The Largest Oil Play of The Decade? (Part 2)

Onshore facilities

James Stafford: Why isn’t drilling with water-based mud the go-to if it’s such a problem?

Daniel Jarvie: There is a difference when exploring in an unknown basin versus production drilling where the oil container has been pinpointed. In the latter case oil-based mud enhances drilling rates (i.e.,minimizes expense). On the other hand, we are trying to find oil and using water-based mud allows us to chemically see the oil. There are certainly many logging operations that allow assessment of petroleum charge, but geochemistry is the only technique that truly measures oil itself rather than inferring that it is oil.

Drillers are obsessed with drilling rates – how fast can we drill the hole to minimize drilling expense – a noble and economic cause. However, I go by the old axiom ‘our job is not to drill a hole, but to find petroleum’.  As these are the first tests in the basin, we need the optimum samples to analyze for the presence of oil and source rocks.

Oil-based mud does have a number of advantages. It allows drilling more quickly because it lubricates the bit; it carries the cuttings back; it helps prevent shale from slopping into the hole etc. But from an exploration point of view, it has serious drawbacks. 

One of the key characteristics of ReconAfrica is that the company owns it’s own drilling rig, so it’s much less concerned about the speed of drilling and more concerned with quality of data.

Many years ago I was working with a major in the Permian and I told them that if they drilled with water-based mud they’d find more bypass pay. The manager stood up and said “We find bypass pay every day”. Their geologist responded: “Yeah, and we bypass pay everyday.” 

James Stafford: Looking at your report on Kavango and the general potential on page 2… These numbers look incredible. Have you come across numbers like this before? Are there any other plays to compare it to? 

Daniel Jarvie: In the report, just released, I put total petroleum generation potential over Recon’s 8.75 million acres at 120 billion boe (Barrels of Oil Equivalent). Now, that’s only looking at 1,641 sections, which represents only 12% of Recon’s total holdings in the basin. As I’ve said, I’ve been conservative with the numbers, and even so, if the potential pans out in full, they are pretty comparable to the Permian Wolfcamp and the Eagle Ford in Texas. 

And ReconAfrica owns the entire basin, subject only to a government royalty. They’ve been extremely savvy about getting land. 

James Stafford: Beyond using only 12% of Recon’s Kavango holdings, how conservative are you being?

Daniel Jarvie: I really can’t stress strongly enough how conservative I’ve been here. I like to be conservative with numbers. Most analyst and industry reports stress the total organic carbon content (TOC) of source rocks, but that’s only half the story for hydrocarbon formation. The other key component is hydrogen. Good source rocks have not only good TOC values (say 2-7%) but also high hydrogen content in the organic carbon.

For my numbers on Recon, I only used a hydrogen content of 358 (mg/g), which is very conservative based on the rock I’ve seen from the Owambo basin. In other words, on a scale of 1-10, I used “3” for hydrogen content, which is quite modest. For comparison, the Eagle Ford source rock would be a 6 and the Permian Wolfcamp a 5.

Thickness is the other key part, and as we don’t know the thickness yet, we are going by what we saw in other sections, but there is 6,000 feet of Permian section in there so that’s a very good start. I anticipate a thickness of between 300 and 400 ft of net petroleum generating source rock.

James Stafford: And if its 400 feet thick, you are estimating the potential at 120 billion barrels of total petroleum generated. And you think this is conservative?

Daniel Jarvie: I do. And it’s not even an unusual number for a basin this size, and this depth. The Eagle Ford and Permian Wolfcamp petroleum potentials are even higher using comparable thickness. They could be sitting on something absolutely huge. 

If you apply those numbers to the entire basin they would be off the wall. 

They would be laughable because they are so high. 

James Stafford: And what would be a normal recoverability rate for a basin of this size and type?

Daniel Jarvie: One of the problems is that no one seems to know how much petroleum is in place when it comes to these kind of plays. This goes back to the Barnett shale. There were early reports that there were 10-15% recovery of the shale gas. But when they got a better handle of oil and gas in place it was more like 6-8%. And for oil, it’s much harder to produce. In the Permian I imagine they are getting 6-8% but it is more of a hybrid system that is better for production. The heterogeneity in our basin is expected to be comparable and therefore provide a high recovery rate from those charged containers.

James Stafford: Well on a 150 billion barrels that’s not bad at all. But let’s swing back to thickness for a moment. I noticed that the Owambo basin slide shows that the Kavango basin is thicker?

Daniel Jarvie: Yes, while the Owambo Basin showed extremely promising core, its depth as it relates to temperature was a major issue; it had not been cooked sufficiently to generate petroleum. What we can see is that there’s a structural high before dipping down into the Kavango Basin, so we are thinking the thickness is probably close to double in this section, maybe more, and higher temperatures.

I have a feeling that it’s more based on what I’ve seen. So we believe it’s a very thick shale and it’s at the optimal depth to get oil production. 

See, everyone talks about the Eagle Ford, but unless you are in a sweet spot you have a hard time producing there. The sweet spot of the Eagle Ford has a 75% Kerogen conversion window, but if you move up to the 50% or 25% wells, those wells are not economic. 

James Stafford: How would you compare the Kavango to the Eagle Ford?

Daniel Jarvie: Well the Kavango actually is quite different. It’s more like the Permian Basin, and that’s a big plus.  

The Eagle Ford is marine carbonate source rock, and it averages 60% carbonate plus it is only about 220-250 ft thick. Kavango is dramatically different to that. From what we know so far, it’s more akin to the Permian basin, a marine shale that generates a high quality oil, and it is thick and heterogeneous system. I expect to find stacked pay zones throughout any source rock systems. There will likely be multiple source rocks by the way.

If you want to get a lot of oil out the system you love the heterogeneity. That’s one of the reasons the Permian works so well. It’s also another reason to be excited about Kavango. 

James Stafford: If you prove this system up, what comes next?

Daniel Jarvie: Then it becomes phenomenally more interesting.  

We will probably have some oil production shows and indications of where it is. We will be able to tell the thermal maturity and can expand it across the basin so we can high grade different prospects by their depth and burial history. 

Right now we don’t have a good handle on that. The formation got laid down hundreds of millions of years ago but we don’t know what has happened to it since. And that’s what the first well will help with. And that will point us in the right direction. 

James Stafford: How does it do that? 

Daniel Jarvie: Think of it as a container that has a “pipeline” running to it from the source rock (a migration pathway). If we drill through the so-called pipeline we can identify oil that has travelled through it toward a big conventional container. Does it go to that trap? So it points to the direction the oil is going if it has gone through the system. It will pinpoint which trap should be best.

In fact the pipeline itself may be a reservoir such as the Middle Member of the Bakken formation.

James Stafford: How does RECO’s Kavango stand up to your long-time wildcatting experience?

Daniel Jarvie: Given the nature of the basin and the tremendous thickness, this is pretty much a no brainer…It will be productive and I’m expecting high-quality oil.”

This was the issue when I worked in Uganda, for instance. We could see there was a system but knew there would be waxy oil. But Kavango is different: The system is marine and terrestrial so it should give us high-quality oil and allow it to move and be produced. You need to be able to flow the oil for optimum recovery. 

The bottom line is this: The Kavango Basin has all the characteristics necessary for conventional and unconventional petroleum systems. Although I’m known for my unconventional work, I’m actually hopeful that the conventional exceeds the unconventional. Why? Because conventional reservoirs are inherently more productive.

Continued in part 3

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