Atlantic Richfield Company

Sybtroleum Corporation

Richard L Payne

Miroslav M Kolpak

Gary L Beer

Sophany Thach

Richard F Stoisits

Jean S Weingarten

John R Wolflick

Tuan D Ma

M Jane Williamson

Richard A Cadle

Jeffry A Rugen

Gordon J Krist

Michael C Vincent

Wayne E Ogren

Gary K Youngren

Anthony C Schwarz

James C Wilcoxson

Richard E Huff

A process for converting a hydrocarbon gas (e.g. natural gas) to syngas which, in turn, is converted into a liquid hydrocarbon product wherein a substantial amount of the heat generated in the process is recovered for use in generating steam needed in the process or for conversion into mechanical energy. Further, tail gas produced by the process is used to fuel the gas turbine which, in turn, is used power the compressors needed for compressing the air used in the process. By using tail gas to fuel the gas turbine, less of the compressed combustion-air is needed to cool the combustion gases in the turbine and, instead, can be used to provide a portion of the process-air required in the process; thereby possibly saving up to 20 to 30 percent of the horsepower otherwise needed to compress the required volume of process-air.

Process for converting gas to liquids

A spiral or auger type gas-liquid separator, particularly for well production fluid flow, includes a vertically oriented conduit section having a spiral separator element disposed therein and around a central gas discharge conduit. The inlet to the gas discharge conduit is disposed adjacent the discharge end of the separator element and includes a liquid carryover control mechanism comprising a closure member which is operable to shut off fluid flow into the gas discharge conduit when high liquid flow rates or liquid slug flow passes through the separator. The shutoff closure member is connected to a float actuator responsive to liquid accumulation to actuate the closure member to move to a closed position. A coil spring biases the closure member toward a valve open condition. The float actuator includes cooperating telescoping members, one supporting the closure member and the other member comprising a flotation member, and a coil spring interposed between the two members to absorb impact forces due to rapid movement of the actuator to minimize damage to the closure member or its seat.

Liquid carryover control for spiral gas liquid separator

A system for distributing a fluid to a plurality of locations, in which a first conduit is provided receiving the fluid and a splitter is provided having a housing in flow communication with the first conduit for receiving the fluid. At least two branch conduits extend from the first conduit and parallel to the axis of the housing for respectively receiving portions of said fluid.

Fluid distribution system and method utilizing a radial splitter

A method for mitigating slugs in pipelines carrying multiphase mixtures of gas and liquid by adding a quantity of a surfactant selected from the group consisting of ethoxylated alcohols, polyglycosides and alpha olefin sulfonates to the multiphase mixture in the pipeline. After addition of a quantity of surfactant, a determination is made as to whether the quantity of surfactant added is sufficient to mitigate the slugs, and thereafter adjusting the quantity of surfactant added to an amount sufficient to mitigate the slugs.

Method for mitigating slugs in a pipeline

Liquid slug flow in oil production well flowlines and the like is controlled by a throttling valve in the flowline upstream of a gas-liquid separator and a differential pressure gauge, densitometer or other device for measuring the presence and the volume of the slug in the flowline. The throttling valve may be actuated to throttle fluid flow into the separator in relation to the presence of the slug and the duration of the slug as determined by the slug detection device. Slug mitigation may also be controlled by throttling flow into the separator in relation to the level of liquid in the separator between a threshold level and a maximum liquid level. A third method for mitigating slug flow measures the available volume in the separator vessel and the volume of the liquid slug moving toward the separator vessel to effect proportional throttling of fluid flow. A liquid slug may be detected by a differential pressure gauge or a densitometer interposed in the flowline upstream of the throttling valve.

Slug flow mitigation control system and method

A downhole gas-liquid separator for multiphase fluid producing wells includes a tubular member with a spiral baffle disposed therein and a duct including an inlet disposed adjacent the discharge end of the spiral baffle. Fluid flow into the separator undergoes substantial gas and liquid separation by centrifugal forces imposed on the liquid as it progresses through the spiral flowpath. Gas is drawn off at the discharge end of the spiral baffle and discharged into the wellbore annulus while liquid and a small amount of gas pass on through the separator and the production tubing to the surface. The spiral baffle may be disposed in the wellbore between the distal end of the production tubing string and the point of entry of gas and liquid into the wellbore. The separator may include a retrievable tubular body inserted in a ported nipple interposed in the tubing string.

Downhole gas-liquid separator for wells

Natural gas is reinjected into an earth formation for storage and/or stimulating the recovery of hydrocarbon liquids by mixing the gas with water at a pressure sufficient to maintain bubble flow of gas dispersed in a water flowstream in a range of volumetric gas fraction up to about twenty percent of total flow. A water and gas distribution system includes static flow mixers for maintaining uniform distribution of gas bubbles in the water flow stream through the distribution conduits. The mixers may comprise multi-stage bladed mixing elements of the same or opposite pitch and extending across the intersection of branch conduits with the main conduit of the distribution system. The water and gas may be mixed in an injection well having a tubing string extending within the well and having a distal end below the point of injection into an earth formation so that a uniform gas and water mixture enters the formation through the well perforations.

Simultaneous water and gas injection into earth formations

Multiphase fluid flow, such as a mixture of oil, water and gas, is measured by a system which includes one or two densitometers for measuring the multiphase fluid density flowing through a flowline or conduit and a flow restriction, pump, expander or heat exchanger interposed in the flowline between the densitometers to effect a pressure or temperature change in the multiphase fluid. Densities, pressures and temperatures are measured on the upstream and/or downstream sides of the flow restriction, pump, expander or heat exchanger and the measured values of density, pressure and temperature are used to obtain the flow rates of the respective phases in the flowstream.

Multiphase fluid flow measurement

Slug flow is substantially prevented in cylindrical pipes and other conduits by placing a generally flat plate partition extending within the pipe and dividing the pipe into a gas flow space and a liquid flow space. The position of the partition and the cross-sectional flow areas of the gas flow space and the liquid flow space are determined by predetermining that the pressure losses of gas flow and liquid flow should be substantially equal.

Fluid slug flow mitigation with partitioned pipe

A slug flow mitigation and gas separation device for well production fluids includes a primary fluid inlet conduit and a slug mitigation and gas separation chamber formed by a conduit section mounted generally vertically above the primary conduit. Spaced apart branch conduits interconnect the primary conduit with the slug mitigation and separation chamber and a check valve is interposed in the branch conduit disposed in the downstream direction of fluid flow through the device. Gas vent conduits are in communication with the slug mitigation and separation chamber for conducting separated gas away from the device.

Fluid slug flow mitigation and gas separation system

Oil and gas well production flow is gathered in field common line manifolds and conducted through a separator to make a coarse separation of gas from liquid and minimize slug flow in the conduits leading from the manifolds to further separation, treatment and pumping facilities. A liquid level signal transmitter provides a signal to a valve controller which controls separate liquid and gas discharge flow control valves or a variable speed pump to maintain a set point level of liquid in the separator. Liquid level control is accomplished automatically by varying the flow from the fluid discharge conduit which is connected to the lower pressure flow line, which is usually the gas flow line. Manifold pressures may be sensed to prevent exceeding a predetermined pressure in the manifolds and the well flow lines.

Growing community of inventors

McKinney, TX, United States of America

Richard L Payne