LATIN AMERICA: Trinidad & Tobago trying to match reserves search, market opportunities
Trinidad & Tobago's history of oil development has been, for the most part, eclipsed by the huge gas finds off the Islands' east coast. The Petroleum Company of Trinidad & Tobago (Petrotrin) sees a lot of potential long-term, from the east, but would like to see west coast oil fields producing more to ensure feedstock for the island's refineries. Oil companies operating in the market not only concern themselves with exploration and production, but also the downstream market.
Trinidad & Tobago production began in the 1920s with oil fields onshore. This sector now produces 20,000 b/d of the islands' 120,000 b/d overall production. The balance comes from oil fields off the west coast (30,000 b/d) and relatively new gas fields off the east coast (70,000 boe/d).
Land production began as far back as the turn of the century and peaked in the mid 1960s. These fields are considered mature, producing heavy crude in the range of 20-25° API. The onshore fields also produced a lot of associated gas in the early years, though this gas tapered off dramatically. The onshore fields now produce less than 20 MMcf/d. That is in contrast to the 1 bcf/d BP alone produces off the east coast.
BP's purchase of Amoco three years ago makes it the largest operator in Trinidad & Tobago. The company has 13 tcf in proven reserves with estimates of another 10 tcf in unproven gas. With such large finds, it is difficult for these small islands (population 1.3 million) to provide a market.
Much of the industrial complex that receives this gas is located on the island's west coast. The gas is used as feedstock for ammonia plants, converted to methanol, and for electric power generation. The island government is doing everything it can to maximize the domestic market. Even the taxicabs in the nation's capitol, Port of Spain, run on natural gas. The country recently increased its capacity to transport electrical power to provide more cheap energy for domestic consumption.
Still, the bulk of the gas produced will be converted to liquid via LNG and shipped to the US or Spain. One of three LNG trains has already been brought on line as part of the Atlantic LNG project. The first train had a capacity of 450 MMcf/d. With the addition of trains two and three, by 2003, that rate will jump to 1.5 bcf/d. There is also discussion of a fourth and possibly fifth train of LNG. Beyond this some operators are also looking at gas to liquids (GTL) technology. There are so many plans to develop more processing capacity, that one of the islands' chief concerns may not be what to do with the gas, but how to deal with too much infrastructure.
Clearly, there is a lot of gas coming on line, and plentiful reserves in the ground, but with four trains of LNG, it will be necessary to find massive replacement reserves far into the future. Petrofin acknowledged this is a chief concern of the Ministry of Energy and Energy Industries (MEEI), which recently launched an audit of the islands' reserves, and commissioned a subsequent master plan for gas.
Andrew Jupiter is Permanent Secretary of MEEI. He said the master plan would evaluate three distinct markets for gas, electricity generation for domestic markets, ammonia and methanol plants, and LNG. Currently the island nation is the top exporter of ammonia and methanol in the world, and will rank sixth in the export of LNG after trains two and three of the Atlantic LNG project are brought on line in 2003. He said the goal of the master plan is to examine realistic estimates of the islands' proven reserves. The audit of reserves and the master plan were conducted by separate, independent consulting companies under the supervision of the MEEI geologists.
Chanin Motilal, Director of Geology and Geophysics for the MEEI, said the audit was a key first step, since the definition of current reserves will inform the master plan. While the audit produced the information on reserves, Motilal said current exploration and production make this a moving target. New discoveries and new techniques applied to existing fields could increase these reserves. At the same time, increased downstream capacity is consuming reserves rapidly. This relationship is at the heart of the master plan.
The ministry wants to promote downstream activities, which fuel the economy, but must carefully weigh increased production with the operator's ability to replace reserves. There is a risk that too much downstream capacity could deplete the islands' gas reserves, leaving the various refineries and facilities without sufficient feedstock to operate.
The master plan is not going to define policy for the ministry, Jupiter said. Instead it will consider the various options available to the islands and present these to the government. With the second and third trains of LNG coming on line in less than two years, and a new ammonia plant already in the works, quite a bit of the gas production is spoken for. Using the audit information, a master plan will be developed that presents the Trinidad & Tobago government with a host of options including ammonia smelters, additional LNG, and the possibility of GTL technology.
The key goal Jupiter's office will pursue in evaluating the plan is the creation of wealth and increased employment on Trinidad. This would combine gas production policies with increased education for local workers. Jupiter said operators and service companies are involved in the development of engineering curriculums at the Trinidad & Tobago Institute of Technology. Operators are represented on the institute's board of directors and have contributed money to the development of the institute. Currently, Jupiter said 90% of workers in the islands' energy sector are Trinidadian. Although this figure is not disputed, some operators have complained that the islands produce mainly civil and mechanical engineers rather than petroleum engineers.
