(In retrospect, I do still consider possible effects from entrained methane/H2S on the dispersed oil if there was any notable effect on the acidity of the local water during the time the oil was still flowing.)
I thought this was very odd, given the decision to apply COREXIT at the wellhead, given there is no precedence in the situation.
Here's my theory/thoughts:
I think that any chemist or engineer in the petrochemical industry ( which I am definitely not ) is well aware of cavitation and emulsions. " Hydrodynamic Cavitation Emulsion " is the term. When you emusify hydrocarbons for any reason, you add surfactants to aid in the emulsion. I honestly think that somebody realized that there was a massive opportunity to possibly to aid in emulsifying the oil at the wellhead since it was already being cavitated by the turbidity induced in the flowpath from the obstructions of the stuck drillpipe sections.
The concept is simple really, a denser fluid passes at high pressure & high temperature through an obstructed( read constricted/reduced ) flowpath, which causes the cavitation as it passes through the area back into an area of lower pressure, where it cavitates in the other fluid ( seawater ) and surfactants are added to stabilize the emulsion. The effect is greatly sped up due to the temperature difference and the ability of the ocean to act like a heatsink. The oil coming out of the wellhead is IIRC around 212-F, which drops almost immediately to the ambient temperature-37-F If you have ever seen what happens to emulsified salad dressing when you refrigerated it, you understand what I am talking about. The temperature is one of the things that actually helps keep the emulsion from breaking. You could make the same salad dressing and leave it out on the counter, it will eventually break, especially since you have not used surfactants in it......Sodium bis(2-ethylhexyl)sulfosuccinate is also a laxative, so you'd have to have one twisted sense of humor to do that to somebody,...anyway.....( that's the primary surfactant in COREXIT ). This post is put together with some fairly technical babble, just a warning. I have cited some diverse sources, so hold on to your hat.
There are typically 3 sizes of emulsions considered , with microemulsions and nanoemulsions being the smaller of the 3, they actually tend to appear clear due to the small size of the disperse phase, which also makes them very hard to see.
There are three types of emulsion instability: flocculation, creaming, and coalescence. Flocculation describes the process by which the dispersed phase comes out of suspension in flakes. Coalescence is another form of instability, which describes when small droplets combine to form progressively larger ones. Emulsions can also undergo creaming, the migration of one of the substances to the top (or the bottom, depending on the relative densities of the two phases) of the emulsion under the influence of buoyancy or centripetal force when a centrifuge is used.
Here is a great, easy to read PDF , with visuals to show what emulsion stability is and how what happens,... happens.
http://wefcol.vub.ac.be/wefcol/lectures/Hanoi/h6.pdf
Surface active substances (surfactants) can increase the kinetic stability of emulsions greatly so that, once formed, the emulsion does not change significantly over years of storage.
The Bancroft Rule applies:
The Bancroft rule states: "The phase in which an emulsifier is more soluble constitutes the continuous phase."
It was named after Wilder Dwight Bancroft, an American physical chemist.
In all of the typical emulsions, there are tiny particles (discrete phase) suspended in a liquid (continuous phase). In an oil-in-water emulsion, oil is the discrete phase, while water is the continuous phase.
What the Bancroft rule states is that contrary to common sense, what makes an emulsion oil-in-water or water-in-oil is not the relative percentages of oil or water, but which phase the emulsifier is more soluble in. So even though there may be a formula that's 60% oil and 40% water, if the emulsifier chosen is more soluble in water, it will create an oil-in-water system.
There are some exceptions to Bancroft's rule, but it's a very useful rule of thumb for most systems.
The Hydrophilic-lipophilic balance (or HLB) of a surfactant can be used in order to determine whether it's a good choice for the desired emulsion or not.
- In Oil in Water emulsions – use emulsifying agents that are more soluble in water than in oil (High HLB surfactants).
- In Water in Oil emulsions – use emulsifying agents that are more soluble in oil than in water (Low HLB surfactants).
