Lithostratigraphy and depositional episodes of the Oligocene carbonate-rich Tikorangi Formation, Taranaki Basin, New Zealand

The subsurface Oligocene Tikorangi Formation is a unique and important oil producer in the onshore Waihapa-Ngaere Field, Taranaki Basin, being the only carbonate and fracture-producing reservoir within the basin. Core sample data from seven onshore wells (foredeep megafacies) and a single offshore well (basinal megafacies) are correlated with a suite of sonic and gamma-ray geophysical well log data to derive interpretative carbonate facies for the Tikorangi Formation. Four mixed siliciclastic-carbonate to carbonate facies have been defined: facies A-calcareous siliciclastite (75% carbonate). Single or interbedded combinations of these facies form the basis for identifying nine major lithostratigraphic units in the Tikorangi Formation that are correlatable between the eight wells in this study.The Tikorangi Formation accumulated across a shelf-slope-basin margin within a tectonically diversified basin setting, notably involving considerable off-shelf redeposition of sediment into a bounding foredeep. Analysis of gamma, sonic, and resistivity well logs identifies five major episodes of sedimentary evolution. Episode I comprises retrogradational siliciclastic-dominated redeposited units associated with foredeep subsidence. Episode II is a continuation of episode I retrogradation, but with increased mass-redeposited carbonate influx during accelerated foredeep subsidence and relative sea-level rise, the top marking the maximum flooding surface. Episode III involves a progradational sequence comprising relatively pure redeposited carbonate units associated with declining subsidence rates and minimal siliciclastic input, with movement of facies belts basinward. Episode IV consists of prograding aggradation involving essentially static facies belts dominated by often thick, periodically mass-emplaced, carbonate-rich units separated by thin background siliciclastic shale-like units. Episode V is a retrogradational sequence marking the reintroduction of siliciclastic material into the basin following uplift of Mesozoic basement associated with accelerated compressional tectonics along the Australia-Pacific plate boundary, initially diluting and ultimately extinguishing carbonate production factories and terminating deposition of the Tikorangi Formation

Deep-water turbidites as Holocene earthquake proxies: the Cascadia subduction zone and Northern San Andreas Fault systems

New stratigraphic evidence from the Cascadia margin demonstrates that 13 earthquakes ruptured the margin from Vancouver Island to at least the California border following the catastrophic eruption of Mount Mazama. These 13 events have occurred with an average repeat time of ?? 600 years since the first post-Mazama event ?? 7500 years ago. The youngest event ?? 300 years ago probably coincides with widespread evidence of coastal subsidence and tsunami inundation in buried marshes along the Cascadia coast. We can extend the Holocene record to at least 9850 years, during which 18 events correlate along the same region. The pattern of repeat times is consistent with the pattern observed at most (but not all) localities onshore, strengthening the contention that both were produced by plate-wide earthquakes. We also observe that the sequence of Holocene events in Cascadia may contain a repeating pattern, a tantalizing look at what may be the long-term behavior of a major fault system. Over the last ?? 7500 years, the pattern appears to have repeated at least three times, with the most recent A.D. 1700 event being the third of three events following a long interval of 845 years between events T4 and T5. This long interval is one that is also recognized in many of the coastal records, and may serve as an anchor point between the offshore and onshore records. Similar stratigraphic records are found in two piston cores and one box core from Noyo Channel, adjacent to the Northern San Andreas Fault, which show a cyclic record of turbidite beds, with thirty- one turbidite beds above a Holocene/.Pleistocene faunal «datum». Thus far, we have determined ages for 20 events including the uppermost 5 events from these cores. The uppermost event returns a «modern» age, which we interpret is likely the 1906 San Andreas earthquake. The penultimate event returns an intercept age of A.D. 1664 (2 ?? range 1505- 1822). The third event and fourth event are lumped together, as there is no hemipelagic sediment between them. The age of this event is A.D. 1524 (1445-1664), though we are not certain whether this event represents one event or two. The fifth event age is A.D. 1204 (1057-1319), and the sixth event age is A.D. 1049 (981-1188). These results are in relatively good agreement with the onshore work to date, which indicates an age for the penultimate event in the mid-1600 s, the most likely age for the third event of ?? 1500-1600, and a fourth event ?? 1300. We presently do not have the spatial sampling needed to test for synchroneity of events along the Northern San Andreas, and thus cannot determine with confidence that the observed turbidite record is earthquake generated. However, the good agreement in number of events between the onshore and offshore records suggests that, as in Cascadia, turbidite triggers other than earthquakes appear not to have added significantly to the turbidite record along the northernmost San Andreas margin during the last ?? 2000 years

