Pantheon Resources plc

Alkaid #2 – Question & Answer


Implications of Condensate and NGLs in Production test

Q: Does your condensate and NGL production have any value? In your operating update on 30 December (“the Operating Update”) you stated Alkaid #2 was producing 300-350 barrels per day (“BPD”) of condensate and Natural Gas Liquids (“NGLs”) in addition to 200 BPD of oilCan you expand?


A: Yes. As clearly stated in the Operating Update, the liquid mixture includes high quality oil with associated condensates and NGL that are saleable through TAPS (Trans Alaska Pipeline System).

Pantheon’s preliminary views indicated that the current blend of oil, condensate and NGLs produced at Alkaid #2 could be sold in the region of 80% - 90%, or potentially higher, of Alaska North Slope crude oil price (“ANS Crude”).  ANS Crude commonly trades at a premium to WTI oil. Our initial estimates exclude some of the higher value NGL components that we are not able to extract yet, but should be extracted and sold in a development scenario.

Pantheon’s preliminary views of price expectation are based on our current production, our knowledge of the TAPS pricing methodology and the preliminary analysis of the makeup of the Alkaid NGLs and high quality of the Alkaid light oil. The Alkaid NGL stream includes all fractions/components from propane up through gasoline equivalents. Like the other North Slope fields, the NGL mixture at Alkaid is a different mixture versus NGLs in other areas such as the Gulf Coast. 

TAPS throughput is a mix of all the various field outputs in terms of quality and component mix. The field owners have developed a pricing methodology to fairly compensate those contributing higher quality products. Our Alkaid crude oil is high grade and light at 38-41 API and will receive a premium when sold through TAPS. Condensates typically trade at a premium to ANS Crude. For the NGLs, lower value components, such as propane and butane, will be valued at a discount that could be half of the ANS Crude oil price, while other NGLs, such as Naptha or distillates, will get a premium over ANS Crude oil.

The data on the Alkaid NGLs is of course at a preliminary stage and as set out in the Operating Update additional data analysis is being conducted including on Alkaid NGLs. The component mix will also likely change as the well cleans up (the well is presently c.40% through the clean-up phase).


Gas and NGLs


Q: What does producing the amount of gas and NGLs mean?

A: As stated in the Operating Update, we believe Alkaid gas is in solution and the reservoir does not contain a gas cap.

We believe the reservoir we are testing at Alkaid is above Bubble Point pressure. What does this mean? “Bubble point” is defined as a pressure at which the first bubble of gas is formed within the liquid oil phase. Above bubble point pressure, gas remains dissolved in the oil. Below bubble point pressure, gas begins to “exsolve” or “fizz” out of solution. After production testing had commenced reservoir pressure naturally began dropping in line with testing operations, eventually below bubble point and gas was released into the reservoir. A simple analogy can be had with a bottle of Coca Cola or Champagne, unopened there is no “fizz”, but take the bottle cap off or pop the cork, reducing the reservoir pressure below bubble point and the bubbles start forming.

So, in the Alkaid reservoir, the gas we are currently producing is effectively “fizzing” out of the oil in the reservoir near the well bore. Importantly, when the gas comes out of solution it is saturated or “rich” with a broad range of heavier hydrocarbons, like propane (your patio heater) and butane (a Bic lighter), all the way up through gasoline. These are the NGLs, that have been discussed in the Operating Update and in this Q&A.  We can strip these out of the gas and sell them at or near ANS Crude oil price (sometimes above ANS Crude).

As set out in the Operating Update, Alkaid #2 is currently being shut in for a pressure build up test and we have commissioned at PVT (pressure volume temperature) analysis of the crude so we can understand these parameters better.


Handling the gas


Q: Was the gas production a surprise and what does it mean for the testing operation and ultimate commercial production?

A: No, we were expecting gas production and in fact our conceptual development plans incorporate gas handling capabilities. As set out in the Operating Update, while the gas production is not a surprise, the volume was higher than anticipated, and is not considered a problem.

Many reservoirs throughout the world reinject the entirety of their excess gas back into the reservoir for pressure maintenance to enhance oil production. The poster child for this is Prudhoe Bay, the largest oilfield in Alaska and located just over 20 miles from Alkaid, where from original production in 1977 it is believed substantially all excess gas has been reinjected. That has been our plan from the beginning for full field development.

The associated gas production can enhance the oil production especially in tight reservoirs and will also assist in extracting the frac fluid from the reservoir during current testing. Longer term, the gas can be used for power generation in the facilities and to run the gas compression equipment where we always planned on gas compression for both gas lift and reinjection.


Treatment of sand blockage


Q: Why did you use a through tubing CTU (coiled tubing unit) instead of using a workover rig to pull the tubing for the clean out back in November?

A: When we realized there was a sand blockage we undertook an extensive search for a winterized workover rig (after 1 November, it is a requirement for all rigs to be winterized on the Alaska North Slope). None were available, however there was a single non-winterized workover rig available. We sought a waiver from the regulator to allow us to use this non-winterized rig but were denied permission. We appealed this decision and were again denied. We also evaluated the option of using a “mothballed” larger drilling rig that was available in Deadhorse but decided against this option.

