143 results about "Free gas" patented technology

A plasma ashing process for removing photoresist material and post etch residues from a substrate comprising carbon, hydrogen, or a combination of carbon and hydrogen, wherein the substrate comprises a low k dielectric layer, the process comprising forming a plasma from an essentially oxygen free and nitrogen free gas mixture; introducing the plasma into a process chamber, wherein the process chamber comprises a baffle plate assembly in fluid communication with the plasma; flowing the plasma through the baffle plate assembly and removing photoresist material, post etch residues, and volatile byproducts from the substrate; periodically cleaning the process chamber by introducing an oxygen plasma into the process chamber; and cooling the baffle plate assembly by flowing a cooling gas over the baffle plate assembly. A process chamber adapted for receiving downstream plasma, the process chamber comprising an upper baffle plate comprising at least one thermally conductive standoff in thermal communication with a wall of the process chamber; and a lower baffle plate spaced apart from the upper baffle plate.

High-purity polysilicon granules are prepared by depositing reaction gas on silicon granules in a fluidized bed reactor having:

• • a reactor space comprising at least two zones lying one above the other, the lower zone weakly fluidized by introduction of a silicon-free gas into silicon granules in the lower zone by a plurality of individual dilution gas nozzles, and a second, reaction zone directly abutting the lower zone,

the reaction zone heated via its outwardly bounding wall,

introducing silicon-containing reaction gas as a vertical high speed gas jet into the reaction zone by reaction gas nozzle(s), forming local reaction gas jets surrounded by bubble-forming fluidized bed, gas decomposing leading to particle growth,

wherein the reaction gas has fully or almost fully reacted to chemical equilibrium conversion before reaching the wall or bed surface.

A method for determining properties of a formation fluid including obtaining data related to an optical density at a methane peak and an optical density at an oil peak for a fluid sample at a plurality of times, calculating an apparent gas-oil-ratio of the sample fluid from the optical density of the fluid sample at the methane peak to the optical density of the fluid sample at the oil peak at each of the plurality of times based on the data, selecting a power function of a sampling parameter for a buildup of the apparent gas-oil-ratio, calculating an exponential constant of the power function based on the data, and determining at least one selected from the group consisting of a contamination free gas-oil-ratio and a percent contamination.

This invention relates to a method for the preparation of an osteoinductive agent, the use of such an agent, and to a kit for preparing such an agent. This invention further relates to the use of the said kit in the preparation and dispensing of such an osteoinductive agent in a method of reconstructive bone surgery. The kit includes an osteoinductive agent comprising a modified naturally occurring biocompatible biopolymer which was subjected, in the solid, or dry state, to a source of ionising radiation in the presence of a mediating gas and annealed in the absence of oxygen at a temperature of from 40° C. to 120° C. to render the product in a dry particulate form, the product being disposed in a hermetically sealed container containing oxygen-free gas.

A device and method can detect, and also break, an occurrence of gas lock in an electrical submersible pump assembly in a well bore based upon surface or downhole data without the need for operator intervention. To detect an occurrence of gas lock, an instantaneous value is monitored using a sensor. Then a controller compares the instantaneous value to a threshold value over a predetermined duration to thereby detect the occurrence of gas lock in the electrical submersible pump assembly. Sensors can include, for example, a differential pressure gauge, a pressure gage located in a pump stage located toward the inlet, a fluid temperature sensor located toward the discharge, a free gas detector located near the pump discharge, an electrical resistivity gage, a flow meter located within surface production tubing, and a vibration sensor attached to a tubing string to measure a vibration signature.

The present disclosure relates to a method to estimate a subsurface formation property. A downhole logging tool is provided and disposed in a wellbore. Multiple measurements of various measurement types are obtained at various depths of investigation using the downhole logging tool. The multiple measurements may include natural gamma ray measurements, density measurements, resistivity measurements, nuclear measurements, and nuclear magnetic resonance measurements. The signal-to-noise ratio of the measured signals is increased using, for example, lateral stacking and multi-shell inversion. The subsurface formation property is estimated using the increased signal-to-noise ratio signals. The subsurface formation property may include porosity, adsorbed gas volume, free gas volume, bound water volume, free water volume, oil volume, and kerogen volume. A fluid analysis may be performed using a multi-dimensional nuclear magnetic resonance technique. Fluids such as water, oil, gas, and oil-based mud in the wellbore may be identified and/or evaluated.

