Abstract: A process for reducing pressure in a well for well kill, during and after recovery of hydrocarbons from a formation. A mobilizing fluid is injected through the well and into the formation to mobilize the hydrocarbons and increase the well pressure, followed by emulsion fluids production to surface while mobilizing fluid injection is discontinued, which decreases the well pressure in preparation for well kill. The emulsion fluids are directed to a produced emulsion line at a first pressure, with at least some of the emulsion fluids instead redirected to an additional line at a lower second pressure as well pressure decreases, and these fluids from the additional line are then pumped at a third pressure higher than the second pressure into the produced emulsion line.

Abstract: A wellhead boosting apparatus (14) comprising a multi-phase separator module (30) having a separator module support (32); a multi-phase separator (28), an oil-phase pump (48) for extracting an oil phase from the multi-phase separator (28), and a water-phase pump (46) for extracting a water phase from the multi-phase separator (28), the multi-phase separator (28) including a separator fluid inlet (38) comprising a wellhead connector (34), and a separator gas outlet (40) for extracting separated gas; and a compressor module (24) having a compressor module support (26); a compressor (22), a gas engine (68) which utilises separated gas as fuel for powering the compressor (22), the compressor (22) including a compressor gas inlet (50) connected with the separator gas outlet (40) and a compressor gas outlet (20) which is communicable with the wellhead (12) to provide gas lift thereto using the separated gas.

Abstract: A high pressure injection flushing head includes a flushing body comprising an upper body portion, and a lower body portion coupled to the upper body portion. The upper body portion and the lower body portion cooperate to define a bore. A shaft is rotatably disposed at least partially within the bore. A plurality of rotary elements are configured to facilitate rotational movement of the shaft relative to the flushing body. The flushing body comprises a lubrication system having a plurality of grease nipples, and a network of pathways in fluid communication with the grease nipples that are configured to deliver grease to the rotary bearings. The flushing head couples to an adapter via a flanged connection so that the flushing head can be adapted for use with a plurality of drill rod types.

Abstract: Methods of the present disclosure may include obtaining an origin fluid having a calcium concentration of about 1.5 M or greater. A treatment fluid may be created by introducing an amount of slaked lime to the origin fluid to change a pH of the resulting treatment fluid to about 11 or greater. The treatment fluid may be introduced into a subterranean formation containing a formation gas comprising natural gas and carbon dioxide. The calcium in the treatment fluid may be allowed to react with the carbon dioxide within the subterranean formation to form calcite. The treated formation gas may be removed from the subterranean formation after the formation of calcite, wherein the concentration of carbon dioxide in the treated formation gas is lower than the formation gas before it was contacted with the treatment fluid.

Abstract: A fugitive gas remediation (FGR) system for eliminating fugitive gas, such as surface casing vent gas produced from the casing head of an oil well, or so-called casinghead or Bradenhead gas, and other fugitive gas sources. An enclosure is positioned at a site with a fugitive gas source, such as a wellhead. A separator is located in the enclosure to remove liquid from the fugitive gas. A catalytic heater is located in the enclosure and coupled to the separator to react with the fugitive gas and produce heat in the enclosure. A pilot gas source can provide pilot gas to the catalytic heater.

Abstract: A continuous process for enhanced oil recovery (EOR) to be used in heavy and extra heavy oil wells, where low and/or non-profitable production rates occur is presented. The process is named Hot Crude Gravity Drainage (HCGD), and HCGD may include different components to support the heating of crude produced in the oil well that is later going to be injected at the same volumes as heated crude. The crude may be injected in the sand from which it was produced, in order to continuously supply the required energy to significantly lower the viscosity, which in turn increases mobility in the pores of the producing sand and allows for an increment (e.g., of more than 100%) in production as regards the base or initial production of the oil well, in a 45 consecutive day period. The process unit may be simple, compact, modular and skid mounted.

