Abstract: Embodiments herein generally relate to a method and system for oil recovery using solvent-assisted electric heating. In at least one example, the method comprises A method for oil production using solvent-assisted electric heating, comprising conveying liquid solvent into a subsurface formation; operating at least one downhole electric heater to vaporize the solvent in-situ, the at least one downhole electric heater being operated in a temperature range that is: (i) above the vaporization temperature of the solvent; and (ii) below the steam saturation temperature of the reservoir; conveying a mixture comprising oil and solvent from the subsurface formation to a separation subsystem; and separating, using the separation subsystem, the oil from the solvent.

Abstract: The present invention disclosed a method for underground separation of components in sulfur-containing flue gas and sequestration of carbon dioxide and sulfides, comprising: injecting sulfur-containing flue gas into injection well which is arranged in a well pattern of a sequestrated aquifer in advance; transiting and injecting formation water into the formation at a first preset injection speed by injection well of the well pattern after injecting the sulfur-containing flue gas for a first preset time, maintaining the first formation pressure, and conducting water drainage and gas production by a production well of the well pattern in a mode of a fixed bottom hole flowing pressure; and determining the well shut-in time according to the nitrogen molar concentration of the production well and conducting well shut-in. The separated N2 is produced, while the separated CO2 and sulfides are sequestered in aquifer, achieving effective underground separation of the flue gas components.

Abstract: Methods and systems for gasifying coal are disclosed herein. In some embodiments, a representative coal gasification system can comprise (i) an injection well extending from a ground surface to an underground coal gasification (UCG) reaction region of a coal seam; (ii) a production well spaced apart from the injection well and extending from the ground surface to the UCG reaction region, and (iii) conduits each extending from the ground surface to areas of the coal seam. End portions of the conduits within the coal can be laterally peripheral to the UCG reaction region. The conduits are configured to deliver a primary fluid from the ground surface to the primary region, the injection well is configured to deliver an oxidant gas to the UCG reaction region, and the production well is configured to deliver the product gas from the UCG reaction region to the ground surface.

Abstract: A method for preparing a geothermal system involves preparing a wellbore that extends into an underground magma reservoir. Characteristics of the drilling process and the borehole are monitored to detect when the magma reservoir is reached, such that specially configured drilling operations can be performed to drill to a target depth within the magma reservoir.

Abstract: Methods and systems for quenching an underground carbonaceous formation with carbon and/or sequestering carbon within an underground carbonaceous formation are disclosed herein. In some embodiments, a representative system can comprise (i) an injection conduit extending to a first underground region that has a first hydraulic resistance, (ii) a production conduit extending from the first underground region, and (iii) an injection well extending toward a second underground region that has a second hydraulic resistance. The second underground region is laterally spaced apart from the first underground region by an adjacent formation having a third hydraulic resistance higher than that of the first hydraulic resistance and the second hydraulic resistance.

Abstract: A system and method for treating associated gas in which a stream of raw gas is passed through safety valving, an inlet pressure control mechanism, and an inlet scrubber. Pressure/temperature data is transmitted to a control system via pressure and temperature transducers. The raw gas is sent to a gas compressor to generate pressurized gas, which is sent to an aerial cooler and a chiller heat exchanger, in which a chilling media contacts the pressurized gas. The chilled pressurized gas is sent to a vapor liquid separator to generate processed gas, which is routed through either a system backpressure valve or a pressure reducing recycle valve that directs the processed gas to the inlet scrubber. The processed gas that has passed through the system backpressure valve is delivered as fuel or routed through a backpressure regulating recycle valve that directs the processed gas to a system inlet pressure reducing valve.

Abstract: A biogas treatment process is integrated with a water treatment process to adjust the pH level of the water and to provide more effective disinfection of the water. A water wash process is utilized to separate methane and carbon dioxide present in the biogas. During the water wash process, the biogas is mixed with water and the carbon dioxide is absorbed into the water. Because the process typically occurs at an elevated pressure and reduced temperature to enhance the solubility of carbon dioxide in water, the water stream becomes supersaturated with carbon dioxide. This water stream, which is supersaturated with carbon dioxide, is provided to the water treatment process to adjust the pH level of the water treatment process. The pH level is regulated to a desired level such that an increased relative concentration of hypochlorous acid is produced when sodium hypochlorite is added to the treatment process.

