Zhuoheng Chen

Predicting average annual groundwater levels from climatic variables: an empirical model

On the basis of one-dimensional theoretical water flow model, we demonstrate that the groundwater level variation follows a pattern similar to recharge fluctuation, with a time delay that depends on the characteristics of aquifer, recharge pattern as well as the distance between the recharge and observation locations. On the basis of a water budget model and the groundwater flow model, we propose an empirical model that links climatic variables to groundwater level. The empirical model is tested using a partial data set from historical records of water levels from more than 80 wells in a monitoring network for the carbonate rock aquifer, southern Manitoba, Canada. The testing results show that the predicted groundwater levels are very close to the observed ones in most cases. The overall average correlation coefficient between the predicted and observed water levels is 0.92. This proposed empirical statistical model could be used to predict variations in groundwater level in response to different climate scenarios in a climate change impact assessment.

A revised method for organic porosity estimation in shale reservoirs using Rock-Eval data: Example from Duvernay Formation in the Western Canada Sedimentary Basin

Studies suggest that nanometer-scale pores exist in organic matter as a result of thermal decomposition of kerogen. Depending on the host rock lithology, organic pores could be the primary storage for hydrocarbon accumulation in unconventional petroleum plays. Although various methods are publicly available, estimation of organic porosity remains a challenge because the procedures involve certain simplification or some implicit assumptions on the calculation of initial total organic carbon (TOC). In this study, we propose a revised method to address some of these issues. A model of estimating hydrocarbon expulsion efficiency is developed and incorporated into the calculation of initial TOC, thus producing an estimate of organic porosity with an improved mass balance. The method has been tested and compared with estimates using other methods based on a Rock-Eval data set in the literature. An application of the method to a large data set from the Upper Devonian Duvernay Formation petroleum system in the Western Canada Sedimentary Basin reveals that the modification has a significant effect on the estimated organic porosity. This study also indicates that organic porosity in the Duvernay Formation ranges greatly from none in immature intervals to >6% in highly mature and organic-rich shale intervals. Scanning electron microscope images of immature and mature organic-rich shale samples of the Duvernay Formation show a progressive increase in organic porosity with increasing thermal maturity, supporting the proposed model calculation. The presence of a large volume of organic porosity in mature shale intervals suggests a significant amount of hydrocarbon may be stored in the organic nanopores in the Duvernay Formation.

Geological risk mapping and prospect evaluation using multivariate and Bayesian statistical methods, western Sverdrup Basin of Canada

The current practice of geological risk evaluation at the play level involves substantial subjectivity and rarely considers the spatial correlations among the identified prospects. A quantitative procedure using multivariate and Bayesian statistical methods is proposed, which treats exploration-risk evaluation as a two-group classification, to provide a more objective and reproducible result. The spatial correlation among the identified prospects is considered because the proposed approach is applied to the entire evaluation area. The exploration-risk evaluation of the Upper Triassic–Lower Jurassic Heiberg Group structural gas play in western Sverdrup Basin, Arctic Canada, illustrates the method.

Spatial variation of Bakken or Lodgepole oils in the Canadian Williston Basin

There are two opposing schools of thought that infer either the Bakken Formation or the Lodgepole Formation as the primary source rock for the Madison-reservoired oils in the Canadian Williston Basin. A recent geochemical study revealed evidence indicating the existence of significant mixing of Bakken and Lodgepole oils in the Madison reservoirs. To investigate the geographic distribution of the oil compositions, we employed a multivariate statistical method to extract source and maturity-specific geochemical signatures from a geochemical data set for spatial analysis. Oil mixing appears to be geographically dependent and restricted by a northeast-southwest–striking zone (Torquay-Rocanville trend) in southeast Saskatchewan. Thus, fracture or fault systems are inferred to have provided high-permeability zones allowing Bakken-derived oil to migrate upward across the Lodgepole Formation. The areas without significant fault or fracture systems favor lateral oil migration along porous beds, restricting Bakken-derived oil accumulation to pools in Bakken reservoirs and Lodgepole-derived oils to occur primarily in overlying reservoir beds of the Madison Group.

Hydrocarbon migration detected by regional temperature field variations, Beaufort-Mackenzie Basin, Canada

The regional Beaufort-Mackenzie Basin temperature field is characterized using data collected from drill-stem tests and bottom-hole temperature logs. We recognize two thermal anomalies, each of which is associated with a specific geological setting. Elevated temperatures are observed in (1) the western Beaufort Sea, where post-Eocene erosion removed Cenozoic strata and folding is common in a contractional tectonic regime, and (2) along fault zones where upward flow transports heat by advection. Depressed temperatures are observed in Eocene and post-Eocene rapidly subsiding depocenters, with overpressure developed below 3000 m (9843 ft). Older strata along the southeast rifted margin are characterized by a more normal thermal regime. Evidence from anomalously high temperatures in both map and cross-sectional views suggests that fault zones and major regional aquifers accommodate the upward expulsion of fluids from deep overpressured zones. Many significant petroleum discoveries occur in areas where anomalously high temperatures are observed, suggesting that petroleum migration occurs along the same flow networks. Identifying anomalies in the temperature field may therefore be a useful exploration technique.

