Trinidad and Tobago’s oil and gas fields are found in six main areas. The three offshore fields are in the North Coast Marine Area, the East Coast Marine Area and the South-west Coast Marine Area. The three onshore areas are located in South-east Trinidad (including Guayaguayare and Moruga), South-west Trinidad (Point Fortin, Guapo and Forest Reserve) and Central Trinidad (including the Central Range Block and the Central Block). Currently, the top priority in the upstream realm – in both oil and gas – is to take the necessary actions to put a stop to and ultimately reverse the decline in production.
It is estimated that the amount of gas needed to meet all downstream demand is around 4.2m standard cu feet per day (scfd). When upstream production drops below that level, the downstream plants suffer disruption and supply shortfalls. For the last three years supply has averaged less than the necessary amount. In 2014 natural gas output fell 1.8% to 4.07m scfd. In 2015 it contracted 5.8% to 3.83m scfd and in 2016, according to preliminary data, it fell 12.9% to 3.33m scfd.
“Significant investment is needed to drill and explore for oil in order to increase our reserves. That is what is taking place right now,” Richard Jeremie, chief technical officer for the Ministry of Energy and Energy Industries, told OBG. He explained that three onshore exploration blocks were tendered in 2014 and assigned to locally based entities Lease Operators, Touchstone of Canada and Range Resources of the UK. These companies are in the process of identifying drill locations, with exploration work due to start up in 2017-18. Offshore exploration blocks were also assigned in 2013 and 2014, and BHP T&T – one of the licensees from that particular round – is now conducting drilling work.
Jeremie further told OBG that in late 2016 Spanish oil company Repsol sold its 70% interest in the Teak, Samaan and Poui (TSP) block to Perenco of France, and that the government was interested in seeing whether the new operator would step up exploration and production activity in the area. The TSP block is located offshore, south-east of Trinidad, and is currently producing some 14,000 barrels per day.
Perenco has previous experience operating mature fields in a low-price environment.
At the annual Trinidad and Tobago Energy Conference held in Port of Spain in January 2017, Colm Imbert, the minister of finance and acting minister of energy and energy industries at the time, noted that new exploration and production licences would be offered. “The Ministry in 2017 will make available for exploration acreage on land and in marine areas, including our deep-water province. Such areas may include acreage that has been relinquished or that has reverted to the state by virtue of the expiration of contractual deadlines,” he announced.
The standard industry definition is that proven reserves (1P) are those with a 90% certainty of commercial extraction using current technology; probable reserves (2P) have a 50% certainty of commercial extraction; and possible reserves (3P) have a 10% certainty of commercial extraction. According to an audit by Dallas-based petroleum consultant Netherland, Sewell and Associates completed in 2013, T&T had 199.5m barrels of proven crude oil reserves, 85.5m barrels of probable reserves and 124.8m barrels of possible reserves. This gave total reserves (proved, probable and possible) of 409.8m barrels of petroleum. The reserves-to-production ratio was 6.6 years for 1P Currently, the top priority in the upstream realm, in both oil and gas, is to take the necessary actions to halt and ultimately reverse the decline in production reserves and 13.6 years for 3P reserves. However, significant further discoveries have been made since that audit, including some in areas licensed to Petrotrin (the Jubilee field), Repsol (the Teak Bravo field), and Trinity Exploration and Production (the Galeota, Trintes and East Galeota fields).
After 2011 the Ministry of Energy and Energy Industries signed 21 new production-sharing contracts or licences, none of which would have been included in the audit. Netherland, Sewell and Associates had also estimated prospective resources running up to 811.5m barrels of crude in their report.
Gas reserves are assessed on a more regular basis – specifically, once per year – by US consultancy Ryder Scott. By 2014 the reserves-to-production ratio for 1P gas reserves had fallen to 8.3 years, while the ratio for 2P reserves had reached 13 years. In 2015 it was reported that 1P gas reserves had fallen to approximately 10.6trn scf, down from 11.5trn scf the preceding year – a decrease of 7.8%. The 2P and 3P reserves also fell, to 3.24trn scf and 1.15trn scf, respectively.
