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An automatic pilot

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Oilfield Technology,


In an exclusive article for the March/April issue of Oilfield Technology, Michael Konopczynski and Mojtaba Moradi, Tendeka, UK, discuss how flow control can be optimised with an autonomous outflow control device.

Recent applications of horizontal drilling techniques to injection wells in waterfloods has seen an improvement in sweep efficiency and enhanced oil recovery from the reservoir. To counter the challenges associated with these wells, such as low permeability formations, complex pore and fracture systems, and water short-circuiting to nearby production wells, outflow control devices (OCD) installed along the lower completion string can balance the heel to toe water outflux.

Due to the complexity of heterogeneous reservoirs, identifying and mitigating thief zones prior to completing the well is problematic. This can potentially result in a non-optimised OCD completion leading to poor water conformance and ineffective sweep that may create short-circuit pathways from injector to producer.1 Additionally, the benefits of water injection can be diminished by the presence of highly conductive fractures in the injection well within the reservoir. These fractures zones can create a flow corridor connecting the injection well to production wells, resulting in early water breakthrough in the production well and leading to poor sweep efficiency.

Traditionally, OCDs with sliding sleeves have been installed to isolate thief zones.2 However, this requires the well to be accurately logged to firstly identify the location of the sleeves to be closed, and then to deploy a shifting tool to shut-off those sleeves.

Autonomous outflow control

As a result, Tendeka developed the FloFuse, a new autonomous injection control device. As a bi-stable device, this will restrict the injection of fluid into dilated/propagated fractures and mitigate the disproportional injection of fluid into the thief zone. This technology removes the need and cost of running a production logging tool (PLT) and the complex well interventions required to open/close the integrated sliding sleeves. Figure 1 shows the cross section and key features of the bi-stable valve.


Figure 1. Cross-section of FloFuse valve.

The new devices should be installed in several compartments in the well and can initially operate as normal outflow control valves. When a trigger flow rate is exceeded, the outflow is constrained into the ‘fused’ zone enabling injection to be distributed among the valves installed at neighbouring compartments. This valve is fully reversible and will re-set if the rate becomes evenly distributed again. The target normal operating rates and degree of outflow control and trigger rates can be varied by application.

The technology can be used to independently optimise flow distribution into the fracture/matrix structure and ensure effective injection when highly conductive fracture paths are encountered. Where sand control is needed, the outflow will be injected into the housing and through the screen (Figure 2).


Figure 2. Valve mounted in screen housing.

This procedure enables the operator to minimise the impact of natural fractures on the injected fluid conformance and to control the growth of thermal fractures while improving the efficiency of the injection well systems.

Under normal operating conditions, injection outflow passes through the ‘normally operating nozzle’ into the inflow control devices (ICD) housing and through the screen as required. If the pressure drop in the formation decreases as a result of increased injectivity due to a fracture or high permeability streak, the injection rate into that compartment will increase. The resultant increased pressure drop through the nozzle acts against the return spring until the flow area between the seal face and the nozzle becomes restricted and the valve triggers to the fused position restricting the outflow into that compartment. In the fused position, some bypass is maintained to enable the valve to re-open should the conditions allow.

Assessing performance

To validate performance, full-scale laboratory tests on realistic water injection conditions were carried out for a single bi-stable valve. Several single-phase water injection experiments were also performed to define the characteristics of the valve using different sizes – 2.2 mm, 3 mm and 4.5 mm.


Figure 3. Valve performance.

The characteristics are described by the differential pressure across the valve versus flowrate through the device. The plotted data in Figure 3 represents the pressure drop across the device as a function of flow rate for single phase water across the varying valve sizes. Based on the results, it shows that after reaching a certain flow rate, the valve shuts off the water flow. The trigger rate outlined below is dependent on the nozzle size and spring constant:

  • 2.2 mm valve triggers at 0.55 m3/hr.
  • 3 mm valve triggers at 0.9 m3/hr.
  • 4.5 mm valve triggers at 1.75 m3/hr.

If a minimum flowrate is needed to be injected to the fracture formation, the autonomous outflow control valve can be paired with a bypass ICD to deliver the desired outflow.

The flow performance of the bi-stable valve has been proven while flow behaviour of the flow can be simulated in the reservoir model. Pressure relief is accomplished by stopping injection and by the inclusion of one or more ICDs in the same zone as the device(s) in order to equalise pressure. The flow rate of the trigger point is an important parameter to calculate the number of devices in a completion.

To read the rest of this article, download Oilfield Technology's March/April issue for free: https://bit.ly/2VP0kVs

Read the article online at: https://www.oilfieldtechnology.com/special-reports/05052020/an-automatic-pilot/

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