Paul Baay Touchstone

The right fiscal regime needs to be put in place to make EOR attractive.

Paul BAAY President and CEO TOUCHSTONE EXPLORATION

In Trinidad, a new outlook from Ortoire

November 12, 2020

Paul Baay, president and CEO of Touchstone Exploration, spoke in March 2020 to The Energy Year about the company’s latest work in its Ortoire and development blocks, its approach to EOR and why the Supplemental Petroleum Tax (SPT) needs to change. Touchstone Exploration is a Canadian upstream company operating in Trinidad and Tobago.

What have been your main activities since 2017?
In 2017 and 2018, we drilled 15 development wells on our four lease operatorship blocks. All of the wells drilled were successful. We added roughly 50% to our total production in the country. We went from roughly 1,300 bpd, peaked at 2,200 bpd and we are currently producing approximately 1,700 bpd. Each development well costs about USD 1 million.
In 2019, we drilled no development wells. Our agreements with Petrotrin, which is now Heritage, were coming up to their five-year renewal, and it did not make sense to spend lots of capital on the development side not knowing what the exact terms of the renewal would be. Rather, we used that cash to focus on our exploration programme.
In regard to the lease operatorship agreements with Heritage, we would like to get the new agreements sorted in the first half of 2020. Heritage is talking about expanding the breadth of those development agreements so they would cover additional wells and give us more freedom to do what we would like on those blocks. It would really become like a farm-in where we have a much greater scope of activity.
If the new Lease Operatorship Agreements do come through as we hope, Touchstone will then crank up that development drilling programme. We have identified over 200 drilling locations on the development blocks, and if we have the agreements in place we could potentially drill 15 wells per year, which would mean roughly a 12- to 13-year well inventory.
Touchstone would also like to start looking at options on the development blocks for enhanced oil recovery (EOR), specifically waterfloods. We have commenced the first waterflood on our WD-8 block by converting one of the wells from production to water injection. To date we have completed the injectivity test, which went very well, and submitted the Waterflood Application; we are now waiting for approval

Why is waterflood more attractive than gas injection at this well?
Number one, we don’t have enough gas on the island; meanwhile, we have an abundance of water. Secondly, waterfloods allow us to put our produced water back into the reservoir. We would not have any effluent released to surface, which is great from an environmental point of view. The original driver that started the waterflood projects was when our team started to look for water disposal wells. The one particular well took the water very well, and that is when we went from thinking about disposal wells to thinking about waterfloods. Now, we’re looking at the same concept on every one of our blocks.

In Ortoire, the Coho-1 well revealed 105 feet of net gas, and the Cascadura-1ST1 well showed 1,037 feet of net liquids-rich gas. What key work has been undertaken in the block so far, and what further tests remain?
Coho-1 was the smallest structure out of the four exploration wells on the Ortoire block; however, we chose to drill this well first as it was the closest well to the current infrastructure. It tested dry gas. We were expecting about 8 mcf [226,560 cubic metres] per day, and it looks like the well will come on line at about 11.6 mcf [328,470 cubic metres] per day, which we hope to have online by mid-2020. A key achievement with that well was that we did it for USD 3 million, which was what the authorisation for expenditure was.
Coho-1 has also proved the geological model, which was fundamental. We were looking for a turbidite sequence that had good porosity and permeability and could provide high deliverability; that is clearly what we ended up with. The well tested as high as 19.8 mcf [560,736 cubic metres] per day, so to produce it at 12 mcf [339,840 cubic metres] per day will be fairly simple.
The next prospect, Cascadura-1ST1, we thought was going to be an oil prospect, and we were looking for about 300 feet of pay and average production at approximately 600 bopd. Instead, it looks like we have about 1,037 feet of liquids-rich gas pay, far exceeding our expectations. We are now in the process of testing the well and have completed the lowermost 162 feet of the Herrera formation, which has a total of 777 feet of identified pay. This lowest formation tested at an average 5,180 boepd, including 26.9 mcf [761,808 cubic metres] per day of natural gas and 694 boepd of natural gas liquids.

