In this paper, we present for the first time, a classification system for naturally-occurring gas hydrate deposits existing in the permafrost and marine environment. This classification is relatively simple but highlights the salient features of a gas hydrate deposit which are important for their exploration and production such as location, porosity system, gas origin and migration path. We then show how this classification can be used to describe eight well-studied gas hydrate deposits in permafrost and marine environment. Potential implications of this classification are also discussed.
Introduction Of the three permafrost regions, our calculations show Mohe Basin has the thickest hydrate stability (1300 m). This is followed by Qinghai-Tibet Plateau (1200 m) and Qilian Mountain (800 m).
Le, Huy (Geophysics Department, Stanford University) | Pradhan, Anshuman (Geophysics Department, Stanford University) | Dutta, Nader C. (Geophysics Department, Stanford University) | Biondi, Biondo (Geophysics Department, Stanford University) | Mukerji, Tapan (Geophysics Department, Stanford University) | Levin, Stewart A. (Geophysics Department, Stanford University)
We use a workflow that combines various sources of information, such as mud weights, well logs, basin history, and diagenesis, to model pore pressure-velocity relationship based on rock physics principles. This produces velocity templates, which can be used to build velocity models for imaging and inversion. We apply this workflow to a data set from the Gulf of Mexico. We study the diagenesis of shale, particularly, smectite-illite reaction. From well logs, we build models for velocity-porosity and density-overburden relations. Thermal history is approximated from available Bottom Hole Temperature (BHT) data and depositional history is inferred from interpreted horizons. We use mud weight data to calibrate pore pressure-velocity transformation. A number of different pore pressure gradient scenarios result in different velocity profiles or templates. The integration and calibration of many sources of data in this workflow ensure the resulting velocity model is geologically feasible and physically plausible.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: 202A (Anaheim Convention Center)
Presentation Type: Oral
Shafrova, Svetlana (ExxonMobil Upstream Research Company) | Holub, Curtis (ExxonMobil Upstream Research Company) | Harris, Matthew (ExxonMobil Upstream Research Company) | Cheng, Tao (ExxonMobil Upstream Research Company) | Matskevitch, Dmitri (ExxonMobil Upstream Research Company) | Foltz, Raymond (ExxonMobil Upstream Research Company) | Mitchell, Douglas (ExxonMobil Upstream Research Company)
A Common Operational Picture (COP) can generally be described as a system of hardware and software that produces a shared display of information to facilitate situational awareness and decision making. A brief history of the development and use of COP technology in Arctic operations is provided. Experience and learnings from ExxonMobil's research into the use of COPs in ice management and Arctic floating drilling is described. Experience gained from simulations, desktop studies, and field observations is used to frame preliminary functional requirements for such technology needed for future Arctic floating drilling operations in high concentration ice. The COP must facilitate the planning and execution of complex and remote operations with many geographically distributed assets (e.g., drilling rig; icebreakers; shore base; manned or unmanned aviation) and stakeholders (e.g., icebreaker captains, drilling management, ice analysts, weather forecasters) at times communicating over limited bandwidth channels. The COP will serve to collect, store, communicate, and display the necessary data and information. The role of COP components (e.g., databases; communication network, displays) is described and functional requirements are outlined.
This paper presents a case for flexibility in the design of an effective and efficient Arctic lease tenure system, with a particular focus on the Canadian Arctic lease tenure system. The author will outline aspects of the legal approaches that have been adopted in the countries with Arctic coastlines and recommend modifications to the Canadian Arctic tenure system that are necessary to enable the effective exploration and development of hydrocarbons in deepwater areas of the Beaufort Sea.
Subsalt velocity model building is challenging due to a limited seismic raypath, narrow angle coverage, scattering effects, and mode conversion caused by the large elastic property contrast between the salt body and background sediments. Uncertainty in the salt geometry and lack of well control aggregate further the subsalt velocity model-building process.
To overcome these drawbacks, a workflow that integrates well and seismic data, guided by a regional stratigraphic framework, and constrained by rock-physics modeling was adopted to generate a basin-scale subsalt velocity model that covers more than 50,000 km2 (over 2,000 Outer Continental Shelf (OCS) blocks) in the central Gulf of Mexico. Over 300 subsalt wells and multiple wide-azimuth and full-azimuth seismic surveys were utilized to build the model. The velocity model was further validated through iterations of full-azimuth subsalt tomography. As a result, the final velocity model is consistent with both well and seismic measurements, follows stratigraphic framework, and obeys the law of rock physics. The final model was used in prestack depth migration of wide-azimuth and full-azimuth seismic data over the entire area, yielding a superb result. It can be used as a benchmark earth velocity model in the central Gulf of Mexico for exploration and appraisal applications.
