Touchstone Exploration is the operator of the 184-square kilometer Ortoire Block onshore south eastern Trinidad. The block spans from the villages of Tableland in the west to Pierreville Mayaro in the east and to the very remote areas within the Guayaguayare forest to the south. Structurally, the block covers the greater part of the open east facing Ortoire Syncline which entails Late Miocene Lower Cruse to Pleistocene Mayaro Formation deltaic fill. These passive fordeep infill deposits sit conformably onto a southeastern-verging Early to Middle Miocene fold belt. As such throughout the breadth of the Ortoire Block there are numerous tear fault dissected west-southwest to east-northeast trending anticlines. These anticlines were the result of the oblique collision between the highly attenuated northern margin of the South America continental plate with the leading edge of the apparent easterly migrating oceanic Caribbean Plate culminating in the Middle Miocene.
Historical exploration within the area, dominantly within the 1950s, by United British Oilfields of Trinidad and Shell, had been primarily focused on Middle Miocene Herrera amalgamated channelized slope to base of slope deepwater turbidites of the Cipero Formation and Late Miocene Lower Cruse base of slope sheet like turbidite fans. Considered shallow water deposits at the time of exploration, the results of many of those wells were considered disappointing or uncommercial. Further to this, these operators considered the area dominantly extensional and did not apply fold and thrust belt geometries to their geological model.
Subsurface mapping on the Talisman 3-D seismic survey, Cometra 3-D seismic survey and numerous Southern Basin Consortium 2-D seismic lines, integrated with surface geology, regional well data and fold and thrust belt models have revealed numerous potential Middle Miocene Herrera plays within the block. To name a few, from north to south, Touchstone Exploration has identified an eastern extension of the prolific Penal Barrackpore oilfield in the Cascadura area, a subthrust north verging anticline at Coho, a south easterly verging subthrust anticline at Royston and an eastern extension of the Carapal Ridge north verging subthrust anticline in the Chinook area.
These structures have all been tested by the drill bit in the past, but results were grossly misunderstood by generations of operators. Two of these structures, Coho and Cascadura, have been successfully explored to date by Touchstone Exploration. At Coho-1, initial tests and extended tests have been completed and commercial discovery notification has been submitted to the Ministry of Energy and Energy Industries. At CAS-1 ST1, two zones were tested and the results are astounding.
The Coho area occurs immediately south, in the subthrust of the south easterly verging Penal Barrackpore thrusted anticline. This subthrust fold is north verging due to backthrusting resulting in the Mid Miocene Herrera interval being found at approximately 5,400 feet, and then again at 7,800 feet. The north verging backthrust therefore provides a potential trapping mechanism for imbricated pay. The Coho-1 well was drilled to evaluate the untested Herrera Gr7 repeat section and follow up on the offsetting Corosan-1 gas test, which was never placed on production.
The Coho-1 exploration well was spud on Aug. 7, 2019 and reached a total measured depth of 8,560 feet (8,543 feet true vertical depth) on Sept. 3, 2019 using Well Services rig No. 80. The Coho-1 well logs indicate four gas bearing packages in the Herrera member of the Mid-Miocene aged Cipero formation. Based upon wireline logging, two sand packages between 5,486 and 5,782 feet with approximately 64 feet of net gas pay were encountered in the upper Herrera Gr7b. The Gr7b sand packages correlate to the offsetting Corosan-1 well drilled in 2001, where similar sands tested natural gas in excess of 8 million cubic feet per day. Wireline logging also indicated two prospective gas sand packages in the Herrera Gr7c section between 6,530 and 7,240 feet. These two sand packages contain a combined 41 feet of probable net gas pay, which was not tested in historical offsetting wells. In addition, logging identified the presence of oil sands in the lower Herrera Gr7b repeat section at a depth of 7,788 feet. This lower quality 100-foot thick gross interval does not appear to be commercially prospective but proves the presence of hydrocarbons in this previously untested thrust sheet, and may de-risk future exploration opportunities.
“The primary objective in Coho-1 was natural gas and we are very pleased to have found 105 feet of prospective gas pay, which we will now evaluate for commercial production,” said James Shipka, chief operating officer of Touchstone Exploration, following the discovery. “The presence of oil in the repeat section confirms the presence of previously unproven hydrocarbons in the deeper Herrera thrust sheet and confirms the potential for further exploration targets in the lower Herrera sand sheets within the Ortoire exploration block.”