The government's insistence on local content can hamper the rapid mobilization of rigs into the market. While workers with experience in other markets, such as the Gulf of Mexico, can easily make the transition to activities offshore Trinidad, one operator said it is difficult to train a new crew made up of locals to safely operate a vessel within the time constraints of a drilling program.
Service Sector
Phil Scott is Oilfield Service Manager for Schlumberger in Trinidad & Tobago. He said he has not had any problem with either hiring or training locals for the service sector. Scott said his company has an international focus that is a good fit for working on the islands. Schlumberger's approach is to employ workers from across the globe and station them in different regions. The company has an advantage in Trinidad, Scott said, because Venezuela is so close. Venezuela is a large market, so there are a lot of skilled workers to draw on from that area. With the coming boom in activity offshore Trinidad, Scott said workers could be transferred from Venezuela to the islands. This ability to share resources extends beyond personnel to equipment. The Schlumberger facilities at San Fernando, Trinidad, hold very little idle equipment. The equipment that is at the facility is either being tested prior to being shipped out, or cleaned and disassembled after completing a job.
Jay Rampersad, General Field Engineer for Schlumberger, explained that the company has ready access to the people and equipment it needs so that it holds a just-in-time inventory. While the people working in the shop and back office are all native to Trinidad, including Rampersad, many of the engineers that will be needed in the coming boom will be mobilized from elsewhere.
Rampersad said he is expecting an increase in activity of 50%-60% based on rigs coming into the area. This increase is due to more activity by some clients, while others still have their projects on hold. The majority of the new work is on exploration wells, although there are a lot of producing wells already on line. Some of these older wells, mainly oil producers, will require recompletion in the near future to increase production. Currently, the bulk of the work is running logging suites on exploration wells. The discovery rate offshore Trinidad's east coast is impressive, according to Rampersad. "You hardly ever see a dry well," he said.
With respect to the oil fields off of Trinidad's west coast, Scott said this is an opportunity for Petrotrin to partner with Schlumberger and take advantage of the company's advanced technology. There has not been any discussion so far on this point, but the west coast fields could clearly benefit from a deal like the one Schlumberger has with PDVSA on Lake Maracaibo, Venezuela (see related story on p. 40, this issue). If the state oil company were willing to give the service company a lump-sum arrangement on these wells, it could take advantage of Schlumberger's advanced technology to increase production and avoid the expense and time of developing this technology in house.
Boom in works
The fourth quarter of 2001 should be very busy for operators and service companies working offshore Trinidad, according to Ian Stauble, Operations Manager for Schlumberger. British Gas is developing a prospect in an area where no one else has been drilling, Stauble said. The company is installing a platform on its field in the North Coast Marine Area (NCMA). Schlum- berger will drill 9-12 extended-reach wells from this platform.
In addition to this new production platform, BP is drilling an exploration well on Block 27. This well is one Arco committed to before the BP purchase, but BP will drill the well in late October or early November, Stauble said. Even further out, Conoco is drilling a deepwater well offshore Barbados, an island also handled by Schlumberger's Trinidad operation. In deepwater blocks offshore Trinidad's east coast, ExxonMobil has drilled two wells and plans to drill five more, although Stauble was not sure when these wells might be drilled. Shell has drilled one well in its deepwater block and plans to drill two more. BP plans to drill two deepwater wells in November. So far that adds up to three deepwater wells drilled offshore Trinidad with what have been called "disappointing results."
The deepwater contracts are set to expire in February 2002. It is not clear if the operators will apply for extensions or simply let the contracts run out. BP did receive a six-month extension on its deepwater contract. BP's Manikin Field is very close to the Trinidad border with Venezuela and is supposed to hold a substantial find. The reservoir itself may extend across the border under Venezuelan waters. The Trinidadian government says this boundary is very clear and was negotiated less than 10 years ago. Others have said it may not be as stable as Trinidad would hope. In any case, BG has reported a find along the boundary as well.
While there are a number of big finds coming onstream, there are questions about the best way to get future production to shore. There is currently production offshore from wells covering over 100 sq km. It is not practical to build a new pipeline for every project. If gas production could be carried to a centralized production facility, it could all be pro-cessed there before heading to shore. The Trinidad Natural Gas Co. (NGC) will look at this as part of the natural gas master plan. Because this would be a central facility tied back to shore it would be the government gas company's responsibility.