Presentation Date: Wednesday, October 19, 2016
Start Time: 3:10:00 PM
Presentation Type: ORAL
Wu, Songtao (Research Institute of Petroleum Exploration & Development) | Su, Ling (Research Institute of Petroleum Exploration & Development) | Zhai, Xiufen (Research Institute of Petroleum Exploration & Development) | Zhu, Rukai (Research Institute of Petroleum Exploration & Development) | Cui, Jinggang (Research Institute of Petroleum Exploration & Development)
Three low mature shale samples, including Triassic Chang 7 shales from the Ordos Basin, Permian Lucaogou shales from the Junggar Basin, and Middle Proterozoic Ximaling shales from North China are slected as study objects. The 3-D porosity evolution with temperature increase and its main controlling factors are analyzed based on the physical modeling under high temperature & pressure and nano-CT scanning data. More and more nano-pores were developed in three organic-rich shales with the increase of maturity. The porosity calculated from the nano-CT scanning model increased more than 250% times larger, when temperature increased from 20 centigrade to 550 centigrade. The process of porosity evolution can be divided into three phases. Firstly, porosity decreased rapidly from immature to low mature stage because of weak hydrocarbon generation and strong compaction; Secondly, porosity increased rapidly when the maturity increased from low mature stage to mature and post-mature stage, organic matter cracked into hydrocarbon (HC) massively, and clay minerals transformed intensively; Thirdly, porosity system kept stable when the shale entered into post-mature stage and the intensity of both HC generation and clay mineral transformation decreased. Organic matter thermal evolution, clay mineral transformation and brittle mineral transformation make different contribution to the porosity of shale, and the ratio is 6:3:1 respectively. It is inferred abundant organic matter pores occur when Ro is over 1.2%.
In recent years, with the successful exploration and development of shale oil and gas, researchers have realized shale can not only serve as “source and caprock” but also reservoir. Shale reservoirs have drawn universal attention and become a research hotspot. Researchers at home and abroad have made extensive studies on the static characterization of shale reservoir space, and achieved valuable information on pore type, size, shape, distribution and connectivity (Loucks et al., 2009; Joel et al., 2011; Songdergeld et al., 2011; Zou et al., 2014; Chalmers et al., 2012), but there are few reports on shale porosity evolution. Different from the evolution of conventional sandstone reservoirs, which is mainly controlled by diagenesis, shale porosity evolution is a process combining porosity increase caused by hydrocarbon generation, and porosity decrease caused by compaction and cementation, controlled jointly by hydrocarbon (HC) generation and diagenesis (Jarvie et al., 2007; Cui et al., 2013; Hu, 2013; Schieber, 2010). The Published methods for shale porosity evolution study can be divided into two groups: (1) Visual observation, which includes analysis on shale samples of different maturities with high resolution equipment, such as Field-emission SEM, to find out differences in pore development. This intuitive method can provide direct information on pore structures, neglect heterogeneity and regional difference of samples, focuse on the organic matter (OM) pores and ignore inorganic matter pores. Therefore, the overall porosity evolution characteristics of shale cannot be demonstrated, and different researchers may produce variable results. Most researchers hold that with a rise of thermal evolution degree of organic matter in shale, the number of organic matter pores increase (Jarvie et al., 2012). However, Curtis et al. (2011) found the size and percentage of organic matter pores in Marcellus shale decreased with increasing maturity; Also, Fishman et al. (2012) found no obvious increase in the size and number of organic matter pores with increasing maturity; (2) Physical modeling, which involves selecting low mature samples, inducing hydrocarbon generation at set temperature sequence, and analyzing pore changes at different stages by using gas adsorption quantitatively (Cui et al., 2013; Hu, 2013). This method, highly comparable, can decrease the influence of heterogeneity on experimental results, and provide all-sided characteristics of porosity evolution, but it cannot provide intuitive images to show the mineral and porosity evolution and cannot analyze different evolution features of organic matter pores and inorganic matter pores. Given these challenges, these two methods were adopted jointly in this research. Taking low mature organic-rich shale samples from China as research objects, high T&P physical modeling, Nano-CT and SEM were used to obtain in-situ 3-D and 2-D structure of the same sample to evaluate the porosity evolution at the same position with varying temperature. Meanwhile, image analysis, gas adsorption, XRD, rock-eval analysis were used jointly to evaluate the porosity changes and find out the effects of different mineral components on porosity evolution, which can provide reference for favorable reservoir prediction and evaluation.