The invention discloses an experiment device for synthesizing a marine natural gas hydrate sample. The device comprises a reaction kettle, an axial compression piston, a kettle outer jacket, an injection system, an axial compression control system, a confining pressure control system and an output system. The invention further discloses an experiment method adopting the experiment device for synthesizing the marine natural gas hydrate sample. The method comprises the steps that firstly, ice powder particles are manufactured, then, the ice powder particles and dried porous medium particles are mixed and placed into the high-pressure reaction kettle in the subzero low-temperature environment so as to simulate seabed geomechanical properties, then, methane is injected to generate a hydrate, ice is directly converted into the hydrate, and finally free gas inside the reaction kettle is removed through the liquid injection system. According to the experiment device and method, true marine natural gas hydrate samples which are hard to obtain on various geological conditions and various occurrence form conditions can be economically, efficiently and accurately obtained, the research on the hydrate is closer to the reality, and the experiment basis is provided for research of natural gas hydrate exploitation.

A method for inferring production of a rod pumped well. Inferred production is estimated in a well manager which not only performs pump-off control with a down-hole pump card, but also estimates liquid (oil-water) and gas production using the subsurface pump as a meter. Methods are incorporated in the well manager for identifying and quantifying several conditions: pump leakage, unanchored tubing, free gas and oil shrinkage. Quantifying such conditions in the well manger enables accurate inferring of production thereby eliminating the need for traditional well tests.

A dual fuel vent free gas heater having at least one gas burner with a plurality of gas outlet ports. The gas outlet ports are in flow communication with at least one pilot flame burner. At least one fuel injector feeds fuel to the burner providing for introduction of more than one fuel to the burner. Optionally, an oxygen detection system, manual control valve, linkage, and/or shut off control system may be incorporated into the dual fuel vent free heater.

The invention discloses an assessment computing method of coalbed methane reserve volume at a coal mining stable region. The method comprises the following steps of: (1) obtaining effective pressure relief range of a mining stable region; (2) judging application condition of an estimation model; (3) computing surrounding rock pore volume in the mining stable region; (4) obtaining free gas concentration in the mining stable region; (5) estimating residual coal quantity in the mining stable region and residual gas content; (6) estimating the coalbed methane reserve volume in the mining stable region. The study on the effective pressure relief range in the mining stable region is capable of determining the estimation border range of the coalbed methane reserve volume in the mining stable region, the estimation on the estimation model application condition is capable of selecting effective estimation region to guarantee the accuracy of the estimation result, the computing of surrounding rock pore volume and the study on the free gas concentration are capable of accurately estimating the total quantity of the free coalbed methane in the mining stable region, and the study on the residual coal quantity in the mining stable region and residual gas content is capable of accurately estimating the total quantity of adsorption coalbed methane in the mining stable region.

The invention relates to a detection device and especially relates to an in-situ detection device for occurrence of hydrates in deposits. The CT in-situ detection device for microcosmic occurrence of hydrates in deposits comprises a pressure control system, a semiconductor temperature control system, an autoclave and an X-CT scanning system. The pressure control system is communicated with the autoclave. The semiconductor temperature control system is arranged at the bottom of the autoclave. The X-CT scanning system is arranged at two sides of the autoclave. The device achieves real-time detection of distribution of deposit particles, water, hydrates and free gas during hydrate formation/decomposition process.

