Patent ID: 12195678

DETAILED DESCRIPTION

Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow.

Hydrocarbon feedstocks can broadly as those commonly known in the refinery industry. These feedstocks can include crude petroleum oil, triglyceride-based feeds, seed oils, tire (or tyre) oils, slop oil, biomass oils, nut oils, and blends thereof. Contaminants can also be present in the hydrocarbon feedstocks which can include salts, acids, amine, metals and other materials that may negatively impart refinery process units and piping.

Wash water can be from a variety of sources within a refinery. For example wash water can comprise of recycled refinery water, recirculated wastewater, clarified water, purified wastewater, sour water stripper bottoms, overhead condensate, boiler feed water, clarified river water, sea water or salt water, brine previously created from the desalting process, or from other water sources or combinations of water sources and blends thereof.

Crude petroleum typically contains salts and other contaminants that may corrode refinery units; salt and other contaminants are removed from the crude oil (petroleum) by a process known as “desalting,” in which crude oil is mixed with water (wash water) to form a water-in-oil emulsion or mixture which provides intimate contact between the oil and water, transferring salt and contaminants into the water. The salty emulsion water (or droplets) then separates in a desalting vessel. During the separation process, the salty water settles to the bottom of the tank under gravitation. The desalted oil forms at the upper layer in the desalter from where it is continuously drawn off for distillation. The salty water is withdrawn from the bottom of the desalter.

Hydrocarbons or crude oils may contain many impurities that are detrimental to refinery operation and the refined products themselves. Some of these impurities, including various salts, are known to contribute to corrosion of refinery equipment, to decreased heat transfer efficiency due to fouling of heat exchangers, and to catalyst poisoning, among other undesirable conditions. Salt and other contaminants in the hydrocarbons may take the form of metallic salts, including metal halides such as magnesium chloride, sodium chloride, calcium chloride, and other salts known to those skilled in the art.

In some settings, the hydrocarbons and/or the wash water are heated prior to or following mixing. The heating can be independent of the refinery process or transferred from other processes in the refinery. In one embodiment, it is also ideal to heat the hydrocarbon and/or wash water to minimize thermal gradients.

In some settings, after the salty emulsion enters the desalting vessel, it is optionally passed into a high voltage electric field inside the closed separator vessel. In that instance, the electric field forces water droplets to coalesce, forming larger water droplets than without this modification. This electric field facilitates desalting but is not necessary.

In one embodiment, the hydrocarbon feedstock containing dissolved salts enters a desalter vessel as pre-treated crude. The pretreated crude is mixed with wash water containing an alkalinity modifier. That mixture is transferred to a desalting vessel where the dissolved salts are separated from the pretreated crude oil to create desalted crude oil. The separated salts are transferred to wash water wherein said water becomes a brine. The desalted crude oil and brine are then separately removed from the vessel. Notably, in some embodiments, some or all of the desalted crude oil may be recycled back into the process as pre-treated crude oil. In some embodiments, some or all of the brine may be recycled back into the process as wash water. Still, other embodiments, the process may feature recycle of both desalted crude and brine into pre-treated crude and wash water, respectively.

In one embodiment, desalting is performed in a batch manner. In another embodiment, desalting is performed as a continuous activity, which may or may not be slowed or shut down from time to time. In yet another embodiment, desalting is performed in a two- or multi-step format, where crude undergoes multiple stages of desalting, and multiple desalting units may be connected either serially or in parallel. This aspect of the invention can be described as multi-stage or cascade. Aspects of the invention may take place in the forms of systems, apparatuses, methods, processes and/or any other means known to those skilled in the art.

Feedstocks recovered from a subterranean formation generally are contaminated with those salts present in the formation brines or oil field brines. Examples of salts include magnesium chloride, calcium chloride, sodium chloride, calcium bromide, zinc bromide, magnesium sulfate, sodium sulfate, or combinations of any two or more thereof. It is well known that salts contribute to corrosion of refinery equipment such as the fractionators, to decreased heat transfer efficiency due to fouling of heat exchangers and coking of furnaces, and to catalyst poisoning.

