Kegang Ling

Cost comparison of syngas production from natural gas conversion and underground coal gasification

Underground coal gasification (UCG) is a promising technology to reduce the cost of producing syngas from coal. Coal is gasified in place, which may make it safer, cleaner and less expensive than using a surface gasifier. UCG provides an efficient approach to mitigate the tension between supplying energy and ensuring sustainable development. However, the coal gasification industry presently is facing competition from the low price of natural gas. The technology needs to be reviewed to assess its competiveness. In this paper, the production cost of syngas from an imaginary commercial-scale UCG plant was broken down and calculated. The produced syngas was assumed to be used as feedstock in liquid fuel production through the Fischer-Tropsch process or methanol synthesis. The syngas had a hydrogen (H2) to carbon monoxide (CO) ratio of 2. On this basis, its cost was compared with the cost of syngas produced from natural gas. The results indicated that the production cost of syngas from natural gas is mainly determined by the price of natural gas, and varied from

More Accurate Gas Viscosity Correlation for Use at HP/HT Conditions Ensures Better Reserves Estimation

24.46 per thousand cubic meters (TCM) to

Nitrogen Injection Experience to Development Gas and Gas Condensate Fields in Rocky Mountains

90.09/TCM, depending on the assumed price range of natural gas. The cost of producing UCG syngas is affected by the coal seam depth and thickness. Using the Harmon lignite bed in North Dakota, USA, as an example, the cost of producing syngas through UCG was between

Determining Coefficient of Quadratic Term in Forchheimer Equation

37.27/TCM and

Measurement of Gas Viscosity at High Pressures and High Temperatures

39.80/TCM. Therefore, the cost of UCG syngas was within the cost range of syngas produced by natural gas conversion. A sensitivity analysis was conducted to investigate how the cost varies with coal depth and thickness. It was found that by utilizing thicker coal seams, syngas production per cavity can be increased, and the number of new wells drilled per year can be reduced, therefore improving the economics of UCG. Results of this study indicate the competitiveness of UCG regarding to natural gas conversion technologies, and can be used to guide UCG site selection and to optimize the operation strategy.

New Method To Estimate Surface- Separator Optimum Operating Pressures

High-pressure and high-temperature (HPHT) gas reservoirs are defined as having pressures greater than 10,000 psia and temperatures over 300oF. Modeling the performance of these unconventional reservoirs requires the understanding of gas behavior at elevated pressure and temperature. An important fluid property is gas viscosity, as it is used to model the gas mobility in the reservoir that can have a significant impact on reserves estimation during field development planning. Accurate measurements of gas viscosity at HPHT conditions are both extremely difficult and expensive. Thus, this fluid property is typically estimated from published correlations that are based on laboratory data. Unfortunately, the correlations available today do not have a sufficiently broad range of applicability in terms of pressure and temperature, and so their accuracy may be doubtful for the prediction of gas viscosity at HPHT conditions. This paper reviews the databases of hydrocarbon gas viscosity that are available in the public domain, and discusses the validity of published gas viscosity correlations based on their applicability range. A falling body viscometer was used in this research to measure the HPHT gas viscosity in the laboratory. The instrument was calibrated with nitrogen and then, to represent reservoir gas behavior more faithfully, pure methane was used. The subsequent measured data, recorded over a wide range of pressure and temperature, was then used to evaluate the reliability of the most commonly used correlations in the petroleum industry. The results of the comparison are presented here and suggest that at pressures higher than 8000 psia; the laboratory measurements drift from the National Institute of Standards and Technology (NIST) values by up to 7.48%. Finally, a sensitivity analysis was performed to assess the effect of gas viscosity estimation errors on the overall gas recovery from a synthetic HPHT reservoir, using numerical reservoir simulations. The result shows that a -10 % error in gas viscosity can produce an 8.22% error in estimated cumulative gas production, and a +10% error in gas viscosity can lead to a 5.5% error in cumulative production. These preliminary results indicate that the accuracy of gas viscosity estimation can have a significant impact on reserves evaluation.

Optimising the Multistage Fracturing Interval for Horizontal Wells in Bakken and Three Forks Formations

Nitrogen injection into gas condensate or volatile oil fields has been practiced as a method of pressure maintenance as well as enhanced hydrocarbon recovery in Rocky Mountains for more than two decades. Reservoir management has experienced miscible displacement in the gas cap, reservoir pressure maintenance, and reservoir blow down in different fields. In the implementation of nitrogen injection, a tremendous amount of experiences on injection and reservoir performance had been accumulated without appropriate documentation. Furthermore, even though nitrogen injection has been widely used in the world to enhance recovery by miscible displacement or maintaining reservoir pressure, literature survey shows that the experience with nitrogen injection is sporadic. This paper reviews reservoir characteristics and summarizes the lessons learned from nitrogen injection all of the world; then focuses on Rocky Mountains reservoir management to further analyze its production and surveillance, reservoir development stages in the life of fields, and the relationship between the fields and processing facility. Compositional reservoir simulation was performed to study the enhanced hydrocarbon recovery by injecting nitrogen and use nitrogen breakthrough information across the field as a continuous tracer to study the well connectivity between the injector and producer pairs. The main contributions of the paper are that it highlights the accumulated experience associated with nitrogen injection, and provides information on amenable reservoir features which can be used to select nitrogen as a viable alternative for enhanced oil recovery purpose.

