Oil production offshore Trinidad has for many years been dominated by Amoco, working off the eastern coastline, and by Petrotrin and Texaco, through their Trinmar joint venture, off the west coast. However, a third party is now entering the frame, with an ambitious program of offshore field rehabilitation.
Trinidad has a long history of exploration and production stretching back to the last century. Onshore oil discoveries made there between 1910 and 1940 played an important role during WWII. Trinidad, by then a significant refining center, became a major supplier of aviation fuel for the war effort. During the Suez crisis, the strategic importance of Trinidad was again emphasized - with throughput at one point touching 500,000 b/d at the island's refineries at Point Fortin and Pointe Pierre.
Offshore oil production was initiated by Texaco in the late 1950s, and was centered on the west coast Soldado group of fields in the 1960-1970 period. Meanwhile, Amoco had established a pre-eminent position off the east coast. It was here that Amoco made the giant gas discoveries of the 1980s and 1990s, leading to the huge investment in natural gas and LNG infrastructure for which the Trinidad energy sector is best known today.
Change of operators
The 1980's saw a restructuring of Trinidad's upstream sector, with the withdrawal of several international players, and the emergence of Petrotrin as the principal nationally-owned exploration and production company. During the downturn of the late 1980's, Petrotrin struggled to maintain investment in its aging fields and looked to the private sector to provide new investment through a program of farmouts, leased operatorships, and acreage tenders.
UK independent Lasmo was one of the companies which evaluated Trinidad at the time. Bruce Dingwall, a Lasmo geoscientist involved in the evaluation and with personal roots in the island, continued to monitor the situation through to 1997, when he left Lasmo and with three colleagues formed a new independent oil company in Aberdeen called Venture Production.
Venture's focus from inception was to target "stranded" reserves in mature or marginal fields in which reworked and enhanced subsurface models could be harnessed to new drilling and completion technologies such as the SCRAMs smart completion systems developed by fellow Director Larry Kinch's company PES.
In 1998, Venture acquired from Petrotrin its first leases onshore southwest Trinidad. These included the WD-13 and WD-14 blocks in the Forest Reserve field and the Tabaquite block in central Trinidad, which contains a number of small producing fields. A successful program of workovers has since been undertaken in the two blocks, while a series of horizontal wells is about to get underway in Tabaquite.
Offshore Trinidad, Venture is poised to conclude two joint-venture agreements with Petrotrin which will confer on them operatorships for the 15,000-acre Brighton Marine/ Guapo Bay and 4000-acre Point Ligoure field rehabilitation projects.
The offshore Brighton Marine Field was discovered in 1952 via a well drilled from the shore. It was brought onstream in 1958 via a 36-slot production platform - at the time, the world's biggest. Recent re-interpretation of field data suggests in-place oil well in excess of 500 million bbl, but only 56 million bbl have been produced to date.
New seismic
The Brighton Marine Field lies only 2-3 km offshore in waters 5-30 meters deep. Originally developed by Texaco during the 1960s, seismic was never acquired over the field. However, a 192-sq-km 3D survey was performed over Brighton by Western Geophysical in 1997, and subsequently processed in Caracas.
According to Dingwall, small-scale secondary recovery attempts were conducted in the late 1960s and early ྂs, "but in hindsight, and with the benefit of of the 3D data, they were conducted over a particularly compartmentalized part of the field, so they were doomed from the start."
Venture plans to focus the new studies on areas with better prospects for sustainable secondary recovery. Venture has a 55% controlling interest in the production license, and will have a 65% interest in any exploration work carried out in the block. In both cases, Petrotrin holds the balance.
The reservoir at Brighton is of early Miocene age in turbidite sands of the Nariva Formation - the same producing interval as the onshore Tabaquite block. The main producing structure is a thrust anticline with later extension. Average net pay thickness is 180 ft, while average reservoir porosity and permeability are respectively 26% and 300 mD.
Between 1958 and 1971, nine platforms were installed in the field, with development drilling continuing through to 1973 (although the bulk was completed by the late 1960s). In total, 274 wells were drilled, including 128 drilled directly from the shore - all of these since abandoned. That leaves 130 platform-drilled wells and 16 free-standing wells. Sixty-nine platform-based wells are still active, although they are produced intermittently, and generate just 400 b/d cumulatively.
Producing depths vary from 1,800 ft to 8,500 ft, with the principal zone at around 3,000 ft. Oil quality is good, averaging 34°API, with a gas-oil-ratio of around 530 cf/bbl. Production is achieved via solution gas drive, and all the producing wells are gas lifted.
