The application of chemostratigraphy to problems in modern and ancient environments has a long and successful history. In particular, the use of high-resolution X-ray fluorescence (XRF) spectrometry for studying the elemental content of core and rock at the sub-millimeter scale to understand provenance, grain size, paleoredox state, terrigenous influence, and other aspects of strata is well documented in paleoclimatology literature.
ABSTRACT: We use an evolutionary geomechanical model to study stress and deformation in sediments during the emplacement of a frontal-rolling salt sheet. We show that overturned-roof sediments develop high differential stresses and plastic strains. We illustrate that these high plastic strains may allow roof layers to overturn and fold below the advancing salt. Sediments fail during roof overturn but regain strength as they get buried below salt. We discuss that sediment strength and failure depend on the overall evolution of the salt system. We show that the salt-base geometry can provide a first order estimation of the level of shear as well as of the decrease in least principal stress below salt. We build our large strain models in the finite element program Elfen. We model salt as solid viscoplastic and sediments as poro-elastoplastic materials. Overall, our evolutionary models provide insights into the mechanics of salt-sheet emplacement, identify potential drilling hazards and help understand stress and deformation of basin sediments near salt.
A salt sheet is an allochthonous salt body sourced from a salt diapir, and whose breadth is several times greater than its maximum thickness (Jackson and Hudec, 2017). Salt sheets are a common feature in salt systems around the world, including a very strong presence in the Gulf of Mexico (Jackson and Hudec, 2017).
Salt is a solid viscous rock that cannot sustain deviatoric stresses over geologic time (Urai and Spiers, 2007). When subjected to differential stresses, for example by differential sedimentation or tectonic loading, salt flows until its stress state is uniform. During this process, it may form diapirs and salt sheets. In particular, salt sheets commonly form when the upward rise of the salt in a diapir is much faster than the local sedimentation rate (Hudec and Jackson, 2006).
The advance of a salt sheet imposes strains onto roof and underlying-basin sediments; hence, it perturbs their state of stress. Indeed, shear zones and high pore pressures are often encountered below salt (Dusseault et al, 2004, Harrison et al, 2004, House and Pritchett, 1995, O’Brien and Lerche, 1994, Willson et al, 2003, York et al, 2009, Zhang, 2013). As a result, exiting the base of a salt sheet is one of the most dangerous moments in subsalt drilling. There is a lot of uncertainty in evaluating the present-day stress, pore pressure, and deformation state of subsalt sediments because seismic imaging is poor immediately below salt (Israel et al, 2008, Jackson and Hudec, 2017, Perez et al, 2008). Under these conditions, one of the most plausible ways to predict stress and pressure anomalies subsalt is to understand how salt was emplaced and how it interacted with basin sediments during its emplacement.
An integrated analysis of different seismic attributes like similarity, dip, azimuth, dip variance, energy, curvature and ridge enhancement filter (REF) (a special filter derived using similarity attribute) is executed over 3D seismic data of the Penobscot prospect to delineate detail structural features corresponding to Wyandot, Dawson Canyon and Logan Canyon formations of the Scotian Basin, Canada. At first, following the dip and azimuth information from each of the adjacent traces a dip-steered volume is generated from the 3D pre-stacked time migrated seismic volume. This volume is used to develop several dip-steered filters such as dip steered median filter (DSMF), dip steered diffusion filter (DSDF) and fault enhancement filter (FEF). DSMF removes random noises and maintains the lateral continuity of the seismic events. DSMF seismic volume is then taken as input for DSDF computation in order to enhance the fault contrast from the background. The seismic volumes from these two filters are taken as input for the FEF computation. This filtered data volume provides a sharp image of the fault. FEF data is then used for extracting the attributes as mentioned above. With the help of a Multi-Layer Perceptron Network (MLP) all the extracted attributes are combined to prepare a meta-attribute, known as fault probability cube. This meta-attribute brought out major NE-SW trend and several additional structural details of the Cretaceous formations of the Scotian basin pertaining to faults, fault scraps and horstgraben features. This structural interpretation will provide a better understanding of the probable petroleum system (or hydrocarbon traps) over the study area. Thus, the study demonstrates an effective workflow for enhanced structural interpretation using seismic multi attributes and ANN.
This paper has been withdrawn from the Technical Program and will not be presented at the 87th SEG Annual Meeting.