Potential sinks for geologic storage of carbon dioxide generated by power plants in North and South Carolina

Duke Energy Progress Energy Santee Cooper Power SCANA CorporationBureau of Economic Geolog

The impact of shale pressure diffusion on 4D seismic interpretation

Shale typically has a low but non-negligible permeability of the order of nanodarcys (recognized an appreciated in production of unconventional resources), which could affect the magnitude and pattern of the pressure in conventional reservoirs over the lifetime of a producing field. The implications of this phenomenon for reservoir monitoring by 4D seismic can be significant, but depend on the geology of the field, the time-lines for production and recovery, and the timing of the seismic surveys. In this PhD thesis I developed an integrated workflow to assess the process of shale pressure diffusion and its elastic implications in the 4D seismic interpretation of four conventional reservoirs (three North Sea case studies and one from West Africa), with different geological settings (shallow marine and turbidites) and production mechanisms. To accomplish that, first, a detailed petrophysical evaluation was performed to characterize the overburden, intra-reservoir and underburden shales. Next, the simulation models were adjusted to activate the shale-related contributions, and then, applying simulator to seismic workflows, 3D and 4D synthetic seismic modelling were performed, for comparison with the observed seismic data and to establish the impact of the shale pressure diffusion in the elastic dynamic behaviour of the reservoir. This work also includes a case study where evaluation of shale pressure diffusion was integrated with geomechanical simulations to assess the propagation of time shifts and time strain in the overburden of a high pressure/high temperature reservoir under compaction, improving the understanding of the distribution and polarity of the observed seismic time strain. Fluid flow simulation results of this work indicate that activation of the shale improves the overall reservoir connectivity, enhancing model prediction (production history matched data). The fit to observed 4D seismic data was improved in all the field applications with a noticeable reduction (up to 6%) in the mismatch (hardening and softening signal distribution) for the models with active shales. In reservoirs where the saturation was very sensitive to changes in pressure, shale activation proved to impact strongly on the breakout and distribution of gas liberated from solution. Overall, this work found that inclusion of shale in the 3D and 4D reservoir seismic modelling can provide valuable insights for the interpretation of the reservoir’s dynamic behaviour and that, under particular conditions such as strong reservoir compartmentalization, shale pressure diffusion could be a significant process in the interpretation of the 4D seismic signature

Seismic and sparse data integration through the use of direct sampling

textThe integration of seismic attributes and well data is an important step in the development of reservoir models. These models draw upon large data sets including information from well logs, production history, seismic interpretation, and depositional models. Modern integration techniques use the extensive data sets to develop precise models using complex workflows at increased cost of time and computational power. However, a gap exists in which a geostatistically driven procedure could integrate pattern statistics inferred from seismic images and those integrated from analogous geologic systems in order to develop spatially accurate reservoir models. Direct Sampling Seismic Integration Process, DSSIP, was first proposed by Henke and Srinivasan (2010) as an alternative to traditional seismic integration methods. The process provides a probabilistic mapping tool for fast reservoir analysis based on sparse conditioning data in a target reservoir and fully interpreted data from an analog field. DSSIP combines the structural information present in seismic data and facies patterns present in a training reservoir to create a fully realized output map for the target field. In this work, the basic DSSIP algorithm has been further optimized by performing a detailed parameter sensitivity study. The basic DSSIP algorithm has been demonstrated for a real field data set for a deepwater Gulf of Mexico reservoir. The basic DSSIP algorithm has also been analyzed to understand and model the effects of features such as salt canopy that can blur the seismic image. Finally, a modification to the basic algorithm is also presented that uses only a training model and the seismic data for the target reservoir in order to generate reservoir models for the target reservoir. This procedure eliminates the requirement to have a matching pair of training data sets for both the facies distribution and the corresponding seismic response.Petroleum and Geosystems Engineerin