Abstract: The present disclosure relates to a system for storing and time shifting at least one of excess electrical power from an electrical power grid, excess electrical power from the power plant itself, or heat from a heat generating source, in the form of pressure and heat, for future use in assisting with a production of electricity. An oxy-combustion furnace is powered by a combustible fuel source, plus excess electricity, during a charge operation to heat a reservoir system containing a quantity of a thermal storage medium. During a discharge operation, a discharge subsystem has a heat exchanger which receives heated CO2 from the reservoir system and uses this to heat a quantity of high-pressure, supercritical CO2 (sCO2) to form very-high-temperature, high-pressure sCO2 at a first output thereof. The very-high-temperature, high-pressure sCO2 is used to drive a Brayton-cycle turbine, which generates electricity at a first output thereof for transmission to a power grid.

Abstract: A system for compressing casing gas from a hydrocarbon well is provided. The hydrocarbon well has a wellhead, a production string that produces fluids from a hydrocarbon formation, and a casing string that receives the production string. The wellhead is connected to a pipeline that transports the produced fluids. The system has a liquid conduit that receives liquids liquid from a source of liquid, a casing gas conduit that receives casing gas from the casing string, an outlet conduit, and a pump that is capable of pumping a liquid/gas mixture. The pump is in fluid communication with the liquid conduit and the casing gas conduit, such that the inlet receives liquid from the liquid conduit and casing gas from the casing gas conduit and an outlet connected to the pipeline.

Abstract: A process for preparing a well for use in subsequent recovery of hydrocarbons from a hydrocarbon-bearing formation wherein (i) mobilizing fluid is injected into the formation and emulsion fluids are produced to surface and directed to a high-pressure produced emulsion line, reducing pressure in the well, (ii) mobilizing fluid injection is terminated while emulsion production continues at reduced pressure, (iii) redirecting a portion of the reduced-pressure emulsion fluids to an additional low-pressure line instead of the produced emulsion line, and (iv) pumping the portion of the emulsion fluids at an elevated pressure from the additional line into the produced emulsion line.

Abstract: Systems and methods for controlling operation of a well, of which the method includes receiving an operation setting for operation of a system that provides lift gas into and produces gas from the well, monitoring operation of the system using a first controller, determining, using the first controller, that the system is not operating at the operation setting, and in response to determining that the system is not operating at the operation setting, sending, using a two-way communication link from the first controller to a second controller, a control signal to the second controller. The control signal is configured to cause the second controller to modify an operation of a compressor of the system.

Abstract: The present invention relates to a modified MPD vessel which allows the coupling of identical secondary MPD vessels, which can house either sand filter and/or sand cyclonic MPD internals, to the vessel without the need for any vessel or pipework modifications whereby, a plurality of these MPD vessels can be further coupled using identical inlet and outlet configurations. This configuration of MPD vessels allows for improved means for removing produced solids from a hydrocarbon fluid stream and allows for a vastly more flexible system as a whole.

Abstract: An automated sand separator discharge system includes a sand separator disposed downstream of a wellhead, an inlet conduit for transporting a process stream to the sand separator, a fluid outlet conduit for transporting a liquid and gas stream from the sand separator, a sand discharge conduit for removing sand from the sand separator, first, second, and third valves disposed along the sand discharge conduit, a first transducer connected between the first and second valves and operative to measure pressure in a portion of the sand discharge conduit and to produce a pressure reading, and a control panel operatively connected to the first, second, and third valves and the first transducer, the control panel being programmed to initiate and terminate discharge of sand from the sand separator, and to determine if the first and second valves are sealing completely when closed.

Abstract: A gas-oil separation plant (GOSP) is configured to process crude oil produced from a well. A production stream from the well operates at a first pressure. A processed crude oil stream from the GOSP flows to a multi-phase ejector. The multi-phase ejector induces flow of a production stream from the well in response to the flow of the processed crude oil stream.