Abstract: A method of removing a sulfate scale from a surface is provided. The method includes contacting the sulfate-comprising scale with a conversion solution including 1 to 10 wt. % of an alkali metal carbonate, 0.5 to 10 wt. % of a borate salt or hydrate thereof, and 0.5 to 2.5 wt. % of a base to produce a carbonate-comprising scale. The method further includes exposing the carbonate-comprising scale with an acid solution including 2.5 to 25 wt. % of an acid.

Abstract: A production well system includes a main wellbore extending from a wellhead and penetrating a subterranean hydrocarbon-bearing formation, a lateral wellbore extending from the main wellbore, production tubing arranged within the main wellbore and in fluid communication with a production fluid present in the subterranean hydrocarbon-bearing formation, a separator arranged within the production tubing and operable to separate the production fluid into a hydrocarbon stream and a water stream, wherein the hydrocarbon stream is conveyed to the wellhead within the production tubing and the water stream is conveyed to the lateral wellbore, and a pump arranged uphole from the separator and operable to receive and convey the water stream into downhole portions of a lateral wellbore, thus creating a multi-purpose well which may reduce operating and capital expenditures while increasing production of existing and dead wells.

Abstract: A method and a system for oil recovery are provided. An exemplary method includes injecting thickened carbon dioxide (CO2) into the top of a reservoir containing oil. An interface is formed between the thickened CO2 and the oil. The oil is mobilized by the thickened CO2. The mobilized oil is recovered with a recovery well drilled below the reservoir.

Abstract: A system includes production tubing, a telescoping joint, a pump sub, a lock ring, and a crossover. The production tubing provides a hydraulic connection from a surface location to a well. The telescoping joint has a housing and a by-pass hanger having a head. An opening of the housing is larger than the by-pass hanger and smaller than the head and the head is moveably located within the housing. The lock ring is disposed around the by-pass hanger directly beneath the opening of the housing. The lock ring absorbs a compressive force and prevents the by-pass hanger from moving in an upwards direction. The crossover component is hydraulically connected to the production tubing and provides the hydraulic connection to the telescoping joint and the pump sub. The pump sub is located parallel to the telescoping joint, and the pump sub is connected to an electric submersible pump string.

Abstract: Systems, methods and apparatus are provided through which in some implementations an apparatus to produce SAF from dry natural gas includes a natural gas reforming area that receives the dry natural gas and that produces synthetic gas from the dry natural gas, a Fischer-Tropsch conversion area that is operably coupled to the natural gas reforming area and that receives the synthetic gas and produces a hydrocarbon chain from the synthetic gas and a product upgrading area that is operably coupled to the Fischer-Tropsch conversion area that receives the hydrocarbon chain and that produces the SAF from the hydrocarbon chain.

Abstract: A drilling fluid may include a carrier and a lubricant composition. The lubricant composition includes ethylene bottoms heavy pyrolysis oil. For example, the heavy pyrolysis oil may be bottoms of a fractionated fuel oil product separated from ethylene gas produced by a cracking of a hydrocarbon feedstock in a furnace.

Abstract: A process for controlled in-situ coal gasification is disclosed. The process includes surveying one or more selected coal bearing sites for designing a plurality of panels; designing a plurality of sub-panels of a plurality of corresponding panels with a plurality of bi-directional boreholes and a plurality of vertical service boreholes; channelizing the plurality of bi-directional boreholes and vertical service boreholes to one or more layers of coal seams; constructing one or more coal slice areas of predefined dimensions within the one or more layers of the coal seams; combusting coal inside the one or more coal slice areas; extracting combusted coal from the one or more coal slice areas through the plurality of vertical service boreholes; monitoring physical condition of at least one cavity created by extraction of the combusted coal; controlling remote filling of a filling material simultaneously at the at least one cavity using the filling device.

Abstract: Systems, methods and apparatus are provided through which in some implementations an apparatus to produce SAF from dry natural gas includes a natural gas reforming area that receives the dry natural gas and that produces synthetic gas from the dry natural gas, a Fischer-Tropsch conversion area that is operably coupled to the natural gas reforming area and that receives the synthetic gas and produces a hydrocarbon chain from the synthetic gas and a product upgrading area that is operably coupled to the Fischer-Tropsch conversion area that receives the hydrocarbon chain and that produces the SAF from the hydrocarbon chain.

Abstract: A method for selectively optimizing water chemistry within a wellbore may include positioning a system tubing in the wellbore. The system tubing may include an electrochemical cell, a first chamber, and a second chamber. The method may also include injecting a fluid into the electrochemical cell and directing an electrical current into the electrochemical cell wherein the fluid separates by charge into a first fluid and a second fluid. The method may also include passing the first fluid into the first chamber and the second fluid into the second chamber. Also, the method may include rotating the system tubing, wherein the first fluid flows from the first chamber to the wellbore through a first radial conduit and the second fluid flows from the second chamber to the wellbore through a second radial conduit.