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.

SuperSD: an object-based stochastic simulation program for modeling the locations of undiscovered petroleum accumulations

Object-based stochastic simulation is a widely applicable method that has been used to predict channel sand bodies in fluvial depositional systems. Petroleum pools are spatial objects and the location and characteristics of the undiscovered pools can be predicted using similar techniques. An object-based stochastic simulation program, Simulating Undiscovered PEtroleum Resource Spatial Distribution (SuperSD), is presented for the purpose of predicting the locations of undiscovered petroleum accumulations in a play. This program simultaneously considers all the necessary geological conditions for the formation of petroleum accumulations and the spatial correlation of these accumulations in the simulation. An independence chain of the Hastings algorithm is used to generate an appropriate structure of pool combinations. The uncertainty associated with the data and the geological models for predicted locations is expressed as a relative probability map. The executable codes of the SuperSD program are available from the Geological Survey of Canada.

The Paleozoic Hudson Bay Basin in northern Canada: New insights into hydrocarbon potential of a frontier intracratonic basin

The Hudson Bay Basin is the largest intracratonic basin in North America, although it is the only one without any proven hydrocarbon reserves. The stratigraphic succession that fills the basin consists mainly of Paleozoic strata, with a maximum preserved thickness of about 2500 m (8202 ft). The Paleozoic succession includes Ordovician to Devonian shallow marine carbonates, reefs, and shales with locally thick Devonian evaporites. The Paleozoic strata are locally unconformably overlain by a thin Mesozoic and Cenozoic cover of nonmarine and marine strata. From 1964 to 1985, over 46,000 line-km (28,600 mi) of seismic reflection data were acquired, and four onshore and five offshore exploration wells were drilled. The data acquired at that time led to pessimistic conclusions on source rocks and the thermal rank of the basin and resulted in the stoppage of exploration activities. However, hydrocarbon shows or indicators were identified in well log data and seismic reflection profiles. The likelihood of an active petroleum system has also been recently supported by recognition of pockmarks on the seafloor and possible marine oil slicks identified on satellite images. New studies of geological, geophysical, and biostratigraphic data reveal that the Hudson Bay Basin had an irregular subsidence and uplift history. Syntectonic deposition occurred during the Late Ordovician(?) to Early Devonian and sag-basin deposition during the Middle to Late Devonian. The basin contains four unconformity-bounded sequences, with significant depocenter migration over time. Analyses of petroleum-system data indicate the Hudson Bay Basin has higher petroleum potential than previously considered. Porous platform limestones, reefs, hydrothermal dolomites, and siliciclastics form potential hydrocarbon reservoirs. Upper Ordovician organic-rich shales with type II-S organic matter are recognized at several locations in the basin. Newly acquired organic matter reflectance and Rock-Eval data indicate Ordovician–Silurian strata locally reached the oil window. Basin modeling demonstrates significant potential for oil generation and expulsion from Ordovician source rocks. Five petroleum play types are identified in the Hudson Bay Basin, including an untested fault-sag or hydrothermal dolomite play. The synthesis of the petroleum system information indicates that the Hudson Bay Basin is, at least locally, prospective for oil accumulations.

Stochastic Simulation of Undiscovered Petroleum Accumulations

Geographic characteristics of undiscovered petroleum accumulations are important both to better natural resource management and improved exploration efficiency. Stochastic simulation is a useful tool that reveals uncertainties in petroleum exploration and exploitation applications. The lack of information regarding the locations of undiscovered petroleum accumulations presents a major difficulty to the application of this technique to petroleum resource assessment. In order to facilitate the locations of undiscovered petroleum accumulations, we propose a model-enhanced simulation approach that uses a geological model, in either the form of geological favorability or probability of petroleum occurrence derived from available geological and geophysical observations. The proposed approach employs a Fourier transform algorithm in the conditional simulation because it permits the spatial correlation-specific and location-specific features from different data sources to be studied separately and integrated in the frequency domain subsequently. This approach is illustrated by the analysis of the Rainbow petroleum play in the Western Canada Sedimentary Basin. The proposed approach produces a resource map showing the possible size of undiscovered petroleum accumulations with geographic locations. A comparison with the results from a traditional conditional simulation indicates that the proposed approach produces maps with improved features and predictions validated by the test data set.

Application of a Least Square Non-parametric Discovery Process Model to Colorado Group Mixed Conventional and Unconventional Oil Plays, Western Canada Sedimentary Basin

A least squares non-parametric discovery process model has been developed recently for assessing petroleum resources in mature plays with complex size distribution characteristics. Applications of this model to oil plays in the Colorado Group suggests that these techniques can be used to assess petroleum plays composed of a mixture of pools comprising both conventional and unconventional petroleum accumulations. We use the Cardium oil play of the Colorado Group in the Western Canada Sedimentary Basin to illustrate use of the non-parametric approach for such a mixed petroleum play. Our Colorado Group resource assessment indicates a large remaining oil resource potential in this petroleum system, largely in tight unconventional reservoirs.