Abstract: Embodiments of the present disclosure include a system, method, and apparatus comprising a direct steam generator configured to generate saturated steam and combustion exhaust constituents.

Abstract: The invention relates to a method to produce a particulate activated carbon material for capturing CO2 from air, wherein the particulate activated carbon is impregnated with alkali carbonate salt such as K2CO3; and wherein the impregnated particulate activated carbon either has, determined using nitrogen adsorption methods, a pore volume of at least 0.10 cm3/g for pore sizes of at least 5 nm and a pore volume of at most 0.30 cm3/g for pore sizes of less than 2 nm or is based on a mixture of different alkali carbonate salts, or has a particular pore surface for pore sizes in the range of 2 nm-50 nm.

Abstract: A modular skid mounted oil production system, comprising multiple skid sections that are connectable via alignment pins coupled to the skid beam structure. The alignment pins having a fork connector that is connected to a knife connector. When the skid sections are connected, the piping, electrical, and pneumatic tubing connectors are connectable to the other corresponding skid piping, electrical, and pneumatic tubing connectors without the need for welding or field construction of connecting components. The modular skid oil production system is capable of expansion or contraction as required by the operation of the system. For example the system includes removing a skid section having a larger separator and replacing it with a skid section having a smaller separator, without the need of welding or field construction of connecting components.

Abstract: A method of separating hydrocarbons from an oil field production stream may include providing a production stream having a gas phase and a liquid phase, the production stream including oil, hydrocarbon gas, carbon dioxide, and water; substantially separating the gas phase from the liquid phase; separating the liquid phase into a stream composed substantially of oil and a stream substantially composed of water, the stream substantially composed of water containing carbon dioxide absorbed therein; pressurizing the water stream containing carbon dioxide absorbed therein; and injecting the pressurized water stream containing carbon dioxide absorbed therein to a downhole injection location; the method may include operating each step at a pressure above 150 psig.

Abstract: A modular skid mounted oil production system, comprising multiple skid sections that are connectable via alignment pins coupled to the skid beam structure. The alignment pins having a fork connector that is connected to a knife connector. When the skid sections are connected, the piping, electrical, and pneumatic tubing connectors are connectable to the other corresponding skid piping, electrical, and pneumatic tubing connectors without the need for welding or field construction of connecting components. The modular skid oil production system is capable of expansion or contraction as required by the operation of the system. For example the system includes removing a skid section having a larger separator and replacing it with a skid section having a smaller separator, without the need of welding or field construction of connecting components.

Abstract: A method for moving fluid through a pipe in a wellbore includes placing at least two different fluids in the pipe and in an annular space between the pipe and the wellbore. Fluid is pumped into the pipe at a rate to achieve a desired set of conditions. Using a predetermined volume distribution of the annular space, an axial position of each of the at least two fluids in the annular space during the pumping the displacement fluid is calculated.

Abstract: The present invention provides environmentally-friendly compositions and methods for recovering oil from oil sands. The present invention can also be used for reducing the viscosity and/or increasing the API gravity of oil. In specific embodiments, the invention utilizes compositions comprising biochemical-producing microorganisms and microbial growth by-products, such as biosurfactants, as well as cavitation, to enhance oil recovery.

Abstract: The disclosure relates to a method for producing heavy oil by generating solvents in situ in the reservoir, an electric heating device is used to heat up the crude oil in the reservoir near the wellbore to the target temperature. Chemical reaction additives are injected into the heating section to meet the preset reaction conditions for the high temperature thermal cracking and aquathermolysis of crude oil, so as to generate light hydrocarbon components and gases. Under the effect of heat and gravity, the light hydrocarbon components and gases rise to the steam chamber. The light hydrocarbons and some gases that move to the vapor-liquid interface of the steam chamber are dissolved in the crude oil to reduce the viscosity of crude oil and increase the production rate of crude oil.

