Saudi Arabian Oil Company

Samusideen Adewale Salu

Mohamed Ahmed Soliman

Talal Al-Zahrani

Nisar Ahmad K Ansari

Nisar Ahmad Ansari

Talal A Zahrani

Khalid F Alanazi

Faris Abdullah Alshuaibi

Samer Osamah Abduljabbar

Mohamed Alwani

Hussain M Bayat

Najamulhasan S Tirmezi

Ali Mohammad Abbas

Ali Homoud Hassan Alshehri

Abdulrahman Alhumud

A gas oil separation plant may include a gas compression plant, configured to receive, compress, and separate one or more feed streams and a warmed refrigerant stream into a compressed gas stream and a condensate stream, a flow system for dividing the condensate stream into an export condensate stream and a refrigerant stream, a gas dewpoint control plant comprising a gas chiller configured for indirectly contacting the compressed gas stream with the refrigerant stream, producing the warmed refrigerant stream, and a flow line for feeding the warmed refrigerant stream to the gas compression plant. A method for gas oil separation may include compressing and separating one or more feed streams and a warmed refrigerant stream into a compressed gas stream and a condensate stream. The condensate stream is divided into an export condensate stream and the refrigerant stream which chills the compressed gas stream and becomes the warmed refrigerant stream.

Integrated gas compression and refrigeration with internal cooling regeneration

A compact pressure energy conservation gas oil separation plant system includes an inline separator device (ILS) that receives a wild crude oil and separates at least 95% of free gas and free water from the wild crude oil and discharges an ILS outlet crude stream, a wet-dry heat exchanger for heating the ILS outlet crude stream, thereby producing an exchanger outlet crude stream, a three-phase high-pressure-high-temperature (HPHT) separator that receives and separates gas and water from the exchanger outlet crude stream to achieve a Basic Sediment & Water specification of 0.2 v/v % or less, thereby producing an HPHT outlet crude stream, a high-pressure desalter and dehydrator (HPDD) that receives, desalts, and dehydrates the HPHT outlet crude stream, thereby further and producing an HPDD outlet crude stream, and a high-pressure stabilization column (HPSC) that receives and stabilizes the HPDD outlet crude stream, thereby producing an export grade crude stream.

Compact static high-pressure, high-temperature gas oil separation plant systems and methods

A flare gas recovery system includes an ejector that receives flare gas from a suction line extending from a flare gas header, and further receives a motive fluid that draws the flare gas into the ejector to be mixed with the motive fluid and discharge a recovered gas into a discharge gas line. A solid oxide fuel cell system receives the recovered gas and includes a fuel cell power module that uses the recovered gas to generate electrical power, an anode exhaust, and a cathode exhaust, a combustor that receives and combusts at least a portion of the anode and cathode exhausts and thereby generates waste heat, and a process gas heat exchanger that receives and converts the waste heat into electrical power.

Ejector and fuel cell-based flare gas recovery system

While operating a compressor system equipped with compression train(s), condensate is collected from within stages of the compression train(s), and directed to a blowdown system. Gas from a later stage of the compression train is routed to the blowdown system and used to drive the condensate to a condensate destination at a pressure that avoids flashing of the condensate until it reaches the condensate destination. Inside the blowdown system the condensate is stored in a tank and directed to parallel piped vessels. Operation of the vessels includes (1) receiving the condensate, (2) pressurization with gas from a later stage of compression, (3) flowing the pressurized condensate from the vessel to the condensation destination, (4) depressurizing the vessel, and (5) repeating steps (1)-(4). A flow of condensate from the blowdown system is continuous by staggering the phases of operation between the two vessels.

System for transferring condensate

A system for analyzing a multiphase production fluid, the system including a pipeline, an inlet divider having a set of analyzing apertures with densitometers and a set of production apertures, a fluidic separation chamber with flowmeters, a pressure control valve, and a fluidic control unit. Each analyzing aperture of the set of analyzing apertures disposed on a vertically-oriented axis of the inlet divider. The pipeline is configured to supply the multiphase production fluid to the inlet divider. The inlet divider is configured to provide an analysis portion of the multiphase production fluid to the set of analyzing apertures. The inlet divider is configured to provide a production portion of the multiphase production fluid to the set of production apertures. The set of analyzing apertures is configured to provide the analysis portion to the fluidic separation chamber.