Improving Deep Exploration with Cost-Effective Geophysical Methods

Subsurface exploration is rapidly changing and ‘easy to target’ deposits are depleting across the world. This reality has pushed exploration in two directions: re-evaluating known deposits and exploring greater depths. The goal of this thesis was to address these trends in a cost-effective manner. First, by combining geophysical, borehole, and open-source spatial data, a 3D model was synthesized for a volcanogenic massive sulphide (VMS) deposit located in Nash Creek, NB. Evaluating this model showed a need for structural controls to better understand the genesis of the deposit. A lesser-known geophysical system, Extremely Low Frequency EM (ELF-EM), measures ~2km deep and can produce conductivity models. While perfect for Nash Creek, ELF lacked modern software support which limited the modelling that could be done. Using an open-source inversion package, a python script is presented with this thesis that runs inversions of tipper (ELF) data to produce 3D conductivity models. This new workflow was tested at the Key Anacon VMS deposit near Bathurst, NB. A 3D wireframe model derived from geophysical surveying and borehole logs was available to compare with the ELF-EM derived model at Key Anacon. While individual mineralized horizons could not be discerned, a ‘conductive envelope’ follows a very similar strike and dip to the wireframe model. Promising results from Key Anacon led to the re-interpretation of past ELF-EM surveys. The final section of this thesis revisits a survey in Burwash Landing, Yukon to compare conductivity modelling results. The Burwash Landing survey aimed to identify potential geothermal wells drilling sites along the Denali fault. The new 3D model showed a coherent fault trace along strike, as well as eliminated several anomalies the researchers in the original paper could not explain. This improved ELF-EM inversion workflow has greatly improved 3D modelling of deep conductivity contrasts. In future, the techniques outlined here can be applied to various exploration scenarios while following the current trends in exploration

Development of a geological model useful for the study of the natural hazards in urban environments. An example from the eastern sector of Rome (Italy)

Detailed knowledge of the subsoil setting is an extremely important issue for a correct risk reduction policy, especially when dealing with urban areas hosting cultural heritage, which enhance risk conditions even at low geo-hazard levels, as in the case of Rome. In general, the reliability of risk assessments related to geo-hazards is strictly dependent on the resolution of the reference geological model. The study presented here exemplifies an integrated methodology aimed at refining the knowledge of the geological setting in unique urban environments, such as the city of Rome, where canonical approaches are limited by the scarcity of outcrops and ad-hoc geognostic surveys may be expensive and time-consuming. The methodology used in the study is based on a critical review of available geological, stratigraphic, archeological and historical-archival data. The integration of such data, properly stored, managed and analysed in a GIS environment, made it possible to: i) better frame the geological setting of a wide sector of the eastern part of Rome; and, in particular, ii) focus on buried natural morphologies (i.e. valleys) strongly modified by progressive urbanisation that determined their filling with huge thickness of backfills, which often represent a critical geotechnical issue. A detailed geological model was thus developed. The model shows slight but significant differences with respect to already available official maps, emphasising the need for carrying out in-depth analyses of already existing data from different sources, in order to collect thematic data to be used for effective land management policies

Controlling realism and uncertainty in reservoir models using intelligent sedimentological prior information

Forecasting reservoir production has a large associated uncertainty, since this is the final part of a very complex process, this process is based on sparse and indirect data measurements. One the methodologies used in the oil industry to predict reservoir production is based on the Baye’s theorem. Baye’s theorem applied to reservoir forecasting, samples parameters from a prior understanding of the uncertainty to generate reservoir models and updates this prior information by comparing reservoir production data with model production response. In automatic history matching it is challenging to generate reservoir models that preserve geological realism (obtain reservoir models with geological features that have been seen in nature). One way to control the geological realism in reservoir models is by controlling the realism of the geological prior information. The aim of this thesis is to encapsulate sedimentological information in order to build prior information that can control the geological realism of the history-matched models. This “intelligent” prior information is introduced into the automatic history-matching framework rejecting geologically unrealistic reservoir models. Machine Learning Techniques (MLT) were used to build realistic sedimentological prior information models. Another goal of this thesis was to include geological parameters into the automatic history-match framework that have an impact on reservoir model performance: vertical variation of facies proportions, connectivity of geobodies, and the use of multiple training images as a source of realistic sedimentological prior information. The main outcome of this thesis is that the use of “intelligent” sedimentological prior information guarantees the realism of reservoir models and reduces computing time and uncertainty in reservoir production prediction