Initial testing on Coho-1 was conducted on Nov. 16, 2019 with a flowback period spanning seven hours using gradually increasing choke sizes. During the final flowback period, a peak rate of 19.8 million cubic feet per day (3,300 barrels of oil equivalent) of dry, sweet natural gas was observed with a wellhead pressure of 2,632 psi on a 32/64-inch choke. The average natural gas rate associated with this final period was 17.5 MMCFD (2,917 BOEPD) with an estimated 23 percent draw down.
“These positive well test results represent a new era for Touchstone as we expect to add significant natural gas volumes to our production base,” said Touchstone Exploration CEO Paul Baay. “The results outline the opportunities that still exist for onshore Trinidad exploration and position Touchstone to become a top three onshore petroleum producer. It must also be noted that the Coho-1 well is in the smallest prospect of the Ortoire exploration program. The Company will proceed to tie in the well through a 3-kilometre pipeline to an existing production facility that has capacity in excess of this well’s estimated production rates. We anticipate bringing the well on production during the first half of 2020.”
The Cascadura Well
The Cascadura well, located at Poole Valley Road along the Rio Claro Guayaguayare Road, structurally tests an eastern extension of the west-southwest plunging, south easterly verging, and heavily imbricated Penal/Barrackpore/Mandingo Anticline. CAS-1 was planned to be drilled to a total depth of 8,150 feet, targeting three distinct thrust sheets with Middle Miocene Herrera sandstones – the shale-rich Overthrust or Sheet 1, the secondary target/Sheet 2 which correlates to the BW-5 well sandstones that produced 27,000 bo before shut-in at an uneconomic rate of 13bopd in 1963, and the primary target – the Overturned or Intermediate Limb/Sheet 3.
While drilling the well, there were mechanical issues with the drilling rig, and as such the well was sidetracked beneath surface casing. We encountered several distinct high-pressure hydrocarbon kicks that were controlled through the use of high-weight drilling fluid and pressure control. For safety reasons, the company decided to cease drilling operations and case the well to preserve the significant hydrocarbon saturated sand reservoirs which had been encountered to total depth of 6,350 feet. These sandstones both occurred within the Sheet 1 and Sheet 2 structural levels. However, Sheet 1 was found further imbricated three times.
As a result of the high pressures and mud weights, we were unable to use a conventional open hole logging tool; Schlumberger was on site on Dec. 12 and completed cased hole logging operations using their Pulsed Neutron Extreme tool on Dec. 15, 2019. The Cascadura-1ST1 cased hole well logs and drilling samples indicated oil pay in the regional Lower Cruse Formation as well as three significant oil-bearing packages in the Herrera member of the Mid Miocene aged Cipero formation. While drilling the surface and intermediate sections of the well, several oil-bearing sands in the Lower Cruse formation were encountered. A total of 220 gross (80 net) feet of prospective pay was logged at depths between 1,030 and 2,134 feet. These sands correlate to sands observed in the offset BW-5 well but they were wet in the structurally lower offset. The Lower Cruse Formation was not considered to be a target in the Cascadura prospect and Touchstone will evaluate this potential new Lower Cruse pool.
The primary target at Cascadura were the turbiditic Herrera sands and the Cascadura-1ST1 well encountered a total of 1,154 gross sand in the Herrera of which 957 net feet is interpreted to be hydrocarbon bearing. These sand packages appear to occur in unique and separate fault sheets. 320 gross feet of Herrera Gr7c sands were encountered in the upper thrust sheet with 180 net feet bearing oil at depths between 4,198 and 4,994 feet. An additional 646 gross feet of Herrera Gr7c sands were identified in the middle thrust sheet, with 600 net feet of hydrocarbon bearing sands found at depths between 5,516 and 6,162 feet. The sands found in the upper and middle thrust sheets do not appear to correlate to any known historical well data in the area. In the lower thrust sheet, logging and drill sample results indicated the presence of 188 gross feet of Herrera Gr7a sands with 177 net feet identified as hydrocarbon bearing. These sands were found at depths between 6,162 and 6,350 feet and correlated to a sand package which was present in the offsetting BW-5 well originally drilled in 1958. The Cascadura well is calculated to be at least 200 feet up-structure from the original BW-5 well
The initial test interval was completed on Jan. 17, 2020 to evaluate the lowermost 162 foot pay interval between 6,056 and 6,218 feet. The well was opened to test on Jan. 18, 2020 on a 4/64-inch choke for a period of 97 minutes with load fluid, hydrocarbon emulsion and gas recovered at surface prior to shut-in. Shut-in tubing head pressure observed at surface built to 4,200 psi, which we deemed to be higher than current equipment could safely evaluate. The well is currently shut-in while we mobilize a three-phase separator and testing package designed to safely evaluate the high pressures and gas volumes observed upon initial completion.
