Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
When Gerald Schotman, Shell's chief technology officer, looks at the unconventional oil and gas business, he sees so many young technologies and "from the perspective a chief technology officer, that is such an opportunity." Shell's list of promising areas for research and development is broad, ranging from creating cheaper, more effective sensors for seismic testing to a new generation of specialized, automated drilling rigs. The goal is always "change that creates value." In natural gas the rewards can be broken down three ways: produce more gas per well now, bring down the costs per well, and reduce the footprint when doing so. The footprint can be defined in many ways: the size of the pads used for drilling multiple wells; the level of emissions; the water used; and the many ways exploration and production can touch the people and the environment, near and far.
- Oceania > Australia > Western Australia > Western Australia > Timor Sea > Browse Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Timor Sea > Browse Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Browse Basin > WA-371-P Permit > Block WA-371-P > Prelude Field > Plover Formation (0.99)
- (4 more...)
Static and Dynamic Estimates of CO2-Storage Capacity in Two Saline Formations in the UK
Jin, M.. (Heriot-Watt University) | Pickup, G.. (Heriot-Watt University) | Mackay, E.. (Heriot-Watt University) | Todd, A.. (Heriot-Watt University) | Sohrabi, M.. (Heriot-Watt University) | Monaghan, A.. (British Geological Survey) | Naylor, M.. (University of Edinburgh)
Summary Estimation of carbon dioxide (CO2)-storage capacity is a key step in the appraisal of CO2-storage sites. Different calculation methods may lead to widely diverging values. The compressibility method is a commonly used static method for estimating storage capacity of saline aquifers: It is simple, is easy to use, and requires a minimum of input data. Alternatively, a numerical reservoir simulation provides a dynamic method that includes Darcy flow calculations. More input data are required for dynamic simulation, and it is more computationally intensive, but it takes into account migration pathways and dissolution effects, so it is generally more accurate and more useful. For example, the CO2-migration plume may be used to identify appropriate monitoring techniques, and the analysis of the trapping mechanism for a certain site will help to optimize well location and the injection plan. Two hypothetical saline-aquifer storage sites in the UK, one in Lincolnshire and the other in the Firth of Forth, were analyzed. The Lincolnshire site has a comparatively simple geology, while the Forth site has a more complex geology. For each site, both static- and dynamic-capacity calculations were performed. In the static method, CO2 was injected until the average pressure reached a critical value. In the migration-monitoring case, CO2 was injected for 15 years, and was followed by a closure period lasting thousands of years. The fraction of dissolved CO2 and the fraction immobilized by pore-scale trapping were calculated. The results of both geological systems show that the migration of CO2 is strongly influenced by the local heterogeneity. The calculated storage efficiency for the Lincolnshire site varied between 0.34% and 0.65% of the total pore-volume, depending on whether the system boundaries were considered open or closed. Simulation of the deeper, more complex Forth geological system gave storage capacities as high as 1.05%. This work was part of the CO2-Aquifer-Storage Site Evaluation and Monitoring (CASSEM) integrated study to derive methodologies for assessment of CO2 storage in saline formations. Although static estimates are useful for initial assessment when fewer data are available, we demonstrate the value of performing dynamic storage calculations and the opportunities to identify mechanisms for optimizing the storage capacity.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Oceania > Australia > Western Australia > Bonaparte Basin > Petrel Basin (0.89)
- Oceania > Australia > Western Australia > Ashmore Cartier Territory > Timor Sea > Bonaparte Basin > Londonderry High > Vulcan Basin > Eclipse Field (0.89)
- Oceania > Australia > Western Australia > Ashmore Cartier Territory > Timor Sea > Bonaparte Basin > Bonaparte Basin > Vulcan Basin > Eclipse Field (0.89)
- (3 more...)
