity. Characterized by an averaging TOC of 0.82%, the kerogen is primarily identified as type I, with a minor presence of type II, and underwent thermal maturation up to the post-maturity stage. Throughout its geological history, the maximum intensities for hydrocarbon generation and residues were 4.5 × 107 t/km2 and 3.2 × 107 t/km2, respectively. Additionally, cumulatively generated and residual hydrocarbon quantities amounted to 2.7 × 1012 t and 1.67 × 1012 t, respectively. This study indicates significant exploration potential for the Ediacaran Dengying Fm microbial dolomite. Consequently, the central region in the Sichuan Basin has been identified as a promising area for future exploration endeavors. Our study provides valuable insights for the understanding of shale gas exploration in high-maturity source rock areas.

Determination of in situ hydrocarbon contents in shale oil plays: Part 3: Quantification of light hydrocarbon evaporative loss in old cores based on preserved shales

Petroleum resource assessment obtained from laboratory tests on old core samples shelved in the open environment tend to underestimate in situ resources. Therefore, hydrocarbon loss and its restoration need to be investigated. The hydrocarbon loss was studied via the difference of programmed pyrolysis parameter (Rock–Eval derived S1) between preserved/fresh cores and their replicas that had been long-term exposed to ambient conditions. However, the in situ hydrocarbon potential is still seemed to be underestimated, because the effect of sample crushing and crucible waiting on pristine S1 detection did not receive enough attention. To solve this issue, 50 preserved shale core samples with Ro from 1.00% to 1.51% were collected from the K1qn1 Formation of northern Songliao Basin, Eastern China. All the samples were subjected to four parallel experiments: Dean–Stark extraction and nuclear magnetic resonance (NMR) T1–T2 mapping, using large rock pieces 3–5 cm in size, and thermal desorption gas chromatography (TD–GC) and Rock–Eval analysis, using 60-mesh powdered samples. In addition, a time series of TD–GC and Rock–Eval analyses were conducted on a preserved shale sample to investigate hydrocarbon loss during sample crushing, Rock–Eval crucible waiting process, and elapse-time exposure to the open environment. Rock–Eval pyrolysis was also conducted on one month-exposed shale cores and solvent-extracted samples. The results show that the total hydrocarbon content of large rock pieces is significantly greater than that of powdered samples. Sample crushing or grinding leads C8− light hydrocarbons to evaporate, and results in a loss of approximately 35% of S1. Rock–Eval crucible waiting process causes C14− hydrocarbons to evaporate, and results in an additional 25% loss of S1. To compensate for the sample crush induced S1 loss, an exponential distribution model was proposed based on the C8+ hydrocarbons in the TD–GC S1 fingerprints. Sample maturity, pristine light hydrocarbon (C14−) proportions, organic matter richness, and oil-bearing pore size primarily control the hydrocarbon loss of old shale samples. The higher the proportion of C14− and the lower the abundance of organic matter, the higher the amount of hydrocarbon loss. Finally, S1 restoration coefficient charts for large rock pieces and powdered samples with Ro ranging from 1.00% to 1.42% are provided. It highlights that previous studies have severely underestimated the in situ S1 when using the Rock–Eval method. This research has great implication for estimating in situ hydrocarbon potential using conventional coring samples.

Differential hydrocarbon generation and evolution of typical terrestrial gas-prone source rocks: An example from the Kuqa foreland basin, NW China