How did you approach conducting exploration based on old wells?
The wells had been drilled in the ‘50s and ‘60s, and we looked at them in a new light. The turbidite geological model wasn’t very well understood in the ‘50s and ‘60s. Therefore, when these wells were drilled, they didn’t know exactly what they were looking at on the logs. When you look now, you see them in a different way – especially in light of comparisons with turbidites in the Gulf of Mexico, the North Sea and the coast of South Africa.

 

What infrastructure is already in place at Ortoire?
There is an existing gas plant in which our partner, Heritage, has an interest. There is also the National Gas Company of Trinidad and Tobago (NGC), which has a main line through Ortoire that goes up to Point Lisas, so we could put our gas production directly into that. As for oil, there is a line that runs straight through the middle of the block, so if we happen to get oil we could build a pipeline directly to that.
Once we have completed our tests at Cascadura-1ST1 and understand exactly how much gas and liquids we are looking at producing on a daily basis, we will then have a better understanding of what infrastructure we will need to use that is currently in place. There is about 40 mcf [1.13 mcm] per day of capacity in the existing gas plant, which is ideally where we would like to take the gas. However, if we end up with more than that, then we may have to look at doing something with the NGC.

You have said that the right structure is not yet in place here for mature oil, especially with the SPT regime. What changes do you want to see in the Trinidadian energy market fiscally or politically?
The fortunate thing is that Trinidad has fixed a lot of issues, so there is a good regulatory regime and a good marketing setup, and you do not have to worry about getting paid. It really is down to one last piece of the puzzle, which is to fix the taxation.
I refer to the SPT because it is an easy tax to look at that differentiates between oil and gas and old pools versus new pools. It was originally designed in the ‘60s. Oil was at USD 10, and the concept was that if it ever got to USD 50, this was going to be a windfall tax. Today 50 is the new 5, and they have not changed it. This has to be dealt with.

If the SPT threshold was set at USD 70, would it be more of a windfall tax in line with its original intention?
SPT is an 18% tax that comes right off the top of the sale price after royalties are deducted. You can dress it up however you want to, but at the end of the day it is a royalty on oil, and that does not make any sense. They have to fix it.
Moving the threshold up is not a long-term fix. In oil and gas projects, you need 10 years of visibility. Moving the price of oil up before the tax is implemented is a band-aid fix, and a band-aid is not going to fix the underlying issue with SPT. They have to commit. The government either wants to develop their mature oilfields, or else they will have to be happy seeing onshore oil production decline and rely on offshore production for the next 20 years.
Quite frankly, with the election this year, we do not believe that there are not enough people who are educated on SPT, and the trickle-down effect it has on the economy, to have the votes swung by changing SPT. That said, part of what Touchstone is trying to do is make SPT a campaign issue for the election this year. How? By emphasising that the government laid off over 4,000 people at Petrotrin when they closed their doors, which will help people relate with the situation. That means there are 4,000 highly qualified individuals without work.
If the country is looking to reduce unemployment and attract these highly trained individuals, who know the oil and gas business, then there must be an incentive for onshore oil companies like ourselves, Trinity, Columbus and others that can re-hire – but those incentives are not there.
There was the argument that once they got a royalty on the gas, i.e. a proper share of the gas revenue, they could then deal with the oil revenue. Now they have put that in place for the gas, so let’s see if they actually do make a change for the oil.

Is EOR economically difficult to undertake in Trinidad and Tobago?
I do think EOR is doable here. However, the right fiscal regime needs to be put in place to make it attractive. That is really the only thing holding it back. The technology is simple: CO2 from the plant goes back into the reservoir, and you get more oil. But if you have to pay 30% tax on all the oil that comes out, it does not make the capital go around.

How have operations at Ortoire changed the nature of Touchstone’s presence in the country?
Touchstone is a completely different company than it was a year ago as a result of Ortoire. It is going to be natural gas-centric. Instead of focusing on a large number of low-production wells, it is going to focus on high-production wells. The outlook is very different. Operating costs are going to come down, while volumes are going to grow. Ortoire has been transformational for Touchstone.

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