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Collaborating Authors
Results
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...)
Summary Over the years, environmental legislation has forced changes in the types of scale-inhibitor molecule that can be deployed in certain regions of the world. These regulations have resulted in changes from phosphonate scale inhibitor to polymer-based chemistry, particularly in the Norwegian and UK continental shelf where phosphonates have been either on the substitution list or phased out for many applications. Over the past 10 years, significant improvements in inhibitor properties of the so-called "green" scale inhibitors have been made. However, for one particular operator, the squeeze application of this green scale inhibitor resulted in poorer than expected treatment lifetimes and significant operating cost because of the frequency of retreatment. To overcome the increasing operating cost, an evaluation was made of the current treatment chemicals vs. the older, more-established phosphonate scale inhibitors. The results for the laboratory evaluation suggested that the older chemistry would extend treatment life and reduce operating cost. A case was made to the legislative authority, who approved the use of the phosphonate scale inhibitor, and field applications started. The squeeze lifetimes for the red phosphonate chemistry were shown to be significantly better than the existing yellow/green inhibitors. During the following months, other scale inhibitors with improved environmental characteristics were developed and evaluated. One such molecule was shown to have similar coreflood retention to that of the applied red phosphonate and presented no formation damage. This paper presents the laboratory evaluation of the new scale inhibitor, and illustrates the improvement observed with this new inhibitor through field squeeze-treatment results from a well treated with both the red and new yellow environmental profile inhibitor chemicals. This paper outlines the challenges with environmental legislation and how it has been possible to develop technical solutions (in terms of environmental vs. safety issues and with new inhibitor chemicals) to meet the challenges of offshore scale control.
- Europe > United Kingdom > North Sea (0.51)
- Europe > Norway > North Sea > Central North Sea (0.28)
- Water & Waste Management > Water Management > Water & Sanitation Products (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Sleipner Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Skagerrak Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 038 > Block 15/12 > Varg Field > Hugin Formation (0.99)
- (22 more...)
Abstract INPEX has begun construction of one of the world's largest oil and gas projects following the Final Investment Decision (FID) on the US $34 Billion Ichthys LNG Project in Australia on 13 January 2012. The Ichthys LNG Project is a joint venture between INPEX (Operator) and Total with Tokyo Gas, Osaka Gas, Chubu Electric and Toho Gas. The Ichthys Field is situated in the Timor Sea approximately 200 kilometers off the Western Australian coast and over 800 kilometers from Darwin. Three exploratory wells drilled in 2000 and 2001 resulted in the discovery of an extremely promising gas and condensate field with resource estimates from two reservoirs totaling approximately 12TCF of gas and 500 million barrels of condensate. Conceptual studies, FEED and ITT followed and development leading to sanctioning of the Ichthys LNG Project by INPEX and Total. Gas from the Ichthys Gas-Condensate Field in the Browse Basin will undergo preliminary processing offshore to remove water and extract condensate. The gas will then be exported to onshore processing facilities in Darwin via an 889 kilometer subsea Gas Export Pipeline (GEP). Most condensate will be sent to a Floating Production Storage and Offloading (FPSO) vessel for stabilization and storage prior to being shipped to global markets. The Ichthys LNG Project is expected to produce 8.4 million tons of LNG and 1.6 million tons of LPG per annum, along with approximately 100,000 barrels of condensate per day at peak.
- Oceania > Australia > Western Australia > North West Shelf (1.00)
- Asia > Japan > Kantō > Tokyo Metropolis Prefecture > Tokyo (0.24)
- Asia > Japan > Kansai > Osaka Prefecture > Osaka (0.24)
- 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 > Caswell Basin > Ichthys Field (0.99)
- (3 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)
Summary Geoscience techniques that are well established for conventional oil and gas exploration and production are equally applicable to shale gas systems. A robust data set allowed lithostratigraphic classifications and reservoir characterizations to be carried out in the Horn River Basin of northeast British Columbia. When it was demonstrated that statistical relationships existed between the lithostratigraphic classifications and elastic rock properties it became possible to invert 3D seismic volumes for the elastic properties and map the lithostratigraphic units by directly applying the statistical relationships. These findings for lithostratigraphic classifications are also applicable to key shale gas reservoir properties such as porosity or total organic carbon. From these transformations it was straightforward to apply standard data-reduction and mapping processes to determine quantities needed for key project decisions such as pad design and land acquisition rankings.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.89)
- Geology > Geological Subdiscipline > Stratigraphy > Lithostratigraphy (0.87)
- 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)
- (7 more...)
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 The region immediately south of West Timor, offshore Indonesia, has been largely underexplored, with only one well drilled onshore in the West Timor Block operated by eni, and no wells drilled offshore. The area is located along the Outer Banda Arc, a geologically complex, non-volcanic semi-circular belt where the Australian and Asian Plates obliquely collide. The main reservoir target is the clastic Plover formation. Imaging and resolution of the Top Jurassic horizon and the overlying accretionary section is the primary geophysical objective for prospect generation and poses a formidable challenge to marine seismic acquisition and processing. The seismic exploration history dates back to a legacy 2D survey in 1991. In 2009, a regional 2D survey using towed streamer dual-sensor broadband technology yielded significantly improved continuity of events beneath the accretionary section. Encouraged by these results, in 2010 eni acquired a pilot study of 2D lines and subsequently a 3D survey using the same broadband acquisition technology. Broadband marine seismic via dual-sensor streamer resulted in improved resolution of the overburden and greater penetration at the target level. These benefits are a direct consequence of eliminating the receiver ghost. Ghost-free data is rich in both low and high frequencies, has improved signal to noise ratio, and is easier to interpret. A second important contribution comes from utilizing a unique implementation of Beam Depth Migration to correctly image the complex overburden and underlying target structure. Unique aspects of this implementation include near-vertical steep dip imaging, residual multiple attenuation in the depth domain, and the ability to detect and correctly position weak signal. These features play an important role in imaging both the accretionary prism and the target structure. The combination of the broadband dual-sensor acquisition and the Beam migration imaging provided significant uplift in the understanding and interpretability of the seismic data promoting the development of a new exploration play in the region.
- Asia > Indonesia (0.72)
- North America > United States > Illinois > Madison County (0.45)
- Oceania > Australia > Western Australia > North West Shelf > Browse Basin > Block WA-315-P > Plover Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Browse Basin > Block WA-274-P > Plover Formation (0.99)
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)