Vol. 58 No. 2

February 2006

José Formigli, E&P Production Engineering Executive Manager, Petrobras

Brazil’s goal has been to reach energy self-sufficiency early this year. Is that goal still attainable?

Our target is to reach self-sufficiency, on a sustainable basis, during 2006, when Petrobras’ domestic oil production will reach an average of about 1.9 million BOPD.

What are Petrobras’ growth targets for offshore and onshore oil and gas production?

In the recent revision of our Strategic Plan, we forecast production growth of 8.1% per year, from 1.76 million BOEPD in 2004 to 2.81 million BOEPD in 2010 (Fig. 1). This growth will come mainly from deepwater fields in the Campos and Espírito Santos basins.

Fig. 1—By percentage, Petrobras’ 2005 peak production (left) and Petrobras’ 2004 proven reserves.

The onshore oil production comes from mature basins, relying on an important existing infrastructure. Onshore findings can come on stream at a fast pace, requiring low capital expenditure, which compensates for the decline of the mature fields. The corporate program named Revitalization of Fields with High Degree of Exploitation is focused on the identification of economically feasible opportunities for increasing the production of oil and gas and/or increasing the ultimate recovery. The focus is not only on onshore brownfields, but also on offshore fields beyond the production peak. As a result of these efforts, we expect that the 2010 onshore production of oil and gas will be kept at the same level of 293,000 BOEPD attained in 2004.

What new offshore production has recently come on line or will start up in the near future?

Many offshore production systems started up at the end of 2005 or are scheduled to start up throughout 2006:

• Peroa-Cangoa gas field, in the Espírito Santos basin, is beginning production of 2.5 million m3/D through a shallow-water fixed platform.

• Floating production, storage, and offloading vessel (FPSO) P-50, located at the Albacora Leste field, started up in November 2005, with a production capacity of 180,000 BOPD.

• FPSO P-34, located at the Jubarte field, is expected to start production of 60,000 BOPD during the first quarter of 2006.

• The Manati offshore gas field in Bahia has a capacity of 6 million m3/d through a fixed platform and will start production in the second quarter of 2006.

• Golfinho I, in the Espírito Santos basin, will produce 40°API oil and has production capacity of 100,000 BOPD. It is scheduled to come on stream in mid-2006.

• The deepwater Piranema field in the Sergipe-Alagoas basin is scheduled to produce 20,000 BOPD of light oil using the pioneer concept of a cylindrical floater production and storage system. It will start operation in the second semester of 2006.
  

What is the status of Petrobras’ U.S. Gulf of Mexico (GOM) E&P program?

Petrobras has participation in four ultradeepwater discoveries—Cascade, Chinook, St. Malo, and Coulomb—in association with several major companies. The last one has been in production since 2004, while the other three have been submitted to an extensive appraisal review that will include an extended production test in 2006. In addition to this ultradeep front, the company has elected three other focus areas in the GOM where strong investment will be applied:

• The deep gas Continental Shelf, where ultradeep gas reservoirs are being investigated in shallow waters.

• The west GOM that has been largely unexplored.

• The Garden Banks area, where the company has participation in the Cottonwood discovery and is currently drilling its first operated deepwater well in U.S. waters. In the recent Lease Sale 196, Petrobras was the highest bidder in 53 of its 57 bids, spread over the four above-mentioned fronts, consolidating its position as one of the major players in the GOM.

How much is Petrobras spending on research and development (R&D) and on E&P?

The total Petrobras R&D budget for 2005 amounted to U.S. $275 million, of which U.S. $107 million was invested in the upstream. In 2006, these values are being increased to U.S. $319 million and U.S. $110 million, respectively.

We spent a total of U.S. $5.2 billion on domestic E&P activities last year. During 2006–2010, we are scheduled to spend a yearly average of U.S. $5.6 billion for E&P in Brazil.

What percentage of Brazil’s total oil production comes from deep water and what from ultradeep water?

