The interest in on Carbon Capture and Storage (CCS) has increased over the last years with recognition of the ability of CCS to achieve a great reductions in CO2 emission as the fossil fuels will continue to be the main supplier for the world energy demand for the upcoming decades with no other alternatives are forecasted to replace them. The comparison between CCS and the other future alternatives or options relies mainly on the CCS cost -which is the main focus of this paper- removal of CCS deployment barrier in addition to the barriers and costs for the alternative options for CO2 emission reduction.
This study gives an insight comparison between the electricity cost for five different options of power generation including Combined Cycle Gas Turbines (CCGT) without and with CCS, coal and finally the nuclear power plants. In addition, it determines the ranges of fuel and carbon prices at which each option can be economically deployed
The recent coal CCS for Nth of a kind power generation plant cost estimates lie in the region of 60 to 100 $/ton of avoided CO2 which is higher than the previous CCS cost estimated and also greater than the accepted range of the forecasted carbon prices in the upcoming years. The higher costs of coal CCS would suggest the following: Coal CCS power generation plants is way less economical than gas ones for the range of carbon prices less than 60-100 $/ton of avoided CO2 Even at carbon prices higher than 100 $/ton of CO2, coal CCS power plants still produces higher cost electricity when compared to the gas CCS ones as long as the natural gas prices are still lower than 9 $/MBTU Coal CCS electricity costs are still higher when compared to a nuclear power plant option
Coal CCS power generation plants is way less economical than gas ones for the range of carbon prices less than 60-100 $/ton of avoided CO2
Even at carbon prices higher than 100 $/ton of CO2, coal CCS power plants still produces higher cost electricity when compared to the gas CCS ones as long as the natural gas prices are still lower than 9 $/MBTU
Coal CCS electricity costs are still higher when compared to a nuclear power plant option
It is widely believed that the CCS power plants (Gas or Coal) are not expected to be economical over the upcoming years, however introduction of subsidized forms of CCS are likely to take place. Also, CCS technology components are expected to be economically implemented in operations like Enhance Oil recovery (EOR), so, in this paper, an economic evaluation is provided for using of CO2 extracted from natural gas plant into EOR operations. CO2 separation cost in the natural gas processing industry is less than the capture cost of CO2 in power plants as a result of its high gas pressure and the fact that CO2 removal is mandatory to increase the value of a natural gas resource
On the other hand, this is not the case for the CCS of the most industrial emissions, as they are expected to be higher than those of power plants as a result of the smaller scale and wider distributed CO2 streams compared to power generation plants. This shows the importance of the realistic CCS cost estimation as a significant factor in the R&D projects and implementation trials that try to overcome the tackles that face the application of such promising technologies.
Briefly stated, carbon capture and sequestration (CCS) will help us to sustain many of the benefits of using hydrocarbons to generate energy as we move into a carbon-constrained world. Even though the CO2 generated by burning hydrocarbons cannot always be captured easily in some cases (as in oil used for transportation), sequestration of CO2 from other sources (such as coal-fired power stations) can help to create, to some degree, the “headroom” needed for the volumes of CO2 that escape capture. Because of the likely continuing competitive (direct) cost of hydrocarbons and in light of the huge investment in infrastructure already made to deliver them, the combination of fossil fuel use with CCS is likely to be emphasized as a strong complement to strategies involving alternative, nonhydrocarbon sources of energy. Moreover, the exploitation of heavy oil, tar sands, oil shales, and liquids derived from coal for transportation fuel is likely to increase, even though these come with a significantly heavier burden of CO2 than that associated with conventional oil and gas. CCS has the potential to mitigate some of this extra CO2 burden. If we wish to sustain the use of oil, gas, and coal to meet energy demands in a carbon-constrained world and to provide time to move toward alternative energy sources, then it will be necessary to plan for and implement CCS over the coming decades. Subsequently, we should expect a continued need for CCS beyond the end of the century.
The current presentation date and time shown is a TENTATIVE schedule. The final/confirmed presentation schedule will be notified/available middle of October 2019. If we have learned anything from the North American experience, unconventional resources cannot be exploited by small incremental projects. If we are to be successful in developing these types of reservoirs, we have to make project scale operations work to bring these resources to market in a timely manner. A number of Eastern Hemisphere unconventional gas projects have raised interest, neared completion or are commencing deliveries.
Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. For a long time, the Fruitland formation coals were recognized only as a source of gas for adjacent sandstones. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Coals in the fairway typically have low ash and high vitrinite contents, resulting in large gas storage capacities and excellent permeabilities of 10 md from well-developed cleat systems.
The process of drilling and completing coalbed methane (CBM) wells is similar to wells in conventional reservoirs. Coring, however, can pose special challenges. The first step in creating a drilling program for a CBM well involves gathering information about existing wells in a given area. After these data are gathered and analyzed, a preliminary drilling and completion prognosis can be drafted with the input of field operations personnel. An important aspect in drilling frontier or appraisal wells is to keep the drilling procedures relatively simple.
Unlike conventional reservoirs, coal seams are the source, trap, and reservoir for coalbed methane (CBM). A comparison of the two reservoir types shows profound differences in reservoir properties, storage mechanisms, flow mechanisms, and production profiles. Organic matter constitutes more than 50% of coal by weight and more than 70% by volume. Type refers to the variety of organic constituents.
Core analyses are a critical part of analyzing CBM reservoirs to determine gas saturations. Coal cores must be placed in desorption canisters and heated to reservoir temperature. As the coal desorbs, gases are captured, and both their volume and composition are determined. Desorption continues for up to several months until the rate at which gas is being liberated from the coal becomes very small. At this point, the canisters are opened, and the cores can be described. The cores then are crushed in a mill that captures any remaining gas (residual gas), and the milled coal is mixed thoroughly to form a representative sample. An alternative to crushing the entire core is to first slab the core and crush one-half.