Abstract: A CCUS system for exploiting a thickened oil reservoir based on an optimal flue gas CO2 enrichment ratio. The CCUS system comprises a flue gas CO2 enrichment unit, a flue gas injection unit, a thickened oil thermal production well group unit and a produced gas recovery unit; the fuel gas CO2 enrichment unit comprises an air separating enrichment unit and a boiler injection gas premixed tank; the air separating enrichment unit comprises an air separating primary device used for separating air into oxygen and nitrogen preliminarily, and an air separating secondary device used for further enriching a part of the oxygen which is subjected to the preliminary separation; and the boiler injection gas premixed tank is used for mixing the preliminarily separated nitrogen, the preliminarily separated part of the oxygen and/or the further enriched oxygen.

Abstract: Systems and methods for controlling operation of a well, of which the method includes receiving an operation setting for operation of a system that provides lift gas into and produces gas from the well, monitoring operation of the system using a first controller, determining, using the first controller, that the system is not operating at the operation setting, and in response to determining that the system is not operating at the operation setting, sending, using a two-way communication link from the first controller to a second controller, a control signal to the second controller. The control signal is configured to cause the second controller to modify an operation of a compressor of the system.

Abstract: Methods of Enhanced Oil Recovery (EOR) from an oil reservoir by CO2 flooding are disclosed. One method comprises producing a well stream from the reservoir; separating the well stream into a liquid phase and a gas phase with a first gas/liquid separator, wherein the gas phase comprises both CO2 gas and hydrocarbon gas; cooling the gas phase with a first cooler; compressing the gas phase using a first compressor into a compressed stream; mixing the compressed stream with an external source of CO2 to form an injection stream; and injecting the injection stream into the reservoir. Systems for EOR from an oil reservoir by CO2 flooding are also disclosed.

Abstract: A system and method for thermal cracking of crude oil is provided. The system includes a plurality of communicatively coupled components configured to support thermal cracking of crude oil and performs a method including a continuous, industrial-sized thermal cracking process used to convert heavy crude oil or extra-heavy crude oil into lighter crude oil, using a liquid catalyst to prevent coke formation and promote alkylation reactions.

Abstract: A two-step process to produce oil or gas from a subterranean formation wherein in a first step the subterranean formation is treated with an aqueous composition containing a chelating agent selected from the group of glutamic acid N,N-diacetic acid or a salt thereof (GLDA), aspartic acid N,N-diacetic acid or a salt thereof (ASDA), methylglycine N,N-diacetic acid or a salt thereof (MGDA), and N-hydroxyethyl ethylenediamine N,N?,N?-triacetic acid or a salt thereof (HEDTA) and wherein, in a next step, in the outlet streams from the subterranean formation the aqueous phase is separated from the non-aqueous phase.

Abstract: Embodiments of the present disclosure disclose a shale oil in-situ lightening development method, apparatus and system, wherein the method comprises: determining an effective shale interval according to an interval with a total organic carbon greater than a first lower limit value in a target stratum; determining a favorable region for shale oil in-situ lightening development according to a thickness of the effective shale interval and an effective layer thickness ratio, wherein the effective layer thickness ratio includes a ratio of the thickness of the effective shale interval to a thickness of a shale section, and the shale section includes the effective shale intervals and interlayers therebetween. By utilizing the embodiments of the present disclosure, the benefit of the shale oil in-situ lightening development can be improved.

Abstract: A method may include: determining a total dissolved solids (TDS) concentration of a water source; correlating the TDS concentration to an ion concentration; and selecting at least one friction reducing polymer for a hydraulic fracturing operation based at least in part on the ion concentration.

Abstract: A method for hydraulically fracturing a subterranean formation includes preparing and sending a first command signal from a master controller to a plurality of pumps of a pump system. The first command signal specifies a flow rate output for each in pump to achieve a first target flow rate for a fracturing fluid being injected into the subterranean formation. A pressure of the fracturing fluid injected into the subterranean formation at the first target flow rate is monitored and, based on the pressure, the master controller determines when to increase a flow rate of the fracturing fluid to a second target flow rate. The master controller prepares and sends a second command signal to the plurality of pumps to specify the flow rate output for each pump to achieve the second target flow rate.