Terrestrial gas-prone source rocks are significant for hydrocarbon gas accumulations especially in central and western basins in China. The Kuqa foreland basin in the northern margin of the Tarim Basin, NW China is rich in natural gas with recent discoveries of several large to giant gas-producing fields (e.g., the Kela-2, Dibei, Dabei-1, and Zhongqiu-1 gas fields, etc.) and a proven 3 P gas reserve of over one trillion cubic meters (TCM). This proliferous petroleum province is powered by an effective and diverse gas-prone source rock series in the basin comprising mudstone, carbonaceous mudstone, and coal seams. To date, little systematic research work has been done on the petroleum generation potential of the source rocks. This has seriously restricted the assessment of petroleum resources and further exploration in the frontier areas of the basin. A sealed gold tube pyrolysis approach was employed to simulate the oil and gas generation and cracking yields for the aforementioned three types of source rock. Compared with typical Type I and II1 kerogens, the three types of source rocks in the Kuqa foreland basin are characterized by (1) far less hydrocarbon yield (150 mg/g TOC) with comparatively larger amounts of CO2 (310 mg/g TOC), (2) a limited capacity and narrower window (0.5%–1.08% Ro) for oil generation, and (3) a much earlier secondary cracking for bulk oil to light oil and gases (>0.86% Ro for mudstone and >1.08% Ro for both carbonaceous mudstone and coal). All the source rocks are gas-prone, and significant amount of gas can still be generated during an over-mature stage. The kinetic parameters obtained allow us to model hydrocarbon generation in the Kuqa foreland basin more realistically. It is concluded that (1) two episodes of hydrocarbon generation occurred with hydrocarbon gases being mainly generated during the later stage (12–3 Ma); and (2) the depocenter of the basin is capable of supplying massive high-mature gases as late as in the Quaternary, which is crucial for the formation of giant gas fields. The findings provide new insight on the reconstruction of oil and gas accumulation processes and further hydrocarbon exploration in the basin.

Fractionation of hydrocarbon generation induced by organic-mineral interactions in fine-grained sediments

Hydrocarbon (HC) generation is closely related to the properties of organic matter (OM), however, rare concern has been paid to the exact influence from its contiguous minerals in fine-grained sediments. Here we employed the physical-chemical sequential treatments and Rock-Eval pyrolysis and pyrolysis gas chromatography determination of shale samples to address the issue. Our results show that the OM type, HC generation potential, Tmax, gas-oil ratio, and ratio of light to heavy HCs (∑C14−/∑C15+) of shales are regularly successively changed after sequential treatments. These successive changes suggest that OM with strong interaction strength with minerals has poor OM quality and HC generation potential, and the strong strength of organic-mineral interactions (OMIs) can decrease the geothermal requirement for HC generation and move forward the onset timing of HC generation. Light and heavy HCs are mainly generated from the tight and weak mineral-combined OM, respectively, and more light or mobile oil can be found if a source rock has experienced the stronger OMI strength. Our study reveals the important influence of different OMI strengths on the fractionation of HC generation in fine-grained sediments, which is significant to improve the understanding of petroleum resource assessment and the carbon cycle.

Quantitative Interpretation of TOC in Complicated Lithology Based on Well Log Data: A Case of Majiagou Formation in the Eastern Ordos Basin, China

Source rock evaluation plays a key role in studies of hydrocarbon accumulation and resource potential. Total organic carbon (TOC) is the basis of source rock evaluation and it is a key parameter that influences petroleum resource assessment. The Majiagou formation in the eastern Ordos Basin has complicated lithology and low abundance of organic matters. There are different opinions over the existence of scale source rocks. Due to inadequate laboratory data of TOC in the Ordos Basin, it is difficult to accurately describe source rocks in the region; thus, log interpretation of TOC is needed. In this study, the neural network model in the artificial intelligence (AI) field was introduced into the TOC logging interpretation. Compared with traditional ΔlogR methods, sample optimization, logging correlation analysis and comparative optimization of computational methods were carried out successively by using measured TOC data and logging data. Results show that the neural network model has good prediction effect in complicated lithologic regions and it can identify variations of TOC in continuous strata accurately regardless of the quick lithologic changes.

An Integrated Mass Balance Approach for Assessing Hydrocarbon Resources in a Liquid-Rich Shale Resource Play: An Example from Upper Devonian Duvernay Formation, Western Canada Sedimentary Basin