Complex hydrocarbon feedstocks can contain strong acids likely used in upstream well acidization (e.g., HCl or other acids), and/or those from other natural and artificial sources. These complex crudes can cause episodes of low desalter pH when processing them.

Literature data shows acids stabilize petroleum crude oil emulsions when system pH is less than about 5.0. For example, the following papers have described this phenomenon, and are hereby incorporated by reference: S. Poteau, Jean-Francois Argillier, D. Langevin, F. Pincet, and E. Perez, Influence of pH on Stability and Dynamic Properties of Asphaltenes and Other Amphiphilic Molecules at the Oil-Water Interface, Energy Fuels, 2005, 19 (4); and Strassner, J. E., Effect of pH on Interfacial Films and Stability of Crude Oil-Water Emulsions. J Pet Technol 20, SPE-1939-PA, 1968. The stabilization of petroleum crude oil emulsions due to low pH within the desalter is not ideal. As discussed above, others have attempted to modify pH by virtue of addition of heavy acids and bases, which has created subsequent troubleshooting and resultant problems.

It has been discovered, as described herein, that modification of the alkalinity (buffer capability)—that is the desalter wash water's ability to resist change in pH (as opposed to targeted modification of pH alone), advantageously allows the desalter to process acidic and complex crudes without significant addition of other components to the wash water stream or reservoir within the desalter unit itself. In particular, the addition of an alkalinity modifier to desalter wash water reduces the need for a complex solution of additions, stabilizes the pH of the solution to increase the desalting capability of the unit, reduces stable and hard-to-break emulsions, and mitigates the concern for corrosion in the desalting unit and downstream.

It has been discovered that direct modification to the alkalinity (capability to buffer pH) to the wash water provides resilience of the desalter unit towards complex hydrocarbon feedstock, particularly those that are acidic in pH. Total alkalinity for a system represents the acid neutralizing capacity of a solution, and it is an indirect measure of a solution's buffering capacity. Water constituents contributing to total alkalinity can come from different sources that contain hydroxide, carbonate, bicarbonate, phosphate, acetate, citrate, and sulfate. The most common contributors of alkalinity are hydroxide (OH−), bicarbonate (HCO3−), and carbonate (CO32−). The proportion of different species contributing towards total alkalinity varies as a function of pH.

Suitable alkalinity modifiers (also known as buffer modifiers or buffer capacity modifiers) include, but are not limited to, sodium carbonate (Na2CO3), sodium bicarbonate (NaHCO3), potassium bicarbonate (KHCO3), potassium carbonate (K2CO3), ammonium carbonate ((NH4)2CO3), ammonium bicarbonate ((NH4)HCO3), sodium acetate (CH3CO2Na), potassium acetate (CH3CO2K), sodium citrate (C6H5O7Na3), potassium citrate (C6H5O7K3), and other compositions that include bicarbonate (HCO3−) anions, other compositions that include carbonate (CO32−), and other compositions that would be known to those skilled in the art to increase alkalinity of aqueous solutions, and combinations of the aforementioned modifiers. In one embodiment, the use of potassium bicarbonate as an alkalinity modifier may be preferable to others, including sodium bicarbonate, due to its higher solubility limits in water at some conditions.

As addressed herein, concentration of the alkalinity modifier may be provided in parts per million (ppm) of equivalent calcium carbonate (CaCO3) unless expressly designated differently (for example, “by mass”). Units of mg/L are a mass dissolved in a liquid. Likewise, units of ppm describe mass dissolved in liquid. Reporting alkalinity as “mg/L as CaCO3” or “ppm as CaCO3” specifies that the sample has an alkalinity equal to that of a solution with a certain amount of calcium carbonate (CaCO3) dissolved in water. The actual units for the alkalinity titration are moles or equivalents per volume (moles/L or eq/L). Converting alkalinity from raw mass to “mg/L as CaCO3” or “ppm as CaCO3” takes into account that one mole of carbonate (CO32−) can neutralize 2 moles of acid (W). The units of “mg/L as CaCO3” or “ppm as CaCO3” are for convenience only, allowing one skilled in the art to consider how much CaCO3would be needed to create a solution with the same alkalinity as a given sample. One skilled in the art would be able to determine sufficient quantities of alkalinity modifier according to the desired outcome, and further, one skilled in the art would be able to convert concentration units (i.e., ppm as CaCO3to mg/L, etc.) as the case may need.