Abstract: A system comprising: a reservoir (14) for holding a liquid; a pump (20) arranged to pump the liquid out of the reservoir (14) or into the reservoir (14); a level sensor (26) configured to detect the level of the liquid in the reservoir (14) and to generate level data; a current monitor (28) configured to monitor the current drawn by the pump (20) and to generate current data; and a controller (30) configured to: receive level data and determine the static head from the level data, and generate head data from the static head; receive first current and head data corresponding to the current drawn by the pump (20) as a function of the static head for a first period of operation of the pump (20); receive second current and head data corresponding to the current drawn by the pump (20) as a function of the static head for a second period of operation of the pump (20), wherein the second current and head data is recorded when the liquid in the reservoir (14) is between a first liquid level and a second liquid level,

Abstract: Disclosed is a method for monitoring well or borehole performance, where the method includes: receiving data including a pumped flow Q from a flow meter in the well or borehole, the well or borehole including at least: receiving a water level from a water level sensor in the well or borehole; a pump and a water level sensor; a flow meter; the pump and water level sensor in connection to computer element; generating one or more values of specific capacity Q/s, at a pump event. The method includes selecting one or more specific capacity Q/s values which are comparable under a first rule, the first rule including values of static water level SWL which remain substantially invariable.

Abstract: Small footprint, portable skid mounted wellhead desander systems are disclosed. In one version, two systems are mounted on the skid, one system being a single well system for testing various properties of well fluids, and the other being a combined bulk system for desanding comingled flow from a plurality of wells. In another version, the skid mounted system has three independent desanders together with all essential equipment, including e.g., plug catcher, hydrocyclone desander, solids accumulator, choke manifold, and all necessary sensors, valving and control equipment.

Abstract: Mitigating corrosion and surface scale formation in a sour gas well includes providing an oil-based liquid to a sour gas well having carbon steel tubing with iron sulfide on a surface of the carbon steel tubing, contacting the carbon steel tubing with the oil-based liquid, and adsorbing a first portion of the oil-based liquid onto the iron sulfide, thereby yielding a hydrophobic coating on the carbon steel tubing.

Abstract: The disclosure generally refers to compositions and methods for treating subterranean formations that improve the recovery of hydrocarbons from the subterranean formations. The compositions include positively and negatively charged nanoparticles suspended in a carrier fluid that is not a drilling fluid and is free of cement and foaming agents. The populations of nanoparticles may be of different sizes, different materials, and comprise different ratios. The composition may also include: surface-active agents, such as surfactants, polymers; detergents; crystal modifiers; stabilizers, or hydronium. In some embodiments, the surface-active agents may bind to the surface of the positively or negatively charged nanoparticles. A subterranean formation may then be injected with the composition.

Abstract: The present invention essentially comprises a system to eliminate and or reduce unwanted vapors from oil by providing a conduit from a vessel holding accumulated oil and communicating the vapors to a burner at a tank battery system.

Abstract: One aspect of an emulsion includes an internal phase including acid, an external phase including supercritical carbon dioxide, and multiple nanoparticles to stabilize the internal phase and the external phase. The acid can include hydrochloric acid. The hydrochloric acid can include 15% hydrochloric acid. The nanoparticles can include hydrophobic nanoparticles. A concentration of nanoparticles in the emulsion can be at least 0.1% by weight. The emulsion can include a corrosion inhibitor. A concentration of the corrosion inhibitor can be in a range of between 0.25% and 0.6% by volume. A ratio of a concentration of the acid to a concentration of the supercritical carbon dioxide can be in a range between 30% and 70%.