Petroleum resource assessment using reservoir volumetric approach relies on porosity and oil/gas saturation characterization by laboratory tests. In liquid-rich resource plays, the pore fluids are subject to phase changes and mass loss when a drilled core is brought to the surface due to volume expansion and evaporation. Further, these two closely related volumetric parameters are usually estimated separately with gas saturation inferred by compositional complementary law, resulting in a distorted gas to oil ratio under the circumstances of liquid hydrocarbon loss from sample. When applied to liquid-rich shale resource play, this can lead to overall under-estimation of resource volume, distorted gas and oil ratio (GOR), and understated resource heterogeneity in the shale reservoir. This article proposes an integrated mass balance approach for resource calculation in liquid-rich shale plays. The proposed method integrates bulk rock geochemical data with production and reservoir parameters to overcome the problems associated with laboratory characterization of the volumetric parameters by restoring the gaseous and light hydrocarbon loss due to volume expansion and evaporation in the sample. The method is applied to a Duvernay production well (14-16-62-21W5) in the Western Canada Sedimentary Basin (WCSB) to demonstrate its use in resource evaluation for a liquid-rich play. The results show that (a) by considering the phase behavior of reservoir fluids, the proposed method can be used to infer the quantity of the lost gaseous and light hydrocarbons; (b) by taking into account the lost gaseous and light hydrocarbons, the method generates an unbiased and representative resource potential; and (c) using the corrected oil and gas mass for the analyzed samples, the method produces a GOR estimate close to compositional characteristics of the produced hydrocarbons from initial production in 14-16-62-21W5 well.

Eocene-Oligocene syn-rift deposition in the northern Gulf of Tonkin, Vietnam

Abstract Reconstruction of non-marine syn-rift deposition in ancient basins is challenged by intense deformation, rapid lateral facies variation and limited biostratigraphic resolution. This affects petroleum resource assessments that relies on prediction of basin fill. The northern Gulf of Tonkin contains such non-marine-dominated rift system. The area is in an early stage of exploration. Depositional facies analysis based on all existing 2D seismic and well data suggests that Eocene-Oligocene deposition in grabens and half-grabens occurred in three steps. This resulted in formation of three successive packages, namely the rift initiation-, the rift development- and the rift termination succession. Rift initiation deposits are mainly composed by alluvial-fluvial strata deposited in segmented and often isolated grabens and half-grabens. As rifting progressed, faults joined and rift depressions merged into larger, coherent areas of deposition. Faulting peaked, which resulted in rapid creation of accommodation space, relief, and the development of deep lakes, alluvial fans and fan deltas. Elsewhere, floodplain, deltaic and shallow lake deposits comprise most of the rift development succession. As rift-subsidence declined, floodplain, deltaic and shallow lake deposits filled accommodation space and therefore dominate the rift termination succession. Structuring by strike-slip faulting and inversion complicates sequence stratigraphic analysis. Moreover, diachronic rift culmination caused the rift initiation, -development and -termination successions to vary laterally in age, further obscuring sequence stratigraphic analysis. Even so, tectonostratigraphic grouping into these three units allows a meaningful mapping of gross-depositional facies. The locally developed deep lake successions, potentially containing petroleum source rocks and seals, together with areas including potential deltaic, fan-delta, fluvial and turbidite reservoir sand suggest play types similar to those working in the Chinese part of the Beibuwan Basin. The most prospective areas are least explored suggesting an overlooked petroleum potential in the northern Gulf of Tonkin.

Formation and evolution of the Ediacaran to Lower Cambrian black shales in the Yangtze Platform, South China

Black shales in the Ediacaran Doushantuo Formation (predominantly from Member II, IV and equivalent strata) and the Lower Cambrian Niutitang Formation (or equivalents) occur widely in the Yangtze Platform, South China. These black shales could provide sufficient hydrocarbons for the petroleum system in this region. However, biomarker parameters have proven invalid in the assessment of petroleum resources because of the high thermal maturity. Therefore, it is necessary to study the characteristics and formation mechanisms of these two black shales. This study analyzed redox-sensitive elements, total organic carbon (TOC) contents, and carbon isotopic compositions of organic matter in four continuous sedimentary successions including the two investigated shales in the Yangtze Platform (namely Jiulongwan on the inner shelf, Songlin in an intra-shelf lagoon, Dongkanshang on the upper slope, and Fengtan in the basin). Combined with other previously reported five sections, the redox conditions of sedimentary waters and marine paleoproductivity of the Ediacaran to Lower Cambrian black shales in the Yangtze Platform were discussed and compared. The results showed that the redox conditions of the Early Cambrian in the study area were similar to those of the Ediacaran Doushantuo period, which were oxic-suboxic at surface water, and anoxic in the deep with the occurrence of euxinic conditions. However, the euxinic conditions in the deep waters were distributed more widely in the Early Cambrian than in the Ediacaran period. The source of organic matter in the Doushantuo Formation was dominated by algae in the shallow-water platform and the shelf-margin areas, while chemoautotrophic/methanotrophic biomass may also have contributed in the intra-shelf lagoon and deep-water basin areas. In contrast, the organic matter of the Niutitang Formation was mainly contributed by the chemoautotrophic/methanotrophic biomass, with a minor contribution by photosynthetic algae and cyanobacteria. During the Doushantuo period, the input of terrigenous clastic materials was low, resulting in the enrichment of organic matter and formation of organic-rich black shale in the Yangtze Platform over a long geological time period. Compared to the Doushantuo period, the shorter sedimentation time and the higher deposition rate during the Early Cambrian produced a thicker and higher-quality Niutitang Formation source rock widely distributed in the Yangtze Platform.

