Offshore/subsea systems

Subsea Production Optimization in Field BC-10 Offshore Brazil

The BC-10 asset, located in deep water offshore Brazil, produces heavy oil in the range of 16 to 24 °API. In this article, two examples of production optimization for this field will be provided (further examples are available in the complete paper).

jpt-2016-05-fig1subseaprod1.jpg
Fig. 1—Schematic of the entire caisson and ALM (top left); the support structure, 42-in. conductors, and the manifold on top (top right); ALM populated with four MOBOs (bottom right); closeup of the TEA, showing it attached to the 32-in.-inner-diameter caisson; this forms the MOBO (bottom left).

The BC-10 asset, located in deep water offshore Brazil, produces heavy oil in the range of 16 to 24 °API. Mudline caisson separators with electrical submersible pumps (ESPs) are used to process fluids from multiple wells and boost them to the receiving floating production, storage, and offloading (FPSO) vessel. There are significant flow-assurance challenges in operating the asset. In this paper, two examples of production optimization for this field will be provided (further examples are available in the complete paper).

BC-10

BC-10’s production comes from four fields located in water depths ranging from 1650 to 1920 m and is dependent on artificial lift. This summary focuses on optimizations involving the Ostra field. The subsea architecture that enabled the development of these separate reservoirs consists of multiple drill centers coupled to production manifolds. Manifolds are routed to caisson ESPs. These caisson ESPs will henceforth be referred to as MOBOs (derived from the Portuguese acronym for pump-boosting module). To minimize equipment costs, each field has only two production flowlines routed to the host: one is for production, and the second is for hot-oil displacement and production. In the case of Ostra, a third riser for gas separated subsea is also present. This design reduces the number of risers required. In line with this philosophy, there are only three oil-production trains and one gas separator on the host.

Ostra Field

Ostra consists of seven producer wells, with production collected by two manifolds and routed through two 8-in. intrafield flowlines to the artificial-lift manifold (ALM), which houses four caisson separator MOBOs. The operating philosophy is to run three units out of four, leaving the fourth unit as a standby in case of MOBO failure.

Because the ALM is not located with permanent vertical access, MOBO interventions require the use of a rig capable of pulling the 140-t unit to surface. For this reason, having an installed spare is critical. The production manifolds allow one of two routings per well, which allows a flowline to be aligned to one, two, or more MOBOs; full bypass of the MOBO; and routing of hot oil for MOBO startup and planned shutdown from the surface by a dedicated choke. It is also possible to allow the 4.5-in. hot-oil supply line to be used for production. The 8-in. gas line features a common choke on the ALM to control backpressure on the MOBOs and a surface choke at the FPSO vessel as a second means of control. In practice, to avoid a well trip causing a rapid loss of MOBO pressures (with corresponding well-rate increases), the subsea-gas-line choke is used only in special circumstances, with daily control being performed by use of the topside boarding choke, which allows a much larger gas-storage volume and hence limits rapid pressure transients. The Ostra field has seen good pressure support through the first 5 years of operation because of a strong supporting aquifer, and it currently produces 60,000 to 70,000 B/D gross. Gas disposal was performed through an injection well deeper in the Ostra aquifer while gas export was commissioned.

Subsea-Processing System

The MOBO system is composed of several major components. The top-end assembly (TEA) is the structure on the top of the caisson and contains the inlet- and outlet-isolation valves and actuators, the subsea control module, and injection points for methanol and one other chemical. The electrical and hydraulic connections are also made to the TEA.

The caisson itself is a 32-in.-inner-­diameter, 80- to 100-m-long section of pipe with a reduced diameter at the base to act as an accelerator for the fluid flow, to prevent solids buildup.

Inside the caisson, suspended on 5.5‑in. pipe, is the ESP hanger and 13⅜‑in. ESP shroud. The function of these components is to force fluid down the caisson to the base, cooling the motor as it passes. The caisson may be operated in one of two modes: separated and nonseparated. In separated mode, the caisson flow rate is controlled indirectly by a level controller, which aims to maintain a constant level inside the caisson by use of the level derived from the pressure gauges. With the nonseparated caisson, level is no longer controlled and instead “floats” depending on the temporary balance of inflow and outflow. The pressure in the caisson, however, must be controlled, because this determines what the wells will produce.