Abstract: An arrangement of an unmanned and remotely operated production facility comprising a wellhead platform including a wellhead assembly having an X-mas tree, a flowline transporting hydrocarbon fluids produced from a well via said wellhead assembly to one or more consecutive process equipment(s), and further on to a destination via a transport line. Any process equipment and/or pipeline section located at a higher level than said outlet point from said wellhead assembly, is arranged to either drain back to the x-mas tree, or drain downstream to said transport pipeline by assistance of respective valves arranged along said flowline.

Abstract: The present invention is a device and a method that combines a carbon disulfide-releasing chemical with a low pH organic or inorganic acid to produce a carbon disulfide-containing fluid at or near the point of injection that minimizes or eliminates the possible exposure of carbon disulfide to workers and the environment. In one particular embodiment a positive displacement injection pump injects the carbon disulfide-containing fluid into a crude oil system for treating crude oil transmission lines and in downhole tubulars to remove paraffin deposits. The device uses a unique in-line motion mixer to mix two fluids. The device is electronically controlled locally and remotely with the system operating data displayed locally and transmitted remotely. The paraffin treating carbon disulfide-containing fluid and supplemental chemicals dissolve, disperse and remove paraffin deposits.

Abstract: Disclosed are methods for making emulsions and emulsions, that in some embodiments can be considered to be Pickering emulsions.

Abstract: Producing high purity lithium solution from a lithium source containing dissolved Na+, Ca2+, and Mg2+, by: passing the source into and out of a bed of sorbent composed of hydrated alumina intercalated with LiX, preferably LiCl, to extract lithium from the lithium source into the sorbent; washing the bed of sorbent with dilute aqueous LiCl to remove lithium from the sorbent to obtain a lithium eluent of increased Li+ concentration; subjecting this eluent to nanofiltration to produce a lithium permeate from which Ca2+, Mg2+, and other nanofilterable components are concurrently removed, yielding a permeate solution with 25% or less, and a retentate solution with 75% or more Ca2+ and Mg2+, as compared to the eluent from washing; and subjecting the permeate solution to a particular forward osmosis yielding a solution having 13,000-25,000 ppm dissolved lithium. Specified optional steps and new features can be used to increase lithium concentrations and purity.

Abstract: Systems and methods for subsea fluid phase separation. A two phase embodiment of the subsea fluid separation system separates a multiphase flow into gas and liquid phases. A three phase embodiment of the subsea fluid separation system separates multiphase flow into gas, oil, and water phases. The subsea fluid separation systems include a wellhead desander system to remove solids from the multiphase flow, a vertical gas-liquid separation module having associated valves disposed in series with a horizontal gas-liquid separation module having associated valves, one or more pumps to provide fluid flow to the vertical and horizontal separators, and a control system to control operation of the valves and pumps. The three phase embodiment further includes oil-water separators and multi-stage hydrocyclones for produced water treatment in a subsea environment.

Abstract: A system (100) for injecting flue gas to a subterranean formation, wherein the system (100) is configured to receive an initial mixture of N2, CO2 and less than 2% other components and comprises a compressor (110) for obtaining and maintaining a predetermined downhole pressure. The system (100) has a control system (200) for maintaining the amount of CO2 in an injection mixture in the range 12-90% and can be configured for EOR.

Abstract: Systems and methods for removing iron from waste water employ one or more oxidizers, one or more treatment tanks having one or more self-generating and self-sustaining active sludge layers, and one or more spray-atomizing devices. A mixture of flowback fracturing water, or produced water, and the one or more oxidizers is spray-atomized by the spray-atomizing device inside the one or more treatment tanks. The atomized mixture settles in the one or more treatment tanks resulting in one or more self-generating and self-sustaining active sludge layers and one or more treated solutions. Additional mixtures of the flowback fracturing water, or produced water, and the one or more oxidizers may be continually spray-atomized into the one or more treatment tanks and filtered by the one or more sludge layer(s) so as to remove precipitated iron species from accumulated distillates and produce additional treated solutions for collection in one or more finish tanks.