The audit report indicated that there has been a steady decline in proven reserves over the last 13 years, reflecting a reserves replacement ratio of only 34%. Presenting the results of the audit in October 2016, Nicole Olivierre, the then-minister of energy and energy industries, said there was hope that the trend might be reversed. She highlighted the fact that exploration work by several operators might lift the proven reserves figure. The impact of a positive gas find, indicating the presence of multiple reservoirs in BHP’s LeClerc deepwater well, had not yet been included in the Ryder Scott audit.
Some analysts maintain that the Ryder Scott report does not give a thoroughly accurate picture of the real reserves available in T&T. They say that the government has been eager to maintain consistency in the way reserves are measured from one year to the next, and that this has been achieved at the expense of incorporating innovations in measurement methodology. Since Ryder Scott has been carrying out the audit for the last 15 years, applying essentially the same criteria, a lot of changes in measurement techniques adopted in the global energy industry have not been incorporated.
Reason for Optimism
Philip Farfan, a geologist at Port of Spain-based consultancy PetroCom, pointed out that reserves, by definition, refer to hydrocarbons deposits where a contract and a commercial pricing mechanism are already in place. If a government issues fewer contracts than actual discovered resources, then the reserves figure will be lower. Hydrocarbons reserves should not be confused with hydrocarbons resources, which are an attempt to measure what Farfan describes as the molecules that are actually in the subsurface.
The optimistic line of thinking suggested by Farfan is that renewed licensing activity to attract companies and encourage exploration work could lead to significant growth in the overall level of known reserves. The international price is a key factor in whether companies are willing to undertake exploration risk. However, the fact that majors such as BPTT and BHP have continued to carry out exploration in the Trinidad basin through a downturn in the international price cycle suggests there are reasons to believe the country may have major hydrocarbons resources ready for conversion into proven reserves.
At present, the true level of hydrocarbons resources in and around T&T is unknown. While much of the recent debate has focused on supply shortfalls and low-resource scenarios, more optimistic scenarios of resources cannot be ruled out. For the moment, the short- and medium-term outlook is one of limited supply. In the gas segment, however, a number of projects are currently being pursued in an attempt to reverse the decline in production.
One of the most important new initiatives is BPTT’s Juniper project to develop five subsea gas wells in the Corallita and Lantana fields off Trinidad’s south-east coast. Drilling began in 2015 and production is expected to start in late 2017. Initial capacity is expected to be approximately 590m scfd, equivalent to around 15% of the country’s current gas output. Juniper is therefore the most significant addition to gas production capacity that the country has seen in recent years. The operation has also been described as one of the primary global projects undertaken in recent years by BP.
The total capital cost of Juniper has been estimated at some $2.1bn. The company gave the project the green light in 2014, meaning it has taken some three years of development and construction leading up to the point at which first gas is expected to flow. The platform, built approximately 360 feet below the water, was designed for a cluster of five separate wells, but it can still incorporate others in the future. It is designed to have a 25-year lifespan, taking into account the possible discovery and exploitation of additional gas in the Columbus basin.
In June 2017 BPTT announced two major finds in the Columbus basin. Drilling of the Savannah and Macadamia wells has uncovered approximately 2trn cu feet of gas, a substantial discovery. According to local media reports the company plans to develop these reservoirs through future tieback to the Juniper platform.
Company sources say that data from an ocean-bottom cable survey suggest that there are still significant hydrocarbons resources in the basin to be developed in future years. Gas from the platform will be fed by pipeline for 10 km to the Mahogany B hub, and from there on through existing pipelines to the Galeota Port onshore facility.
In January 2017 the Juniper platform – which, as a whole, includes jacket, piles, topsides and subsea infrastructure – began to be moved to the installation site some 50 miles offshore. The topsides were built by Trinidad Offshore Fabricators (TOFCO) – a joint venture between local company Weldfab and US-based Chet Morrison Contractors – at its local fabrication yard in La Brea. The jacket and piles were built at Gulf Marine Fabricators of Texas, under TOFCO’s direction and supervision.
