The world's energy challenges are multi-dimensional. Meeting growing demand, while also protecting the environment, will require an integrated series of solutions. Expanding all commercially viable energy sources, developing and deploying technology to help mitigate the growth of emissions, and accelerating gains in energy efficiency are all essential elements.
Energy efficiency is one of the largest and lowest-cost ways to extend our world's energy supplies and reduce greenhouse gas emissions. Between 1980 and 2005, nearly half the increase in global energy demand was met by improvements in energy efficiency. Further gains in energy efficiency through 2030 will curb demand growth by about 65 percent.
At ExxonMobil, we are taking actions to reduce energy usage and emissions in our own operations, and we are working on energy-efficient products and technologies that will help manufacturers and consumers do the same. On the operations side, we have invested 1.6 billion dollars since 2006 in activities that improve energy efficiency and reduce greenhouse gas emissions. Through our own actions, greenhouse gas emissions are down over 12 million tonnes since 2005, equivalent to removing about 2.5 million cars from U.S. roads.
Through deployment of our proprietary Global Energy Management System (GEMS), we have identified opportunities to improve the energy efficiency of our refineries and chemical plants by 15-20 percent. A strong focus on operation and maintenance of existing equipment, coupled with energy efficient design of new facilities, enabled us to achieve best-ever energy efficiency in 2010. We are on track to achieve our goal of improving energy efficiency across our worldwide refining and chemical operations by at least 10 percent from 2002-2012.
On the consumer side, we have developed a variety of technologies that are available today, including lighter-weight vehicle parts, improved tire liners, energy-efficient synthetic lubricants and lithium-ion battery separator films. We are also working on a number of breakthrough technologies to help power next generation lower-emission vehicles, and we continue to sponsor strategic research into ways to make alternatives like solar, hydrogen and biofuels more affordable for use on a broader scale.
Improving energy efficiency is more than just good business. It is a triple-winner that benefits companies, consumers, and the environment alike. More efficient operations extend the supply and affordability of conventional energy resources, while reducing plant operating costs and greenhouse gas emissions. Unlike other options, which may require trillions of dollars and decades to develop, improving energy efficiency can make a significant difference today.
Combustion and gasification of pulverized coal have been investigated experimentally for the conditions under high temperature gradient and CO2-rich atmospheres with 5% and 10% O2. Crushed coal samples were heated rapidly by a CO2 gas laser beam to give a high temperature gradient of order 100 °C!s-1 in order to simulate radiation heat transfer conditions expected in coal gasification furnaces. The rapid heating is able to minimize effects of coal oxidation and combustion compared with previous studies with a TG-DTA that requires much longer time to heat up with oxidation effect. Moreover, coal-water mixture samples with different water/coal mass ratio were used in order to investigate roles of water vapor on the combustion and gasification. The experimental results indicated that coal weight reduction ratio or coal conversion ratio to gases follows the Arrhenius equation with increasing coal temperature; in addition, coal weight reduction ratio of the sample was increased around 5% with adding H2O in CO2-rich atmosphere. Furthermore, generations of CO gas and Hydrocarbons gases (HCs) were mainly dependent on coal temperature and O2 concentration, however, those are also affected by chemical reactions including H2O. Especially, reactions generating CO and HCs gases were stimulated at temperature over 1000 °C in the CO2-rich atmosphere with 5% O2.
Keywords: coal, coal-water mixture; combustion and gasification; temperature gradient; CO2 gas laser beam
According to the IEA statistics (2007) , CO2 emission from fossil energy consumption in China was accounted for about 19% of global CO2 emission, of which coal-fired power plants occupied about 30% of total CO2 emission in China. Conventional coal fired boilers use air for combustion in which N2 gas is 79% in volume ratio, and it dilutes the CO2 gas concentration in the flue gas. CO2 capture cost from flue gases using amine stripping is expected to be relatively high . Consequently, a new zeroemission coal gasification with CO2 and Oxygen combustion technology has been studied for new coal fired power plants [3,4],
such as Integrated Gasification Combined Cycle (IGCC), including CO2 Capture and Storage (CCS). In this type of plants, recycled flue gas is used to control flame temperature and make up the volume of the missing N2 gas to ensure there is enough gas to generate energy in a gas turbine and heat in a steam boiler. As a consequence, a flue gas consisting mainly CO2 and water steam are generated, thus CO2 can be easily separated by condensation . In addition, pulverized coal fired power plants could be the best candidates to install CO2 capture system, of which oxy-fuel or CO2/O2 combustion technology is one of promising methods to evade problems of CO2 separation .