Source rock assessment within a sequence stratigraphic framework of the Yogou Formation in the Termit Basin, Niger

A preliminary sequence stratigraphic geochemical investigation was carried out to assess the areal distribution and hydrocarbon generation potential of marine mudstones of the Upper Cretaceous Yogou Formation in the Termit Basin, Niger. A total of three third‐order sequences (YSQ1, YSQ2, and YSQ3, from bottom to top) and nine systems tracts were identified in the Yogou Formation. Mudstones of each sequences are widely distributed throughout the study area with their maximum cumulative thickness of ~600–900 m in the Dinga and Moul depressions. The ΔlogR method was applied to establish a prediction model for predicting the total organic carbon (TOC) content of the Yogou Formation mudstones. The results of this source rock evaluation indicate that thick offshore mudstones with fair to good hydrocarbon generation potential and dominated Type II to Type III kerogen widely occur in YSQ1, YSQ2, and in the LST (lowstand systems tract) and TST (transgressive systems tract) of YSQ3, while the thin lower shoreface mudstone intervals in the HST (highstand systems tract) of YSQ3 are characterized by good to excellent hydrocarbon generation potential, dominated by Type II kerogen. The present‐day thermal maturation level of source beds from the YSQ3, YSQ2, and YSQ1 has overpassed the main zone of oil generation in the depocenter of Dinga Depression, whereas the YSQ3 and part of YSQ2 source beds were still within the oil window in the depocenter of Moul Depression. The organic matter richness and hydrocarbon generation potential of source beds varies within the Yogou Formation because of changes in organic matter source during evolution of Western Africa rift basins and global sea‐level fluctuations. This study provides a practical sequence stratigraphic geochemical framework which will give a better understanding for the geochemical characteristics of source rock and support improved assessment of petroleum resources.

Integrating Geochemical Anomaly and Remote Sensing Methods to Predict Oil- and Gas-Bearing Areas in the Yanchang Oil Field, Ordos Basin, China

Oil seepage is one of the most important characteristics of hydrocarbon formation, and understanding oil seepage is crucial for oil-gas exploration and the assessment of petroleum resources. Remote sensing and geochemical methods have the same material and theoretical bases for extracting oil and gas information from underlying strata and the identification of media features. As an emerging exploration method, hyperspectral remote sensing is efficient compared with traditional geochemistry because it is a finer, and sometimes more directly quantitative method for determining the specific mineral anomaly content. Hence, the use of both methods together is important. This paper describes the analysis of hyperspectral remote sensing data and the extraction of abnormal index information, including the level of carbonate alteration and the content of acidolytical hydrocarbons, pyrolysis hydrocarbons, headspace gas, and ferric and ferrous ions. The two methods have mutual authentication, and they are complementary and are useful in oil-bearing areas. When these methods are integrated, the acidolytical hydrocarbon index is the most effective geochemical index and is better at characterizing the oil field distribution than other indices. Also, hydrocarbon geochemical anomalies occurring in oil fields generally show continuous distribution points and are consistent with oil reservoirs. Consequently, a 3D model was established to comprehensively utilize hyperspectral remote sensing and geochemical data to determine the distribution of petroleum reservoirs efficiently as well as to delineate oil- and gas-bearing prospects. There is great potential for determining oil- and gas-bearing fields through the integration of hyperspectral and geochemical data.