Within the deepwater range of 300 to 1500 m, oil production accounts for 62% of the total. Beyond 1500 m, our ultradeep water accounts for 5% of our production, with great potential for increase.

What are Petrobras’ biggest offshore E&P challenges?

Concerning technical aspects, we highlight the right match of solutions for the “hard and soft mechanics” issues needed for attaining proper flow rates of oil, gas, and/or water. Flow from subsea wellheads to the host processing facility is one of the most demanding technical challenges:

• Static as well as dynamic portions of the rigid or flexible lines must be designed to withstand the internal and external stresses generated by pressure and temperature.

• Production and export risers for ultradeep waters have to withstand their own weights under dynamic loads as a result of floating-unit movement and sea current.

• Riser thermal properties must be adequate to prevent heat losses from the flow stream to the environment, thus preventing wax and hydrate formation.

• Riser and flowline installation-vessel capability is also a major issue, especially for large-diameter pipes in ultradeep water.

To overcome these challenges, we are working on several technology developments, including self-sustained hybrid risers, midwater buoys, riser towers, towed pipe-in-pipe risers, and flowlines.

Another key technical challenge is related to accurate reservoir characterization. It impacts many produced- and injected-water management issues such as sweep efficiency, scale preventive/corrective actions, and biogenic souring, among others, with a direct impact on operational costs. Consequently, recovery efficiency is directly linked to the overall economics of field development.

A large nontechnical challenge for a company leader in deepwater activity such as Petrobras relates to the proper strategy implementation for supplying all critical services, equipment, and logistic support needed for E&P development under the current market shortages caused by high oil prices.

What new technologies have made the biggest difference in increasing offshore production?

Offshore well construction has evolved significantly in the past few years. The outcome of large-bore long horizontal wells has helped our industry exploit deepwater reservoirs with fewer production and injection wells. Nowadays, it is fairly common for 1000-m horizontal wells to inject 30,000 BWPD or produce 20,000 BOPD in Campos basin. That would have been unthinkable 15 years ago, especially if you consider that most wells require sand-control schemes for production from unconsolidated sands.

Another front-end technology is the deepwater taut-leg mooring system using synthetic ropes and different anchor devices, from suction piles, passing through vertical-loaded anchors up to, nowadays, torpedo piles (Fig. 2). Besides the lower floating-capacity requirement for the drilling rig or the production platform because of the lighter mooring lines, the reduced footprint of the mooring radius reduces the distance from the wellhead to the host facility. Together with extended-reach wells, this significantly benefits both artificial-lift and flow-assurance issues in deep water.

Fig. 2—Deepwater taut-leg mooring system.

What are the major subsea challenges and issues across the different offshore basins of the world?

The challenges vary widely. In the GOM, for example, the market provides fast response to many demands related to technology, engineering, construction, and equipment supply. Nevertheless, the harsh GOM ultradeepwater environment or, as in some recent discoveries, rather deep reservoirs with high pressure and high temperature still pose significant technical challenges. On the other hand, there are places such as west Africa where the environmental and technical challenges are not as demanding, but the local market is not yet fully developed. In this case, commonly used technologies sometimes become economically prohibitive. Then, one must account for limited intervention and repair capabilities when designing the production systems. To a lesser extent, the same applies to the Brazilian case. We have tried to use heated pipe-in-pipe flowlines and bundles in Brazil, but because of the lack of installing capacity, they end up being too expensive to apply when mob/demob fees are considered. We are still struggling to get a start in this direction.

It is worthwhile mentioning that all operators, no matter where their deepwater operations take place, look for a kind of “holy grail”—reliable technologies that may reduce the size of and/or even entirely dismiss the host production facility, while taking to the seafloor some of the processing-plant components that traditionally have operated at the surface.

Are there best-practice approaches to subsea developments that can be applied to other deepwater producing areas of the world?

