Orca: An Innovative World First
By Enrico Barbaglia, Tim O'Connor, Kevin Joseph, Pieter Bezuidenhout, & Isak Mohali
Oribi oil production is the culmination of a 30-year search, both on- and offshore for South Africa's own oil resources. During 1980-1990, numerous small oil accumulations were encountered offshore, 10 of which were classified as being capable of flowing at potentially commercially viable flowrates. This total oil-in-place is conservatively estimated at +120 million bbl.
The seas off South Africa's southern Cape coast are characterized by strong currents and unusually high swells. However, this had not prevented semisubmersible rigs drilling in these treacherous waters. Soekor E&P (Pty) Ltd, in partnership with Energy Africa drilled extensively in the Bredasdorp Basin. In June 1990, the first of five boreholes were spudded in the E-BT oilfield off the southern Cape coast.
Volumetric limitation, doubts over the natural aquifer support, and uncertainty over duration of plateau production all posed major obstacles in the commercial recovery of these reserves. High production up time was critical to the economic viability of the project.
Two boreholes, E-BT1 and E-BT01P were completed as production wells, 35 meters apart. Reservoir studies indicated that the early implementation of water injection would significantly reduce the uncertainty of recoverability and sustain a higher rate of production. Subsequently E-BT5 was drilled as the injector well, 2.3 km from the two production wells. On 18 March 1996, contracts were signed between Soekor, Energy Africa, and Schlumberger. Fred Olsen Production is also part of the team with the supply and the management of the tanker.
It was decided to target subsea development with the production and injection wells tied back to a floating production, storage, and offloading facility (FPSO). A shuttle tanker would be connected to a CALM (Catenary Anchor Leg Mooring) buoy while receiving processed oil via a subsea flexible export line. When the tanker is loaded it detaches itself from the CALM buoy and delivers the crude oil to an onshore refinery.
During 1992-1994, the 'Sedco I' a three-legged semisubmersible MODU (Mobile Offshore Drilling Unit) was stacked in Port Noire, Congo. Prior to this she had been operating all along the coast of West Africa. Sedco Forex was contracted to convert the 'Sedco I' from a MODU to a FPSO and also operate the unit during production. Interestingly though, the same rig was earmarked for the re-entering of the wells to facilitate the production tubing and subsea trees. Still today the rig maintain her full drilling capability.
Schlumberger Wireline and Testing was entrusted with the design and installation of the subsea facilities and piping, as wells as the topsides production plant.
On 8 June 1996, 'Sedco I' arrived in Simonstown harbor, South Africa for refurbishing and conversion to a FPSO. This stage of the project was eventually completed 15 February 1997. On 20 February 1997, the 'Sedco I' was renamed "Orca", a tribute to the majestic killer whales that roam the south seas.
On 9 May 1997, South Africa's offshore oil industry came of age. The first commercially produced crude oil in South African waters were pumped to the tanker "Knock Dee"—a major milestone reached by Soekor and Energy Africa. Initial oil production averaged 25,000 b/d.
On 13 June1997, the first tanker load of 650,000 bbl oil was dispatched to Cape Town harbor. The magical 1 million bbl mark was reached a month later, on 12 July 1997. The proud milestone of 10 million bbl was passed 452 days after production commenced. This was achieved without any downtime or environmental incidents, and the current record is over 18 months without a lost-time incident.
Currently production is averaging 20,000 b/d oil. An economic cut-off point had been established as being 5,000 b/d. Representing 6% of South Africa's daily crude consumption, the Oribi Field production saves the country US$125 million in annual foreign exchange.
The Orca (back to top)
Oil flows from the reservoir via flexible flowlines onto the facility's riser platform. Water and gas are removed in a production separator, operating at 190 psia. An option exists to divert flow from either well into a test separator, for monitoring the performance of a particular well. In both cases, the oil will then flow via secondary separator operating at 20 psia. Additional gas is removed from the system, before being pumped to the shuttle tanker. It is essential to ensure that the oil has been reduced to a sufficiently low Reid Vapor Pressure (10 psia) before it is pumped to the tanker.
The rig has a diesel/crude oil power capacity of 6600HP supplied by 4 EMD engines. Due to the high quality of the crude oil, the diesel fuel is only stocked as emergency fuel.