In one embodiment, it has been found that wash water having about 100 ppm to about 950 ppm (by equivalent of CaCO3) alkalinity modifier, and preferentially that amount of sodium bicarbonate, has a positive effect on the desalter's ability to handle acidic crude, mitigate stable emulsions, and maintain desirable pH conditions. In another embodiment, it has been found that wash water having about 100 ppm to about 950 ppm (by equivalent of CaCO3) alkalinity modifier, and preferentially that amount of potassium bicarbonate, has a positive effect on the desalter's ability to handle acidic crude, mitigate stable emulsions, and maintain desirable pH conditions. The overall concentration of alkalinity modifier in the wash water, however, may be increased, decreased, or otherwise moderated based on desirable conditions and incoming crude feedstocks. One skilled in the art would be able to select the alkalinity modifier from any array of suitable options described herein and add said modifier in desirable concentrations to wash water based on availability, crude characteristics, and other concerns.

In one embodiment, a brine pH of at least about 5.0 is desirable to be maintained within the exit stream (brine stream) of the desalter. In one embodiment, a pH of at least about 5.5 is desirable to be maintained within the exit stream (brine stream) of the desalter. In another embodiment, a pH between about 5 and about 10 is desirable to be maintained within the exit stream (brine stream) of the desalter. In another embodiment, a pH between about 6 and about 8 is desirable to be maintained within the exit stream (brine stream) of the desalter.

In some embodiments, wash water may be derived from various sources and the water itself may be, for example, recycled refinery water, recirculated wastewater, clarified water, purified wastewater, sour water stripper bottoms, overhead condensate, boiler feed water, clarified river water, sea water or salt water, brine previously created from the desalting process, or from other water sources or combinations of water sources. Salts in water are measured in parts per thousand by weight (ppt) and could range from fresh water (<0.5 ppt), brackish water (0.5-30 ppt), saline water (30-50 ppt) to brine (over 50 ppt). Although raw water varying in hardness levels (such as deionized water, city water or soft water) may be used to favor exchange of salt from the crude into the aqueous solution, de-ionized water and/or soft water is not normally required to desalt Crude Oil feedstocks by themselves, although it may be mixed with recirculated water from the desalter to achieve a specific ionic content in either the water before emulsification or to achieve a specific ionic strength in the final emulsified product. One skilled in the art would know of other sources of wash water for the systems and processes described herein.

The use of the alkalinity modifier in the desalter wash water is without prejudice to the use of the demulsifiers commonly used in the processing of petroleum crude oil. Among the demulsifiers which may be used are those typically based on the following chemistries: polyethyleneimines, polyamines, polyols, ethoxylated alcohol sulfates, long chain alcohol ethoxylates, long chain alkyl sulfate salts, e.g. sodium salts of lauryl sulfates, epoxies, di-epoxides (which may be ethoxylated and/or propoxylated). A useful class of polyamines comprises the succinated polyamines prepared by the succination of polyamines/polyamine/imines with a long chain alkyl substituted maleic anhydride.

Likewise, the use of the alkalinity modifier is also without prejudice to emulsion breakers, wetting agents, reverse emulsion breakers, amines, inhibitors including other additives commercially available from chemical suppliers.