Tian, Jianwei (The University of Western Australia) | Liu, Jishan (The University of Western Australia) | Elsworth, Derek (The Pennsylvania State University) | Leong, Yee-Kwong (The University of Western Australia) | Li, Wai (The University of Western Australia) | Zeng, Jie (The University of Western Australia)
Heterogeneous pore structure is critically important for unconventional gas recovery. In this paper, a dynamic fractal permeability model is proposed to investigate the interplay between heterogeneous pore structures and gas transport for coal seam gas reservoir. In this model, pore diameter and fractal dimension of pore size distribution are dynamically changing as a result of the variation of effective stress. Besides, based on fractal approach, a new Klinkenberg coefficient that dynamically changes with pore pressure is employed to incorporate the non-Darcy effect. This dynamic permeability model is applied to couple Multiphysics in coal seam gas recovery process. The impacts of these fractal parameters on permeability evolution are explored through a benchmark reservoir simulation. The numerical results exhibit good agreements with experimental data. The simulation results indicate that: (1) the dynamic permeability model matches better with experimental data than other homogeneous models, especially in low-pressure stage; (2) reservoir with larger initial fractal dimension is more sensitive to pressure depletion; (3) fractal dimension would change more dramatically when initial porosity is relatively smaller; (4) Klinkenberg coefficient increases with the decreasing of reservoir pore pressure during gas depletion. In summary, the dynamic permeability model predicts permeability evolution well in gas production process and provide some fundamental insights into the implications of reservoir heterogeneity on gas transport in reservoir simulation.
With the natural gas depletion, there is an increasing need for the exploration of unconventional natural gas, unconventional gas is typically regarded as a substitute that can relieve energy supply shortage. Permeability is the dominant factor that controls unconventional natural gas production. Therefore, it is significant to understand the mechanisms of permeability evolution and the associated influential factors. Notably, coal reservoir exhibits multi-scale heterogeneity, and pore size spans from micrometer to nanometer, which affects gas transport and storage capability substantially.
The heterogeneous pore structure of coal reservoir is characterized by multiscale pore size distribution (PSD) and the tortuous flow channel. Knudsen number ( Kn ) is defined as the ratio between the molecular free path and characteristic length, which is usually applied to describe flow regimes. The gas flow regimes include viscous flow ( Kn < 0.001 ), slip flow ( 0.001 < Kn 0.1 ), transitional flow ( 0.1 < Kn < 10 ) and free molecular flow ( Kn > 10 ). According to the definition of Knudsen number, pore size distribution determines the flow regimes in micropores when pore pressure remains constant. Therefore, the pore structure of coal has a significant impact on the apparent permeability of coal matrix. Different distribution functions have been employed to study the effect of PSD on apparent permeability, demonstrating that permeability is highly sensitive to the variation of the distribution function (Tian et al. 2017, Civan 2002). When the proportion of micropores is larger, the specific surface will increase, which will provide much more adsorption volume for coal seam gas (Tian et al. 2017). The original gas in place (OGIP) and corresponding sorption-induced swelling can be influenced substantially. For coal seam at different depths, coal swells or contracts greatly depend on PSD (Yang et al. 2010). Except for porosity, tortuosity of pore structure is an essential parameter for permeability prediction, which reflects the ratio between actual flow length and characteristic length of coal sample. According to the Kozeny-Carman model, there is a negative correlation between permeability and tortuosity(Walsh and Brace 1984). The theoretical investigation indicates that large tortuosity can increase the resistance of gas transport (Wang et al. 2017).
We show that nitrogen flooding can double matrix permeability of gas shales. In laboratory experiments, nitrogen gas increased permeability in the bedding-perpendicular and bedding-parallel directions by 206% and 234%, respectively. Experiments are performed at constant stress, pore pressure, and temperature. We build a model to show that the permeability enhancement is controlled by the sorptive strain, pore geometry, and the spacing-to-aperture ratio. This work addresses how an organic-poor shale can experience large permeability changes driven by sorption induced strains. We plot methane and helium permeability curves as a function of pore pressure to isolate the portion of permeability evolution controlled by sorption. We independently build strain curves to solve for the sorptive strain and find good agreement between these two methods. This work demonstrates that matrix permeability in gas shales can be doubled, which suggests that ultimate recovery can be improved as well.
Shale is a sedimentary rock composed primarily of silica, calcite, clays, and organic matter. Within the matrix, these individual mineral components form thin laminae separated by fracture planes which allow for fluid flow. The role of adsorption in shales has been a topic of great interest in both the scientific and industrial community, as in situ methane is adsorbed within the organic pore space. Adsorption in shales can account for up to half of the gas storage—in the case of low organic content, illite may be responsible for the additional sorptive storage (Lu et al. 1995).
This article discusses the geology, depositional setting, and hydrogeology of promising CBM areas, along with a discussion of data sources that can help in evaluation of prospects. Foreland basins are flexural troughs that form in front of rising mountain belts. These basins, which include the Black Warrior and San Juan basins of the U.S., have provided more than 90% of the world's coal gas production to date. Cratonic basins such as the Williston basin, which straddles the U.S./Canadian border, are simple structural depressions that favor the deposition of widespread, continuous coal seams. Intermontane basins, which are common in the Appalachian Mountains of the eastern U.S., form within mountain belts and often are structurally complex, resulting in a more heterogeneous coal distribution.