Exploration Properties
Touchstone has interests in a number of small undeveloped exploration properties and three larger exploration blocks. Our main exploration focus is the Ortoire exploration block.
Ortoire
In 2014, we signed an exploration and production licence with the Trinidad and Tobago Ministry of Energy and Energy Industries for an 80% operated working interest in the Ortoire block (the “Ortoire Licence”). The Ortoire Licence is effective for an initial term of six years and can be extended a further 25 years in the event of a commercial discovery. The property covers approximately 44,731 gross acres (35,785 net) on the east side of Trinidad. The Ortoire Licence includes a commitment for a six-year minimum work program which consists of technical reviews, an 85-kilometre 2D seismic program and a four-well drilling program.
Historical Production
77 wells have been drilled on the Ortoire Licence area prior to Touchstone acquiring the Ortoire Licence. Our geological team reviewed the logs and historical data from these wells and identified four established “legacy” pools in the Ortoire property where production has previously occurred. These legacy pools have diverse production histories and now represent potential future reactivation or recompletion opportunities. Historical pools on the Ortoire Licence include:
- Balata West with conventional oil produced from the Herrera formation;
- Mayaro with conventional gas produced from the Gros Morne formation;
- Maloney with conventional oil produced from the Lower Cruse formation; and
- Lizard Springs with fractured shale oil produced from the Lengua/Karamat formation.
No production is currently associated with these legacy pools; however, we continue to evaluate the potential to develop these pools in the future.
Exploration Prospects
In addition to the historical pools located on the Ortoire Licence area, we have identified several exploration prospects based on 2D and 3D seismic data, historical well logs, and geological similarities to offsetting gas deposits at Carapal Ridge. Four of these exploration prospects – Coho, Cascadura, Chinook and Royston – have been identified for drilling to prove our technical model.
Coho
Our Coho-1 well was spud on August 7, 2019 and was drilled to a total depth of 8,560 feet. Wireline logs indicated approximately 64 feet of prospective natural gas pay in the Herrera Gr7b formation between 5,486 and 5,782 feet. The final production and flow test results indicated the following:
| Coho | |
| Extended flow rate | 11.6 MMcf/d (boe/d) |
| Absolute flow rate | 46 MMcf/d (7,671 boe/d) |
| Expected initial production rate (net) | 8.0 – 9.6 MMcf/d (1,333 – 1,600 boe/d) |
| Gas composition | 98.7% pure methane |
Coho-1 is approximately three kilometres from a natural gas tie-in point, and we anticipate bringing the well onto production in 2020 through the development of a new pipeline.
Cascadura
The second exploration well, Cascadura-1, was sidetracked (ST1) and drilled to a total depth of 6,350 feet. Cased hole wireline logs and drilling samples indicated approximately 1,037 feet of prospective hydrocarbon pay in the Cruse and Herrera formations at depths between 1,030 and 6,350 feet. The first stage of the production test of the well was designed to evaluate the lowest 162 feet of prospective pay found in the Herrera Gr7c and Herrera Gr7a formations between 6,056 and 6,218 feet. Stage one test results were as follows:
| Cascadura – 1 (stage 1) | |
| Extended flow rate | 5,157 boe/d (12% liquids) |
| Natural gas | 26.8 MMcf/d (4,466 boe/d) |
| Natural gas liquids | 691 bbl/d |
| Natural gas liquids API | 55° |
The second stage of the production test of the Cascadura-1ST1 well was designed to evaluate 345 feet of prospective pay between 5,570 and 5,915 feet in the Herrera Gr7bc formation. Stage two test results indicated the following:
| Cascadura -1 (stage 2) | |
| Extended flow rate | 5,472 boe/d (14% liquids) |
| Natural gas | 28.1 MMcf/d (4,689 boe/d) |
| Natural gas liquids | 783 bbls/d |
| Natural gas liquids API | 55° |
| Expected initial production rate (net) | 6,200 – 7,760 boe/d |
| Natural gas | 32 – 40 MMcf/d (5,300 – 6,670 boe/d) |
| Natural gas liquids | 880 – 1,120 bbls/d |
We are currently evaluating various alternatives to bring the well onto production, which is expected to occur in 2021.
Chinook
The well at Chinook-1 was drilled to a total depth of 10,039 feet to test a separate structural formation 1.5 kilometres south from the successful Cascadura gas discovery. Wireline logs indicated significant natural gas pay totalling approximately 589 net feet in three unique thrust sheets. Furthermore, additional natural gas pay of approximately 20 net feet was encountered in the shallower Cruse formation.
In the first quarter of 2021, we expect to initiate a comprehensive completion and testing plan to evaluate the economic potential of the hydrocarbon sands.
Royston
The Royston location is targeting a deep gas prospect with an estimated target depth of 11,500 feet. Royston offsets a well originally drilled in the 1960s, and wireline logs indicate approximately 700 feet of gas; however, the well was never tested. The Royston prospect is targeting a separate structure along the same geological trend as Coho-1 and Cascadura-1ST1.
Natural Gas in Trinidad and Tobago
Trinidad has a diverse industrial economy which is driven from the country’s vast hydrocarbon reserves. Natural gas is a vital feedstock for power generation as well as for the country’s manufacturing industry. As the natural gas reserves base in Trinidad and Tobago has been falling steadily since 2002, the demand for new gas production and reserves to continue to support local industry has intensified. As a result, the Trinidad and Tobago Ministry of Energy and Energy Industries has implemented a Trinidad and Tobago Gas Master Plan to help stimulate development and growth in the gas industry. Click here to see the full details of the plan.
Advisories
Forward-Looking Statements
Certain information provided herein may constitute forward-looking statements within the meaning of applicable securities laws. Forward-looking information herein include, but is not limited to, statements with respect to the quality and quantity of prospective hydrocarbon accumulations; well test results; our exploration plans and strategies, including anticipated timing, development, tie-in, and production from current exploration wells, and with respect to future exploration drilling and the timing thereof; and the sufficiency of resources and available financing to fund future exploration operations. Although we believe that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because we can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. Certain of these risks are set out in more detail in our 2019 Annual Information Form dated March 25, 2020 which is available on our website.
Oil and Gas Matters
References herein to production test rates and initial flow rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. Additionally, such rates may also include recovered “load oil” fluids used in well completion stimulation. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Touchstone. A final pressure transient analysis and/or well-test interpretation has yet to be carried out in respect of the Cascadura-1ST1 well. Accordingly, we caution that the second stage of the Cascadura-1ST1 test results should be considered preliminary.
Oil and Gas Measures
Where applicable, natural gas has been converted to barrels of oil equivalent based on six thousand cubic feet to one barrel of oil. The barrel of oil equivalent rate is based on an energy equivalent conversion method primarily applicable at the burner tip, and given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.