Khoudaiberdiev, Rustam (University of Texas of the Permian Basin) | Bennett, Craig (University of Texas of the Permian Basin) | Bhatnagar, Paritosh (University of Texas of the Permian Basin) | Verma, Sumit (University of Texas of the Permian Basin)
Summary Potential reservoirs can be found within deltaic channels, these channels have the ability to form continuous transport systems for hydrocarbons. Distributary sand-filled channels in particular can serve as excellent reservoirs. The emphasis of this study is taking a detailed look into the sand channels within the Cree Sand of the Logan Canyon, as well as using coherence and coherent energy seismic attributes to delineate these features. Extensive studies have been performed in analysis of deltaic channel systems and their ability to act as reservoirs for hydrocarbons. The paper will follow an equivalent approach, employing 3D seismic survey data and seismic interpretation techniques to identify and map sand channels.
Bhatnagar, Paritosh (University of Texas of the Permian Basin) | Bennett, Craig (University of Texas of the Permian Basin) | Khoudaiberdiev, Rustam (University of Texas of the Permian Basin) | Lepard, Sterling (University of Texas of the Permian Basin) | Verma, Sumit (University of Texas of the Permian Basin)
Transfer zones — a feature where deformational strain is transferred from one fault system to another — play an important role in controlling fluid migration in the subsurface. More specifically, a synthetic transfer zone occurs where strain is transferred between two parallel normal faults in an extensional system. A previous study used surface curvatures derived from a clay model to highlight different geological features related to a synthetic transfer zone, including fault planes and relay ramps. We follow the same approach, applying our understanding to a 3D seismic survey to identify geological features related to a synthetic transfer zone. This study discusses the effect of synthetic transfer zones on an intrabasin extensional system, and describes listric normal faults and a relay ramp using the curvature and coherence seismic attributes. Our research area focuses on Penobscot, an offshore potential field in the Scotian Basin.
Presentation Date: Wednesday, September 27, 2017
Start Time: 4:20 PM
Presentation Type: ORAL
Zhao, Huawei (State Key Laboratory of Petroleum Resources and Prospecting in China University of Petroleum, Beijing (CUPB)) | Ning, Zhengfu (State Key Laboratory of Petroleum Resources and Prospecting in China University of Petroleum, Beijing (CUPB)) | Zhao, Tianyi (State Key Laboratory of Petroleum Resources and Prospecting in China University of Petroleum, Beijing (CUPB)) | Yu, Lei (Research Institue of Exploration & Development of Changqing Oilfiled Company, PetroChina) | Zhang, Rui (State Key Laboratory of Petroleum Resources and Prospecting in CUPB) | Dou, Xiangji (Ministry of Education Key Laboratory of Petroleum Engineering in CUPB) | Hou, Tengfei (Ministry of Education Key Laboratory of Petroleum Engineering in CUPB)
To evaluate the exploration potential of tight oil reservoirs in the Upper Triassic Yanchang Formation, a combined research was done to investigate the source rock distribution, diagensis, pore systems, petrophysical parameters. To begin with, the horizontal distribution and vertical thickness of the reservoir were clarified with data from well drilling and regional geological background. After that, X-ray diffraction and scanning electron microscopy experiments were conducted to study the pore types and morphologies. Then the pore size distribution was calculated based on mercury injection capillary pressure data. Finally, porosity and permeability were tested. Also, the causes of the tight sandstone, the controlling factor of petrophysical parameters and the fracability were discussed.
The Upper Triassic Yanchang Formation is rich in tight oil reserves and shows good exploration potential. Horizontally, reservoir is accumulated at the centre of the lake deposit with an area of 7.5×103 km2; vertically, reservoir is in Chang 6, Chang 7 and Chang 8 member with total depth 25–80m, among which Chang 7 member acts as the main source rock. Sediments are mainly fine grained sand, cements including clays, calcite and dolomite. After early stage mechanical compaction and late stage cementation, the reservoir becomes quite tight. Pores are classified into four types, residual interparticle pores, intraparticle grain pores, clay dominated pores, and micro fractures. Residual interparticle pores and clay dominate pores are main pore types for storage and flow; existence of micro fracture can improve permeability and is a good indication of fracturing potential. Porosity is between 6.12–13.80% and air permeability normally smaller than 0.3 mD, the early stage compaction is the main reason of porosity reduction, while combination of compaction and cementation results in dramatic decreasing in permeability. This reservoir can be commercially developed with horizontal well and hydraulic fracturing stimulation.