“Numerous opportunities will present themselves in T&T and the region over the next five to 10 years,” Javed Mohammed, general manager at TOFCO, told OBG. “But to take advantage of these, important discussions between key stakeholders and government officials must be held to ensure a path towards greater enhanced global competitiveness.”
Another important prospect is BHP’s deepsea drilling programme in five blocks in the Atlantic Ocean, which the company confirmed in January 2016.
By early 2017, however, there was some concern that the first phase may not have been as successful as hoped. BHP was seeking to find 250m barrels of oil through a $700m exploration programme off T&T and in the Gulf of Mexico.
To the company’s surprise, drilling at the LeClerc well (Block TTDAA5) revealed promising indications not of oil, but of gas. Further North, drilling at the Burrokeet well (Block 23a) encountered some initial technical difficulties. A company statement said only that the results of Burrokeet drilling were being evaluated. News in January 2017 that the drill ship, the Deepwater Invictus, had been moved from Burrokeet to the Gulf of Mexico, triggered speculation that no significant finds had been made at the former location. However, in an October 2016 briefing, Niall McCormack, the vice-president of global exploration at BHP, explained that the results at LeClerc and Burrokeet would be integrated into phase two, due to start in the second half of 2017. “Historically, these types of areas take more than one well to prove the presence of tier-one discoveries,” he said.
At the T&T Energy Conference which took place in January 2017, Geraldine Slattery, the asset president at BHP, said that BHP was encouraged by the gas find in LeClerc, and “pleased to have oil shows in the deep of that well.” The company further stated that it was very optimistic of a tier-one play, and will return to drilling that area in FY 2018.
Troc & Sercan
The Trinidad Onshore Compression (TROC) project is being implemented by BPTT in association with domestic company Atlantic and the National Gas Company (NGC), a state-owned enterprise. The project involves the installation of a compressor at the Atlantic liquefied natural gas (LNG) facility at Port Fortin, which will be used to reduce the pressure running though NGC and BPTT pipelines, in turn increasing gas availability from BPTT’s low-pressure wells in the Columbus basin.
It is estimated that TROC can deliver an additional 200m scfd of gas into Atlantic, starting from early 2017. The total investment cost of TROC has not been revealed, but BPTT regional president Norman Christie has described it as “significant”.
The Sercan field in the East Manzanilla block is jointly owned by BPTT and EOG Resources. EOG, a US-based company, is the operator. The development programme involves drilling five wells and the field is expected to begin production in mid-to-late 2017. Output is expected at 250m-275m scfd.
Dragon Field Discussion
One way T&T could move to reduce or eliminate its gas supply deficit would be to develop fields in collaboration with Venezuela, its immediate neighbour. Officials have been investigating this possibility in discussions with the Venezuelan government. To this end, Prime Minister Keith Rowley visited Caracas for talks in December 2016. Reports said that two main options were being investigated, involving the Dragon field in Venezuelan waters and the Loran-Manatee field, which straddles the maritime border between the two countries. The Dragon field would be the quickest to bring on-line. Under the agreement struck during Rowley’s December visit, the field would be developed through a partnership between the Venezuelan state oil company PDVSA, T&T’s NGC and Shell, which has operations in both countries. Dragon is part of the multi-field Mariscal Sucre complex, which is believed to hold 14.7trn scf of gas.
The plan would be to pump gas from Dragon via pipelines to Atlantic, T&T’s liquefaction complex, which has the capacity to produce 14.8m tonnes per year of LNG, and with which Shell is a major partner. The Venezuelan gas could also be used to supply T&T’s downstream ammonia and methanol plants. As mentioned, these plants, along with Atlantic, have been operating below capacity because of gas supply impairments, with shortfalls sometimes as high as 30% of contractually established levels.