The degree of performance of the desalting process may be defined by one or more metrics, including water dehydration (also described as fraction of water separated) and/or final salt composition of desalted crude. These metrics—and by extension the degree of desalting performance—are a function of, but not limited to, the following non-exhaustive list of characteristics of the system and/or process: type of wash water or volume, Crude Oil quality, alkalinity modifier, amount of alkalinity modifier, desalter temperature, emulsion breaker chemistry, and other variables known to those having skill in the art. Additionally, these metrics are also a function of desalter system hardware than can include electric field, desalting vessel size and configuration, and mix energy. In one embodiment, the percentage of water dehydration is measured in terms of fraction of water separated from the crude oil and wash water mix. The fraction of water separated is determined by comparing the volume of water recovered versus the initial volume of water added to the system. In one embodiment, the fraction of water separated could be between 90% and about a 100%, though such performance could vary based on type of alkalinity modifier, amount of alkalinity modifier, temperature of the system, and other variables discussed herein and known to those having skill in the art. Still, in another embodiment, the fraction of water separated could be between 70% and about a 100%, though such performance could vary based on type of alkalinity modifier, amount of alkalinity modifier, temperature of the system, and other variables discussed herein and known to those having skill in the art. Likewise, in one embodiment the final salt composition of the desalted crude is measured as chlorides ppm. In one embodiment, the salt composition of the desalted crude is less than 10 ppm by weight. In another embodiment, the salt composition of the desalted crude is less than 8 ppm by weight. In yet another embodiment, the salt composition of the desalted crude is less than 6 ppm by weight.

The Figures discussed herein depict aspects of the invention by means of systems, apparatuses, methods, processes and/or any other means known to those skilled in the art.

FIG.1depicts an embodiment100for desalting oil featuring addition of an alkalinity modifier. A source of petroleum crude101is delivered to the system via inlet supply104. A source of wash water102is delivered to the system via inlet supply105. A source of alkalinity modifier103is delivered to the system via inlet supply106. The wash water from inlet supply105may be mixed with the alkalinity modifier from inlet supply106by virtue of valve109. The mixture of wash water and alkalinity modifier may be flowed through supply107to valve108. Valve108may regulate the addition of wash water and alkalinity modifier solution to the petroleum crude supply. Following their mixture, the wash water, alkalinity modifier, and petroleum crude are introduced to the desalting vessel111via supply110. The wash water with alkalinity modifier then separates salts from the petroleum crude within desalting vessel111. Following the desalting process, a composition consisting of desalted crude oil leaves the vessel111via outlet line112. Likewise, following the desalting process, a composition consisting of water with dissolved salts (brine) leaves the vessel111via outlet line113. Optionally, pump114supplies the Crude Oil to the process is described here. In this and other embodiments, one skilled in the art may also include optional control units (not shown) within the system to regulate the rates at which the crude, wash water, and alkalinity modifiers are introduced into the system.

FIG.2depicts an embodiment200for desalting oil featuring addition of an alkalinity modifier. In this embodiment, the same embodiment as100may be employed, though with the addition of an optional electric field201within the vessel111. Optionally, pump214supplies the Crude Oil to the process is described here. Here, the mixture of oil and water may be optionally passed into a high voltage electric field inside a closed separator vessel. In that instance, the electric field forces water droplets to coalesce, forming larger water droplets than without this modification. In this embodiment, the electric field facilitates desalting, but is not necessary.

FIG.3depicts an embodiment300for desalting oil featuring addition of an alkalinity modifier. In this embodiment, the same embodiment as100may be employed, though with the addition of optional heat exchangers301,302,303, and304. Optionally, pump314supplies the Crude Oil to the process is described here. Here, each heat exchanger is optional, and any combination of these may be used. The heat exchangers preheat the fluids in lines104,105,107, and110, respectively, to facilitate desalting. In another embodiment (not shown), heat exchangers may be added anywhere into the systems depicted byFIGS.1-3. One skilled in the art would know how to implement and operate these heat exchangers.

While certain embodiments may be described inFIGS.1-3, in other embodiments, the alkalinity modifier may be introduced into the crude oil inlet supply104inFIG.1as opposed to the wash water inlet supply (not shown). Additionally, the alkalinity modifier may be introduced before or after any of the pumps present inFIG.1.