A New Method To Detect Partial Blockage in Gas Pipelines

Forchheimer equation takes non-Darcy flow effect into account in the event of high flow velocity in porous media. Its application requires both permeability, which is in linear term, and Beta factor, which is in quadratic term. Permeability and Beta factor are determined by rock type, textural of rock, effective porosity, pore throat size, geometry of the pore, and connection and distribution of pores. Beta factor comes into play when the fluid flow rate is high and the flow rate deviates from Darcy’s law. Non-Darcy flow is described by Forchheimer equation. Usually the coefficient of non-Darcy flow term is hard to be determined. Existing approaches are core measurement and empirical correlations. To the best of our knowledge there is no theoretical equation available. To get an accurate estimation of flow rate or pressure drop in the reservoir, we need a method that has solid theoretical basis. The deficiency triggered our study. Starting from multiple-capillary tubes concept, we derived a rigorous relationship between pores geometry and pressure drop required for fluid flow through the pores. Through this correlation pressure drop can be calculated from known pores geometry. Since pores geometry can be often obtained from lab experiment or well logging, the new correlation also provides a unique approach to quantify the coefficient of quadratic term in Forchheimer equation. In this study we developed a governing equation through a rigorous theoretical derivation. With this equation the non-Darcy flow coefficient in Forchheimer equation can be calculated. The required input data for the new equation are readily obtained from well log interpretation. The new equation is a powerful tool in the event of no experimental measured non-Darcy flow coefficient available. It eliminates the errors or the arbitrary content in the empirical correlations.

Fractional flow in radial flow systems: a study for peripheral waterflood

Gas viscosity is an important fluid property in petroleum engineering due to its impact in oil and gas production and transportation where it contributes to the resistance to the flow of a fluid both in porous media and pipes. Although the property has been studied thoroughly at low to intermediate pressures and temperatures, there is lack of detailed knowledge of gas viscosity behavior at high pressures and high temperatures (HPHT) in the oil and gas industry. The need to understand and be able to predict gas viscosity at HPHT has become increasingly important as exploration and production has moved to ever deeper formations where HPHT conditions are more likely to be encountered. Knowledge of gas viscosity is required for fundamental petroleum engineering calculations that allow one to optimize the overall management of a HPHT gas field and to better estimate reserves. Existing gas viscosity correlations are derived using measured data at low to moderate pressures and temperatures, i.e. less than 10,000 psia and 300 oF, and then extrapolated to HPHT conditions. No measured gas viscosities at HPHT are currently available, and so the validity of this extrapolation approach is doubtful due to the lack of experimental calibration. The falling body viscometer is selected to measure gas viscosity for a pressure range of 3,000 to 24,500 psia and temperature range of 100 to 415 oF. Nitrogen was used to calibrate the instrument and to account for the fact that the concentrations of non-hydrocarbons are observed to increase dramatically in HPHT reservoirs. Then methane viscosity is measured to reflect the fact that, at HPHT conditions, the reservoir fluids will be very lean gases, typically methane with some degree of impurity. The experiments showed that while the correlation of Lee et al. accurately estimates gas viscosity at low to moderate pressure and temperature, it does not provide a good match to gas viscosity at HPHT conditions.

A rigorous method to calculate the rising speed of gas kick

Summary The significance of setting optimal surface separation pressures cannot be overemphasized in surface-separation design for the purpose of maximizing the surface liquid production from the wellstream feed. Usually, classical pressure-volume-temperature (PVT) analysis of reservoir fluids provides one or several separator tests through which the optimum separator pressures are estimated. In case separator tests are not available, or the limited numbers of separator tests are not adequate to determine the optimum separator pressures, empirical correlations are applied to estimate the optimum separator pressures. The empirical correlations, however, have several disadvantages that limit their practical applications. In this study, we approached the problem with a rigorous method with a theoretical basis. According to the gas/liquid equilibrium calculation, the optimum separator pressures were determined. Comparisons of our results with experimental data indicated that the proposed method can simulate the separator tests very well. Because the method has a theoretical basis and does not require existing two-stage or multiple-stage separator-test data as in the application of empirical correlations, it potentially has wide applications in practice for a variety of conditions and yields a more optimal separation scheme than the empirical correlations. Furthermore, the method is independent of reservoir fluid. In the event that separator tests are available from fluid analysis, our method can be used as a quality-control tool. Because the setting for optimal separation pressures vary as the composition of the wellstream changes during the field life, our method provides a quick and low-computational-cost approach to estimate optimum separator pressures corresponding to different compositions.