Pat Woods, Operations Manager for EOG Resources, said his company has to look even further downstream when considering development scenarios. The company holds a large interest in an SECC Block and a production-sharing contract in Block Modified Ua. The company is currently building production facilities for Block Modified Ua and gearing the start-up to coincide with the completion of a new ammonia plant under development. Woods said this downstream activity is driving the company to produce gas from this field. EOG has partnered with the Caribbean Nitrogen Co. (CNC) to build this facility, and will develop the offshore gas as feed stock. Woods said the initial contract with CNC calls for delivery of 60 MMcf/d for 15 years, and added that it is very likely that plant capacity will be increased to 120 MMcf/d by 2004. Woods said the Osprey Development in Block Modified Ua is capable of producing about 100 MMcf/d per well from a two to three well development. This will fulfill the company's 15-year contract to provide the plant with gas. To get the production ashore, Woods said EOG will construct two pipelines. A 16-in. line will carry the gas 10 miles from the Osprey platform to a 24-in. NGC trunk line. Condensate from the Osprey field, estimated to be 25 barrels per MMcf/d, will be transported to Trintomar's Pelican platform via an 18-mile, 6-in. pipeline the company will also install.
The NGC is in charge of getting production ashore once it reaches one of its offshore hubs. Gas that is destined for the new LNG facilities is an exception to this rule. Still, Woods said there will need to be quite a bit more pipeline capacity in the future to accommodate all the increased production. Woods said the Osprey Field is very strong and will not require primary compression for at least eight years, so the real challenge is pipeline capacity and the downstream market.
"That's what really drove the development in Block Ua," Woods said. In Trinidad, he explained, it is not enough to have an E&P strategy. Companies operating fields in Trinidad must also consider the markets for gas.
BG plans to install a new platform on its prospect in the North Coast Marine Area (NCMA) this month, according to BGTT's Drilling Department. Once the platform is in place and a rig is installed, nine wells will be drilled from this platform, of which four will be extended-reach wells. Gas from this prospect will supply feedstock for the second LNG train, which is due to come on line in 2003. The nine wells will constitute Phase One of this development and will be drilled between now and 2004. Before this field even comes on line, BG is exploring for new finds in different areas offshore Trinidad's north and southeast coasts. BG has the NCMA Field on a fast-track schedule designed to deliver production just in time to feed the second LNG train. This is a field that was discovered back in the 1980s, but is just now being produced because of the increased demand for gas. While BG is confident there are still discoveries to be made in conventional water depths, deepwater is where the larger finds will be made. One of the key technological advances, according to BG, that allows for the identification of these gas fields is bottom-cable seismic. This allows geologists to better image the younger formations, closer to the surface. This is where much of the gas reserves are located.
The new field to the north will be tied back to shore via a 120 meter, 24-in. pipeline installed by the operator. This will run all the way from the platform to the Atlantic LNG facility at Pointe-a-Pierre. Because it is the first find in this area, BG has to lay a new line all the way to shore. BG said the size of the 24-in. line gives the company some spare capacity for additional production to be added in the future.
While it is relatively easy to make a find off Trinidad, drilling is another matter. There are some very strong currents off of the north end of Trinidad, which are not tidal currents. These move at a number of water depths making it tricky to maintain station. In addition, there are eddy currents to the southeast of the island coming from offshore Brazil.
Preparing for the boom
Scott, with Schlumberger, said this is a propitious time for the Trinidad market to pick up, since work in Venezuela is expected to drop off about 8% in the next quarter. Skilled workers from Venezuela could temporarily be used during periods of peak activity in Trinidad. Many of the Trinidad wells will need sand control completion work. Scott said Schlumberger performs a lot of open hole gravel pacs offshore Trinidad. The company is planning on installing pump-down fiber optic systems to receive distributive temperature readings on offshore wells. The system is designed so the fibers can be pumped downhole outside the sand screens then back to surface. This system will replace the quartz permanent downhole gauges typically installed on such wells.
In addition to such completions, Schlum-berger will apply a system known as MudSolve to stimulate formation of the BG wells in the NCMA. This fluid allows the well to be cleaned out without the use of coiled tubing. The tools for the system are still in development and Scott points out this is an example of how technology is used to ensure that the prolific wells produce as well as expected.
New bidding round
The Trinidad & Tobago government hopes to spark more interest in the new bidding round, closing this month, than it did in the last. Actually, the concern was not the number of bids received in the last round, but the quality, Motilal said. All of the bids received were rejected for one reason or another.
Still, the ministry is not discouraged. Motilal said the government does not advise the operators on how to make their bids more attractive. It is up to the operators to perform the evaluation of the prospects up for bids and make the government an offer. Motilal said, rather than restraining the possibilities of creative offers from operators, the ministry allows them to bid first and only then addresses the details of the offer.
"What we look for is a proposal in sync with their concept. A comprehensive bid," he said. While the Gas Development Master Plan may look at the administration of such bidding rounds, Motilal said, it would focus on the use of resources rather than administrative issues.
