Oily Nuggets

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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.
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.

Super Critical Phase
Means when the liquids exist in gaseous form in the reservoir – lower viscosity and can flow at higher rates. https://en.wikipedia.org/wiki/Supercritical_fluid

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.

Science Well versus Production Well SP-Oiler
There is no strict definition of what a science well is, but it is generally used to describe a well that is being drilled without any real expectation of making a discovery, but to gather data from the play.

As to why we could not test Icewine 1, well you cannot just decide on the spot if you want to test, as the well will have to have been designed with that in mind, plus you would need to mobilise crews and equipment and have sourced the water and proppant and have in place the waste water handling and separators etc. So that is a lot of upfront cost for something that we were not sure we would need. Add to that the fact that you need the laboratory analysis, which takes time, before you can design your frac program.
So having a plan to test Icewine 1 would have been contrary to the play to fail fast and fail cheap.

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.

Alaska North Slope Oil Pricing SP-Oiler
In summary, what comes out the end of TAPS is all sold as ANS which over the past couple of years has mostly been trading at a price between WTI and Brent, but this can vary. Then each producer is paid according to a quality rating set by the FERC, so given a discount or premium according to the quality of the oil.
This discount/premium used to be based on API gravity, with lighter oils getting more, but as more lighter oils and NGLs were being produced, this got out of whack and the system was changed to one based on the value of the components that could be refined from the oil. This is probably a much fairer system, especially as with the shale oil revolution, US production has swung too much towards lighter oils.
The attached link is about disputes over how the price is determined, so it gives a good explanation of how that pricing v. quality is done.

And finally, I found a source of data for Alaska North Slope prices compared to other Benchmarks (you can choose data from any time range)

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
Here's one that talks about 7.4 acres for 6-8 well pads

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

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.

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

Shale Production per Domun HC
"research has also found that emphasis on high initial production rates is misleading. Analysis of hundreds of Eagle Ford wells found that those with the highest initial production rates do not necessarily yield the greatest production during their first 2 years online. “There is lots of talk about IP rates. IP is not the game. Sustainable [production] rate is the game

Heres a link to a couple of items anyway.



And this item has a wealth of Unconventional industry info that will be pertinent to 88e investors


Propping Agents
Technological Advances Increase Proppant Consumption Per Well

The surge in frac sand consumption relative to the number of active horizontal drilling rigs has increased substantially over the last several years. This results from numerous factors that include: 1) application of advanced technologies such as: (a) multi-stage and higher density hydraulic fracturing per well, which increased from an average of about 3.4 hydraulic fracturing stages in 2008 to over 13 at the beginning of 2012. In 2014, wells with 30 stages were not uncommon and some wells have as many as 50 stages; (b) methods that result in more extensive fracturing in bedrock; and (c) reservoir stimulation of older wells by hydraulic fracturing; 2) improved efficiencies by drilling multiple holes from one site with closer spacing; and 3) refreshing of previously fracked wells by re-fracking (CBC News, 2014; Helman, 2014; McDivitt, 2014; Nangia, 2013; Schaefer, 2009; Schlumberger, 2014a; Spencer, 2014; Tucker, 2013). These advances have increased the average proppant consumption per well. For example, in 2008, the average amount of proppant, which was nearly all sand, used per horizontal well was approximately 900 t for a 1,500 m well. In 2010, the average amount of sand used was closer to 2,300 t for a well completed on a 3,000-m length measured horizontally. In 2014, an average horizontal well consumed from 4,100 to nearly 5,000 t of proppant of which over 90 percent, by weight, was sand, equivalent to 40 to 50, 100 short-ton capacity train car loads. In a few recent cases, wells required about 9,000 t of sand (Cadre Proppants, 2013; Fielden, 2013; Rock Products, 2014). Also, a well may be refracked multiple times over its life to increase production or refresh the well (Streetwise Reports, 2013; Tate, 2014). For the purpose of comparison, from 2011 through mid-2014, the amount of proppant required for fracking a vertical drill hole, nearly all of which was sand, remained essentially level, at about 230 t per well (Down Hole Trader, 2014; Geiver, 2014; PacWest, 2014b).

The average amount of proppant used per unit distance for horizontal holes is expected to continue to climb with improved fracturing technologies, closer-spaced and increased number of stages per drill hole, and refreshing of previously developed wells.

The Future

Farm Out
In the oil and gas industry, a farmout agreement is an agreement entered into by the owner of one or more mineral leases, called the "farmor", and another company who wishes to obtain a percentage of ownership of that lease or leases in exchange for providing services, called the "farmee." The typical services described in farmout agreements is the drilling of one or more oil and/or gas wells. A farmout agreement differs from a conventional transaction between two oil and gas lessees, because the primary consideration is the rendering of services, rather than the simple exchange of money.[1]

Farmout agreements typically provide that the farmor will assign the defined quantum of interest in the lease(s) to the farmee upon the farmee finishing: (1) the drilling of an oil and/or gas well to the defined depth or formation, or (2) drilling of an oil and/or gas well and the obtaining of commercially viable production levels.[2] Farmout Agreements are the second most commonly negotiated agreements in the oil and gas industry, behind the oil and gas lease.[3] For the farmor, the reasons for entering into a farmout agreement include obtaining production, sharing risk, and obtaining geological information. Farmees often enter into farmout agreements, because they wish to obtain an acreage position, need to utilize underutilized personnel, need to share risks, or because they desire to obtain geological information.[4]

A farmout agreement differs from its sister agreement, the Purchase and Sale Agreement (PSA), in that the PSA addresses an exchange of money or debt for immediate transfer of assets, whereas the farmout agreement addresses an exchange of services for a transfer of assets, and that transfer is often delayed until a later date (such as when the 'earning barier' has been m
*Farm In**
An arrangement whereby an Operator buys in or acquires an interest in a lease owned by another Operator on which oil or gas has been discovered or is being produced. Often farm-ins are negotiated to help the original owner with development costs and to secure for the buyer a source of crude oil or natural gas.

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