Abstract: An aqueous feed stream having a first total dissolved solids (TDS) level is flowed to a forward osmosis separator. The aqueous feed stream includes seawater. An aqueous draw stream having a second TDS level is flowed to the forward osmosis separator. The second TDS level is greater than the first TDS level. A disposal stream and an injection fluid stream is produced by the forward osmosis separator by allowing water to pass from the aqueous feed stream to the aqueous draw stream through a membrane of the forward osmosis separator based on a difference between the first TDS level and the seconds TDS level. The injection fluid stream is flowed from the osmosis separator to a subterranean formation.

Abstract: A method for using a surfactant formulation in chemical enhanced oil recovery, wherein said surfactant formulation comprises at least: (i) an anionic salt of an alkyl alkoxylated sulfate, wherein said alkyl alkoxylated sulfate has a molecular structure as shown in (I), wherein R is a linear, branched or mixture of linear and branched alkyl group having from 10 to 20 carbon atoms, n=4 ?15, m=0-10, M+ is an alkali metal ion, an alkanolamine ion, an alkyl amine ion or an ammonium ion; and (ii) a non-ionic alcohol O ethoxylate, wherein said alcohol ethoxylate has a molecular structure as shown in (II), wherein R1 is a linear, branched or mixture of linear and branched alkyl group having from 8 to 24 carbon atoms, y=20-100.

Abstract: A method includes receiving, by a processing device and from one or more sensors coupled to a water reservoir storing water received from a separator, fluid information. The fluid information includes a water level of the water reservoir. The separator is fluidically coupled to a wellbore string disposed within a wellbore. The method also includes determining, based on the fluid information, operation mode instructions. The method also includes transmitting, to a controller communicatively coupled to at least one flow regulation device fluidically coupled to the wellbore string, the operation mode instructions. The controller controls, based on the instructions, the at least one flow regulation device to regulate, during a production mode of the wellbore string, a flow of production fluid from the wellbore string to the separator or regulating, during a water injection mode of the wellbore string, a flow of water from the water reservoir into the wellbore string.

Abstract: A filling element has a gas valve that controls flow of gas through a gas channel that extends into or faces the container during filling thereof. The gas valve transitions between discrete states, which includes a fully-open state, a closed state, and one or more partially-open states.

Abstract: A method for controlling corrosion is described. The method includes determining a concentration of a first gas in a first formation, determining a concentration of a second gas different than the first gas in a second formation, determining a ratio between the first gas and the second gas, comparing the determined ratio to a threshold ratio of the first gas to the second gas for the wellbore which reduces a corrosion rate within the wellbore, and based on a result of comparing the determined ratio to the threshold ratio, modifying a quantity of the first formation fluid or the second formation fluid flowed into the wellbore. The first gas and the second gas mix within the wellbore.

Abstract: This disclosure relates to membrane-based systems for transporting dissolved gases to a formation and methods for increasing a mass transfer rate of gases in a formation. The membrane-based system may include an aqueous injection well, a diffusion-based membrane, a gas, and an aqueous solution.

Abstract: New formulation for pyrite scale removal from oil and gas wells and a method of pyrite scale removal are disclosed. The chemical formulation is composed of K2B4O7-4H2O, in a concentration of about 9-20 wt. % of the composition, preferably about 14 wt. % of the composition. The new formulation has the ability to dissolve pyrite without generation of the toxic H2S. Furthermore, the new formulation is cheaper and has very low corrosion rate compare to 15 wt. % HCl with corrosion inhibitor. The disclose method uses the disclosed new formulation to dissolve iron sulphide scale, performed at about 100-150° C. and about 500-2000 psi.

Abstract: Herein are provided tools and processes for extracting oil from subterranean formation. The processes can include lightening the oil in the formation prior to extraction by the addition of a nanogas solution. The tools include injectors for the formation of the nanogas solution within the subterranean formation.

Abstract: A subsea multiphase fluid separation system has a gas separator for separating gas from a well stream containing oil. A water separation stage downstream of the gas separator has at least one dual pipe separator for separating water from the oil of the wellstream. A water treatment system for cleaning oil from water is produced by the water separation stage. On an oil outlet path, downstream of the or each dual pipe separator, there is an electrocoalescer and at least one second separator in series.