“This is the best possible outcome for the initial test results from the Cascadura well, as natural gas and liquids have superior economic value under the Trinidad fiscal regime,” said Bay. “Based on the information acquired while drilling, the thick sand we encountered in the well appeared to contain oil with some associated gas. It is now evident that it is likely a liquids rich gas structure. Given this is only the lowermost 162 feet of pay in the well, these initial results are extremely encouraging.”
Stage two testing achieved a peak production rate in excess of 5,760 boe/d (15 percent liquids) during the extended 24-hour flow test period. This production rate included 29.4 MMcf/d of natural gas and 865 bbls/d of natural gas liquids. The flowing pressure of the well at this point in testing was 3,581 psi through a 40/64-inch choke. During the final 24-hour flow test period, the well averaged a production rate in excess of 5,472 boe/d (14 percent liquids), including 28.1 MMcf/d of natural gas and 783 bbls/d of natural gas liquids at a flowing pressure of 3,578 psi through a 40/64-inch choke, resulting in an estimated 13 percent drawdown. A total of 43 million cubic feet of natural gas (7,162 barrels of oil equivalent) was produced during testing, with 1,095 barrels of natural gas liquids and 78 barrels of water which included 69 barrels of load fluid. During the final flow test, stage two testing yielded 55-degree API natural gas liquids at a ratio of approximately 28 barrels of natural gas liquids per million cubic feet of natural gas produced. Laboratory analysis of the produced gas indicated liquids rich natural gas with no hydrogen sulfide content and no measurable solids.
An independent reserves report on Cascadura was undertaken by GLJ Limited in July 2020. GLJ has assigned gross discovered petroleum initially-in-place (“DPIIP”) volumes of 571.5 Bcf of natural gas in the high estimate and 241.2 Bcf in the low estimate, with a best estimate of 398.5 Bcf.
This places Cascadura as the largest onshore natural gas discovery in Trinidad’s history.
“We are delighted to report that the independent reserves report verifies the material size of the reserves yet to be produced in the Cascadura structure and provides the groundwork for a multiyear future onshore development program in Trinidad,” said Baay. “Through the excellent work of the Touchstone team in the drilling of our first two exploration wells, we have successfully proven up the hydrocarbon bearing turbidite model in Ortoire. This model will be further evaluated by our next two exploration targets at Chinook and Cascadura deep, with drilling at Chinook on track to commence within the next few weeks. We could not have envisioned a better start from the first two wells of the Ortoire exploration program, and we look forward to updating the market and our Trinidad stakeholders as we progress with our Ortoire exploration and development activities in the coming months.”
The success in the Ortoire Block to date speaks to the merit of an integrated approach, utilizing vintage datasets and applying basic geological principles while looking at it with a different perspective. Many companies in the past struggled to integrate datasets, as they were limited to postage stamp acreage scattered across the island. The Ortoire Block is a fair sized block to observe the relationship of the different exploration efforts or campaigns of the 1940s and ‘50s. Touchstone Exploration also has an added advantage of operating blocks in Forest Reserve, Coora, Palo Seco, Barrackpore, San Francique, Fyzabad and even Bouvallius in the east, which enable our team to observe the entire onshore Southern Basin and draw on appropriate structural or sedimentological analogues.
Many geologists and geophysicists in the past were also fixated in their own subsurface models and were unwilling to accept alternative interpretations. This is something we strive to avoid. We strive to be a dynamic team, continuously testing our models with various interpretations and utilizing modern techniques and technologies wherever possible.
One thing for sure is that there are a lot of hydrocarbons onshore still to be found. We first need to believe that. That will be the first step to trying something different.