Silica diagenesis, polygonal faulting, and shallow gas: implications for fluid migration, storage, and shallow hazards

By integrating 3D seismic data, petrophysical well logs and well cuttings samples, three (3) broad areas related to hydrocarbon plumbing systems and subsurface fluid flow in the eastern Central North Sea are investigated in this research, silica diagenesis, polygonal faulting, and shallow gas accumulations. Silica diagenesis which generally involves a two-step process of the conversion of amorphous biogenic silica (Opal-A) to crystals of cristobalite or tridymite (Opal-CT) and subsequently to crystals of quartz has been identified in sedimentary basins around the world. This process has the potential of significantly affecting the physical, mechanical, and fluid flow properties of the host rock and are important to the development of sedimentary basins. This study identifies for the first time, the presence of an Opal-A/CT reaction front in the Cenozoic mudstones of the eastern CNS by the use of a range of techniques including X-ray diffraction data (XRD) and the Quantitative Evaluation of Minerals by Scanning Electron Microscope (QEMSCAN) and conventional 3D seismic and well data interpretation techniques. Further, we analysed the impact the presence of salt diapir in the study area and conclude that it helped in elevating temperatures locally which led to the fossilization of the silica diagenetic reaction front. Furthermore, we investigate the relationship between silica diagenesis and polygonal fault systems hosted within the same interval. Recently, there has been a growing link between silica diagenesis in biosiliceous sediments and the evolution of polygonal faults. We investigated this link using conventional 3D seismic and well data through a spatial, temporal, and kinematic analysis of the polygonal fault systems within the sediments. We proposed a model for the nucleation, growth, and propagation of the polygonal fault system as a contemporaneous process happening alongside silica diagenesis and report that most of the faults are in-active at present, except for a few breaching the mid-Miocene unconformity surface and this is contemporaneous also, with the fossilization of the Opal-A/CT reaction front. Lastly, we investigated twenty-six shallow gas accumulations appearing as ‘bright spots’ on seismic data as seismic anomalies within the Cenozoic succession using conventional 3D seismic interpretation methods and geochemical methods for the evaluation of organic matter richness and thermal maturity from well cuttings sample within the shallow section. We classified the shallow gas accumulations based on their on their direct hydrocarbon indicator (DHI) characteristics, spatial and temporal distribution, and their relationship with other focused fluid flow related features into two types, Type I & Type II. The Type I shallow gas anomalies are often found associated with the Zechstein salt diapirs while the Type II anomalies are found in discreet pockets within Delta Front sediments. Geochemical analysis from well cuttings samples indicates an average total organic carbon (TOC) content of 5% and with a very good generative potential, suggesting the possibility of the charging of shallow reservoirs hosting the shallow gas accumulations by biogenic gas in combination with deep thermogenic sources. We present a model for the shallow gas accumulations within the study area which may assist in mitigating risks associated with shallow gas accumulations whether they are considered as a shallow geohazard for the drilling of deeper targets or a potential new play where they are located near existing infrastructure. This study has implications for fluid migration, subsurface storage of carbon dioxide and nuclear waste and the assessment of shallow geohazards

A Comprehensive Reservoir Characterization Of The Bakken Formation: Blue Buttes Field, Williston Basin

The Bakken Formation is an unconventional reservoir in North Dakota’s Williston Basin. A complex lithology of the producing formation requires a better understanding of its rock properties and mineralogy, as well as further analysis such as geologic modelling and reservoir simulation. It is important to analyze its properties to manage production efficiently. The work started with analyzing petrophysical properties of the Middle Bakken. It included porosity, permeability, water saturation, shale volume, and lithology. Individual logs were obtained from a database and then run through well logging software to obtain the properties. Available core samples were analyzed using XRD. Construction of geologic model was based on well log information. The model is needed in order to see the properties distribution and prepare it for reservoir simulation. The model was built using geostatistical analysis. Reservoir simulation was done in order to predict the performance of the field