Abstract: A method for pumping a liquid-gas mixture into a subsurface well includes introducing gas into a liquid at a first pressure to generate a mixture. The mixture is pumped through a first positive displacement pump to a second pressure greater than the first pressure. The mixture at the second pressure is pumped through at least a second positive displacement pump to a third pressure greater than the second pressure. The mixture is moved into the subsurface well at at least the third pressure.

Abstract: A method may include providing a humidification-dehumidification unit proximate one or more abandoned wells, circulating a water feed through the one or more abandoned wells, using geothermal heat in the one or more abandoned wells to heat the water feed, directing the heated water feed to the humidification-dehumidification unit, and treating the heated water feed in the humidification-dehumidification unit to provide purified water.

Abstract: A hydrocarbon production field layout comprising a first pipeline (1) with a first inner diameter and a second pipeline (2) with the first inner diameter. A cut off valve (20) with an inner bore with the first diameter, is arranged in a connecting arrangement between an end of the first pipeline (1) and an end of the second pipeline (2). At least one dual main header manifold (3) is in fluid connection with at least one hydrocarbon well (8, 9). A first branch pipe (16, 18) with a first valve (5, 6) is branched off from the first pipeline (1) and a second branch pipe (17, 19) with a second valve (5, 7) is branched off from the second pipeline (2). The branch pipes are connected to the at least one manifold (3, 4).

Abstract: A method of dissolving a gas hydrate in a pipeline includes introducing a gas hydrate dissolving solution into the pipeline and allowing the gas hydrate dissolving solution to at least partially dissolve the gas hydrate in the pipeline. The gas hydrate dissolving solution includes cesium formate, potassium formate, or both, and has a flash point of greater than 50° C.

Abstract: An oil-water fractionation system is positioned within a wellbore on a subsurface end of a production tubing proximate to a production region. The fractionation system includes a permeable hydrophobic media for preferentially conveying an oil-enriched stream (reduced water-cut presence) from the production region into the production tubing, and a permeable oleophobic media for preferentially conveying a water-enriched stream (reduced oil-cut presence) into a second flow path. The permeable hydrophobic media and the permeable oleophobic media are in simultaneous hydraulic communication with the production region. The permeable hydrophobic media is manufactured with a relatively high effective permeability to oil, allowing the oil-enriched stream to flow through the permeable hydrophobic media into the production tubing.

Abstract: A method and system of providing source water and managing produced/flowback water during a hydraulic fracturing process in an oil and gas operation. The process is an environmentally friendly method of reducing use of fresh water and recycles frac water. The net result is that a volume of frac water is properly managed. Thus, less reliance on transportation vehicles and trucks reduces costs as well as reduction of piping systems. It further reduces a threat of seismic events from disposing of produced water and flowback.

Abstract: A method of dissolving a gas hydrate in a pipeline includes introducing a gas hydrate dissolving solution into the pipeline and allowing the gas hydrate dissolving solution to at least partially dissolve the gas hydrate in the pipeline. The gas hydrate dissolving solution includes a glycol, dimethylformamide, or both, and has a boiling point of greater than 80° C. A method of dissolving a gas hydrate in a pipeline may also include introducing a gas hydrate dissolving solution into the pipeline and allowing the gas hydrate dissolving solution to at least partially dissolve the gas hydrate in the pipeline. The gas hydrate dissolving solution includes comprises a glycol, dimethylformamide, cesium formate, potassium formate, or combinations thereof, and has a flash point of greater than 50° C.

Abstract: Methods and systems for gasifying coal are disclosed herein. In some embodiments, a representative coal gasification system can comprise (i) an injection well extending from a ground surface to an underground coal gasification (UCG) reaction region of a coal seam; (ii) a production well spaced apart from the injection well and extending from the ground surface to the UCG reaction region, and (iii) conduits each extending from the ground surface to areas of the coal seam. End portions of the conduits within the coal can be laterally peripheral to the UCG reaction region. The conduits are configured to deliver a primary fluid from the ground surface to the primary region, the injection well is configured to deliver an oxidant gas to the UCG reaction region, and the production well is configured to deliver the product gas from the UCG reaction region to the ground surface.