While certain embodiments may be described inFIGS.1-3, in other embodiments, the alkalinity modifier may be introduced into the supply110inFIG.1(which contains oil and water) as opposed to the wash water inlet supply105. Additionally, the source of the wash water102could also be modified upstream prior to the inlet supply105.

Multiple desalting units or embodiments such as those depicted inFIGS.1-3may be connected together in series or in parallel and may form cascade or multi-stage operations. Similar type of vessel can also be utilized downstream of the crude oil distillation units, for example FCC and potentially other downstream units.

The following examples of certain embodiments of the invention are given. Each example is provided by way of explanation of the invention, one of many embodiments of the invention, and the following examples should not be read to limit, or define, the scope of the invention.

Concentration of the alkalinity modifier used in Examples 1-5 is expressed in parts per million (ppm) of equivalent calcium carbonate (CaCO3) unless otherwise noted.

Example 1

Crude A (as a reference feedstock) and Crude B (which is an acidic crude feedstock) were used to study the emulsion behavior and effluent pH of solutions when subjected to water of varying quality. Static dehydration and emulsion resolution tests were performed using an Interav Model EDPT-228 Portable Electrostatic Dehydrator (PED). Crude oil and wash water (as optionally modified or sourced by the variations described herein) were poured and blended using Chandler Blender cups, then put into a 90° C. water bath for 20-30 minutes to allow the mixture to equilibrate to the test temperature. Cups were removed from the bath one at a time and blended at a pre-determined blend condition. The crude and water blends were then poured into preheated PED tubes and placed in the PED heater block, which was set at 90° C. Once all the PED tubes were filled, 500 volts were applied to each tube to promote water droplet coalescence.

PED run conditionsBlender speedCrude B (3000 rpm);Crude A (4000 rpm)Blending time8sTemperature90°C.Voltage500VWash water8% (vol)Duration of run60min

The water separated from the PED was measured visually versus time for all tests. Pictures of the PED tubes were taken at 30 mins. After the PED tests were completed, the PED tubes were centrifuged for 20 minutes at 1500 RPM and the separated water was measured; this provided an estimate of the maximum possible water separation. The following tests were also performed on the separated oil and effluent water phases: 1) Water=Separated water pH and 2) Top oil (desalted crude)=Salt and water (Karl Fisher) of separated oil. The separated water pH is measured after allowing cooling of effluent water that separated out.

FIGS.4band5bshow the crude oil emulsion generated with Crude A (results depicted inFIG.4a) and Crude B (results depicted inFIG.5a) with buffered waters (pH of 3, 5, 7, 9, and 11). The buffered water at pH of 3 results in lower water separation for both Crude A and Crude B. Both cases exhibit a rag layer, which will increase the risk for a water carryover event in the desalter leading to an increased risk for overhead corrosion. Highest water separation is seen for separated water with pH of 7 and 9, with higher pH giving lower separation and much dirtier water, especially with Crude B oil. The asphaltene content of Crude A and Crude B crude oils used in this example were about 0.50%. Asphaltenes are reactive with both acids and bases. It is theorized that, in a low pH “acidic” environment the asphaltene will become protonated, and in a high pH “basic” environment asphaltenes become de-protonated. These changes increase the hydrophilic behavior of the asphaltene making them more polar thus allowing them to readily accumulate at the oil-water interface). The results inFIGS.4band5bshow more stable emulsions at low and high pH, respectively (i.e., not near neutral pH). This work shows desalter pH that results in manageable emulsion is between 7 and 9. If the desalter experiences excursion of tramp amines, then operating the desalter at target pH range 5.5 to 6.5 is preferred. Lower pH favors amine partitioning that minimizes amine carryover reducing the overhead corrosion risk.

Example 2

Example 2 was prepared in the same fashion as Example 1.

