56
For the DWH spill, the fluid exiting the wellhead consisted of approx. 40–50 vol%
gaseous components (mainly methane) and 50–60 vol% oil, which was by itself
saturated with dissolved gases (Reddy et al. 2012; Boufadel et al. 2018). The fluid
experienced a pressure drop of approximately 86 bar (Lehr et al. 2010) within the
BOP and cooled from approximately 105 to 4.3 °C within a few meters distance
from the discharge point (Reddy et al. 2012; Gros et al. 2016).
4.4.1 Influence of Dissolved Gases on the Droplet Size
Distribution
As the solubility of many gases in oil rises linearly with pressure (Jaggi et al. 2017),
the amount of short-chained hydrocarbons such as C 1 to C 5 dissolved in crude oil
can be hundredfold at reservoir or deep-sea conditions compared to sea surface
conditions (Lehr and Socolofsky 2020). For the DWH spill, Gros et al. (2016)
calculated the amount of methane dissolved to be 141 times higher at the wellhead
than at the sea surface. A crude oil with such an amount of dissolved and volatile
components, such as it exists inside the reservoir itself, is commonly called a “live
oil”, in comparison to a “dead oil” at ambient conditions with no or just very little
dissolved gases (Ahmed 2010). While “dead” oil is a nearly incompressible liquid
and is comparatively unaffected by an elevated hydrostatic pressure, the properties
of “live oil” will change significantly with increasing pressure due to the increased
amount of dissolved gas. For more details on the effect of deep-sea conditions on
physical and chemical properties of oil and gas, please see Oldenburg et al. (2020).
Two recent studies performed by SINTEF and Hamburg University of Technology
investigated the effect of dissolved gas on the DSD of a crude oil under elevated
hydrostatic pressure (Brandvik et al. 2017; Malone et al. 2018). As Brandvik et al.
(2017) also reported the formation of gas bubbles in their experiments, the “live oil”
must have undergone a phase change during the discharge, which means that the
results cannot be attributed to the “live oil” properties only. They do, however,
report an underestimation of volume median diameter by the modified We-scaling
model by approximately 10%.
At Hamburg University of Technology, a direct comparison between two “dead”
and “live” oils (Louisiana sweet crude oil and n-decane) was performed using the
same setup and experimental conditions (Malone et al. 2018). Oil jets were generated quasi-isobaric by using an equal-volume cylinder in order to exclude any side
effects of a pressure change on the oil (Seemann et al. 2014, Malone et al. 2018).
Median diameters of “live oil” were increased by 74% to 97% compared to “dead
oil” under otherwise unchanged conditions. The experimental data was compared
with the models by Johansen and Li (Johansen et al. 2013, Li et al. 2017), which
account for changes of the physical properties density, viscosity and IFT by use of
the dimensionless numbers We and Re (see Sect. 4.3.1). Both models predicted a
very similar d v50 for “live” and “dead” oil in contrast to the experimental results.
K. Malone et al.
For the DWH spill, the fluid exiting the wellhead consisted of approx. 40–50 vol%
gaseous components (mainly methane) and 50–60 vol% oil, which was by itself
saturated with dissolved gases (Reddy et al. 2012; Boufadel et al. 2018). The fluid
experienced a pressure drop of approximately 86 bar (Lehr et al. 2010) within the
BOP and cooled from approximately 105 to 4.3 °C within a few meters distance
from the discharge point (Reddy et al. 2012; Gros et al. 2016).
4.4.1 Influence of Dissolved Gases on the Droplet Size
Distribution
As the solubility of many gases in oil rises linearly with pressure (Jaggi et al. 2017),
the amount of short-chained hydrocarbons such as C 1 to C 5 dissolved in crude oil
can be hundredfold at reservoir or deep-sea conditions compared to sea surface
conditions (Lehr and Socolofsky 2020). For the DWH spill, Gros et al. (2016)
calculated the amount of methane dissolved to be 141 times higher at the wellhead
than at the sea surface. A crude oil with such an amount of dissolved and volatile
components, such as it exists inside the reservoir itself, is commonly called a “live
oil”, in comparison to a “dead oil” at ambient conditions with no or just very little
dissolved gases (Ahmed 2010). While “dead” oil is a nearly incompressible liquid
and is comparatively unaffected by an elevated hydrostatic pressure, the properties
of “live oil” will change significantly with increasing pressure due to the increased
amount of dissolved gas. For more details on the effect of deep-sea conditions on
physical and chemical properties of oil and gas, please see Oldenburg et al. (2020).
Two recent studies performed by SINTEF and Hamburg University of Technology
investigated the effect of dissolved gas on the DSD of a crude oil under elevated
hydrostatic pressure (Brandvik et al. 2017; Malone et al. 2018). As Brandvik et al.
(2017) also reported the formation of gas bubbles in their experiments, the “live oil”
must have undergone a phase change during the discharge, which means that the
results cannot be attributed to the “live oil” properties only. They do, however,
report an underestimation of volume median diameter by the modified We-scaling
model by approximately 10%.
At Hamburg University of Technology, a direct comparison between two “dead”
and “live” oils (Louisiana sweet crude oil and n-decane) was performed using the
same setup and experimental conditions (Malone et al. 2018). Oil jets were generated quasi-isobaric by using an equal-volume cylinder in order to exclude any side
effects of a pressure change on the oil (Seemann et al. 2014, Malone et al. 2018).
Median diameters of “live oil” were increased by 74% to 97% compared to “dead
oil” under otherwise unchanged conditions. The experimental data was compared
with the models by Johansen and Li (Johansen et al. 2013, Li et al. 2017), which
account for changes of the physical properties density, viscosity and IFT by use of
the dimensionless numbers We and Re (see Sect. 4.3.1). Both models predicted a
very similar d v50 for “live” and “dead” oil in contrast to the experimental results.
K. Malone et al.