International oil and gas companies continue to develop major projects in Trinidad and Tobago

The financial squeeze that has been caused by lower oil and gas prices, together with doubts over the commercial viability of some new projects, has led to pressure on overall levels of exploration activity in Trinidad and Tobago. However, there has not been as sharp a reduction as was experienced during the global financial crisis of 2008.

In 2009 both the number of rig days and depth drilled – two indicators of exploration levels – were down by just over 70% compared to the previous year. Conversely, in 2015 both those indicators rose after a flat performance in 2014. Total depth drilled increased by 27.7% in 2015 to 141,270 metres, while the number of rig days was up by 12.8% to just over 230. However, in the last quarter of 2015 depth drilled was down by 1.8% while rig days fell 7.6%, which could point to a weaker performance in 2016.

Price Squeeze Hits Drilling

An example of the pressure on exploration activity was given by Michael Loewen, country manager for Canadian-owned oil company Touchstone Exploration. Touchstone is one of a number of relatively small onshore producers with acreage in south-western Trinidad, producing around 1400 barrels per day (bpd). “Because of the low-price environment since January 2015 we have not conducted any new drilling operations,” Loewen told OBG, adding “At a price of around $30 a barrel we can make a small profit, but we can’t fund drilling operations.”

He explained that at $30 barrel Touchstone was paying around $18 in operating costs and $11 in taxes, leaving $1 a barrel worth of profit. He expected some drilling activity to take place during 2016, due to contractual commitments in the company’s operating licences and to reassure shareholders that Touchstone remains actively seeking out new opportunities. However, Touchstone would look at other techniques for increasing production, such as spending around $300,000 on a well workovers. In addition, it would go back to some of its service providers seeking to renegotiate existing contracts and cut costs.

Another small company which has cut back on exploration efforts is LGO Energy, listed on the London stock exchange. In a February 2016 update to its shareholders, LGO said that operations at its Goudron oilfield in Trinidad had been “restricted to essential maintenance and well work to optimise production and conserve cash in response to the low oil price,” adding “all discretional infrastructure and drilling projects are on hold”.

However, in a more positive development, in April 2016 Range Resources said that, as a result of its ongoing exploration activity, it had successfully identified “multiple hydrocarbon-bearing zones” in its MD250 development well, and expected to carry out further tests and possible follow-on drilling. From January to March, the company produced an average of 550 bpd, according to a statement released in May 2016.

Oil Majors Keep Exploring

In contrast, various large oil and gas companies operating in the country indicated that exploration work would continue, despite the difficult market conditions.

In January 2015 BPTT, already involved in large-scale development of its Juniper project, said its next development prospect was the Angelin field. According to corporate operations vice-president Giselle Thompson, Angelin had been moved up the company’s development priorities as a result of an ocean bottom cable seismic campaign that had identified three main exploration prospects.

Other BPTT plans included spudding the Savannah exploration well located near the company’s Juniper project, along with an in-field drilling programme on its existing acreages designed to identify smaller pools. BPTT is also expected to take a final investment decision on building an onshore compression facility that would increase gas deliveries into the pipeline network.

BPTT’s ongoing commitment to carrying out exploration and development work was underlined by the company’s regional president, Norman Christie, who at the end of January 2016 said that in spite of falling prices and declining revenues it still intended to invest a total of over $1.5bn in the country during the course of the year. Christie said that BP had realised “close to $1.5bn” in capital expenditure in 2015, and was aiming to exceed that in 2016 if the conditions were favourable.

Meanwhile, Australia-based BHP Billiton was involved both in developing the offshore Greater Angostura field and the Angostura gas scheme, and in exploration elsewhere in and around the Greater Angostura complex. Angostura Phase III drilling began in November 2015.

BHP has said that the number of wells drilled will depend on ongoing seismic analysis. The greater Angostura field is expected to have a productive life expectancy of around 19-24 years. The complex is estimated to contain a total of 49.6bn cu metres of gas, of which 14.2bn cu metres is in Angostura Phase III. The government has approved a 5-year extension of BHP Billiton’s contract to sell gas from Angostura to the state-owned NGC, which now runs to 2026.

New Strategies

Separately, BHP was involved in drilling in the Atlantic deepwater, having signed four production-sharing contracts (PSCs) with the government in 2013, covering the blocks known as TTDAA 5, 6, 28 and 29. The PSCs are reported to be for a period of nine years, with the option of a further extension to 30. Total investment commitments for the nine-year period are believed to be around $565m, with a further $459m to be committed if the licences are extended to 30 years.

BHP has also acquired a 70% share in two further deepwater blocks – TTDAA 14 and 23a – which were previously majority-controlled by BPTT. According to David Rainey, former president of exploration at BHP, the company considers its concentration of deepwater blocks in the twin-island nation to be a “tier-one” prospect.

Rainey said that BHP’s global strategy is to concentrate on a small number of basins considered to be “top-tier” prospects. They must have upwards of 5bn barrels of oil in place and be able to deliver at least 100,000 barrels of oil equivalent per day to the company. Another requirement is that BHP should be a “first mover” in the basin, positioning it to discover the largest reservoirs at an early stage in the basin’s commercial development. The company’s deepwater blocks in T&T looked as if they were within the tier-one criteria.

Two or possibly three wells would be drilled in 2016, with the first focusing on the LeClerc prospect, a large geological structure thought to contain significant hydrocarbon accumulations.

Onshore Work To Be Done

While the ongoing commitment to exploration from major oil players like BP and BHP has been encouraging for the government, it remains aware that more needs to be done, particularly onshore, where there is still significant crude oil in the ground, either in existing mature fields – where enhanced oil recovery (EOR) techniques could be used – or in new areas that are not yet fully explored.

Boosting crude oil production from these onshore blocks is complicated by the fact that there are a wide range of contractual arrangements in play. Many licences are held directly by cash-strapped Petrotrin or sub-leased and contracted out to independent operators.

In the last licensing round held in 2013 three companies – Touchstone of Canada, Range Resources of the UK and locally-based Lease Operators – won blocks on which they committed to drill a total of 12 exploratory wells. However, at current price levels, further licensing rounds are unlikely to be called in the short term, so the government is looking at ways it can encourage output from existing licence holders.

While EOR is holds a lot of promise, there are some question marks over its commercial viability. Using CO injection in southern Trinidad wells would require the construction of a costly CO pipeline from the Point Lisas oil complex. Nicole Olivierre, minister of energy, has suggested that unproductive licences might be reassigned – as she put it “whenever contractual arrangements permit, idle resources will be returned to the state and retendered for exploration and/or development”. However, the details of how this might work have not yet been revealed.

There have also been suggestions that heavy oils in southern Trinidad could be developed, while Petrotrin is assessing two new EOR projects.

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The Report: Trinidad & Tobago 2016

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