Siveter, Robert (IPIECA) | Ritter, Karin (API) | Clowers, Michael (Hess Corp.) | Lee, Arthur (Chevron Corp.) | Juez, Jaime Martin (Repsol YPF) | Poot, Brigitte (Total) | Killian, Terry (Marathon Oil) | Cass, Michael (Shell) | Chaves Cardoso de Oliveira, Rodrigo (Petrobras) | Loreti, Christopher (Loreti Group) | Romero-Giron Gracia, Eva (Repsol YPF) | Stileman, Tim (BP)
Recognizing the need to update the original version of the Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions (the Guidelines) to reflect changing practices, IPIECA and API jointly developed their second edition in 2011. First published in 2003, the petroleum industry has recognized the need for GHG accounting and reporting guidance that is focused specifically on its operations for over a decade. The Guidelines continue to promote credible, consistent, and reliable greenhouse gas (GHG) accounting and reporting practices from oil and gas operations.
The new edition holds significantly revised chapters on setting boundaries (including discussion of financial control and clearer reference to Scope 1, 2, and 3 emissions) and the evaluation of industry GHG emissions, including uncertainty. There are also revisions to discussions around reporting emissions over time, de minimis emissions, and normalization. The WRI/WBCSD GHG Protocol was, as with the original edition, carefully considered for consistency. The revised Guidelines have also aimed to achieve consistency with the approaches described in the IPIECA publication Oil and Gas Industry Guidance on Voluntary Sustainability Reporting revised in 2010.
Buscheck, Thomas A. (Lawrence Livermore Natlional Laboratory) | Friedmann, Samuel Julius (Lawrence Livermore Natl. Lab) | Sun, Yunwei (Lawrence Livermore National Laboratory) | Chen, Mingjie (Lawrence Livermore National Laboratory) | Hao, Yue (Lawrence Livermore National Laboratory) | Wolery, Thomas J. (Lawence Livermore National Laboratory) | Aines, Roger D. (Lawrence Livermore National Laboratory)
CO2 capture, utilization, and storage (CCUS) in deep geological formations is regarded as a promising means of lowering the amount of CO2 emitted to the atmosphere and thereby mitigating global climate change. For commercial-scale CO2 injection in saline formations, pressure buildup can limit CO2 storage capacity and security. Issues of interest include the potential for CO2 leakage to the atmosphere, brine migration to overlying potable aquifers, and pore-space competition with neighboring subsurface activities. Active CO2 Reservoir Management (ACRM) combines brine production with CO2 injection to relieve pressure buildup, increase injectivity, spatially and temporally constrain brine migration, and enable beneficial utilization of produced brine. Useful products may include freshwater, cooling water, make-up water for oil, gas, and geothermal reservoirs, and electricity generated from extracted geothermal energy. By controlling pressure buildup and fluid migration, ACRM can limit interactions with neighboring subsurface activities, reduce pore-space competition, and allow independent assessment and permitting.
ACRM provides benefits to reservoir management at the cost of extracting brine. The added cost must be offset by the added benefits to the storage operation and/or by creating new, valuable uses that reduce the total added cost. We review potential uses of produced brine and conduct a numerical study of potential reservoir benefits. Using the NUFT code, we investigate CO2-injector/brine-producer strategies to improve CO2 storage capacity and minimize interference with neighboring subsurface activities. Performance measures considered in this study include magnitude of vertical brine migration and areal extent and duration of pressure buildup. We consider ranges of CO2-storage-formation thickness and permeability and caprock-seal thickness and permeability, comparing injection-only cases with ACRM cases with a volumetric production-to-injection ratio of one. The results of our study demonstrate the potential benefits of brine production to CO2-storage operations. The economic value of these benefits will require more detailed, site-specific analyses in future studies.