The ability to high-grade gas shales is essential to optimizing completions and maximizing stimulated rock volume (SRV) in the capital-intensive development of the Horn River resource play in northeast British Columbia (NEBC). To assist in optimizing stimulation efforts, seismic data are used to estimate and map four parameters that influence hydraulic fracture effectiveness: rock properties, in-situ stress, natural fractures, and reservoir geometry.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.63)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.47)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation > Seismic Reservoir Characterization > Amplitude vs Offset (AVO) (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.94)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (4 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
Abstract This paper describes the selection, design, successful application and performance monitoring of Electrical Submersible Pumps (ESP) in the giant Mangala oil field and Thumbli water field situated in the Barmer basin in Rajasthan, India. Mangala oil field contains in excess of 1 billion barrels of STOIIP (Stock Tank Oil Initially in Place) in high-quality fluvial reservoirs. The field was brought on production in August 2009 and is currently producing at the plateau production rate of 150,000 bopd of which approximately more than one- third of the oil production is from the ESP oil wells. To support the water requirement of Mangala and other satellite oil fields, Thumbli source water field was developed with 5 water production wells with up to 4 wells operating at a time. Each of these water wells is installed with 60,000 bwpd capacity pumps and the field is currently producing up to 225,000 bwpd to meet the water requirements of Mangala and other satellite fields. The Mangala oil field is a multilayer, multi-Darcy reservoir, has waxy viscous crude with in-situ oil viscosity up to 22 cp and wax content in the range of 18 to 26%. The field was developed using hot water flood for pressure maintenance. Significant production challenges included unfavorable mobility ratio with early water cut and hence the early requirement of artificial lift to maintain the plateau production rate. The field has 12 horizontal producers and 92 deviated producers. ESP was selected as the artificial lift method for the high rate horizontal producers while hot water jet pumping was selected as the artificial lift method for low rate deviated oil wells. Each horizontal well is capable of producing up to 15,000 blpd and high rate ESPs were designed and installed to deliver the production requirement. Currently 8 of the 12 horizontal producers are on ESP lift and the remaining four wells are planned for ESP installation in the near future. Apart from two early ESP failures during installation, ESPs have had a good run life; the paper also describes lessons learnt from the infant mortalities. The Thumbli water field, located ~20 km southeast of Mangala field has been developed to meet the water requirement of Mangala and other satellite fields. Thumbli water aquifer is a shallow water field which contains water of ~ 5000 ppm salinity with dissolved CO2, oxygen, chlorides and sulphate reducing bacteria (SRB). 5 high capacity water wells were drilled in Thumbli field to meet the huge water demand from Mangala for water injection in Mangala and satellite field injector wells, hot water circulation in oil production wells and associated water requirement for boilers etc. 1000 HP water well ESPs were designed to produce up to 60,000 bwpd from each well with installed water production capacity of up to 300,000 bwpd from Thumbli field. A state of the art ESP control and monitoring architecture including ESP tornado plotting was developed and successfully implemented in the ICSS to remotely operate, monitor and optimize ESP well performance from the central control room within Mangala field and from the company headquarter located in Gurgaon.
- Geology > Sedimentary Geology > Depositional Environment (0.34)
- Geology > Mineral > Sulfate (0.34)
- Oceania > Australia > Western Australia > Indian Ocean > Perth Basin > Abrolhos Basin > Block WA-325-P > Cliff Head Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.95)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.95)
- (9 more...)
A Diagenetic Diagram as a Tool for Systematic Detailed Characterization of Carbonate Rocks: Applications to the Diagenetic Evolution of Hydrocarbon Reservoirs
Inês, Nuno (Partex Oil and Gas) | Azerêdo, Ana (Universidade Lisboa, Faculdade, Ciências, Departamento and Centro de Geologia, Lisboa, Portugal) | Bizarro, Paulo (Partex Oil and Gas) | Ribeiro, Teresa (Partex Oil and Gas) | Nagah, Adnan (The Petroleum Institute, Abu Dhabi)
Abstract Carbonate reservoirs are commonly heterogeneous and their reservoir quality results from complex interactions between depositional facies and diagenetic processes. The Diagenetic Diagram is a powerful tool that helps in the characterization of the diagenetic processes that have affected the reservoir. From this knowledge, it is possible to significantly improve the understanding of the reservoir's pore system and permeability distributions, which are key factors for development optimization and production sustainability. A multi-scale and multi-method study (petrography, blue-dye impregnation, selective staining and porosity determination) of Middle Jurassic carbonates from the Lusitanian Basin (Portugal) has been undertaken, to find the best systematic approach to these reservoirs. It has involved thorough diagenetic characterization of each lithotype (lithofacies, texture, porosity, qualitative permeability assessment and diagenetic evolution). The study area was selected based on its excellent and varied exposures of carbonate facies and availability of core. Methodological and terminological challenges were faced during the study, especially dealing with data coming from several scales (macro, meso, and micro). In order to overcome these challenges, a diagenetic diagram was developed and applied to the selected rocks. It is a tool that allows the integration of data coming from outcrops, hand samples, cores, cuttings, thin sections, and laboratory experiments. This is carried out in a dynamic, guided, systematic, and rigorous way, enabling the evaluation of the relationship between facies, diagenetic evolution and pore systems. The latter are characterized regarding size, geometry, distribution, and connectivity. This enables the identification and characterization of permeability heterogeneities in the rocks. It was concluded that the main porosity class (i.e. secondary) was created by diagenetic processes. The proposed method has strong application potential for: detailed characterization and understanding of porosity and permeability in carbonate reservoirs, from a diagenetic evolution and fluid flow perspective (e.g. SCAL and pore system description); definition of diagenetic trends for modeling petrophysical properties and rock types. In this regard, the method is being applied to a Valanginian carbonate reservoir in Kazakhstan, and some preliminary results are presented in this paper. Refining this technique may be helpful for similar carbonate studies, enhancing the results of typical diagenetic studies by improving the characterization of reservoir properties at various scales, thus contributing to a more sustainable exploitation of hydrocarbon reservoirs.
