Intelligent well technology can control oil reservoir inflow, auto-gaslift system
The industry’s ability to remotely monitor downhole conditions in real time and to control the flow of fluids between the reservoir and the wellbore without physical intervention has been achieved through intelligent completion technology and continues to prove its value in unconventional applications.
Recently, intelligent well technology was applied in India’s Panna field to a secondary recovery project with complicated well conditions. Using auto-gaslift, the operator reduced the capital expenditures related to conventional gas lift infrastructure, lowered operating costs through minimized well intervention, and optimized production. To use auto-gaslift (also called natural gaslift), the operator relies on a natural source of lift gas from either the gas cap of the producing oil zone or a separate gas formation above or below the producing oil reservoir. Field personnel can commingle the lift gas from the downhole source with the oil production in the tubing to reduce the density of the produced fluids, reducing the hydrostatic head in the production conduit and increasing the inflow from the oil zone.
The ability to monitor and control the rate at which the lift gas is added is key to successful auto-gaslift. WellDynamics’ SmartWell technology can monitor the downhole pressure, temperature, and flow rates to optimize the oil production throughout the life of the well as the gas zone and oil zone pressures decline, and water production increases.
Determining feasibility
The Panna field is in the Bombay basin offshore India about 95 km (59 mi) northwest of Mumbai, in water depths of 45-70 m (148-230 ft). The field has a 20 m (65 ft) oil rim layered between a large gas cap and an aquifer. The rock properties of the field are largely heterogeneous, with pressure decline related to fluid extraction conveyed field wide. The main reservoir has an initial oil column of 20 m (65 ft) largely in a transition zone.
Choke performance curve in an auto-gaslift application using intelligent completion technology.
The project team determined auto-gaslift to be the best artificial lift solution for the reservoir conditions. Their analysis considered key factors for both gas and oil zones, such as productivity index, fluid composition, and reservoir pressure, and was the deciding factor in selecting auto-gaslift. The analysis also addressed the question of production conduit size and interval control valve (ICV) design for optimum gas lift controllability in the presence of reservoir uncertainties and changes in future operations.
Certain well conditions must exist to justify auto-gaslift:
- The pressure of the gas reservoir must exceed the hydrostatic pressure of the fluid column in the production tubing (to the depth of gas entry) plus the line-pack under fixed conditions in order to “kick off” the well.
- The gas reservoir must produce sufficient gas for effective lift at moderate drawdown pressures.
- The volume of gas reserves from the gas source must be large enough to maintain sufficient pressure and productivity under a variety of conditions as the oil zone is depleted and water cut increases.
Even if these conditions do exist, auto-gaslift introduces variables not found with conventional gas lift. For example, the productivity of the gas source is uncertain, and pressure and productivity can change over the life of the well. The design of the downhole flow-regulating valve for the gas zone must be properly sized for the range of gas and oil reservoir performance, fluid compositions, and reservoir pressure over time.
For the Panna field, the team considered two well types representing oil/gas reservoir relationships:
- Type 1 wells indicate oil production from the (Zone B) oil reservoir, while lift gas production is from the (Zone A) gas cap reservoir. The reservoir pressure in Zone A is independent of Zone B.
- Type 2 wells indicate oil production from the Zone A reservoir, while lift gas production is from the overlaying gas cap in Zone A. As a result, the reservoir pressure from the gas zone will decline as the oil zone is depleted.
The project team decided that the Type 1 wells will experience Zone B reservoir pressure decline throughout the lifespan of the well, from an initial 2,100 psi down to 1,700 psi. Zone A reservoir pressure will decline at a lower rate, as it is only affected by extraction of the lift gas. In Type 2 wells, the oil column and the gas cap in Zone A will decline together.
When evaluating the gas zone, the project team considered four gas zone productivities (combinations of skin, wellbore diameter, and absolute permeability), along with two gas reservoir pressures. For the oil zones, three reservoir pressures were considered from both the A and B zones. For B and A, two productivity indices were considered: Flowing tubing head pressures of 650 psi, 550 psi, and 400 psi were considered for water cuts of 0%, 40%, and 94%, respectively, while the natural gas-to-oil ratio was fixed at 650 scf/stb.
Specialized technology
Panna development wells have a main wellbore with multiple laterals to provide maximum reservoir contact with the thin oil rim. This construction maximizes productivity while minimizing drawdown and preventing water or gas cresting. Each lateral is isolated from the others by a liner with external casing packers or swell packers, and inside the liner by isolation packers or swell packers. This configuration divides the motherbore into sections that correspond to each lateral, with interval control valves controlling the inflow of fluids from the laterals to restrict unwanted effluents, should one or more of the laterals produce excessive water or gas.
Intelligent completion used in auto-gaslift application.
The upper gas zone is perforated and isolated from the oil zone by the top oil zone isolation packer and from the surface by the main production packer. The auto-gaslift valve controls the gas inflow over 11 valve positions to provide the control range necessary to optimize lift. Pressure and temperature sensors monitor the gas zone flow performance.
The upper completion includes a chemical injection mandrel, optional conventional gas lift mandrels, and a tubing retrievable subsurface safety valve. Downhole permanent pressure and temperature gauges can be installed to monitor drawdown on the oil zone and gas lift performance.
The intelligent completion developed for the Panna field enabled controlled commingling of production from both gas and oil reservoirs, while mitigating variables of the well environment. The flow control valve design optimized the gas lift injection rate with the valve for the broad range of reservoir/production conditions anticipated. Project team analysis determined that the Panna field production wells are suited for auto-gaslift applications and that the specific ICV design gives good gas lift control of projected reservoir and operating conditions.
Michael R. Konopczynski
WellDynamics