A research-focused large-scale carbon dioxide (CO2) injection at Cranfield Field, Mississippi, conducted as part of the Southeast Regional Sequestration Partnership (SECARB), is building experience in technologies and approaches that may be valuable in commercial deployment of CO2 storage projects. Since July 2008, more than 3 million tons of CO2 have been injected into a 25 m thick interval of the Lower Tuscaloosa Formation at 3.2 km depth, with the general goal of providing policy makers with the information needed to increase confidence in CO2 geologic storage capacity predictions and retention estimates. A suite of novel and traditional monitoring technologies was utilized to observe the evolution of the CO2 plume and obtain data about the performance of the reservoir in multiphase flow conditions. The monitoring program focused on above-zone pressure surveillance, down dip plume-edge mapping, and multiphase flow process in heterogeneous sandstone. The project started CO2 injection into the oil bearing formation of the field and advanced injection into the associated water leg, linking enhanced oil recovery (EOR) and downdip brine storage. Monitoring and injection continues through 2017.
Key findings: CO2 moved in preferential paths along fluvial channels. A number of successfully deployed imaging tools support this channel-dominated flow theory. CO2 moved downdip and not preferentially updip, indicating buoyancy forces were not flow dominating at the interwell scale of the experiment.
We hope results from this experimental project provide a strong foundation for transferable research and knowledge gain from the monitoring program, based on both strengths and weaknesses of applied monitoring technologies will be relevant for future commercial CO2 storage applications.
The U.S. Department of Energy (DOE) funded seven Regional Carbon Sequestration Partnerships (RCSP) in 2003 as part of its Carbon Sequestration Program. These partnerships are undertaking efforts to determine the best approaches and technologies to safely and permanently store carbon dioxide in geologic formations (NETL website). During the current development phase (phase III) of the partnerships, several large-scale projects aiming at injecting at least one million metric tons of CO2 are underway. The "Early Test?? described in this paper, part of the Southeast Regional Carbon Sequestration Partnership (SECARB) led by the Southern States Energy Board (SSEB), was the first project in the U.S. (fifth in the world) to document that large injection volume under CCS monitoring conditions.
During the validation phase (phase II), SECARB undertook four tests: two Coal Seam Projects, the Saline Reservoir Field Test in Mississippi, and the Gulf Coast Stacked Storage Project. The latter preceded the Early Test and focused on developing pressure-based above zone monitoring over an extended period, as large volumes of CO2 were injected for enhanced oil recovery (EOR) at Denbury Onshore LLC operated Cranfield Field in Mississippi. The Gulf Coast Carbon Center (GCCC), a consortium functioning within the Bureau of Economic Geology (BEG) of the University of Texas at Austin is the technical leading institution for both the Gulf Coast Stacked Storage Project and the Early Test.
Because supercritical CO2, when injected onshore or in shallow water depths offshore, is mobile and can, therefore, migrate through any conduits or fractures, there is a need for proper physical trapping and also a necessity to monitor the CO2 migration in the injected zone. In addition, public opinion, government regulatory agencies and the lack of space for CO2 injection sites in some of the largest CO2 emitting regions of the world encourage investigating other alternatives such as CO2 sequestration in deepwater sub-seabed formations.
Furthermore, at the high pressures and low temperatures reigning in deepwater sediments where water depths are greater than 9,000 feet (˜2,750 meters), scientists have proposed that the CO2 should become denser than seawater and therefore would remain buoyantly trapped when liquid CO2 is injected within the first few hundred feet of sediments even in the absence of geological seals and traps. Besides, the bulk of the studies and technical papers concerning CO2 sequestration in deepwater sediments have focused on showing the potential and the feasibility of the concept but very little has been published to demonstrate the viability of the injection and long-term storage of CO2 in deepwater sub-seabed formations.