- North America > United States (0.93)
- Asia (0.89)
- Europe > Portugal (0.88)
- Phanerozoic > Mesozoic > Jurassic (1.00)
- Phanerozoic > Mesozoic > Cretaceous > Lower Cretaceous (0.34)
- Geology > Sedimentary Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Oceania > Australia > Western Australia > Canning Basin (0.99)
- Europe > Portugal > Lusitanian Basin (0.99)
- Europe > Germany > Valanginian Basin (0.89)
Planning for Success: The Tridacna 3D Seismic Survey, Scott Reef, Western Australia – 3D Ocean Bottom Cable Seismic Acquisition in a Sensitive And Remote Offshore Environment.
Weiss, Ralph (Woodside Energy Limited) | Fitzpatrick, Jeremy (Woodside Energy Limited) | Taylor, Mark (Woodside Energy Limited)
Summary In late 2011 Woodside Energy Ltd (Woodside), as operator of the proposed Browse LNG Development, acquired the Tridacna 3D Ocean Bottom Cable (OBC) seismic survey (Tridacna survey) over north Scott Reef. The remote offshore location, environmental sensitivity, tidally-emergent reef crests and a semi-diurnal macro-tidal setting imposed significant operational limitations at Scott Reef. The ocean bottom cable technique was selected as the most appropriate technological solution for 3D seismic acquisition in this setting. The survey design incorporated the technical requirements for the acquisition of good-quality seismic data necessary for reservoir imaging whilst cognisant of the operational realities associated with contractor and equipment availability, a shallow restricted marine survey location, complex environmental approval conditions and cost/timing considerations. The survey operations comprised a wide range of activities, operational restrictions and personnel not normally part of conven-tional offshore towed streamer seismic surveys, and required highly-detailed operational planning. The Tridacna survey was successful in acquiring subsurface data and was completed safely with minimal environmental impact.
- Oceania > Australia > Western Australia > Timor Sea > Browse Basin > Caswell Basin > Block WA-30-R > BCT Fields > Torosa Field (0.99)
- Oceania > Australia > Western Australia > Timor Sea > Browse Basin > Caswell Basin > Block WA-28/32-R > BCT Fields > Brecknock Field > Plover Formation (0.94)
- Oceania > Australia > Western Australia > Timor Sea > Browse Basin > Caswell Basin > Block WA-28/31 > BCT Fields > Calliance Field > Plover Formation (0.94)
Summary In some areas, seismic data can exhibit the effects of strong azimuthal anisotropy (AA). One of the major causes of AA can be anomalous horizontal stress regimes, which can be modeled as horizontally transverse isotropy (HTI). The Stybarrow field, located offshore NW Australia in the Carnarvon sedimentary basin, is one such area, where strong horizontal stress conditions have been present throughout the basin’s tectonic history. We find evidence for AA in repeat 3D seismic data acquired at two separate azimuths over the Stybarrow field. AA is observed in amplitude versus offset (AVO) reflection amplitude difference maps and cross plots, and is consistent with dipole shear logs and borehole breakout data in the area. We model azimuthal AVO responses using Ruger’s HTI AVO equation, using the anisotropy parameters derived from dipole shear logs, and compare the results with AVO data from the two 3D seismic surveys. Certain fault blocks (but not all) exhibit the same AAVO trend in the seismic data as those modeled from log data, consistent with a stress-induced HTI anisotropic model interpretation.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-32-L > Stybarrow Field > Macedon Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > WA-255-P > Stybarrow Field > Macedon Formation (0.99)
SUMMARY The ability of the marine controlled source electromagnetic method to resolve anisotropy in the sediment conductivity is not very well understood. In this study, we address the resolvability of anisotropy using a Bayesian approach. Two markedly different methods, slice sampling and reversible jump Markov Chain Monte Carlo have been used for the Bayesian inversion of a synthetic model of a resistive oil reservoir trapped beneath the seabed. We use this to identify which components of data can provide the strongest constraints on anisotropy in the overburden, reservoir and underlying sediments.