All the wellhead platforms except No.5 (damaged by fire) are still serviceable and support producing wells. According to Venture's Reservoir Manager Graham Howes, all 130 platform wells are potential candidates for workovers over the next few years. The planned program includes simple coiled tubing clean-outs, a re-vamp of the gas lift system, recompletions, and sidetracks.
"We are currently reprocessing the 3D seismic data specifically to generate improved fault resolution," he adds. "Effectively, we're planning to rebuild the subsurface model. From what emerges, we hope to identify locations for 12 infill wells, which will be targeting under-depleted fault blocks. We intend to target stepout locations as well."
Under-explored Cretaceous
Venture is committed to drilling four exploration wells over the first two years of the license, and at least one of these will involve a deep test of the underlying Cretaceous play, which Venture believes to be highly under-explored. Full integration of the newly interpreted subsurface data with the existing production history will take 12-18 months, with the ultimate aim of identifying potential areas in the field for a pilot secondary recovery scheme. "The reservoir has lost much of its energy," Howes says, "if it responds well to re-pressuring, eventual production rates of 10,000-15,000 b/d should be feasible. First, however, we need to understand exactly how these wells have performed over the years, and to focus on optimizing recovery in existing producers."
Venture intends to retain only a small technical capability in-house, concentrating on higher-level planning and problem-solving. Other elements of the project will be outsourced to integrated technical service providers. In Trinidad, Venture's general manager, operations manager and subsurface exploitation manager are all Trinidadians. "All of our staff get share options from day one," Dingwall points out. "As far as I'm aware, we're the only oil company in Trinidad doing this."
For the drilling program, Venture has been evaluating a variety of low cost systems. "It's a very benign area," Dingwall says, "with a tidal reach of just 1 meter. It's also south of the Caribbean hurricane belt." Offshore operations are also conveniently close to a marine base serving the Trinmar fields.
Point Ligoure
The same in-house team is managing the evaluation of the Point Ligoure block, which Venture operates with a 25% interest. Venture's partners on this block are Petrotrin (50%), and local Trinidadian partners KPA (17.5%) and Ligoven (7.5%).
Although the block lies just over 3 miles west of Brighton Marine, the geology is completely different. The main reservoirs lie within the younger Forest, Cruse, and Manzanilla Formations, within a deltaic depositional system. It is characterized by wrench faulting and synsedimentary structuring, with an average net pay thickness of 170 ft, and an average porosity of 26%.
Oil was first discovered in the block as long ago as 1938, with development drilling getting under way in 1953. Between then and 1988, 42 wells were drilled, nearly half being extensions drilled from known accumulations outside the block, such as the Point Fortin Field to the southeast, within the Forest onshore complex. Only one of these wells, ALS-14 is currently still in production, at around 200 b/d; the rest remain idle.
Over the years, a number of under-exploited discoveries have been made in Point Ligoure, but development has been piecemeal, through extended reach drilling from the shoreline and a single wellhead platform which was installed in the northern part of the block.
The potential of these and other appraisal prospects within stepout distance will be assessed following reprocessing of existing seismic data. The main information available is a 3D survey shot by Western Geophysical for Petrotrin in 1992 over a 16 sq km area in Point Ligoure, with a bin size of 25 meters by 12.5 meters. This forms part of a larger 500 sq km survey across the Trinmar fields.
To date, 5 million bbl have been extracted from an estimated in place reserve base of nearly 200 million bbl. Venture believes a further 20 million bbl could be recovered, a figure that should rise following further appraisal drilling. Redevelopment options are still being evaluated. Extended reach drilling from the shoreline is still an attractive option for the prospects in the southern third of the block, while small, minimal facilities wellhead platforms can be built quickly and cost effectively by local fabricators with a proven track record for Trinmar in the Soldado fields.
The planned program in Point Ligoure includes rehabilitation of 12 idle production wells, plus drilling of new development wells in the ALS-14 area, east of the East Soldado Field. Further scope for development drilling will depend on the results of subsurface studies and future appraisal drilling.
According to Howes, "Sand production is known to be a problem in Point Ligoure. In a low-cost operating environment such as nearshore west coast Trinidad, the best approach may be cost-effective sand management, rather than resorting to higher cost sand control technology. Thus conducting frequent coiled tubing clean-out operations may prove a better approach to sand control than pre-pack, gravel pack or expandable sand screens."