This paper presents the results of several case studies located in the Gulf of Mexico, the Pacific Ocean, the North Atlantic Ocean and the Sea of Japan. Large time-scale reservoir simulations have been conducted for up to 250 years and show that injected liquid CO2 can remain trapped in deepwater sediments under certain sediment physical properties. Therefore, CO2 sequestration in deepwater sediments provide another attractive technical solution when applied under certain conditions of pressure, temperature, sediment type, thickness, permeability and porosity notably for regions where there are few depleted oil and gas fields available for storage or limited space accessible onshore.
New Zealand is a comparatively "green?? country with respect to land-cover, with approximately 39% land area under pasture and 31% under exotic and native forest. Throughout New Zealand's history conversion between forest and pasture has been a major land-use change. Forests contain a large amount of carbon stored in the plant biomass compared with pasture; however, trees reflect less incoming radiation compared with grass. The reduction in albedo increases the radiative forcing and hence negates some of the benefit of carbon storage. This paper examines the relationship between the radiative forcing due to reduction of albedo and the CO2 absorption when converting pasture land to forest. Previous studies have used a linear approximation of the highly non-linear relationship in the analysis. However, this approximation significantly overestimates the amount of CO2 uptake required to compensate for typical changes in albedo. This paper describes three commonly used non-linear functions that can more accurately calculate CO2 uptake required to balance albedo changes. Results are presented for New Zealand plantation and indigenous forests. Five different forest types were investigated, and without accounting for the albedo effect the forests captured on average between 0.64 and 1.86 kg CO2/m2/yr over a 50-year period. Accounting for the increased radiative forcing due to the reduction in albedo by 7 % reduced the equivalent CO2 removal from the atmosphere to between 0.18 and 0.80 kg CO2/m2/yr. Changing albedo by only 5 % instead of 7 % will increase the equivalent CO2 removal rate from the atmosphere by 0.012 kg CO2/m2/yr.
Large volumes of CO2 will have to be stored in the subsurface for carbon capture and geological sequestration to have a significant impact on the reduction of carbon emissions. Injection of large volumes of CO2 into deep saline formations can lead to significant pressure increases within that formation. The increased pressure can be a limiting factor for injection rates; it can also drive vertical brine migration through leakage pathways (e.g., abandoned wells) that could contaminate sources of drinking water. Production of brine from the injection formation can reduce the pressure increase while also limiting the spatial extent of the pressure increase.
The impact of brine extraction is investigated using a hypothetical injection domain conditioned by parameters from the Illinois Basin. The domain contains one injection well and encompasses several aquifers connected through diffusive brine leakage. A vertically-integrated approach is used to model the injection formation and overlying aquifers. A set of production scenarios illustrates the impact of brine production on injection rates and vertical brine movement. The scenarios include production with surface disposal and production with reinjection into overlying formations (with and without desalinization).
The results show that brine production can reduce the pressure buildup in the injection formation, leading to an increase in injectivity and a concomitant reduction in fresh water contamination risk by reducing the area of potential impact. While reinjection of brine into an overlying aquifer solves the disposal problem, it also reduces the effectiveness of brine production by increasing the pressure. Injection of a smaller amount of more concentrated brine resulting from desalinization reduces the impact of reinjection and acts as an additional source of fresh water, but increases the cost of the injection operation.
Based on the results from these numerical experiments pressure management through brine production should be considered for industrial-scale CO2 injection operations, as it increases injectivity and reduces the size of the area of potential impact. However, the brine disposal problem needs to be solved for brine production to be a useful endeavor.
The Illinois Basin - Decatur Project (IBDP) plans to inject one million tonnes of carbon dioxide (CO2) into the Mt. Simon Formation over a three-year period, starting in late 2011. Uncertainty analyses that were conducted at successive stages of the project have been used to evaluate the impact of additional data on the uncertainty in reservoir performance predictions.