The invention relates to a shale gas reservoir character prediction method. In the method, scanning lines in the horizontal direction are formed through focusing by a reflective mirror in a mirror box with a synchrotron radiation light source. Vertical scanning is achieved through rotating vibration of the reflective mirror for obtaining micro-structure three-dimensional data of a shale gas occurrence porous sample. Three-dimension reconstruction is carried out to the obtained micro-structure three-dimensional data and porosity and an inherent permeability of a shale three-dimensional digital rock core are obtained through calculation in a manner of coupling between molecular dynamics and crystal lattice Boltzmann method and are expressed by mathematic expressions. In the invention a synchrotron radiation light and a computer technology are employed for researching the porosity and the inherent permeability of the shale three-dimensional digital rock core. The method is economic and environmental-protective, is easy to operate, can provide required important evaluation parameters for exploration and development of shale gas, can predict an adsorption/desorption principle of free gas and adsorbed gas in the shale gas, can be used for researching the porosity and the inherent permeability of the shale three-dimensional digital rock core, and provides technical support for development of the shale gas.

The invention provides a method for nuclear magnetic resonance on-line detection of shale gas. The method comprises steps: a shale sample is heated to a set temperature and pressurized to a set pressure by utilization of a high-temperature and high-pressure probe, the set temperature is 150-170 DEG C, and the set pressure is 50-60MPa; at the set temperature and the set pressure, the shale sample is subjected to nuclear magnetic resonance measurement by utilization of a pulse sequence, and the relaxation time T2 spectrum of the shale sample is obtained through inversion; the adsorbed gas saturability and the free gas saturability of the shale sample are calculated according to the relaxation time T2 spectrum. The detection method can evaluate occurrence of methane well and obtains the adsorbed gas saturability and the free gas saturability rapidly.

The invention discloses a method for measuring the content of free gas in coal bed gas. By calculating the surface water saturation of a fresh coal core and performing back calculation to obtain water saturation in the stratum state, the volume of the free gas in a coal rock of unit mass is measured. Preferably, the method comprises the following steps of: collecting a sample, namely collecting a cylindrical coal sample which is not polluted by drilling fluid; measuring the volume Vtotal of the coal sample; measuring the volume Vwater1 of initial water; measuring the volume Vwater2 of saturated water; measuring an effective burden pressure delta p and a volume coefficient B; and according to parameter results in the preceding steps, calculating the content of the free gas. By adoption of the method, the content of the free gas can be accurately measured, so a total gas content test result is approximate to an underground true value, and great significance is provided for exploration and development of the coal bed gas.

The invention discloses a method for draining gas from an underground coal bed. The method comprises the following steps of: firstly, establishing a drill site in the coal bed to be drained; then, punching an anchor net (4) and anchor rods (3) in the surface of and around the coal bed to reinforce the coal bed; selecting at least one of the drill holes to serve as a heat source hole (2); performing negative pressure drainage of the gas through other drainage drill holes (1) by using drainage equipment; protecting a protective layer coal bed (6) by using a heat insulating material (5) to prevent a protective layer from being heated; heating the coal bed except the protective layer coal bed (6) by using heating equipment; heating the coal bed to 80-200 DEG C; and after the coal bed is heated, quickly desorbing the adsorbed gas into free gas. The volume of the free gas is increased, the gas pressure in the coal bed is increased, the development of fractures in the coal bed is promoted due to the increased gas pressure of the coal bed, the flow of the coal bed gas is facilitated, and the aim of quickly and efficiently draining the coal bed gas can be fulfilled under the action of the negative pressure drainage drill holes (1).

Embodiments of the present invention provide hydrogen-free dielectric films and methods of fabrication. A hydrogen-free precursor, such as tetraisocyanatosilane, and hydrogen-free reactants, such as nitrogen, oxygen (O2/O3) and nitrous oxide are used with chemical vapor deposition processes (PECVD, thermal CVD, SACVD, HDP CVD, and PE and Thermal ALD) to create hydrogen-free dielectric films. In some embodiments, there are multilayer dielectric films with sublayers of various materials such as silicon oxide, silicon nitride, and silicon oxynitride. In embodiments, the hydrogen-free reactants may include Tetra Isocyanato Silane, along with a hydrogen-free gas including, but not limited to, N2, O2, O3, N2O, CO2, CO and a combination thereof of these H-Free gases. Plasma may be used to enhance the reaction between the TICS and the other H-free gasses. The plasma may be controlled during film deposition to achieve variable density within each sublayer of the films.

