Petrobras leads subsea pumping development to overcome deepwater production problems
Subsea boosting has evolved since the first subsea multiphase pump was installed, in 1994, by Shell at Draugen field in the Norwegian Sea. That pump was installed in 270m (885ft) water depth and sent production 6km (3.7mi.) from Rogn South field to the gravity-based platform at Block 6407/9, Figure 1. Adding the pump increased output by 5000b/d and proved the concept of developing satellite fields with extended tiebacks with a pump on the seabed.
That one-pump/one-spare system was modest compared with today’s installations. It was rated at 1MW and could handle differential pressures up to 53bar (768psi). By comparison, Total’s Pazflor field that was installed in 2011, in 800m of water, has six pumps with two spares, is rated at 13.8 MW and can handle differential pressures up to 105bar.
Subsea pumps have seen continual and incremental development as the industry has stepped into deeper water and discovered reservoirs with increasingly challenging production characteristics. Recently, Petrobras has moved to the forefront with its R&D efforts to overcome production challenges in deepwater developments off Brazil. Many of the company’s fields produce heavy oil with gravities less than 20°API, with high flow rates, and with high gas- and watercuts. Petrobras is finding more fields, but in deeper water with attendant production problems.
These developments have led Petrobras to seek technologies through its PROCAP Technology-Future Vision program that can extend the operational envelope of subsea boosting and develop equipment for subsea processing. Among the projects are gas compression systems, compact oilwater separation, compact gas-liquid separation, and high differential pressure multiphase pumps. The pumping projects are bearing fruit and Petrobras shared a few of their developments in a subsea session at the recent Offshore Technology Conference in Houston.
Mudline ESP
One of Petrobras’ goals is to reduce capital and operational expenditures (capex, opex) in its deepwater operations. For fields that have low gas-oil ratios (GOR), the company normally installs gas-lift equipment in addition to electric submersible pumps (ESP) within wells to minimize production downtime if a pump fails. At Jubarte and Golfinho fields in the Campos basin off Espirito Santo state, booster pumps were installed in dummy wells in the seabed. By moving the ESPs out of the producing well and onto the seabed, an intervention rig can install and service equipment. The operation is simpler, easier, and less expensive than using a semisubmersible rig.
The company has taken the next step by creating a seabed pump skid, using off-the-shelf components. The seabed unit has two modules: a pump module containing a pair of ESPs, set in series at a 5° angle to the seabed, and a flowbase module that fits underneath the pump module to support the ESPs and their flowline connections. The pumps use 600hp electric motors and each has 24 stages.
In December 2011, the prototype system was used in the Campos basin at Espadarte field, in water 1300m deep, to produce 24°API crude oil. The system sent crude to the FPSO Rio das Ostras, about 11km from the wellhead at 2,000cu m/d (12,580b/d) with no water and a 60:1 GOR, using 100bar pressure differential at the pumphead.
The test was successful, increasing the flow rate by 600cu m/d compared to natural flow from the wells. Petrobras intends to apply the mudline ESP concept next in the Gulf of Mexico at its Chinook and Cascade fields. These fields have high pressures (12,500psi) and temperatures (236°F, 113°C), and produce 20-27°API crude oil.
Raw water injection
Petrobras has developed what it calls the subsea raw water injection (SWRI) system - a way to use subsea pumping, coupled with in-water filtration of raw seawater, to maintain reservoir pressure. Maturing fields with declining pressures often require water injection to maintain production, but this can be problematic for deepwater fields that are developed early in the opening of a new basin.
Many early fields are developed without adequate plans for reservoir support because future water-injection needs are estimates. This means that the topside facilities (ship-shaped FPSO or semisubmersible FPS) do not have space or weight capacity to add more water treatment, processing, and injection equipment to prepare and send water into the reservoir. So, a retrofit solution is required to maintain reservoir pressure and stabilize crude oil production.
Petrobras’ Albacora field in the Campos basin had this problem. As a mature, giant field in water depths of 250-1100m, it has seen much development. The original FPSO, P. P. Morales, was installed in 1987, followed by FPS semisubmersible P-24 in 1993 in a second development phase. In 1996, the P-24 was replaced by two units: the FPS semi P-25 was installed first, followed two years later by the FPSO P-31 in 1998. Field production peaked in 1999, and the reservoir required more pressure support than the existing water injection system could deliver.
The company created a research project to solve the problem, facing the issues of water properties, reservoir compatibility, equipment reliability, power delivery, corrosion, and biologic control. In addition, new infill drilling was planned for the field, which would increase the need for water injection at higher flow rates. SWRI was the most economic solution, rather than adding conventional topside capacity, replacing the existing FPS, or adding a new FPS.
The SWRI system includes a buoy to support water intake at about 100m above the seabed, where water quality is best; a skid with variable-speed controllers, filtration, and pumps that sits on the seabed; and related power cable, flowlines, jumpers, etc. The subsea system is connected to the P-25 topside facility for delivery of biocide and related chemicals.
The system began operating October 2012. Water injection will ramp up as needed to a maximum 16,500cu m/d into seven injection wells.
Helico-axial multiphase pump
Petrobras has had difficulty finding helico-axial multiphase pumps (HMPP) to meet its need for high differential pressure to move viscous crudes. The gas-lift systems it uses can handle pressures around 45 bar (652psi), which is similar to the limit on many HMPPs. However, the company has fields that require stronger equipment. The company initiated a research program in cooperation with FRAMO, FRAMO, a Schlumberger company, to produce an HMPP that can withstand differential pressures up to 60bar.
HMPPs use a series of rotating impellers, separated by diffusers, which together increase flow pressure to move produced fluids. The design overcomes gas-locking by keeping gas and liquids mixed as they move through the pump, Figure 2. A new high-boost HMPP was designed by modifying the impeller and diffuser geometries, as well as the pump speed and flow rate, taking into account the field’s gas fraction and 20cP crude oil viscosity. The final HMPP had 13 stages for a 14cP fluid with an intake of 177cu m/hr, and could operate at a maximum differential pressure of 70bar.
Barracuda field was chosen to test the prototype pump. The Campos basin project tied-back Barracuda to Caratinga field, whose FPSO P-48 had sufficient capacity to handle the flow from Barracuda. The fields are in water 600-1300m deep and are about 10km (6.2mi.) apart. The HMPP is positioned on the seabed in water 1040m deep, 330m from the producing well.
The HMPP was installed and began operations 14 July 2012. The initial fluid flow was 3000cu m/d with a pressure differential of 60bar and a gas volume fraction of 45%. The pump worked as expected and raised production by 1000cu m/d (6290b/d), a 40% increase compared to natural flow from the well. Reliability has been 100%, despite 11 shutdowns during commissioning and personnel training, with no need for hydrate treatments.
The extension of HMPPs operational envelope opens many new applications for this technology. Petrobras continues to press forward to solve its deepwater operational problems and thereby help the industry extend its production capability into ever deeper water, deeper reservoirs, and more challenging production scenarios.
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