Understanding and distinguishing reflectance measurements of solid bitumen and vitrinite using hydrous pyrolysis: Implications to petroleum assessment

Solid bitumen is a common organic component of thermally mature shales and typically is identified by embayment against euhedral mineral terminations and by groundmass textures. However, because these textures are not always present, solid bitumen can be easily misidentified as vitrinite. Hydrous pyrolysis experiments (72 hours, 300-360°C) on shale and coal samples show solid bitumen reflectance (BRo) in shales is less responsive to thermal stress than vitrinite reflectance (VRo) in coal. This effect is most pronounced at lower experimental temperatures (300-320°C) whereas reflectance changes are more similar at higher temperatures (340-360°C). Neither a ‘vitrinite-like’ maceral or ‘suppressed vitrinite’ was identified or measured in our sample set; rather, the experiments show that solid bitumen matures slower than vitrinite. The data may explain some reports of ‘vitrinite reflectance suppression’, particularly at lower thermal maturity (VRo≤1.0%), as a simple case of solid bitumen being mistaken for vitrinite. Further, the experimental results confirm previous empirical observations that VRo and BRo are more similar at higher maturities (VRo>1.0%). It is suggested that ‘vitrinite reflectance suppression’, commonly reported from upper Paleozoic marine shales of early to mid-oil window maturity, is a misnomer. This observation has important implications to petroleum exploration models and resource assessment because it may change interpretations for the timing and spatial locations of kerogen maturation and petroleum generation.

鄂尔多斯盆地三叠系延长组低渗透石油资源评价方法

鄂尔多斯盆地三叠系延长组低渗透石油资源评价方法

Creaming and the Likelihood of Discovering Additional Giant Petroleum Fields

The applied context of this paper is the exploration for petroleum resources, like petroleum accumulations in different deposits, where the most promising deposits are likely to be drilled first, based on some size indicators, so-called creaming. The paper explores creaming models in the context of sampling with probabilities in proportion to size, for which a lognormal size distribution has nice analytical features. It departs from the traditional paradigm in petroleum resource assessment. Instead of conceiving a finite population being depleted over time in a decaying fashion with respect to size, the situation is studied within the framework of independent observations (infinite population) and an exploration maturity-dependent creaming factor. The theoretical and practical consequences for inference on the parent population and the probabilities and expectations linked to future discoveries are studied. The theory applies to the issue of remaining sizes of petroleum resources to be found within different future discovery horizons on the mature part of the Norwegian Continental Shelf. The aim is to obtain reasonable and useful predictions, and not to provide the best possible explanation of the exploratory behavior itself.

Assessment and exploration risking workflows for conventional and unconventional Arctic resources: Applications on the Alaska North Slope

Arctic oil and gas have been E&P targets for several decades; however, the petroleum potential of this region is far from being fully understood. Assessments of undiscovered petroleum in the Arctic indicate that it holds a significant amount of the world's undiscovered gas and oil (Gautier et al., 2009) and recent assessments also indicate the potential of shale resource plays for oil and gas, for example on the Alaska North Slope (Houseknecht, 2012). In this article, we present technology and workflows for efficient petroleum exploration risk and resource assessments for both conventional and unconventional resources in the Arctic, including gas hydrates. We also present a recent successful exploration campaign which resulted in the first technically proven shale oil play on the Alaska North Slope.

