Wellbore Pressure versus Formation Pressure
There seems to be confusion between static wellbore pressure, formation pressure, and flowing wellbore pressure in various posts. Perhaps the following explanation will help clear things up. They are discussed from simplest to most complex.
Static Wellbore Pressure
The wellbore is a hole in the ground and its pressure gradient from bottom to top is no different than that of a vertical pipe of the same length. If the wellbore, or pipe, is full of a single fluid that is not moving (i.e. static), the pressure at any point is a function of the height and specific gravity of the fluid per the formula:
Pressure (psi) = .433 x specific gravity x height (feet) + Atmospheric pressure (psi)
The specific gravity of fresh water is 1.0, so a wellbore, or pipe, that is 16,600 feet deep/tall (MJ#1 depth) will have a pressure of about 7,200 psi at the bottom, depending on what the atmospheric pressure is at the top of the wellbore/pipe.
The pressure along the depth/height of the wellbore/pipe is called the hydrostatic pressure. It is linear, meaning that every foot of increased fresh water height will add 0.433 psi.
Formation Pressure
The formation pressure is the pressure of the fluid in the rock independent of the wellbore. The formation pressure can be higher, the same, or lower than what the hydrostatic pressure is at any depth. Oil field service companies know how to measure formation pressure independent of the hydrostatic pressure, or pressure from any fluid in the wellbore. Further, when reporting a well's pressure, the E&P company always reports the formation pressure. The hydrostatic pressure is not what is measured; it can simply be calculated.
When drilling and testing an oil well, a fluid called "drilling mud" is intentionally placed in the wellbore in an attempt to "balance" pressures between the formation and the wellbore. In a balanced condition, the drilling mud holds the formation fluids in place (avoids blow out) and the drilling mud does not disappear into the formation (drilling blind). The drilling mud is heavier than water because it is more important to avoid a blowout than to avoid drilling blind.
In the upper Jurassic of MJ#1 a zone did not have high enough formation pressure to balance the drilling mud and hence the drilling mud disappeared into the formation and ZN was drilling blind (fluid and cuttings not returning to the surface to provide drilling feedback). This was a major concern and a primary reason (along with water coming into the wellbore) that the 9-5/8" casing had to be set at 2,000 meters instead of the planned 2,700 meters. Dustin explained this at about the 18 minute mark in the June 2018 operations update video.
When a cap rock (material shale) was penetrated in the lower Jurassic (3,300 meters), the opposite problem occurred: the increased gas presence (10x) at the surface was a sign that the formation pressure was overcoming the drilling mud pressure in the wellbore. The concern was a blowout might occur if drilling continued deeper which would release even more gas, so drilling was stopped for 42 days to upgrade well control including BOP. ZN communicated this in the Oct & Nov 2017 operational updates.
So, MJ#1 provides an example of the formation pressure being low in the upper Jurassic (not good for hydrocarbon production) and high in the lower Jurassic (very good for hydrocarbon production), where both low and high are in relation to the hydrostatic pressure.
What caused the pressure to be higher than hydrostatic at about 3,300 meters is that the cap rock trapped hydrocarbons, and hydrocarbons always contain gas. Even if an oil well and not a gas well, the oil will have gas embedded in it. And the embedded gas is under pressure from its formation process in the source rock. Hence there is no better initial indication of a complete and active petro system than high pressure gas just under a cap rock.
Flowing Wellbore Pressure
After drilling is complete and casing is set, the formation pressure versus the flowing oil back pressure on the formation is what is of interest. The oil/gas mix flowing up the casing will have a non-linear specific gravity where the specific gravity decreases as the oil/gas mix rises. This is because as the pressure is reduced coming up the casing the gas expands. So, it's a fairly complex equation that describes the pressure gradient versus depth. Its primarily a function of the oil/gas mix. But the important thing to know in regards to whether MJ#1 would naturally flow or not is that flowing oil exerts considerably less pressure on the formation relative to hydrostatic pressure. The TD on MJ#1 was 16,600 feet and the reported formation pressure was 7,500 psi, which is only slightly higher than the hydrostatic pressure of 7,200 psi. This formation pressure was in the Triassic which unfortunately was not commercial. Had it been commercial (oil easily flowed from the formation into the wellbore), then the oil would easily have flowed to the surface without the need for pumping.
Since the lower Jurassic had a high enough pressure relative to hydrostatic to cause a 42 day delay for well control upgrade, then its safe to assume that if commercial oil is there it will easily flow to the surface without the need for pumping.