This study provides a workflow to fully characterize the storage and transport properties of a tight oil reservoir, and the workflow can act as reference to other similar reservoirs.
In April 2009 a comprehensive review of the prospectivity of the offshore Nova Scotia Basin was commissioned by the Offshore Energy Technical Research Association of Nova Scotia (OETR). This was fundamentally based on a complete reevaluation of the exploration history of the Scotian margin.
This paper describes the overall approach used in this study and presents the main results and key conclusions.
The play fairway program addressed three key issues:
1. Plate Tectonic Reconstruction: a better understanding of the rift history of the Nova Scotia/Morocco conjugate margin pair was needed. Understanding the relationship between rifting and salt deposition is critical in developing models for potential syn-rift and early post rift depositional environment and the development of source rocks.
2. Sequence Stratigraphic Framework: lack of a published modern sequence stratigraphic framework for the margin has impeded the development of robust regional exploration models. Hence the program included a re-evaluation of the biostratigraphy of several key wells, which were integrated with the seismic interpretation, and tectonic models, to build a comprehensive sequence framework.
3. Forensic Geochemistry: although much geochemical data exists on the margin through the many hydrocarbon shows and discoveries, the source rock story was not well understood. The program has undertaken a systematic evaluation of the geochemistry of source rocks and hydrocarbon fluids. An important component of this work was analysis of hydrocarbon bearing fluid inclusion found in the salt. A key goal of this project was to demonstrate evidence for lacustrine or restricted marine early Jurassic source rocks, which would considerably enhance the hydrocarbon potential of the area.
The program integrated a number of specialist sub-projects to help develop a robust regional exploration model for the Scotian margin. These included extensive work on biostratigraphy, plate tectonics, seismic interpretation, geochemistry, petroleum systems analysis as well as acquisition of new geophysical data (refraction seismic) and reprocessing of multichannel and existing refraction seismic. The whole integrates to deliver a set of Gross Depositional Environment (GDE) maps built on internally consistent sequence and seismic stratigraphic interpretations. A key component of this was development of a thorough understanding of the salt kinematics offshore Nova Scotia. The complex salt dynamics have had a very significant influence on sediment dispersal pathways and present a significant challenge to oil and gas exploration.
The paper shows the underlying geological models that underpin the prospectivity of the Scotian margin. A number of plays can be been defined, including Jurassic carbonates, delta and deep marine reservoir systems, sourced locally or from deeper syn/post rift lacustrine/restricted marine sediments. Extensive large-scale salt related structures show the potential of a high value petroleum province in the under-explored shelf/deep water areas offshore Nova Scotia.
This paper presents part of the modeling results obtained in the Play Fairway Analysis project launched in 2009 by OETRA that consists of an integrated geosciences approach in a collaborative program between academy and industry institutions. A 210 km long depth-migrated seismic line (NovaSPAN 1400) was interpreted in age, paleo-environments and lithology. The structural evolution was reconstructed to constrain the backstripping. Two major source rocks, Late Jurassic marine type II and Early Cretaceous terrestrial type III were identified from pyrolysis analyses. A third type II source, of Early Jurassic age has been inferred from the presence of Gammacerane biomarkers in the Venture B13 condensates, which were correlated with Pliensbachian source rocks and oils from the conjugate margin in Morocco and Portugal.
The interpreted section displays 3 structural domains: the little deformed shelf area, the strongly disturbed bathyal domain with complex salt tectonics structures and the flat lying strata domain of the abyssal plain.
Modeling results show that the Early Jurassic and Late Jurassic sources are presently in the gas and oil window respectively. Early cretaceous is immature. Expulsion and entrapment occurred lately and first significant accumulations appeared during the Cretaceous (about 80 Ma ago) and are still active today. Three potential plays can be considered for exploration: 1) Late Jurassic carbonate bank with a risk of biodegradation due to low Present temperature (around 60°C); 2) Early Jurassic carbonate ramp along the northern salt basin boundary, 3) Hypothetical turbiditic sands in the Early Cretaceous (Logan Canyon equivalent)
Exploration in the Sable Sub-basin shelf is relatively immature and still holds surprising near-field exploration prospectivity around the Sable Offshore Energy Project (SOEP) infrastructure. Shell and partners have drilled 19 exploration wells on the current Shell interest leases in the Sable Sub-basin from 1969 to 2001 and have discovered nearly 1BBOE. Exploration proceeded in 3 phases, an early phase of hydropressure exploration, a main phase of deep geopressure exploration, and a later phase of exploration in geopressures.