THE EARLY JURASSIC OIL SHALES IN THE QIANGTANG BASIN, NORTHERN TIBET: BIOMARKERS AND TOARCIAN OCEANIC ANOXIC EVENTS

In the Qiangtang Basin, northern Tibet, the most complete and extensive marine sedimentary strata outcropped in the Shuanghu-Sewa-Amdo area during the Jurassic, especially the Early Jurassic. The organic-rich marine sediments - commonly referred to as black shales - were deposited in the Early Jurassic, therefore, many petroleum geologists have been focusing on them for many years. Although achievements in geological investigations and petroleum resource assessments during recent years have been remark- able, the environmental conditions, mechanics, and process that resulted in the deposition of high-organic sediments during the Early Toarcian (183- 176.5 Ma, Early Jurassic) Oceanic Anoxic Event are still a matter of dis- cussions. In this paper, we deal with the biomarker distributions of Lower Jurassic oil shales in the Biluo Co section, Shuanghu area of northern Tibet. The oil shales are characterized by a marked predominance of short chain n- alkanes with a maxiumun at C16 or C17, nC17/nC31 ratio values between 9.4 and 17.8, and low Pr/Ph ratios. Furthermore, a series of C27 and C29-C35 hopanes with minor amounts of gammacerane are present in all samples, as indicated by gammacerane/C30-17α-hopane values from 0.06 to 0.12 and the steranes C27/C29 ratios higher than 1 in the three samples. The above- mentioned parameters indicate that the organic matter source is attributed to an algal/bacterial contribution. According to maturity parameters, all the homohopane 22S/(22S+22R) values in this study are > 0.58 and the sterane 20S/(20S+20R) values are all between 0.48 and 0.59, which is consistent

Unconventional petroleum resource evaluation in Queensland

The search for unconventional petroleum resources requires a shift in the way the petroleum potential of sedimentary basins is assessed. Gas in source rocks and tight reservoirs has largely been ignored in preference for traditional conventional gas plays. Recent developments in technology now allow for the extraction of gas trapped in low-permeability reservoirs. Assessments of the unconventional petroleum potential of basins, including estimates of the potential resource are required to guide future exploration. The Geological Survey of Queensland is collaborating with Geoscience Australia (GA) and other state agencies to undertake regional assessments of several basins with potential for unconventional petroleum resources in Queensland. The United States Geological Survey methodology for assessment of continuous petroleum resources is being adopted to estimate total undiscovered oil and gas resources. Assessments are being undertaken to evaluate the potential of key formations as shale oil and gas and tight-gas plays. The assessments focus on mapping key attributes including depth, thickness, maturity, total organic carbon (TOC), porosity, gas content, reservoir pressure, mineralogy and regional facies patterns using data from stratigraphic bores and petroleum wells to determine play fairways or areas of greatest potential. More detailed formation evaluation is being undertaken for a regional framework of wells using conventional log suites and mudlogs to calculate porosity, TOC, maturity, oil and gas saturations, and gas composition. HyLoggerTM data is being used to determine its validity to estimate bulk mineralogy (clay-carbonate-quartz) compared with traditional x-ray diffraction methods. These methods are being applied to key formations with unconventional potential in the Georgina and Eromanga basins in Queensland.

Introduction to a Special Issue on Petroleum Resource Assessment Methods and Case Studies

This Special Issue of the Bulletin of Canadian Petroleum Geology contains thematic research articles based on presentations first made to the Third Resource Assessment Methodology Symposium, held September 15–17, 2010, in Canmore, Alberta. These ad hoc symposiums gather investigators to focus on petroleum resource assessment methods and case studies in conventional and unconventional reservoirs. The Canadian Gas Potential Committee (CGPC) initiated these symposiums beginning in Calgary, in 2000, with nine scientific articles published in a special issue of Natural Resource Research (Logan, 2005). The United States Geological Survey (USGS) hosted the second symposium in Denver, Colorado, in 2004, with emphasis on special problems associated with the appraisal of conventional petroleum resources. The 2010 symposium was the third of a similar theme. The Canadian Society for Unconventional Gas (CSUG), now the Canadian Society for Unconventional Resources (CSUR), the Geological Survey of Canada (GSC) and the National Energy Board (NEB) were co-organizers of this symposium. The meeting attracted sixty-six participants, including fifteen participants from outside North America. The delegates made twenty-three oral and seven poster presentations, the details of which will appear elsewhere (i.e. Canadian Society of Petroleum Geologists website and Reservoir ). The focus and content of the three symposiums follow and illustrate a number of significant changes in the nature of the petroleum resource-base and the focus of industrial, policy, and regulatory assessment needs to both describe and infer petroleum resources. In the last decade, or so, petroleum exploration and exploitation have made significant advances on two fronts. Advances in drilling and completion technologies have changed not only the supply-demand dynamics in global petroleum markets, but also the petroleum reservoir concept. Almost every rock type is now a potential reservoir. Petroleum is now produced commercially from fine-grained and organic-rich successions that were previously regarded as both top seals and source …