Surfactants have 4 classifications :anionic, cationic, non-ionic, and zwitterionic.( BTW, I was wrong about it being a Zwitt. bond.)
Sodium bis(2-ethylhexyl)sulfosuccinate ( Primary in C9500a) is anionic, from what I have learned, it's a hydrogen bond.
The length of hydrogen bonds depends on bond strength, temperature, and pressure. The bond strength itself is dependent on temperature, pressure, bond angle, and environment.They can vary in strength from very weak to extremely strong.
..Then, if you read the post I put up the other day, you see there are 3 phases of oil released underwater.
Jet Phase: The speed of the oil and natural gas being expelled from the pressurized, confined space of the well into the water makes the oil form droplets and the gas form bubbles.
Plume Phase: The momentum of these tiny droplets and bubbles drags significant volumes of sea water upward into the water column, forming a plume. In deeper water, so much water is incorporated into the plume that eventually, the oil–natural gas–water mix is no longer buoyant, and the plume will become suspended at what is called the terminal layer. If heavier components sink out of the suspension, the plume may reform and begin to rise again.
Post-terminal Phase: Once the plume reaches the final terminal layer, the rise of the oil and gas to the surface is driven purely by the buoyancy of the individual droplets and bubbles.
So that gives us: 3 sizes of emulsions, 3 types of emulsion stabilities, and 3 phases for aqueous oil dispersion.
An emulsion created by cavitation is perhaps the most effective, in terms of small particles size..
From the Arisdyne website , I would recommend watching the video:
Hydrodynamic Cavitation can occur in any turbulent fluid. The turbulence produces an area of greatly reduced fluid pressure. The fluid vaporizes due to the low pressure, forming a cavity. At the edges of the cavity, small amounts of vapor break off. These form smaller cavities 100 nm to 3 mm in diameter. The smaller cavities implode under the high pressure surrounding them. This process of formation and collapse is called cavitation.
Cavitation is an enormously powerful process. Conditions in the collapsing cavity can reach 5000°C and 1000 atmospheres. The implosion takes place during the cavitation process in milliseconds, releasing tremendous energy in the form of shockwaves. The power of these waves generated by the cavitation process disrupts anything in their path.
...so that's my little bit on cavitation. On to fluid flows at high velocities.
" In some prior art Blowout Preventer (BOP) operating systems, high velocity fluid flows and low differential pressures induced vibration in the system. This vibration may result in collapse and failure of hydraulic hoses in the system. A quick dump valve has been added at or near the open port on the BOP assembly to reduce vibration and other problems. The dump valve has a vent position and an open position. Several alternative embodiments add a ball check valve assembly to the shuttle in the quick dump valve."
http://www.patents.com/F-Harold-Hollister/Richmond/TX/3128164/inventors/
I included that one so's you know it's an actual problem, and not a figment of my imagination.Thank you Mr Hollister.
(fluid mechanics) Flow of a fluid over a body at speeds greater than the speed of sound in the fluid, and in which the shock waves start at the surface of the body. Also known as supercritical flow.
Mach waves
A particle moving in a compressible medium, such as air, emits acoustic disturbances in the form of spherical waves. These waves propagate at the speed of sound (M = 1). If the particle moves at a supersonic speed, the generated waves cannot propagate upstream of the particle. The spherical waves are enveloped in a circular cone called the Mach cone. The generators of the Mach cone are called Mach lines or Mach waves.Shock waves
When a fluid at a supersonic speed approaches an airfoil (or a high-pressure region), no information is communicated ahead of the airfoil, and the flow adjusts to the downstream conditions through a shock wave. Shock waves propagate faster than Mach waves, and the flow speed changes abruptly from supersonic to less supersonic or subsonic across the wave. Similarly, other properties change discontinuously across the wave. A Mach wave is a shock wave of minimum strength. A normal shock is a plane shock normal to the direction of flow, and an oblique shock is inclined at an angle to the direction of flow. The velocity upstream of a shock wave is always supersonic. Downstream of an oblique shock, the velocity may be subsonic resulting in a strong shock, or supersonic resulting in a weak shock. The downstream velocity component normal to any shock wave is always subsonic. There is no change in the tangential velocity component across the shock.In a two-dimensional supersonic flow around a blunt body (see illustration), a normal shock is formed directly in front of the body, and extends around the body as a curved oblique shock. At a sufficient distance away, the flow field is unaffected by the presence of the body, and no discontinuity in velocity occurs. The shock then reduces to a Mach wave.