Abstract: A method of removing calcium carbonate-containing oil-based filter cake from a wellbore involving contacting the calcium carbonate-containing oil-based filter cake with a biodegradable acid solution of water, hydrochloric acid, formic acid, citric acid, a surfactant, and a glycol ether mutual solvent. The method is performed at a pressure of 200 to 400 psi and a temperature of 50 to 125° C. The method removes calcium carbonate-containing oil-based filter cake made of a water-in-oil emulsion, calcium carbonate, a primary emulsifier, a secondary emulsifier, a contamination treatment agent, a viscosity control agent, a filtration control agent. The method meets industry standard steel corrosion rates of less than 0.049 lb/ft2 per day. Also disclosed is a biodegradable acid solution of water, hydrochloric acid, formic acid, citric acid, a surfactant, and a glycol ether mutual solvent that meets OECD 301B thresholds for ready biodegradability.

Abstract: The invention relates to a method for recovery of hydrocarbons in a geological reservoir by injection of a low-salinity aqueous solution. A representative model of the evolution of the flow parameters as a function of the aqueous solution salinity is calibrated by use of laboratory measurements performed on a rock sample from the reservoir for at least two salinity values. Then, by use of a flow simulator including the calibrated model, the injection of aqueous solutions into the sample is simulated, with and without capillary effects, for at least the two salinity values with a microscopic residual oil saturation being determined for each salinity value. Then, from the flow simulator including the calibrated model and the microscopic residual oil saturation values, a reservoir development scheme is determined with hydrocarbons of the reservoir being exploited according to the development scheme.

Abstract: The invention relates to the use of a non-ionic surfactant and an anionic surfactant for enhancing the injectivity of an injection well, wherein the non-ionic surfactant and the anionic surfactant are added to produced water, to form a reinjection stream which is injected into a subterranean formation by the injection well.

Abstract: Systems and methods for identifying a status of components of hydraulic fracturing units including a prime mover and a hydraulic fracturing pump to pump fracturing fluid into a wellhead via a manifold may include a diagnostic control assembly. The diagnostic control assembly may include sensors associated with the hydraulic fracturing units or the manifold, and a supervisory control unit to determine whether the sensors are generating signals outside a calibration range, determine whether a fluid parameter associated with an auxiliary system of the hydraulic fracturing units is indicative of a fluid-related problem, determine whether lubrication associated with the prime mover, the hydraulic fracturing pump, or a transmission of the hydraulic fracturing units has a lubrication fluid temperature greater than a maximum lubrication temperature, or determine an extent to which a heat exchanger assembly associated with the hydraulic fracturing units is cooling fluid passing through the heat exchanger assembly.

Abstract: Herein are provided tools and processes for extracting oil from subterranean formation. The processes can include lightening the oil in the formation prior to extraction by the addition of a nanogas solution. The tools include injectors for the formation of the nanogas solution within the subterranean formation.

Abstract: A flowback tank cleaning system and method is described. A flowback tank includes a self-cleaning system. A flowback tank cleaning method may include moving solid debris collected at a bottom of a collection section of a flowback tank towards a lift auger using a cleaning auger or a conveyer belt extending along a length of the collection section, the bottom of the collection section including an angled trough, funneling solid debris towards the cleaning auger or conveyor belt by placing the cleaning auger or conveyor belt at a base of the angled trough, spraying fluid downward through a series of fluid outlets, removing the sand so moved by the cleaning auger or conveyer belt from the flowback tank using the lift auger, and removing the fluid from the flowback tank using a drain manifold below the cleaning auger or conveyer belt.

Abstract: Disclosed is an improved vapor recovery system. The vapor recovery system includes a vapor recovery tower and a vapor recovery unit. The vapor recovery tower includes an internal heat exchanger suitable for heating crude oil processed by the vapor recovery tower. The vapor recovery unit includes a compressor suitable for compressing and thereby heating vapors and gases separated from crude oil by the vapor recovery tower. The gases heated by compression within the vapor recovery unit subsequently pass through the jacket or shell of the heat exchanger.

Abstract: A system and process for defining, blending and monitoring fresh water with subterranean produced formation fluids, with particular constituents of the blended waters being controlled for proper use in gel-type hydraulic fracturing operations. On-site measurements and calculations of clay stabilization replacement, through a Potassium Chloride (KCl) Equivalency calculation, provide feedback on water constituent adjustments that may be needed just prior to the gel-based hydraulic fracturing process. This assures adequate gel cross-linking times, delayed gel cross-linking times, and clay stabilization in the formation to be fractured.