As described by others, refinery wash water could be modified by addition of neutralizing amine (e.g. dimethylethanolamine (DMEA)) in the process, if needed.FIG.6aandFIG.6bshows the effect of adding caustic to create a high pH desalter wash water source (pH 10 to 12). The resulting effluent pH with these caustic treated waters with Crude B crude oil was observed to be 4.4, 4.7 and 7.1, respectively. High caustic dosage (pH 12) results in an effluent pH of 7.1 and fair water separation. Importantly, high pH water wash creates its own concerns for corrosion throughout the system including increased scaling potential.

As described by others, the refinery wash water could be modified by addition of caustic (NaOH) in the process, if desired.FIG.7aandFIG.7bshow the effect of adding a neutralizing amine to create a higher pH desalter wash water source (pH 9.9 to 10.1). The resulting effluent pH with neutralizer amine was observed to be 4.6, 4.9, and 5.5. High neutralizing amine dosage yields a manageable effluent pH 5.5 and suitable water separation. Importantly, introduction of amine to water wash can create its own concerns for corrosion throughout the system including increased downstream fouling and corrosion potential from amine carryover to downstream process. Wastewater plant can also see impacts from increased nitrogen loading from use of amine-based additives in the desalter.

That said, both of these methods have proven to be non-ideal. In addition to being costly, both these water treatment options will significantly raise the pH of the refinery wash water resulting in carbonate scaling risk of the desalter wash water piping. In addition, the high dosage of the neutralizing amine will increase amine partitioning in the desalted crude oil and pose a corrosion risk for the tower that will require detailed review. The use of caustic or neutralizing amine for processing acidic crudes can have significant risks, and therefore, is not ideal for managing desalter reliability.

Example 3

Example 3 was prepared in the same fashion as Example 1.

Stripped sour water is a very common water source for desalting. In this Example, stripped sour water was used as wash water. The total alkalinity is about 330 ppm (as CaCO3ppm) and pH are about 6.6.FIG.8aandFIG.8bshow significantly higher water separation using a stripped sour water source compared to raw and modified refinery wash water. The lab effluent pH using the stripped sour water source is about 5.5. While effective, this process resulted in lower brine effluent pH, which is not desirable from a corrosion science standpoint.

Example 4

Example 4 was prepared in the same fashion as Example 1.

The use of local refinery wash water with total alkalinity of about 40 ppm shows the lab effluent pH of 4.3 with Crude B and very low water separation, as shown byFIG.9b.FIG.9aalso shows the behavior of Crude B crude oil crude emulsion with varying water total alkalinity between 40 to 700 ppm (as CaCO3ppm) by addition of sodium bicarbonate. The higher the alkalinity in this Example, the resulting effluent pH becomes much more manageable at about 6.9 to about 7.8 and greatly improves water separation.

Further Discussion on Examples 1-4

Lower residual salts in the desalted crude are expected to create fewer issues of carryover of overhead chlorides.FIG.10ashows the residual salt remaining in the Crude B crude oil after undergoing treatment with different quality water sources. As expected, the cases that yield lower brine pH result in higher residual salt in the desalted crude, which will increase the risk of tower corrosion risk. Most of the residual salts in these lower pH cases are likely present in an emulsion phase. Crude B crude oil treated with sodium bicarbonate results in the lowest residual levels of salt in the desalted crude. Likewise, the desalter brine effluent pH was of an acceptable level. The alkalinity modifier, as opposed to unmodified refinery wash water, additions of caustic and amine, and stripped sour water, proves advantageous in comparison to the alternatives because it is effective at removing salts and maintains a moderate pH both in the desalter unit and in brine.

FIG.10bshows the effect of pH control with the alkalinity modifier in affecting excess salt (in an emulsion phase) from a desalted Crude B oil sample. The figure shows that the samples treated with the alkalinity modifier between 300 to 700 ppm (as CaCO3) consistently shows to lower excess salt in the desalted oil with pH controlled with the alkalinity modifier between pH 5.0 to 8.0. The Crude B oil sample emulsion made with the refinery wash water resulted in much higher levels of salt when the effluent pH is about 4.0. The desalted crude oil samples that exhibited lower effluent pH resulted in more excess salt present in the top oil phase in comparison to desalted samples where effluent pH was neutralized. Note that the cases with lower effluent pH directionally show less fraction of water separated. This is an indication of more of an emulsion presence containing excess salt that is expected to be carried over in the downstream process affecting downstream reliability.