The invention relates to a calculating method of shale permeability. The multi-field coupling permeability calculating method considering the shale matrix difference is characterized in that the permeability is shown in the description. On the basis of the prior art, the influence of the mutual effect of adsorbed gas and free gas on the shale permeability is further considered, and the influence of the thickness of water membranes on the shale permeability is considered. The influences of the mutual effect of the adsorbed gas and the free gas, the influence of the thickness of the water membranes, and the influence of the viscous flow, diffusion, the adsorbing layer gas thickness, the matrix shrinkage and the stress sensitivity are all coupled into a shale permeability calculating model. The influence of multiple features of shale on the permeability can be more comprehensively represented. Based on respective features of organic matter and inorganic matter of shale, an organic matterpermeability calculating model and an inorganic matter permeability calculating model are built respectively. The calculating error caused by the matrix difference can be effectively avoided.

The invention discloses a shale gas reservoir total reserve calculation method considering multiple factors, comprising the following steps: testing and collecting basic parameters and production dataof the shale gas reservoir; considering fractured free gas, porosity of adsorbed phase, volume change of adsorbed phase, critical desorption pressure of adsorbed gas and shrinkage effect of adsorbedgas desorption on matrix, and considering multi-component adsorption and dissolved gas simultaneously, establishing the material balance equation of shale gas reservoir, and finally obtaining the total reserves equation of shale gas reservoir; the basic parameters and production data of shale gas reservoir are processed according to the established material balance equation, and the relevant curves are drawn; finally, calculating the total reserves of shale gas reservoir Gt. A material balance equation of a new shale gas reservoir is established by comprehensively considering that shrinkage effect of multi-component adsorption and dissolving gas, fracture free gas, adsorption phase porosity, adsorption phase volume change, adsorption gas critical desorption pressure and adsorption gas desorption on a substrate, and the equation has important guiding significance for reasonably calculating the dynamic reserve of the shale gas reservoir.

The present invention provides a system for enriching a flowing liquid with a dissolved gas inside a conduit. The system comprises two or more capillaries, each capillary delivering a stream of a gas-enriched liquid to the flowing liquid. The first ends of the capillaries are positioned to form an intersecting angle with respect to the effluent streams such that these streams of gas-enriched liquid collide with each other upon exit from the first ends of the capillaries, effecting localized convective mixing within the larger liquid conduit before these gas-enriched streams are able to come into close contact with the boundary surfaces of the conduit, whereby the gas-enriched liquid mixes with the flowing liquid to form a gas-enriched flowing liquid. In the preferred embodiment, no observable bubbles are formed in the gas-enriched flowing liquid. Methods of making and using such system are also provided.

The invention provides a natural gas hydrate seismic data processing method and device. The method comprises the following steps: according to log data of a hydrate exploration area, performing fitting on sample data by utilizing a hydrate reservoir rock physical modeling method, and acquiring a target modeling method; constructing a wedge model of a hydrate by utilizing the target modeling method, performing forward modeling on seismic data according to the wedge model, and obtaining a synthetic seismic record; according to the synthetic seismic record, constructing free gas evaluation standards and saturation thickness evaluation standards of a natural gas hydrate; acquiring the actual seismic data of a target area in the hydrate exploration area, and acquiring the actual amplitude spectrum according to the actual seismic data; and according to the actual amplitude spectrum, the free gas evaluation standard and the saturation thickness evaluation standard, determining hydrate featureinformation of the target area. By utilizing each embodiment in the invention, the adaptability problem of the same hydrate reservoir rock physical model in different exploration areas is solved, andnatural gas hydrate seismic data processing accuracy is improved.

The invention discloses a method for judging the content of free gas and adsorbed gas in shale gas. The content of the free gas and the adsorbed gas in the shale gas is judged by collecting gas samples at different temperature sections of a shale field analysis experiment in the shale gas drilling process and combining the field analysis total gas content and methane carbon isotope experimental data. The content of the free gas and the adsorbed gas in the shale formation section can be quickly obtained with the method and is directly connected with the shale gas content, so that the influenceof intermediate parameters is reduced, accuracy of results is improved, and the method has the advantages of being easy to popularize and convenient to implement.