Canada and the United States collaborated in geophysical survey operations in the Amerasia Basin from 2007 to 2011 using the Canadian icebreaker CCGS Louis S. St. Laurent and the US icebreaker USCGC Healy. Over 15000 km of bathymetry, sub-bottom profiles, and 16-channel seismic reflection data were acquired over the Canada Basin and Alpha Ridge. Expendable sonobuoys were deployed to collect P-wave refraction and wide angle reflection data to define the regional velocity structure of the sedimentary successions. Although the new seismic profiles tie with existing GSC multichannel seismic lines on the Beaufort Shelf, water-bottom multiples obscure direct correlation of deeper stratigraphic horizons and (at best) basement is poorly imaged. We present a 2-D gravity and magnetic model for the southern Canada Basin margin and Beaufort-Mackenzie Basin integrating the new LSSL data with an existing deep crustal seismic reflection profile. The model crosses the slope region, where bathymetry shallows, base-of-sediments is deep, and basement is not imaged because of the water-bottom multiple. The density values used in the model are constrained by empirical relationships between velocity and density rock properties; however, magnetic susceptibility values are based on typical values for the inferred crustal lithologies. Velocity analyses of the new sonobuoy data provide constraints on the composition of the sediments, and enable quantitative mapping of continental, oceanic, and transitional domains within the Canada Basin. The 2-D gravity and magnetic forward model provides estimates for basement and Moho depths, the distribution and depths of magnetic sources, and visualization of the underlying crustal architecture controlling basin formation.
Copyright 2014, Offshore Technology Conference This paper was prepared for presentation at the Arctic Technology Conference held in Houston, Texas, USA, 10-12 February 2014. This paper was selected for presentation by an ATC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright. I. Introduction Overview As climate change renders the Arctic increasingly accessible, there has been a substantial uptick in industry interest in the region; it is believed an estimated $100 billion could be invested in the Arctic over the next decade. The Arctic contains vast oil and natural gas reserves--the U.S. Geological Survey estimates the Arctic could contain 1,670 trillion cubic feet (tcf) of natural gas and 90 billion barrels of oil, or 30 percent of the world's undiscovered gas and 13 percent of oil. Energy companies are certain to be at the forefront of Arctic development and investment. Climate change has played an important role in expanding access to the Arctic region, although there have been fewer opportunities to access lower cost oil and gas plays. As conventional production has declined, industry has had to focus more on difficult-to-access and unconventional oil and gas plays throughout the world, including those in the Arctic. Exploration and development in the Arctic requires expensive, tailored technologies as well as safeguards adapted to the extreme climatic conditions. In the wake of the 2010 Deepwater Horizon incident, there have been additional costs associated with emergency response and containment requirements. Regulators, as well as social and environmental groups, have been outspoken about the dangers and risks linked to Arctic energy development. Bearing in mind the enormous challenges of cleaning up an oil spill in icy conditions, the greatest concern is what kind of impact such a disaster would have on the fragile Arctic ecosystem.
MacDonald, Jeffrey Andrew (Osum Oil Sands Corp.) | Yuan, Jian-Yang (Osum Oil Sands Corp.) | Huang, Haibo (Alberta Innovates Technology Futures) | Jiang, Qi (Osum Oil Sands Corp.) | Rabin, Mark (Osum Oil Sands Corp.) | Donald, James (Alberta Innovates Technology Futures) | Chen, Joyce X (Alberta Innovates Technology Futures)
The difficulties of accurately measuring thermal properties, such as thermal conductivity of fractured and/or vuggy rocks are well known. Many commercially available methods are suitable only for liquids or re-packed sands. Others either require samples to be fairly uniform or are potentially destructive due to sample size limitations. In-situ measurements are possible, but can be costly. It can also be affected by in-situ distributions of fluids in the fractures and vugs, such as water, oil and possibly gas. In order to adapt the highly non-uniform nature of the carbonate cores without having to create further destruction of these cores, we developed a non-destructive method for measuring thermal conductivity of highly vuggy and moderately fractured carbonate cores in their whole diameter. In this paper, we report the theoretical background of this methodology; laboratory observations of thermal behaviours; data analysis and resulting thermal conductivity values of carbonates cores. Using this method, we measured 20 cleaned carbonate cores (88 mm in diameter) from Grosmont C and D Formation in Saleski area. Measured thermal conductivity values ranged from 1.00 to 2.87 W/m·K in Grosmont C, and 0.82 to 3.16 W/m·K in Grosmont D. These values were determined to be a strong function of porosity rather than mineralogy, as the Grosmont Formation typically consists of greater than 95% dolomite. These measurements are also shown to be in good agreement with prior studies on non-fractured dolomite reservoirs. A correlation for thermal conductivity was derived which can be used for numerical simulation models.