Example 5

Crude B oil and a more typical refinery crude feed blend were used to study the effluent pH and emulsion behavior by varying the alkalinity of the water source used in the test by addition of KHCO3. The KHCO3was added to a desalter wash water source for mixing with the crude oil. A concentrated high alkalinity stock solution was created by adding 0.38 grams of KHCO3into 200 mL of wash water (1900 ppm KHCO3), this is equivalent to 940 CaCO3mg/L (ppm) alkalinity. The following table shows the different alkalinity targets and the associated recipes for the modified wash waters for testing.

Alkalinity TargetVolume ofVolume ofIDCaCO3mg/LStock Solutionwash waterBlank0 mL100 mLSolution 1300 mg/L24 mL76 mLSolution 2600 mg/L39 mL61 mLSolution 3 (Stock)940 mg/LNo adjustmentNo adjustment

Static dehydration and emulsion resolution tests were performed using an Interav Model EDPT-228 Portable Electrostatic Dehydrator (PED). Crude oil and wash water were poured and blended using Chandler Blender cups, then put into a 90° C. water bath for 20-30 minutes to allow the mixture to equilibrate to the test temperature. Cups were removed from the bath one at a time and blended at a pre-determined blend condition. The crude and water blends were then poured into preheated PED tubes and placed in the PED heater block, which was set at 90° C. Once all the PED tubes were filled, 500 volts were applied to each tube to promote water droplet coalescence.

The table shows the two approaches used to study a Crude B crude oil and its blend with water with varying alkalinity.

Phase 1Phase 2Feed100% Crude B25% Crude B/75%Refinery feed blendTemperature90°C.90°C.Oil/Water Ratio92 mL/8 mL92 mL/8 mLBlend Speed3000rpm12000rpmBlend time8s8sEmulsion breakerNone5ppmWater source300ppm KHCO3300ppm KHCO3

Phase 1 work includes an assessment of the behavior of 100% Crude B, whereas the Phase 2 work was done on a 25% Crude B in the refinery feed blend. The water source used was varied in total alkalinity with KHCO3for both cases. Effluent pH measured after allowing cooling of water phase.

FIG.11shows the behavior of Crude B crude oil crude emulsion with varying water total alkalinity between 300 to 950 (as CaCO3ppm) with KHCO3. Without any KHCO3, Crude B crude oil is expected to result in very low effluent pH. The figure shows a stable emulsion with a low pH of around 4.3. With higher total alkalinity (e.g. 300 as CaCO3ppm), the resulting effluent pH becomes much more manageable at about 6.72 to about 8.72 and greatly improves water separation. These observations are consistent with prior work done with NaHCO3. There is no emulsion breaker added in this test.FIG.12shows the behavior of 25% Crude B blended with the refinery crude feed. These tests were done with and without an emulsion breaker. The use of the emulsion breaker shows more effective resolution of the oil and water phase. In this case, a low effluent pH 4.8-5.0 is still seen with 25% Crude B. The addition of KHCO3(300 as CaCO3ppm) continues to neutralize the effluent pH effectively.

FIG.11shows corrosion control with effluent pH being maintained consistently between pH 5.0 to 8.0 with the addition of an KHCO3alkalinity modifier ranging between 300 to 950 ppm (as CaCO3ppm). Strong acid (e.g. hydrochloric acid) corrosion can result from low pH—carbon steel, in particular, can have high annual corrosion rates ion a low pH environment. The addition of an alkalinity modifier that the effluent pH can be consistently neutralized to pH 5.0 to 8.0 when processing acidic crude oils.

In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as an additional embodiment of the present invention.

Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.