Abstract: The present invention relates to a dry blend one-part pre-flush and spacer package for forming a water-based pre-flush and spacer on-the-fly for use in a subterranean well and a method of mixing a pre-flush and spacer on-the-fly for use in a subterranean well. The dry blend pre-flush and spacer package includes an anionic surfactant, a builder compound, and optionally, a defoamer, a dispersant calcium chelator, a density modifying agent, a viscosifying agent such as a solid, and preferably rapidly hydrating, gellant, salt and one or more lost-circulation materials. The dry blend pre-flush and spacer package is mixed on-the-fly with water at the subterranean well site to form the pre-flush and spacer at a pre-selected density and the pre-flush and spacer, when pumped into the subterranean well by a pressure pumper, converts the well from an oil-wet or substantially non-water-wet condition to a substantially water-wet condition.

Abstract: A reclaiming apparatus includes: a container in which a reclaiming process of an absorption liquid is performed; an absorption liquid supply line for supplying the container with the absorption liquid; a heat exchange device, installed inside the container, for heating a liquid inside the container; a circulation line for extracting the liquid inside the container, circulating the liquid and returning the liquid to the container; and a circulation pump installed in the circulation line.

Abstract: The invention relates to sewage treatment, and more particularly to a system for treating reverse-osmosis concentrated water with permanent hardness. The system includes a first crystallization unit, a first reverse osmosis unit, a second crystallization unit, a lime softening unit and a second reverse osmosis unit, which are connected in sequence. The system of the invention is able to eliminate the permanent hardness and the temporary hardness of the concentrated brine, and the hardness can be reduced to equal to or less than 50 mg/L.

Abstract: A method for recovering natural gas liquids from a recycle stream having natural gas is provided. In one embodiment, a carbon dioxide recycle stream that comprises carbon dioxide, natural gas, and natural gas liquids is received. The carbon dioxide recycle stream is separated into a purified carbon dioxide recycle stream and a natural gas liquids stream. The purified carbon dioxide recycle stream comprises the carbon dioxide and the natural gas, and the natural gas liquids stream comprises the natural gas liquids. In another embodiment, a system comprises piping and a separator. The piping is configured to receive a recycle stream, and the separator is coupled to the piping and is configured to separate the recycle stream into a purified recycle stream and a natural gas liquids stream.

Abstract: Systems and methods generate steam mixed with desired non-condensable gas concentrations using a direct steam generator. Injecting the steam into a reservoir may facilitate recovering hydrocarbons from the reservoir. Cooling an output of the direct steam generator produces water condensate, which is then separated from the non-condensable gas, such as carbon dioxide. Reducing pressure of the condensate subsequently heated by cross-exchange with effluent of the direct steam generator regenerates the steam with the carbon dioxide removed for the injection.

Abstract: A method to extract methane from a coal bed seam with carbon dioxide produced and recovered from a fuel cell anode exhaust stream while simultaneously sequestering the carbon dioxide on the coal. The process produces methane to supply a fuel cell to generate electricity while reducing or eliminating GHG emissions.

Abstract: Methods and systems for treating brine to produce distilled water and dried NaCl are disclosed. The brine enters a crystallization plant and is heated. Once heated, the brine is circulated to an evaporator. The evaporator increases the concentration of NaCl in the brine to a point about the super saturation level. Once above the super saturation level, NaCl crystals are formed. The larger crystals are circulated to a centrifuge for drying and the smaller crystals are recirculated through the evaporator for continued growth. The NaCl crystals are dried in the centrifuge.

Abstract: Methods of preparing an injection fluid for enhancing hydrocarbon recovery from a formation are described. A divalent salt is added to wastewater to form salinated wastewater. The salinated wastewater is tested for a shift in wettability. The salinated wastewater is tested for a change in oil recovery. The salinated wastewater is applied as an injection fluid. The shift in wettability is equal to or greater than a predetermined wettability differential value, and the change in oil recovery of the salinated wastewater is equal to or greater than a predetermined oil recovery differential value.

Abstract: A portable modular treatment system to be remotely deployed adjacent a solvent extraction bitumen well may include a portable initial separation module configured to receive a liquid emulsion from the solvent extraction bitumen well including bitumen, produced water, solvent, and at least one non-condensable gas, and liberate the at least one non-condensable gas while the solvent remains with the liquid emulsion. The system may further include a portable free water removal module configured to receive the liquid emulsion from the portable initial separation module and separate the bitumen and solvent from the produced water, a portable skimming tank module configured to receive the produced water from the portable free water removal module and remove free oil from the produced water through gravity separation, and a portable condenser module configured to receive the bitumen and solvent from the portable free water removal module and separate the bitumen and solvent.