Reservoir simulators are predictive tools that help the project team evaluate the injectivity, storage capacity and containment capabilities of a reservoir for carbon capture and storage (CCS) projects. Simulation studies for IBDP started in 2008 using general regional data. Over time, reservoir models have increased in complexity and have become more representative of the Mt. Simon Formation as more data have been acquired.
An initial uncertainty analysis used models based on two-dimensional (2D) seismic data and available logs from a nearby well. After drilling the injection and monitoring wells at the storage site, petrophysical measurements were obtained that enabled a detailed sensitivity analysis to identify parameters that are critical to injectivity, CO2 migration, and corresponding pressure pulse evolution. This information helped reduce the number of uncertain parameters and their ranges for the second uncertainty analysis. Lastly, after gathering three-dimensional (3D) seismic data, results of special core analysis, and injectivity tests, the reservoir model and uncertainty ranges of other input parameters were updated for a final iteration of pre-injection uncertainty analysis.
Results of the first uncertainty analysis helped the project team identify an uncertainty envelope of possible CO2 migration scenarios. The second stage of uncertainty analysis targeted wide ranges in reservoir performance predictions, indicating several reservoir parameters on which to focus additional characterization efforts. A more complete, final round of uncertainty analysis produced manageable ranges of predicted uncertainties and a credible basis of reservoir performance expectations prior to the operational phase of the project. Results of this analysis can be used to identify the area of review (AoR) for permitting, priority and placement of monitoring tools, as well as timing of repeat surveys and scenarios for injection schemes in the near future.
de Donato, Philippe (Universite de Lorraine) | Pironon, Jacques (CREGU) | Barres, Odile (Universite de Lorraine) | Sausse, Judith (U. of Nancy France) | Quisel, Natalia (Veolia Environmental Services/Marine Division) | Thomas, Stephane (Veolia Environnement) | Pokryszka, Zbigniew (INERIS) | Laurent, Alain (Solexperts)
This paper presents the lessons learned from practical application of CO2 storage site monitoring methodology developed to address geochemical aspects of future CO2 storage site. It covers a detailed description of the methodology and tools applied for the extremely complex industrial site that main technical challenge is the presence of the multi sources of CO2 at the surface and in the soil.
On the basis of previous research programs conducted on natural CO2 storage sites, a specific geochemical monitoring program was developed that combine both a localized and continuous geochemical monitoring.
The paper focuses on the surface gases monitoring techniques spread on specific site to quantify CO2 flux and concentration at different levels from soil-atmosphere-interface : -1m to +1m. The geochemical monitoring was based on the combined use of conventional accumulation chambers and dynamic flow chambers systems equipped with high resolution IR sensors, Fourier Transform infrared sensors equipped with specific gas cell and a CO2 mobile infrared sensor. This first step has lead to the location and discrimination of CO2 sources and the analysis of the carbon cycle involving the influence of anthropogenic
events and of the natural seasonal variations. Combined methodology matrix for a geochemical surface survey adapted to CO2 storage in Paris basin depth saline aquifer is argued and the measurement results are discussed. 13C isotopic analyses to insure gas traceability have been also applied. Results are not shown in the paper. On the basis of such combined surface and subsurface gas measurements, seasonal variations of the natural CO2 cycle were identified. As results, sensitivity and variability were considered to suggest the CO2 warning levels adapted to detect CO2 abnormal emissions on the surface.
Finally, advanced complementary technologies for both soil and atmospheric gas investigations are also detailled as a part of the survey strategy. For soil gases, a specific completion in a shallow well has been developped to perform the continuous acquisition of CO2 concentrations at a depth of 10 m. For atmospheric gases, a scanning imaging infrared remote sensing system was tested to support atmospheric dynamic survey strategy.
This site study applied to Claye Souilly waste disposal represents the real "hand on?? experience and could be considered as a valuable experience to improve part of the geochemical monitoring program of CO2 storage site.