Then I found this patent from Shell.....
The separation of liquid and/or solid components from a multiphase fluid stream passing through a supersonic fluid separator is enhanced by injecting a surface active agent ( READ: SURFACTANT )into the fluid stream passing through the separator. Preferably the spray is injected via an injection tube that has a positive or negative electrical potential, whereas one of the walls of the separator housing has an opposite electrical potential, so that the injected spray and any liquid droplets and/or particles formed around the injected nuclei are induced to flow towards said electrically loaded wall.
http://www.freepatentsonline.com/7261766.html
Shocks waves form because information about conditions downstream of a point of sonic or supersonic flow can not propagate back upstream past the sonic point.
The behavior of a fluid changes radically as it starts to move above the speed of sound (in that fluid). For example, in subsonic flow, a stream tube in an accelerating flow contracts. But in a supersonic flow, a stream tube in an accelerating flow expands. To interpret this in another way, consider steady flow in a tube that has a sudden expansion: the tube's cross section suddenly widens, so the cross-sectional area increases.
In subsonic flow, the fluid speed drops after the expansion (as expected). In supersonic flow, the fluid speed increases. This sounds like a contradiction, but it isn't: the mass flux is conserved but because supersonic flow allows the density to change, the volume flux is not constant.
So the fluid passing through the wellhead would have been restricted by the partially closed blind ram, and the trapped drillpipe sections. You could call that "choking back the flow ". The following from OnePetro:
" Wellhead chokes are installed on wells to control flow rates and to protect the reservoir and surface equipment from pressure fluctuations. Flow through the choke can be described as either critical or subcritical. In the critical-flow region, the mass flow rate reaches a maximum value that is independent of the pressure drop applied across the choke. Therefore, once critical flow is reached, any dis-turbance introduced downstream of the choke will have no effect on upstream conditions. Therefore, chokes are commonly operated under critical-flow conditions to isolate the reservoir from pressure fluctuations introduced by surface processing equipment.
A second use of wellhead chokes is to monitor production rates by operating in the subcritical-flow region, especially when oil and gas are produced from offshore or hostile environments. For these applications, it is advantageous to use MOV chokes that allow the size of the choke opening to be changed while the choke is under pressure without interruption of production. With this feature, the pressure drop across the choke, and thereby manipulation of the flow rate, can be remotely controlled. Surbey et al. I discussed in detail the application of MOV chokes in the subcritical-flow region.
This investigation presents the application of MOV chokes in the critical-flow region. The limitations of conventional correlations in predicting critical-flow behavior for MOV chokes is also discussed. A new correlation is presented to predict the transition between critical and subcritical flow that is applicable to conventional chokes as well."
To end this post :
I hope since they have finally managed to bring the BOP to the surface, that there will be some closure in this matter. We could say without a doubt, that there were certainly some effects on the phases of the oil in the water that may have had something to do with what was happening at the wellhead, ie: the COREXIT products being applied, and the restrictions in the flow.
http://www.freepatentsonline.com/4011661.html
http://www.economicexpert.com/a/Compressible:flow.htm
http://encyclopedia2.thefreedictionary.com/Supersonic+flow
http://cavitronix.com/how-it-works/
http://en.wikipedia.org/wiki/Emulsify
http://en.wikipedia.org/wiki/Bancroft_rule
