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SEE also Oil & Gas Links page
For the Non Oily Private Investor
Please help the non oily types to understand the language:-
In none alphabetical order:
In answer to the "only 2% of oil has migrated from the HRZ comment made by Paul Basinski during London Feb Presentation and mainly due to questions as to whether we can back calculate the likely amount of oil remaining.
"Only some of the oil in place in Prudhoe is sourced in the HRZ. That oil may have come from other parts of the HRZ that were in the oil window earlier.
The oil still in the HRZ in our acreage is calculated using the measurements in Icewine 1 and using estimation of how the thermal maturity, thickness and TOC might vary across the acreage.
Forget the 98%. Paul used that to answer why migration was not important for the HRZ, because we are going after the oil that has been generated but has not migrated. This is how shale plays work." SP_Oiler Feb, 2017
Yes, the HRZ (= organic rich basal part of the HUE) is present across much of the Colville Basin. You also have to remember that other parts of the HRZ will be at different maturities and some of the oil in those other accumulations may have come from parts of the HRZ that are now over mature, so the % of oil generated and expelled from the HRZ will vary across the North Slope.
and
That is the interpretation of where the HRZ is currently in the thermal maturity sweetspot for shale oil production in the area around our acreage. You would need to know the burial history (and therefore depositional history and structure) of the entire Colville basin to know whether there are other areas on the North Slope that are in a similar thermal maturity window. However, as oil generation, expulsion and migration is a process that takes place over millions of years, and as conventional fields hold oil that has already been expelled and migrated to those fields, any HRZ sourced oil could certainly (and probably more likely) have come from other parts of the HRZ.
Remember, we are looking for the oil in the HRZ that has been generated but not expelled, which has a different history to the HRZ sourced oil that has been expelled and trapped in conventional fields.
SP_Oiler Mar, 2017
Clastic Rocks
Clastic sedimentary rocks are rocks composed predominantly of broken pieces or clasts of older weathered and eroded rocks. Clastic sediments or sedimentary rocks are classified based on grain size, clast and cementing material (matrix) composition, and texture. The classification factors are often useful in determining a sample's environment of deposition. An example clastic environment would be a river system in which the full range of grains being transported by the moving water consist of pieces eroded from solid rock upstream.
Grain size varies from clay in shales and claystones; through silt in siltstones; sand in sandstones; and gravel, cobble, to boulder sized fragments in conglomerates and breccias. The Krumbein phi (φ) scale numerically orders these terms in a logarithmic size scale.
Siliceous rock
Siliceous rocks are sedimentary rocks that have silica (SiO2) as the principal constituent. The most common siliceous rock is chert other types include diatomite. They commonly form from silica-secreting organisms such as radiolarians, diatoms, or some types of sponges.
Reserves Replacement Ratio SP-Oiler
The reserves replacement ratio is the ratio of new reserves added to the amount of hydrocarbons produced in a year. Companies would obviously like to keep it at 1 (100%) or above. If they add no new reserves it will be 0. So how can it be negative? It can be negative if they cancel or postpone projects meaning that volumes that were previously counted as reserves no longer are, or if they revise their reserves calculation on existing projects due to technical or economic restrictions.
If I have only one project where the reserves were based on a certain oil price and the oil price is now considered to be going to stay below that, then the project could be revised so that only the cheapest oil to extract will be developed, then I will have a negative reserves replacement ratio.
Flow Test Vertical versus Horizontal SP-Oiler
In a fracced shale well one of the things that determines the flow rates will be the surface area of formation that is exposed to the wellbore via the fracs. This will be very limited in a vertical well, essentially one pair of fracs for each zone tested, when compared to a horizontal well where you will have multiple fracs all spaced out along the well. So don't assume that they are being conservative with their numbers (leaving you to be disappointed if they hit them). The flow from a horizontal well (a real producer) will be much higher.
Gravel Pads SP-Oiler in answer to query.
I suspect the gravel pads will vary considerably in size according what needs to be located on them. For instance if all your pad has are wellheads, the footprint will be much smaller than if you need to put in associated field facilities (surface processing etc.). You don't have a link when you talk about the size of the Armstrong pad, but it could be that they need that size for offices, accommodation, equipment storage etc.
I have looked around this morning for examples of the surface footprint for multi-well pads, hard to find exact data but I saw figures of 3-7 acres, and this link talks about 20,000 square metres which is around 5 acres
http://www.csur.com/sites/default/files/Understanding_Well_Construction_final.pdf
Here's one that talks about 7.4 acres for 6-8 well pads
https://fossil.energy.gov/programs/gasregulation/authorizations/Orders_Issued_2012/66._Pt_4_SC_Sabine_Comments.pdf
The size of pad will not increase linearly with the number of wells, as the wells can be quite closely spaced at surface and much of the surface are will be taken up with area for shared facilities (frac fleet, produced frac fluid handling etc.)
Here is a GIS viewer from the Texas Railroad Commision (the reg. body for oil and gas in Texas)
You can see and measure the size of multiwell pads. I found some 7, 8 and 9 well pads in the Eagle Ford at 6-8 acreas
http://wwwgisp.rrc.texas.gov/GISViewer2/
It is also interesting for those who aren't familiar with how the wells are laid out all in the same orientation (ignore the splayed pattern, the are only showing the top and bottom hole directions, not the true trajectory - in reality the horizontal legs will be parallel), so that they are correctly oriented with respect to the in-situ stress.
Viscosity
Absolute viscosity provides a measure of a fluid’s internal resistance to flow. Any calculation involving the movement of fluids requires a value of viscosity. This parameter is required for conditions ranging from surface gathering systems to the reservoir. Therefore, correlations can then be expected to evaluate viscosity for temperatures ranging from 35 to 300°F. Fluids that exhibit viscosity behavior independent of shear rate are described as being Newtonian fluids. Viscosity correlations discussed in this chapter apply to Newtonian fluids.
The principal factors affecting viscosity are oil composition, temperature, dissolved gas, and pressure. Typically, oil composition is described by API gravity only. As discussed earlier in this chapter, this is a shortcoming. The use of both the API gravity and the Watson characterization factor provides a more complete description of the oil. Table 6.10 shows an example for a 35° API gravity oil that points out the relationship of viscosity and chemical makeup recalling a characterization factor of 12.5 is reflective of highly paraffinic oils, while a value of 11.0 is indicative of a naphthenic oil. Clearly, chemical composition, in addition to API gravity, plays a role in the viscosity behavior of crude oil. Fig. 6.23 shows the effect of crude oil characterization factor on dead oil viscosity. In general, viscosity characteristics are predictable. Viscosity increases with decreases in crude oil API gravity (assuming a constant Watson characterization factor) and decreases in temperature. The effect of solution gas is to reduce viscosity. Above saturation pressure, viscosity increases almost linearly with pressure. Fig. 6.24 provides the typical shape of reservoir oil viscosity at constant temperature