To bring one of the large mothballed rigs to location would have required weeks of shakedown since it had been mothballed after its last operation, and then mobilization and demobilization after completion of the cleanout. To use the drill rig would have meant a several week delay and the total drill rig cost was estimated at about 10 times greater than a CTU. As a result, we opted for the CTU which was successful in clearing an estimated 4,000 ft of the 5,000 ft of perforated wellbore.

As set out in the Operating Update, we have now identified a winterized workover rig, currently working for another operator, which we intend to use when it becomes available in January and is clearly our best option. Per the Operating Update, we believe that Alkaid has encountered a significant hydrocarbon system based upon the volume and spectrum of hydrocarbons already encountered. Remembering that Alkaid #2 was designed with the primary objective of being a test well for long term production testing, it is prudent to clear the full blockage (1) to be able to maximise the analysis and understanding of the Alkaid reservoir, and (2) to remove the current limitations we have on testing – the presence of 1,000 ft of sand still blocking the wellbore has mandated a very cautious approach to flow testing so far, which has slowed progress, in order to not exacerbate the existing blockage.

As stated previously, sand blockages in long horizontal wells are common and rectifying the blockage is not considered a complex operation with the right equipment.  To cleanout the blockage, it is intended that the rig will first pull the tubing out of the hole prior to entering the wellbore with a larger diameter coil tubing to clean out the production liner through the entire 5,000+ feet. We will then re-seat the tubing into the (now cleared) liner and recommence flow testing.


Water cut


Q: What is the current water cut and why didn’t you report it?

A: We are still in production testing phase and wanted to report the complete well results when we had them. This would have included more information on gas and NGLs, as well as water cut and ultimate oil rates. As set out in the Operating Update, we have so far recovered less than 40% of the frac fluid injected, and we believe we need to recover 60% or greater before where we have representative production data. At this early stage we consider the current water cut is meaningless or even potentially misleading.


Well clean-up


Q: Alkaid #2 is currently only 40% through the well clean-up phase. What are the implications of this?

A: The well clean-up phase is the period when drilling debris and fluids are still coming out of the formation and perforations. During this time, the skin effect is changing and any well test results may reflect temporary obstruction to flow that will not necessarily be present in later tests. Pantheon has always advised that a definitive assessment of the well cannot be known until well clean-up is advanced and flow testing operations are completed.

As set out in the Operating Update, Alkaid #2 is only at most 40% through this clean-up phase and thus has potential for further improvement in flow rates. Pantheon will provide an update on flow rates once we are further through clean-up and well testing.


Potential commerciality of Alkaid


Q: Alkaid#2 was designed as a long term production test well to gain important data to ascertain reservoir performance and in a success case, assist in the design and modelling of a full field development. Does the information received so far on Alkaid suggest that the Alkaid project is condemned, or does the potential for commerciality remain?

A: The potential of Alkaid remains very much intact. As stated above, we are only 40% through the clean-up phase and believe we need to get to 60% to get a true feel for the well’s potential. Also, this is a long term production test well. It is designed to gather data to enhance our knowledge of the reservoir to optimize full field development.

As set out in the Operating Update, we are greatly encouraged by the Alkaid data received to date. It confirms that we have encountered a significant hydrocarbon system which possesses a wide range of hydrocarbons – oil, gas, NGLs, condensate etc. 

We are producing from c. 4,000ft of a perforated c.5,000 ft section of horizontal section and as we have always stated, future development wells would ideally have 8,000 – 10,000 ft lateral sections and hence should produce at much higher rates. This is also our first horizontal well in the area and the information learned helps in the positioning of future wells. It is very rare for the first production well in any new play to produce at its optimal rate given the inherent learning curve.


Impact on Pantheon’s other projects – Theta West & Talitha


Q: Do the results of Alkaid impact your assessments of your other projects; Theta West & Talitha?

A: No. As a Company we estimate our 3 projects contain a recoverable resource of 2.3 billion barrels of oil, of which only 76.5 million barrels (3.4%) is attributable to Alkaid. Over recent weeks Schlumberger, the world’s largest oil services Company estimated, after an analysis of all of our projects estimated them to contain over 17 billion barrels of oil in place.  Alkaid was drilled as a relatively small seismic anomaly near the highway. Talitha and Theta West have different hydrocarbon trapping systems and are a much larger resource. Theta West is a giant basin floor fan in a shallower reservoir section where we have 3 well penetrations and we can still go updip on the structure.




Q: Do you plan a webinar to explain your thoughts on Alkaid so far?

A: Yes, we’re planning a webinar at some point over the next fortnight or so and will advise of precise details as soon as available.  Normally we would wait until flow testing operations have been completed when data is of greatest integrity, however it is important that we continue to educate shareholders on what we have so far. 

Go To Top