Flow assurance is an issue with worldwide application in deep water. Seabottom temperature is fairly uniform all over the globe beyond 1000 m water depth. Therefore, hydrate and wax deposition is a common issue to be considered. Solutions that we use can certainly be applied elsewhere. However, because of cultural differences and different experiences, the adopted engineering solutions can be significantly different, requiring additional time to reach common ground. For example, the Petrobras approach in hydrate control started completely differently from those of other deepwater operators. Petrobras project designs take into account some wax and hydrate occurrences, treated by remedial methods as needed. Other operators avoid such occurrences by overprotecting the system with a much higher capital expenditure. Nowadays, there is a convergence to a middle ground on this. That is, Petrobras is reducing its exposure to such risks, while a few operators are taking more chances. Nevertheless, many other best practices spread out rather quickly, such as the already mentioned synthetic ropes for spread mooring.

What are Brazil’s most recent technical milestones and recent advances in ultradeep water?

Our latest innovations successfully implemented were the torpedo piles and torpedo subsea well base, both patented by Petrobras (Fig. 3). Torpedo piles are anchors that are shaped like a torpedo and that are dropped from a certain height to the seafloor. The resulting kinetic energy is sufficient to drive the pile 20 to 30 m down into the ground, providing the required vertical-load resistance. Similar technology, with small modifications, is now used to install the subsea well base. It is sunk by its own weight and then hammered down to its final position in a rather simple way. It has been successfully deployed in the Albacora Leste field. We are confident that we can cut drilling time by a day or two, per well, just by using this technology. At the current rig daily rates, this amounts to a significant benefit from this technology.

Fig. 3—Torpedo pile anchor.

What are some recent lessons learned from ultradeep water projects?

A properly established project-management process is paramount. Any new ultradeepwater project is capital-intensive and, most of the time, quite fast tracking to seek the highest net present value. Therefore, we must have a solid mechanism in place to perform a thorough study of the subsurface information to minimize risk and yet perform accelerated engineering design for well, subsea, and topsides/floater construction. All these require state-of-the-art technologies to keep the economics sound. We should have technical quality assurance at all gates through which a project must pass. After the project sanction, we require multi-disciplinary integration and a very effective contracting strategy. Any delay or lack of communication can cause disastrous impacts on a project. An approach to getting the most benefit from previous projects, as a result of lessons learned, is to standardize whenever possible, without hindering the appropriate technological development implementation.

What innovations are going forward under the Procap-3000 deepwater technology program?

During 2005 and early 2006, we are installing three prototypes of different boosting systems under our Procap-3000 deepwater technology program and heavy-oil production program. The first is a high-power subsea electrical submersible pump (ESP), a 1,200-HP system at the Jubarte 6 well, in approximately 1300 m water depth. It will use a state-of-the-art pump motor system, capable of handling heavy oil, high gas fractions (up to 40%), and providing longer run life (expected 4 years). To lower future intervention costs, we have developed a subsea horizontal tree for 2500 m water depth, with a remotely-operated-vehicle-retrievable cap, and high-power electrical power connectors. In addition, we are using an integrated umbilical (power and hydraulic control plus instrumentation) to run the ESP and control the tree functions. The second prototype is a subsea ESP to be used downstream of the tree at Jubarte 2 well. The pump will be installed in a light vessel-retrievable pump module that will be run into subsea base, with an auxiliary hole. This base is equipped with a bypass valve that opens in case of a pump failure, allowing the well to be produced through a backup gas lift system. The third and final prototype will be the subsea multiphase pump system, SBMS-500, to be installed at the Marlim 10 well, that will be the first deepwater twin-screw-type pump for subsea operation in the world.

A promising technology in which Petrobras will be heavily investing is the subsea processing and pumping system. Studies are well advanced to evaluate the technical feasibility of such a system to be installed at the Marlim Field. The idea is to separate a large portion of the produced-water stream and reinject it in a subsea well to free some topside plant capacity at the host platform, thus bringing other wells on stream. Another interesting technology we are investigating is the subsea raw water injection system. It went through the conceptual design phase last year, with the Albacora field as a potential candidate for the prototype.