One of the major advantages of the Dragon project is that it would not require major capital expenditure on the T&T side. A 17-km flow line would also need to be established between the Dragon field and the Hibiscus platform operated by Shell off Trinidad’s north-west coast.
In March 2017 the signing of a new gas export agreement between T&T and Venezuela outlined the “construction, operation and maintenance of a gas pipeline from the Dragon field in Venezuela to the Hibiscus field in Trinidad and Tobago; a connection with the Hibiscus-Lisas gas pipeline; the supply of natural gas extracted from the Venezuelan field to Trinidad and Tobago’s domestic market; and the NGC plant for commercialisation in international markets,” according to a PDVSA press release.
NGC’s chairman, Gerry Brooks, signed on behalf of T&T, while PDVSA’s president, Eulogio Del Pino, accepted on behalf of Venezuela, and vice-president and county chairman, Luis Prado, represented the commercial interests of Shell in the agreement.
From Hibiscus, the gas could be run through an existing pipeline to the Atlantic facility at Port Fortin. It is estimated that Dragon will produce an initial 300m scfd, later increasing to 500m scfd. A potential disadvantage is that as the gas originates in Venezuela, it will not generate wellhead tax revenue and royalties for the T&T Treasury. Yet it will make a valuable contribution to reducing the gas production shortfalls, and improving the taxable revenues of LNG and petrochemicals operators. There was also some concern over the financial and political crisis in Venezuela, and the possibility that it might mean that the Caracas government would not be able to honour commitments made to T&T. Some industry leaders countered and believe that any Venezuelan government would surely want to protect an arrangement giving it a valuable source of much-needed foreign currency. Earlier, in December 2016, Rowley said he hoped that gas from the Dragon field would start flowing before 2020.
The other area of potential cooperation is the Loran-Manatee field, which holds an estimated 10.25trn scf of gas, of which approximately 74% is on the Venezuelan side and 26% is on the T&T side. Estimates have suggested that the combined field could eventually produce as much as 750m scfd, of which some 200m scfd would represent the share for T&T.
However, discussions have progressed slowly. In 2013 the two governments committed to joint development of the field. In 2015 the Venezuelan side agreed to the gas being extracted and commercialised through T&T. A commercial agreement – and investment decision – is now needed by the licence-holding companies: Shell and Chevron on the T&T side, and Chevron and PDVSA on the Venezuelan side. It is widely expected that if there is a positive decision to develop the field, it could take four to five years before gas starts flowing, meaning it would not come on stream until after 2020.
The Angelin field is possibly the country’s most important medium-term gas prospect, with the exploration rights held by BPTT.
Whether, and on what terms, this field will be developed has become central to the ongoing debate between the government and privately owned oil majors. In September 2016 BPTT president Norman Christie argued in a Statistical Review forum that his company needed better incentives to persuade it to invest in developing Angelin.
He also linked Angelin development to greater clarity on the government’s proposed Gas Master Plan. The plan, Christie said, needed to result in clear policy on gas allocation and prices, and incentivise upstream investments in a competitive environment.
“The next phase of planned major developments, starting with Angelin, are still not sanctioned and will not be sanctioned unless policy decisions properly recognise the context in which we are operating,” Christie said during his address at the forum.
He added that it would not be sensible for his company to commit investments in the Angelin field “without knowing where the gas is going to go and under what pricing mechanism”. In June 2017 it was announced that the contract for the engineering, procurement, construction, installation and commissioning of the Angelin platform was awarded to US-based McDermott International.
Nonetheless, following a March 2017 meeting between Rowley and senior BP executives – including upstream chief executive Bernard Looney, executive vice-president and COO, strategy and regions, upstream, Andy Hopwood, and BPTT regional president Norman Christie – it was announced that BP would invest $5bn over the next five years, and that an agreement between BP and NGC for Angelin’s development was imminent for the first tranche of this investment.
Brooks said that he was “pleased to announce that the NGC team has substantially completed negotiations on a new supply agreement which would support the sanction of the Angelin project.”
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