An oil and gas resource reassessment of the Bonaparte Basin, northwest shelf of Australia

Abstract Bonaparte Basin is an established petroleum province in the Northwestern Australia shelf. The proven recoverable reserves of 2032 million barrels of oil equivalent (MMBoe) has recently exceeded the mean values of undiscovered resource estimates in previous studies, including that in the United States Geological Survey 2000 world assessment. There is a need for a reassessment of the resource potential in this region. For the purpose of reassessment, this paper presents an overall review of the petroleum geology and discusses the key factors controlling hydrocarbon accumulations in the basin. A close examination of the petroleum system elements of the study area found fundamental differences in essential geological conditions, such as structure type, source rock maturity, trap integrity and preservation across the basin. These differences allow a subdivision of the Mesozoic Bonaparte Basin into the Malita and the Vulcan assessment units (AUs). The undiscovered resource potential in the two AUs are estimated using a Monte Carlo simulation procedure developed by the USGS in their 2000 world petroleum resource assessment. Our study shows that the Bonaparte Basin contains 938 million barrels of oil, 1901 million barrels of condensate and 34.423 trillion cubic feet of natural gas yet to be found (mean estimates), which are much greater than the previous assessments.

Comparison of petroleum resource assessments of China by the U.S. Geological Survey and the China National Petroleum Assessment Team

This study compares the results of the petroleum resources of China evaluated in the U.S. Geological Survey World Petroleum Assessment 2000 (USGS WPA 2000) with those evaluated in the China National Petroleum Assessment 2007 (CNPA 2007). The USGS WPA 2000 reported the mean undiscovered petroleum resources of China to be 12.12 BBO and 85.79 TCFG, which is a much lower estimate than the 107.38 BBO and 692.13 TCFG assessment reported in the CNPA 2007. Six major factors, including petroleum resource classification systems, data sources, assessment scopes, unit divisions, assessment methods, and assessment parameters, contributed to the differences in these two assessments. Reserve growth and undiscovered resources are two independent parts of total petroleum resources according to the definition in the USGS WPA 2000, whereas undiscovered resources of the CNPA 2007 included estimates of reserve growth. The USGS WPA 2000 showed a much higher minimum field size than the CNPA 2007 did, and only six Chinese basins were covered in the former, whereas 115 Chinese basins were evaluated in the latter. For the same basins, unit divisions of the USGS WPA 2000 also differed from those of the CNPA 2007 because of their different data sources and exploration and exploitation experiences. Different methods used by these two agencies also affected their assessment results to some degree.

Using copulas for implementation of variable dependencies in petroleum resource assessment: Example from Beaufort-Mackenzie Basin, Canada

Petroleum resource potential modeling seeks to characterize undiscovered petroleum resources. This information from the modeling can contribute to a reduction in corporate risk while characterizing the commercial potential of the undiscovered resources. Such models consider different types of variable dependencies arising from geologic risk evaluation, volumetric calculation, and resource aggregation to higher geographic levels. Commonly, the available data are not sufficient to specify such variable correlations or interdependencies, particularly in frontier regions. It is also a challenge to formulate variable correlations in resource calculations because geologic variables have to be fit to a multivariate lognormal distribution or other specific multivariate distributions with an appropriate correlation structure. However, variable correlations are common among the geologic variables, and ignoring the interdependencies may lead to a serious bias in the resource potential estimation and the uncertainty range. Recent methodological developments in statistics indicate that the use of copulas permits more flexibility for the consideration and incorporation of variable interdependency, thus analogs can be introduced to problems where estimating correlation structures are impossible and wider choices of statistical distributions become available. This article proposes the use of copulas for handling variable dependency in petroleum resource assessment. The methods and procedures are illustrated using examples from a hypothetical data set and the crude oil resource appraisal of Tertiary clastic plays in Beaufort-Mackenzie Basin in Arctic Canada. Comparisons of crude oil resource estimates obtained using different correlation scenarios for these plays suggest that when positive correlations are used, the mean value of the oil resource is increased about 1.6 times that estimated, assuming a complete independence among the input variables.