TECHNOL0GY AT WORK

World’s first all-electric, multi-zone, intelligent well

For the first time, well injection rates from two zones are being remotely monitored and controlled, via satellite link, from an office located 165 mi (265 km) from the well site. The well (VRG-7D) is in Brazil’s Varginha field, and the office is in Petrobrás’ operational base in Natal. This was achieved with the world’s first all-electric, multi-zone, intelligent-well system, installed last May.

Baker Oil Tools’ InCharge Intelligent Well System was deployed in the onshore water-injection well prior to a 2002 subsea installation in Campos basin. The system controls flow while measuring pressure and temperature in real time, using infinitely variable chokes monitored with onboard pressure / temperature gauges and a downhole venturi flowmeter. As water is injected into a zone, the engineer can see, in real time, upstream and downstream pressure changes and the direct impact of water flowing into each injection zone.

A key benefit of the all-electric, multi-zone intelligent well system is the single control line that penetrates wellhead, expansion joint, tubing disconnect and packers, thereby minimizing infrastructure modifications to subsea trees and increasing safety.

All-electric system rationale. Historically, hydraulic limits (primarily associated with surface-controlled subsurface safety valves) have been the primary cause for interventions in Petrobrás’ subsea well completions. Such interventions usually take at least 20 – 30 days of contracted rig time. At rig rates of $150,000/day, this translates to minimum workover costs of $3 – 4.5 million per occurrence. Thus, although most intelligent well systems to date have been either hydraulic or electro-hydraulic, Petrobrás restricted or eliminated hydraulics from its subsea wells for reliability and cost reasons.

Hydraulic and electro-hydraulic systems require multiple control lines to penetrate the wellhead. Subsea trees, on the other hand, were originally intended for only a single downhole electronic gauge. All-electric, intelligent-well designs require minimal retrofitting of subsea trees. As a result, intelligent-well systems can be used with minimal modifications to the subsea infrastructure. Conversely, the cost of modifying existing subsea trees and running multiple control lines downhole can be prohibitive.

Because bottomhole conditions may adversely affect many traditional oilfield hydraulic fluids, hydraulics downhole have typically been limited to fairly shallow applications of subsurface valves. However, intelligent-well devices are positioned at or immediately above the sand face, bringing them much closer to true bottomhole conditions. Exposing standard fluids to deep formation temperatures can cause precipitation of solids and possibly, failure of moving parts.

System mechanics. The primary pressure barrier in the Varginha system is a 9-5/8-in. x 5-1/2-in. packer. The upper 5-1/2-in. tubing string carries the injection fluids to the lower completion intervals, which are mechanically separated at completion by the isolation assembly. Apportionment and allocation of flow are controlled by the intelligent monitoring and control components between the intervals.

Total injected flow volume is measured by passage through the 5-1/2-in. venturi flowmeter before entering the system’s 5-1/2-in. intelligent production regulator (IPR) valve assembly. The desired volume of fluid intended for the upper injection interval is then apportioned and passed from the tubing into the tubing / casing annulus by the infinitely variable choke in the IPR valve assembly. Annular flow volume continues into the upper injection interval. The balance of the total injected volume continues downward in the 3-1/2-in. venturi flowmeter, which measures volumetric flow going into the lower injection interval. The system’s 3-1/2-in. shrouded IPR valve assembly regulates lower zone injection rate.

The heart of the new system is the regulator valve assembly, which provides:

• Infinitely variable choking control of annulus-to-tubing flow
• Two high-resolution quartz pressure and temperature sensors that yield annulus (sandface) pressure, tubing (internal) pressure, and differential pressure across the choke while in any choke position
• Direct choke position sensing
• Mechanical backup shifting capability
• Twin 1/4-in. line feedthroughs for chemical injection or additional sensors.

Additionally, a shrouded IPR valve assembly provides the same basic functionality as the 5-1/2-in. valve assembly. However, the external shrouding and internal wireline-retrievable plug and porting enables variable choking regulation of tubing-to-tubing flow.

Single control line. A key benefit of the system is the single control line that penetrates wellhead, expansion joint, tubing disconnect and packers. The system can monitor and control up to 12 zones in a single well and up to 12 wells in a field, each via a single control line from a single surface-control system. The primary electronic "bus" for the system is a tubing-encased conductor (TEC) cable that comprises twin copper conductors in a 1/4-in.-OD capillary tubing, with an epoxy filler that serves as a fluid / gas blocking agent. The surface control system is also designed to provide an interface to higher-level SCADA, DCS and ESD systems. In addition to minimizing infrastructure modifications to subsea trees, a single control line reduces safety and technological risks.

Downhole electrical wet disconnect / reconnect anchor system. The Varginha VRG-7D intelligent well featured the world’s first downhole electrical wet disconnect / reconnect anchor system. This system, based on an earlier hydraulic snap-in / snap-out anchor, is designed to facilitate disconnection and reconnection of the tubing string and twisted pair conductors leading to intelligent-well components. The wet disconnect enables a single-point downhole disconnection or reconnection of both production tubing and TEC cable anytime after the production packer is set. It eliminates required retrieval of the lower intelligent-completion assembly during upper completion workover operations necessitated by safety valve failures, tubing hanger leaks or tubing leaks. It may also be used to facilitate future tubing space-out and circulation operations.

Whereas the running load in the earlier hydraulic anchor was carried by the shear release latch, the load-carrying mechanism in the new electrical wet disconnect is released after running the completion by applying annulus pressure. A straight pull on the production string disengages the snap-latch anchor of the connector, and the upper completion can be removed.

Nearly 70% of Brazilian oil and gas reserves lie in deep (1,000 – 3,000 ft) and ultra-deep (>3,000 ft) waters. Successfully exploiting these reserves depends on safe, economic extraction. In the mid-1990s, Petrobrás recognized how intelligent-well technology could address existing limitations and expand basic well completion to improve reservoir management. In 1998, Petrobrás began investigating intelligent-well systems that met strict safety criteria, addressed reliability concerns related to hydraulically operated downhole flow-control devices, and enhanced the value of additional downhole sensors with which to resolve key uncertainties critical to deepwater production and reservoir management. To date, Petrobrás and Baker Oil Tools are achieving these objectives.