Inlet dividers having a plurality of analyzing and production apertures for analyzing multiphase production fluid as well as systems incorporating the same

A recovery system includes a special organic Rankine cycle (SORC) system, an internal combustion system, a nitrogen generator and a gas-liquid separator. The SORC system includes a first stage heat exchanger (first HE), a plurality of second stage heat exchangers (second HE), a third stage heat exchanger (third HE), a turbo-expander, and at least one condenser. A recovery method, conducted in the recovery system, includes vaporizing a refrigerant, introducing the vaporized refrigerant to the turbo-expander to generate electricity, condensing the vaporized refrigerant in the at least one condenser, collecting nitrogen from the flue gas feed in the nitrogen generator, and collecting water from the flue gas feed in the gas-liquid separator. The refrigerant is vaporized by introducing the refrigerant through the first HE, second HE and third HE sequentially, and the flue gas feed through the third HE, second HE and first HE sequentially.

Optimized co-generating system and recovery method for power, water and nitrogen

Systems and methods for crude oil separations including degassing, dewatering, desalting, and stabilization. One method includes separating crude oil into a crude oil off-gas and a partially degassed crude oil output; compressing the crude oil off-gas; applying the compressed crude oil off-gas for indirect heating through reboilers of the partially degassed crude oil output; and directly mixing with the crude oil a compressed atmospheric pressure gas. In some embodiments, multiple reboilers are used. In some embodiments, heat exchangers are used. Aftercoolers are used after the compressor to cool the gas; knockout drums are used after the coolers to separate liquids.

Gas oil separation plant systems and methods with reduced heating demand

A flow of a chemical is mixed with a flow of a primary fluid to form a combined fluid, and during mixing a velocity of the combined fluid is maintained at a threshold value so that a resulting mixture of the chemical and primary fluid has a designated homogeneity. The primary fluid is directed to an end of a passage with a venturi like contour that is inside of a mixer, and the chemical is directed to a side passage that extends laterally in the mixer that intersects the passage. A spring loaded valve in the passage maintains the combined flow velocity at the threshold value.

Chemical injection and mixing device

Flare gas is recovered by varying a number of ejector legs that depends on a flare gas flowrate. The ejector legs include ejectors piped in parallel, each ejector has a flare gas inlet and a motive fluid inlet. Flare gas and motive fluid is provided to ejectors by selectively opening or closing valves. The number of ejector legs online is varied to accommodate the amount of flare gas. The controller is also programmed to direct signals to actuators attached to the valves to open or close the valves, or to change the capacity of the ejector legs so they can handle changing flowrates of the flare gas. Included is a flare gas storage system with vessels made with flexible material, when flare gas is evacuated from the vessels, pressure in the vessels is maintained by compressing the vessels with an external force.

Total flare gas recovery system

Additive is introduced into a tubular that carries produced fluid from a wellhead; the additive addition prophylactically guards against damage to the tubular, such as from corrosion or oxidation. Gas from the wellhead is utilized as a pressure source for driving the additive into the tubular. The rate of additive injection is varied based on characteristics of the tubular or fluid in the tubular. Characteristics of the fluid in the tubular include iron content, residual additive, moisture content, and flowrate; characteristics of the tubular include its corrosion rate of the tubular. The characteristics are measured real time, measured historically, or predicted from a model.

Injection of additives into a produced hydrocarbon line

Systems and methods for treating a rag layer in a gas oil separation plant. The method includes withdrawing the rag layer from a vessel proximate an oil water interface, conveying the rag layer to a separation device, and recycling separated oil from the separation device back to the gas oil separation plant process.

Desalting plant systems and methods for enhanced tight emulsion crude oil treatment

A fluid mixing device includes a plurality of nozzles, each having a converging chamber, at least one chemical injection port, a diverging chamber, a nozzle throat, and an adjustable self-opening valve. The fluid mixing device provides for improvements in mixing fluids.

Multi-opening chemical injection device

Control strategy and algorithms to be utilized in a programmable logic control for automating injection rates of corrosion inhibitor and scaling inhibitor in a process plant. The logic control system can be programmed on a Distributed Control System (DCS) or Supervisory Control And Data Acquisition (SCADA) of the plant. The automating system is developed with the objective of optimizing corrosion inhibitor and scale inhibitor usage, thereby reducing operating cost, improving the reliability and integrity of process plant facilities, and preventing undesirable incident of loss of containment.

Methods and systems for optimizing corrosion and scale inhibitor injection rates in process plants

Embodiments provide a surge suppression device, a surge suppression system, and methods for operating the same. The surge suppression device includes a valve body and a plug. The plug is rotatably positioned in a hollow space of the valve body. The plug includes two surge suppression openings defining a fluid flow directed to surge suppression. Each of the two surge suppression openings includes a circular plate having a plurality of orifices. The plurality of orifices allows reduction of surge pressure when the water passes the first fluid flow path. The circular plate has a concave or convex geometry.

Growing community of inventors

Ras Tanura, Saudi Arabia

Samusideen Adewale Salu