The TEA is connected to the ALM with a multibore hub that features bores for inlet, gas outlet, and oil outlet. For caisson control, there are three pressure gauges situated along the length of the caisson. These allow a liquid density in the caisson base to be measured and, in combination with the top gauge, allow a level to be calculated on the basis of this determined density.

The entire MOBO is retrievable and is supported on the manifold, which, in turn, is supported on the conductors; these also serve to provide a slot inside which the caisson can sit (Fig. 1 above).

Optimization 1: Embracing Foaming Operation

Early on in the life of Ostra—the only location of separated MOBOs in BC-10—the criticality of subsea defoamer injection was identified. Without it, the liquid in the caisson became very frothy and started to carry over and also limit the pump because of reduced boost capacity. However, at some point, the nature of the foam changed from liquid in gas (early life) to a gas in liquid. The change was observed during an event in which the defoamer injection was unable to suppress the formation of foam in the lower caisson during transient operations. At this point, it was noted that the defoamer was not effective, so it was taken off line to see whether this was causing the foaming. Once the transient passed through the system, it was noted that the gas at the top of the caisson was still dry (no free liquids) and that the density of the liquid in the caisson was lower than before, suggesting it was holding more gas.

On the basis of these observations, it was decided to try not injecting defoamer on the other caissons to see if they could operate without liquid carry­over and with higher gas volume fraction (GVF). In all cases, the caissons managed to maintain gas dryness, but there was a decrease in pump performance (head) with the increased GVF.

In the field, the additional gas entering the main oil line through the MOBOs caused a dramatic reduction in flowline backpressure because of the “gas lifting effect”—approximately 15 bar, which, given that the MOBOs’ boost in the field was approximately 120–140 bar, represented a 10–12% reduction in boost and, hence, load.

The increase in capacity over the three units was approximately 5,000 B/D gross. Furthermore, the defoamer chemical was the most expensive used in BC-10 on a volume basis, so the requirement to stop continuous injection saved approximately USD 4 million on an annual basis.

Optimization 2: Nonseparated Operation on Ostra

With the Ostra MOBOs now operating without defoamer, there was still some unrealized well potential in the field because the MOBOs were still constrained with respect to power. To increase capacity, and in light of the experience gained operating with higher GVFs on the pump without defoamer, it was decided to try operating one of the MOBOs in Ostra nonseparated so as to further increase the gas entering the oil riser, with the expectation that this would reduce boost requirements and, again, free up some ESP power.

The first step was to select the MOBO with the lowest gas feed and convert this to an in-situ GVF for the pump. Then, the pressure in all the MOBOs was increased to 85 bara (suction) to allow power to be freed up. Finally, the level inside the caisson was increased to allow a buffer of liquid. The gas-outlet valve on the MOBO was then closed, and the control scheme was switched from level to pressure control. The level in the caisson slowly started to rise until it filled the entire caisson; during this time, inflow and outflow were roughly similar and suction pressure remained at the target of 85 bar. Over successive days, the pressure was reduced in the caisson to stimulate additional well production and, as this happened, the level in the caisson diminished, indicating that, for a given GVF, there is an equilibrium level at which point enough gas is carried under with the liquid to equal the amount flowing in from the wells. As the pressure was reduced, additional gas broke out of the oil phase, causing the GVF to increase.

The second MOBO was then also converted to nonseparated mode, and its suction pressure was adjusted downward to maximize the aligned well capacity. Finally, the remaining MOBO, still in separated mode, had its suction pressure increased until as much energy from the wells was used as possible. In effect, this meant that instead of throttling the wells over the production chokes to keep strong wells at a reduced target and maintain the weak wells on target through a lower pump-suction pressure, the boost required for these stronger wells was much reduced. As before, the reduced boost requirement led to a reduction in power required, allowing additional well beanups. In the case of the remaining separated MOBO, the pressure increased from 75 to 115 bar, reducing boost by 40 bar and allowing an additional 10,000 B/D gross to be pumped. This, combined with the extra gas lift from the nonseparated MOBOs, increased total capacity, allowing 1 million bbl of additional oil production in 2013–14.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 26220, “BC-10: Optimizing Subsea Production,” by N.C. Sleight and N. Oliveira, Shell, prepared for the 2015 Offshore Technology Conference Brasil, Rio de Janeiro, 27–29 October. The paper has not been peer reviewed. Copyright 2015 Offshore Technology Conference. Reproduced by permission.