ICDs with feedback control for steam conformance

Steam-assisted gravity drainage (SAGD) is the most extensively used process for development of bitumen resources in Western Canada. It involves pairs of closely spaced horizontal wells where steam is injected into the upper well while the lower well produces reservoir fluids that drain from the steam chamber.

Ideally, the steam chamber should evolve uniformly along the entire length of the well pair; however, there is often very irregular steam chamber development. Reasons for this include hydraulic gradients in the horizontal completion, geologic and fluid variations in the reservoir, and well placement issues.

Operators have implemented various strategies to improve steam conformance. Simultaneous injection/production in dual-tubing completions is commonly used to provide controllable injection and production from the heel and toe regions, but this does not guarantee uniform and efficient performance.

FIGURE 3. The figure shows subcool temperature vs. time at the midpoint of the well pairs.

Inflow control devices (ICDs) incorporated in the horizontal completion can improve SAGD performance by adjusting the completion pressure differential to balance reservoir drawdown. Among other benefits, properly sized and distributed ICDs can create a more uniform flow profile along the horizontal section of the well regardless of permeability, formation damage, and wellbore location. Furthermore, ICDs on the producer can provide a self-regulating effect to prevent steam from entering the sand control screen.

Proportional integral derivative (PID) feedback to control steam injection can lead to further improvements in SAGD performance and can be practically and inexpensively implemented in the field with current technology.

Dual-tubing operations

Installation of dual-tubing strings in the injector and producer wells provides some control of the distribution of heat and production zones. In the example shown in Figure 1, a short string connects to the heel, and a long string connects to the toe of the well. An additional coiled tubing instrument string with either a fiber-optic distributed temperature sensing (DTS) system or thermocouple array may be included in the completion.

To prevent the steam chamber from touching the lower producer, which will remove hot steam instead of using it to heat the upper reaches of the chamber, injection and production rates are usually set to maintain a prescribed temperature difference between fluids exiting the upper injector and entering the lower producer. This temperature difference – also referred to as “subcool” since it is set to be several degrees below a water saturation temperature – may be controlled at both the heel and toe of the well pair. However, the ability to set injection and production rates to reflect the current state of the reservoir and current subcool is difficult using conventional reservoir engineering analysis.

FIGURE 2. Gas saturation (blue = 0, red = 1) and temperature (blue = 15°C, red = 220°C) contours vs. time for three SAGD well-pair configurations are shown.

ICDs

When placed in injectors, ICDs can better equalize the outflow of steam from heel to toe regardless of variations in reservoir mobility properties. In producers, ICDs can equalize the toe-to-heel influx of the emulsion and provide greater control of the subcool. ICDs also behave as autonomous or self-regulating valves since, if the liquid level gets close to the device, flashing of the fluids will occur in the nozzle, thereby increasing pressure drop, which in turn decreases drawdown on that section of the wellbore and consequently prevents steam from entering the screen. When a SAGD well is equipped with ICDs, there is no need for a second tubing string to be landed at the toe, saving both capital and installation costs as well as reducing the complexity of operating the well pair. This study was based on a high-temperature ICD design that combines a sand control screen with a choke designed to give a linear production or injection profile throughout the length of the horizontal wellbore. The devices are installed in 7-in. base-pipe joints, each 14 m (46 ft) long.

PID feedback control

PID feedback control of the steam injection can lead to further improvements in SAGD performance. Each steam injection point in the horizontal well pair is regulated by a PID feedback controller that monitors temperature differences between injected and produced fluids and automatically makes adjustments to both enforce a specified subcool and to achieve uniform production along the entire length of the producer. Achieving the subcool prevents steam from entering the lower producer, and both toe and heel halves are encouraged to produce uniformly since, if one half temporarily operates at a lower/higher subcool than the target, steam injection is decreased/increased in that half to compensate.

For the dual-tubing cases examined in this study, two separate controllers were used for the heel and toe tubulars, each with their own error term. The error term in the heel region was calculated using an average pressure in the annulus of the injection well between the heel and middle of the well, the saturation temperature according to this pressure, the average temperature of fluids flowing into the lower producer between the heel and middle of the well, and a specified target subcool. Equivalent values were used for the second half of the well to calculate the error term in the toe region. Minimum and maximum allowable injection rate values and increase/decrease factors were also predefined.

FIGURE 3. The figure shows subcool temperature vs. time at the midpoint of the well pairs.

Wellbore model

The accuracy of a reservoir simulator is determined by the accuracy of both the flow calculations within the reservoir and the wellbore model itself. As wells become more complex, accuracy of the wellbore model is likely to determine the final acceptability and reliability of the simulation. The multisegment well model used in this work is part of a new scalable parallel commercial reservoir simulator that treats the well as a network of nodes and pipes. A segment consists of a “node” and a “pipe” connecting it to the neighboring segment’s node toward the wellhead. Tubing strings may be added at any point within the multisegment well model.