The early phase of exploration in hydropressures involved 5 wells from 1969 to 1975. Onondaga E-84, Triumph P-50, Thebaude P-84, Citnalta I-59, and Intrepid L-80 tested reservoir objectives ranging from the Late Jurassic MicMac Formation to the Early Cretaceous Upper Missisauga Formation. The discovered volume totaled 1.2 Tcf and 36MMBC. Drilling was suspended at the top of geopressures. Success at the top of geopressures in the Thebaude well encouraged deeper drilling in geopressures.
Discovery of the 1.5 Tcf Venture field in 1978 kicked off a phase of successful deep exploration in geopressures. Another 11 deep wells were drilled through 1985 and discovered another 2.65 Tcf in a series of moderate sized gas fields ranging from 130 to 437 Bcf. These fields include Arcadia, Glenelg, Olympia, Venture, South Uniacke, Alma, Chebucto, Venture West, and Triumph North. Hydrocarbons, primarily gas, were found in both geopressured and hydropressured reservoirs that ranged in age from the Late Jurassic to the Early Cretaceous.
The final phase of exploration resulted in only two wells since 1985, Sable South B-44 and Onondaga B-84, both resulted in discoveries. Most of the industry exploration in the basin since 1985 has focused on carbonate, not clastic plays.
The next phase of exploration remains to be tested by the drill bit. Fifty-five leads have been defined in the Sable Sub-basin around the Sable Offshore Energy Project (SOEP) infrastructure. All the leads are downthrown fault closures with shelf margin delta complexes as reservoirs. The combined factors of rapid subsidence, high sediment input from a large river, and proximity to the shelf margin result in thick geopressured reservoirs with multiple intra-formational seals and thick top seals. Fault closure traps occur along faults with large throw with potentially long columns. Several geopressured traps in the discovered fields have fault dependent columns ranging from 100m to 205m.
In conclusion, considerable scope for near field exploration is present in the Sable Sub-basin in conventional plays that have not been extensively explored since 1985.
In recent years shale resource plays have become increasingly important. However, understanding the controls on reservoir quality in shale formations is still in its infancy, despite thousands of well penetrations. Using examples from several shale resource plays, including the Haynesville, the Eagle Ford and the Muskwa formations, this paper demonstrates how inorganic whole rock geochemical data that are primarily obtained to provide stratigraphic correlations can be used to model mineralogy, model TOC, determine paleoredox facies, recognize zones of biogenic silica and aid with sequence stratigraphic interpretations.
The primary application of whole rock geochemical data to date has been providing stratigraphic correlation based around changes through time in elemental composition, i.e. chemostratigraphy. Stratigraphic correlation is of paramount importance for temporally and geographically constraining other reservoir characteristics. In addition to classic chemostratigraphy, the whole rock geochemical data provide information about terrigenous inputs, which can be used to help elucidate transgressive - regressive cycles and thereby help with understanding sequence stratigraphic correlations.
Reservoir quality in shale is dependent largely on mineralogy. Major element concentrations determined for chemostratigraphy can be used to model most mineral phases, including quartz, clay (semi quantitative abundance of kaolinite, illite and chlorite), calcite, dolomite, feldspars, pyrite and apatite. By adding select trace elements, typically U and Ni, the TOC contents can also be modeled. Furthermore, it will be demonstrated how by combing SiO2 concentrations with elements derived from terrigenous sources, it is possible to recognize zones where biogenic silica is present.
Paleoredox plays an important role in determining TOC values. Consideration of redox-sensitive elements, such as V, Ni, Th, U and Mo provides a means to determine the degree of anoxia during deposition. Using examples from the Haynesville Shale, it will be shown how anoxia is determined and how it varies laterally within the basin.
The methodologies shown in this paper are readily exportable to any shale resource play. The results can be generated from core, side-wall core and cuttings samples, providing a rapid, cost effective means to assess shale in a well-bore penetration.