Separated gas (approximately 18 million cf/d) is flared via a high- and low-pressure flare to the atmosphere. There being no economically viable way of transporting produced gas onshore, it is flared off.
Produced water separated from the oil in the production separation process is dumped overboard via Hydrocyclone and Degasser treatment plant. Currently producing water at a rate of 1,400 b/d, while the system is designed to treat 16,000 b/d. Environmental procedures in place limit the oil-in-water overboard to 25 ppm. Residual oil separated at the Hydrocyclone and Degasser drum is routed back to the secondary separator.
Whenever the tanker needs to disconnect from the CALM buoy, due to either adverse weather conditions or discharge scheduling, the wells are not shut in. Oil flow is routed to onboard storage tanks in the three legs, of which there are nine. Each of the legs had three tanks converted to storage tanks and a fourth one converted to a pump room. The total storage capacity constitutes 30,000 bbl. By reducing the production rate to 5,000 b/d, there is sufficient storage space for six days (tanker discharge turnaround averages four days).
In the event that the storage tanks are filled prior to the tanker being able to connect to the CALM buoy, then production will cease—a contingency plan, which we are fortunate not to have implemented yet.
The tanks operate on a ballast compensated crude oil storage system. This means that the oil float on sea water inside the tanks and the sea water flow in and out of tanks simultaneously as the oil is either being stored or exported. The rig's independent ballasting system usually maintains the unit at 80 ft operating draft. When the storage tanks are full, the draft is measured at 67 ft. When flowing to the storage tanks, the incoming crude displaces seawater in the tanks. This water flows through oily-water separators prior to being routed overboard. Throughout this operation, the working draft of the rig needs to adjust to compensate for the difference in density between the seawater and the oil.
When exporting from the storage tanks, seawater is pumped into the tanks and displaces the oil via a closed drain back to the secondary separator and exported to the tanker. During this mode, the well production is reduced to 20,000 b/d to allow 8,000 b/d to be pumped from the storage tanks.
Several safety mechanisms prevent uncontrolled discharges of oily water to the sea:
- The sea water inlet valve is designed to fail closed so that only sea water can flow into the system.
- While the tanks are being filled the displaced water will pass through a tilted plate oily-water separator unit which is designed to meet a discharge concentration of 15 ppm.
- The displaced discharge water line connection is located 1m above the base of the tank to ensure that it is clear of any sediment that may accumulate.
- The displaced water flows past a crude sensor on its way to the oily-water separator. The sensor will set off an alarm in the control room and shut down the related leg storage, should the oil in water concentration exceed 200 ppm. This makes the operator aware of a possible oil slug moving towards the oily-water separator.
- An oil-in-water monitor is used to monitor the overboard water discharged from the oily-water separator. If the oil in water content exceeds 15 ppm, the water is then routed to the process system.
Water Injection (back to top)
Seawater is taken from beneath the FPS, filtered and treated before being injected via well E-BT5 located 2.3 km away from the production wells. The purpose of injecting water is to maintain the reservoir pressure and help sweep oil towards the two production wells—increasing overall yield.
Either one of two seawater lift pumps lifts water from a depth of 40 feet below the water line. An electrochlorinator injects 1200 barrels chlorinated water at the suction of the lift pump to combat marine bacterial growth.
The water is routed to a filtration system where 95% of particles greater than 5 microns are removed by one cartridge and two fine media filters.
A two-stage vacuum Deaerator reduces the dissolved oxygen to 150 ppb. The injection of an oxygen scavenger chemical ensures that the dissolved oxygen does not exceed 10 ppb.
Various other chemicals are injected to control scale, corrosion, bacterial growth and foaming.
The rig's mud pumps were modified to inject the treated water into the reservoir. The initial demand was for 30, 000 b/d, but after extensive welltest data analysis this figure has been amended to 28,000 bbl.
Enrico Barbaglia—Schlumberger OFS—Oilfield Services manager
Tim O'Connor—Schlumberger Sedco Forex—Project manager
Kevin Joseph—Schlumberger Wireline &Testing—Plant operator
Pieter Bezuidenhout—Schlumberger Wireline &Testing—Plant operator
Isak Mohali—Schlumberger Wireline &Testing—Plant operator.