Case studies

A synthetic heterogeneous reservoir model was created based on publicly available logs and bitumen properties from a region in the Athabasca Tar Sands, Alberta, Canada. As many of the reported parameters as possible were accounted for, including wellbore design and parameters such as absolute and relative permeabilities and injection rates. Grid and linear dimensions were 201 m by 15 m by 44 m (659 ft by 49 ft by 144 ft) and 201 m by 750 m by 55 m (659 ft by 2,461 ft by 180 ft), respectively. The model contained a single SAGD well pair 700 m (2,297 ft) long with a vertical spacing between injector and producer of 5 m (16.4 ft). Bitumen properties were 9°API gravity, 1.2 MMcP gas-free viscosity at 10?C (50?F), and an initial solution gas-oil ratio of 8.

A multisegment well model was constructed to accurately model the behavior and flow dynamics in both a dual-tubing configuration and in a well equipped with ICDs. Evolution of the steam chamber, temperatures, and pressure were examined during the production cycle to discern differences in the processes. Four cases were run with this model:
1. PID Injector, ICD Producer: An injector containing dual 3-in. inside diameter (ID) tubing strings was landed at the heel and toe, and steam injection rates to the heel/toe strings were PID-controlled with a specified subcool target. The producer was equipped with ICDs and hence contained only a single 6.3-in. ID tubular with no additional tubing string landed at the toe. The subcool target was set to 11°C (51.8?F).
2. PID Injector, Dual-String Producer: The injector and producer both contained dual-tubing strings, the injector PID-controlled by a heel/toe subcool target, and the producer produced equally from both heel and toe tubing strings. The subcool target was set to 11°C.
3. ICD Injector, ICD Producer: Both injector and producer were fitted with ICDs along their entire horizontal length. Again, there was no additional tubing string landed at the toe for this case.
4. Dual-String Injector, Dual-String Producer: In a base case in which the injector and producer both contained dual-tubing strings, steam injection rates were constant and equally split between the heel and toe strings, and production was also split between heel and toe.

Results

Figure 2 shows gas saturations and temperatures in a vertical plane containing the well pair after two, seven, and 12 years for the three cases with ICDs and/or PIDs. At two years, temperature and gas saturation profiles are similar between the three cases except ICD Injector, ICD Producer, which displays greater coolness in the mid-region together with lower gas saturations although with similar chamber growth near both ends.

All cases show a good degree of uniformity along the length of the well pair. By seven years, the two PID injector cases show equivalent steam chamber growth along the entire length, while the case without PIDs shows slightly less growth near the toe.

By 12 years, both PID cases show cooler steam chambers than the other because both are achieving their subcool targets. Note also that the steam chambers in the two cases with PID injection are closer to the producer at seven years than later at 12 years, which demonstrates the benefits of enforcing a subcool that is not too small (11°C in this simulation).

In Figure 3, the two cases with dual-string producers show large, uncontrolled subcools up to approximately 5.5 years (2,008 days), while the two ICD cases show controlled subcool throughout the production cycle.

Figure 4 is a comparison of cumulative steam-oil ratio for the four well pair configurations. The base case demonstrates the least favorable economics by exceeding all cases at late times in the production cycle. The two cases with PID-controlled injection start showing economic benefits of controlled subcool later in the production cycle. The case with ICDs in both the injector and producer shows higher steam-oil ratio than expected throughout the production cycle.

FIGURE 4. The chart compares the cumulative steam-oil ratio for three SAGD well-pair configurations and the base case.

Benefits

The aim of the study was to investigate some methods for accurate simulation of PID-controlled injectors and wells equipped with ICDs as well as to demonstrate the ability to simulate complex thermal processes. While the cases presented are specific to the synthetic model used, the results suggest that a hybrid method of using PID-feedback-controlled steam injection from dual-tubing strings with a producer equipped with ICDs may have several benefits. An ICD-equipped producer provides a more even inflow, which results in better controlled subcool throughout the production cycle – particularly in the early stages after switchover when it is more difficult for PID-controlled steam injection to achieve a subcool target. Also, later in the production cycle, the ability of the PID-controlled injection to force a specified subcool target appears to keep the steam chamber close to, but not touching, the producer, improving the economics of the process.

Acknowledgment
This article was prepared with the approval of the Society of Petroleum Engineers and is based on paper SPE 163594 presented at the SPE Reservoir Simulation Symposium, The Woodlands, Texas, Feb. 18 to Feb. 20, 2013.