Abstract: An energy-dissipating device and fluid processing system is provided containing a compressor, a motor, a secondary fluid re-circulation loop, a purge line, and a fluid conduit. The compressor is configured to receive a hot fluid including condensable and non-condensable components, and produce therefrom a primary compressed fluid stream and a secondary fluid stream. The motor is configured to drive the compressor and for ingress and egress of the secondary fluid stream. The secondary fluid re-circulation loop is configured to control an operating temperature of the motor. The secondary fluid re-circulation loop includes a first energy-dissipating device configured to remove excess heat from the secondary fluid stream. The purge line separates a first portion of the secondary fluid stream in the fluid re-circulation loop from a second portion of the secondary fluid stream being returned to the motor. The fluid conduit receives the primary compressed fluid stream from the compressor.

Abstract: A system for offshore hydrocarbon processing may include a host at surface level, a subsea processing plant, and an umbilical connecting the host and the subsea processing plant. The subsea processing plant may be adapted to receive a multi-phase hydrocarbon stream from a wellhead and to output at least a hydrocarbon gas-phase stream satisfying a rich gas pipeline transportation specification to a pipeline. The umbilical provides a desiccant for drying the hydrocarbon gas, as well as power and control, from the host to the subsea processing plant.

Abstract: A system and method for operating a gas lift plunger in a well. The method includes determining that the plunger is at a predetermined position in the well, well. The method also includes introducing gas from a compressor into a sales line in response to determining that the plunger is at the predetermined position in the well. The method also includes and introducing the gas from the compressor into the well at a predetermined amount of time after the plunger is determined to be at the predetermined position in the well.

Abstract: A system includes a manifold and a shared valve actuation system that is operatively coupled to the manifold at a single location. The manifold is comprised of a block with at least one drilled header hole formed within the block, a plurality of drilled flow inlet holes formed within the block, wherein the number of drilled flow inlet holes corresponds to the number of external flow lines that supply fluid to the manifold, and a plurality of isolation valves coupled to the block, the valve element for each of the isolation valves positioned within the block. The system includes an arm that rotates about an axis that is normal to an upper surface of the block of the manifold, a plurality of structural elements that are coupled to one another via rotary joints, and a tool that engages and actuates one of the plurality of isolation valves.

Abstract: The present disclosure provides methods and apparati for separating liquids from production gases and recovering the liquids. The methods and apparati of the present disclosure can reduce or eliminate emissions compared to standard methods and devices and also eliminate the need for haul away of liquids by collecting compressor system liquids in charge vessel(s). The methods and apparati of the present disclosure can also be used to fuel the engines which operate the compressor systems using gas from the compressor drains and the gas used to drain the charge vessel(s).

Abstract: A modular assembly for a portable hemodialysis system may include a dialysis unit, e.g., that contains suitable components for performing hemodialysis, such as a dialyzer, one or more pumps to circulate blood through the dialyzer, a source of dialysate, and one or more pumps to circulate the dialysate through the dialyzer, and a power unit having a housing that contains suitable components for providing operating power to the pumps of the dialysis unit. The power unit may be selectively connected to the dialysis unit and provide power (e.g., pneumatic power in the form of pressure and/or vacuum) to the dialysis unit for the pumps when connected to the dialysis unit, but may be incapable of providing power to the dialysis unit when disconnected from the dialysis unit. The dialysis unit and the power unit are sized and weighted to each be carried by hand by a human.

Abstract: An apparatus for degassing drilling fluid comprising a primary separator and a secondary separator, the primary separator comprising a vessel body having an inlet port, a liquid outlet port located at a lower end of the vessel body, and a gas vent port located at an upper end of the vessel body, the secondary separator having an inlet port which is connected to the gas vent port of the primary separator, a gas outlet port, and a liquid outlet port which is connected to the interior of the vessel body of the primary separator via a liquid return line.