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Plateau > WA-1-R > Scarborough Field (0.99)
- Africa > South Africa > Western Cape Province > Indian Ocean > Bredasdorp Basin > Block 9 > EM Field (0.99)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (0.72)
- Reservoir Description and Dynamics > Reservoir Simulation > Evaluation of uncertainties (0.72)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.56)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.49)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning (0.55)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Uncertainty > Bayesian Inference (0.34)
- Information Technology > Artificial Intelligence > Machine Learning > Learning Graphical Models > Directed Networks > Bayesian Learning (0.34)
Summary Uncertainties in marine controlled source electromagnetic (CSEM) data consist of two independent parts: measurement noise and position uncertainties. Measurement noise can be readily determined using stacking statistics in the Fourier domain. The uncertainties due to errors in position can be estimated using perturbation analysis given estimates of the uncertainties in transmitter-receiver geometries. However, the various geometric parameters are not independent (e.g. change in antenna dip affects antenna altitude, etc.) so how uncertainties derived from perturbation analysis can be combined to derive error-bars on CSEM data is not obvious. In this study, we use data from the 2009 survey of the Scarborough gas field to demonstrate that (a) a repeat tow may be used to quantify uncertainties from geometry, (b) perturbation analysis also yields a good estimate of data uncertainties as a function of range and frequency so long as the components are added arithmetically rather than in quadrature, and (c) lack of a complex error structure in inversion yields model results which are unrealistic and leads to "over-selling" of the capabilities of CSEM at any particular prospect.
Explorers are moving to increase the “discovery space” by exploring under cover and to greater depths, e.g., subsalt and sub-basalt exploration for oil and gas, and beneath transported cover for minerals. With this shift, there becomes an increased reliance on geophysical methods to delineate resources with no recognized geological or geochemical expressions. Different geophysical fields provide information about different physical properties of the Earth. Multiple geophysical surveys spanning gravity, magnetic, electromagnetic, and seismic methods are often interpreted to infer geology from models of different physical properties. In many cases, the various geophysical data are complementary, making it natural to consider a formal mathematical framework for their joint inversion to a shared Earth model. There are different approaches to joint inversion. The simplest case of joint inversion is where the physical properties are identical between different geophysical methods (e.g., Jupp and Vozoff, 1975). In other cases, joint inversion may infer theoretical, empirical, or statistical correlations between different physical properties (e.g., Hoversten et al., 2003, 2006). In cases where the physical properties are not correlated but, nevertheless, can be assumed to share a similar structure, joint inversions have been formulated as a minimization of the cross-gradients between different physical properties (e.g., Haber and Oldenburg, 1997; Gallardo and Meju, 2003, 2004). The latter has now been widely adopted by joint inversion practitioners as the de facto standard (e.g., Colombo and De Stefano, 2007; Hu et al., 2009; Jegen et al., 2009; De Stefano et al., 2011).
- Geology > Rock Type > Igneous Rock (0.90)
- Geology > Mineral > Native Element Mineral > Gold (0.47)
- Geology > Mineral > Oxide > Iron Oxide (0.33)
- Geophysics > Magnetic Surveying (1.00)
- Geophysics > Gravity Surveying (1.00)
- Geophysics > Electromagnetic Surveying (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (0.46)
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Oceania > Australia > Western Australia > Canning Basin > Block EP EP 390 > Olympic Field > Nita Formation (0.94)
- Oceania > Australia > Western Australia > Canning Basin > Block EP EP 390 > Olympic Field > Acacia Formation (0.94)
- Oceania > Australia > Western Australia > Canning Basin > Block EP 473 > Olympic Field > Nita Formation (0.94)
- (7 more...)