2001 Vol. 222 No. 12
TECHNOL0GY AT WORK
Worlds first all-electric, multi-zone, intelligent well
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 Brazils
Varginha field, and the office is in Petrobrás operational base in Natal. This was achieved with
the worlds 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 systems 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 systems 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
- 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 worlds 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