Full steam ahead for new OCD usage in SAGD

Effective steam injection is a key component of steam-assisted gravity drainage (SAGD) development. When deploying outflow control devices (OCDs) as part of SAGD operations, steam injection effectiveness can be measured in operation time, number of on-site personnel required during operations, and confirmation of OCDs shifting open—all three areas improved by the introduction of a new ball-activated OCD during field trials in northeastern Alberta, Canada. 

SAGD is a widespread method for developing resources in Alberta’s vast oil sands country and an essential process for accessing over 80% of the province’s bitumen reserves, which are too deep to mine. OCDs are commonly used in SAGD horizontal injection wells to enhance steam distribution in the well and facilitate uniform heating of the reservoir. Multiple OCDs are positioned in the tubing string across the horizontal portion of the well, to create the desired steam distribution. 

Most OCD designs incorporate a sliding sleeve, which is run in the closed position to allow for steam to be circulated through the well. Circulation continues until communication can be achieved with the producer well, allowing for bullhead steam injection. Post circulation, the sliding sleeves traditionally require coiled-tubing intervention to shift the sleeves open, activating the OCD. The ball-activated OCDs are opened, using degradable balls pumped from the surface. Once landed in the OCD, the tubing is pressured up until the sleeve shifts open. The ball then disengages from the seat and continues to the end of the tubing string. This process is repeated with progressively larger balls for all of the installed OCDs. 

During the field trial of the ball-activated OCD, this innovative tool is compared to coiled tubing-shiftable OCDs on three main criteria—job efficiency, confirmation of shift, and environmental, health and safety (EHS) considerations.

OCD DESIGN 

All wells in the field trial were equipped identically in a dual-tubing eccentric string configuration, with a long tubing string run to the toe of the lateral, complete with two OCDs. A short tubing string also was run to provide a return conduit during steam circulation, and a secondary injection point during SAGD operation of the well. Figure 1 shows the configuration used for all wells in both steam circulation mode and steam injection mode. 

Fig. 1. SAGD injector configuration during steam circulation and steam injection modes.

COILED TUBING-SHIFTABLE SLEEVE 

The coiled tubing-shiftable OCDs required an Otis B shifting tool to open or close the device. In this design, the sleeve is positioned with the blanking portion of the sliding sleeve in the downhole position, requiring an up-hole action to open the sliding sleeve. An Otis B shifting tool is run on coiled tubing, through and past the OCD that requires opening, and is pulled back through the OCD to engage the sleeve and slide it to the open position. Once the sliding sleeve shift is complete, the keys of the shifting tool are released. The drawbacks of this method can include difficulty shifting; inconclusive indication of shift; loss of heat downhole; and EHS considerations. 

BALL-ACTIVATED SLEEVE

Fig. 2. Comparison of shifting procedures for two different OCD designs.

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The ball-activated OCDs utilize a ball seat to initially open the sliding sleeve and an Otis B shifting tool to close or re-open the OCD. In this design, the sleeve is positioned with the blanking portion of the sliding sleeve in the up-hole position, requiring a downhole action to open the sliding sleeve. To open the sliding sleeve, a dissolvable ball is pumped from surface and lands in the OCD, with a ball seat of a corresponding size. Once the ball lands on the ball seat, pressure builds, causing pins to shear and the sleeve to shift. Further pressure is applied, causing the seat to retract and the ball to pass through, leaving a full ID through the device, Fig. 2. 

FIELD TRIAL SET-UP AND RESULTS 

To compare both OCD shifting methods, a total of six wells were included in the field trial—three wells used coiled tubing-shiftable OCDs and three wells used ball-activated OCDs. 

Each well contained two OCDs of the same type, providing six OCDs of each type to compare.

Job efficiency. To evaluate job efficiency, the operational duration is broken into the following categories: well preparation, shifting operations and well handover. 

Fig. 3. Duration of OCD shifting operations and total fluid pumped.

Well preparation includes rig-up of all required equipment and any fluid pumping required to work on the well safely. Shifting operation duration is the total time required from when the well is safe to begin operations to when shifting is complete and all equipment is out of the hole. Finally, well handover covers all rig-out of equipment and steps required to hand the well back over to resume steam injection. On average, the total duration to conduct the shifting operation of the ball-activated OCDs was 45% less, Fig. 3. 

Notably, BA-2 and CT-2 only required one OCD shifted open because of well performance, whereas the other two examples for each OCD had two OCDs shifted and can be directly compared. The largest difference between both methods included the well preparation category and the shifting operation. For well preparation, the ball-activated OCDs only require a pressure truck to deploy, so the rig-up is significantly faster. For shifting, the ball can be pumped to its seat in 10 to 15 min., pumping at a rate of 1.0 m³/min., so that shifts can be conducted more efficiently. The well handover in all trials was similar in duration. 

For the coiled tubing-shiftable trials, there was significant variability in the duration of the shifting operation. This was due to inconclusiveness while attempting to shift open the sliding sleeve, requiring multiple passes through the OCD to properly latch the shifting profile, and subsequently confirm that the shift has occurred. 

Confirmation of shift is evaluated using different techniques based on the OCD used—pump and acoustic charting for the ball-activated OCD; shifting tool latch/release for the coiled tubing shiftable OCD; and post-shift pressure drop for both. 

Pressure, rate and acoustic data were recorded for all ball-activated OCD shifts, using a wellhead mounted pressure sensor and acoustic geophones, as well as a flowmeter on the pump equipment. 

Fig. 4. Typical pressure and acoustic response using ball-activated OCDs.

Once the ball reaches the ball seat, the pressure quickly builds in the system and starts the shift. Further pressure then builds behind the ball to complete the shifting process, deform the ball seat and release the ball. Acoustic tracks for the wells showed a low response prior to the seating of the ball, then a greater response as the pressure builds and the seat shifts, Fig. 4. 

For the coiled tubing OCD, a tension response can be interpreted by reading off the coiled tubing injector pressures while shifting the sliding sleeve. Another indicator of positive shift is the disengagement of the shifting keys from the sliding sleeve profile. If the sliding sleeve fully shifts, the shifting tool keys are forced to disengage, resulting in continued movement up-hole with the shifting tool and coiled tubing. This provides a qualitative indication that the sleeve has shifted; however, it could provide false positive data if the keys pop out of the shifting profile, due to tool malfunction. Failure of the shifting keys to release indicates that the sleeve has not shifted completely.

Multiple passes were required to either successfully latch or release from the sliding sleeve in all coiled tubing-shiftable OCDs during the field trial. In only one trial, CT-3, did the tool successfully latch and release, indicating a high confidence of shift. 

For both OCDs, the pre- and post-shift tubing pressure drop can be compared to modelled values, to provide another indication of shift. When the OCDs are shifted open, the required injection pressure at a constant rate will decrease as the result of lower tubing friction of the system (Medina, 2013).

Wellbore hydraulic simulations were performed to accurately predict pressure drop across the tubing string from surface to downhole, before and after shifting. A decrease in pressure drop from surface to downhole can be expected after shifting operations, due to less friction in the system. For all trials except CT-1, the modeling results are within approximately 25% of the actual field data, which is considered to be within the error of modeling. The CT-1 trial has the actual pressure drop observed at approximately 50% of the modelled results. These data suggest a possible partial shift, failure in one sub to shift, or an error in modeling results and were categorized as an inconclusive shift. 

EHS CONSIDERATIONS 

OCDs are deployed in many SAGD injection wells, so it’s important to consider each operation with respect to EHS. To assess the EHS impacts, two main considerations were investigated—total equipment required, and total personnel required. 

By looking at the total equipment required and what type, a qualitative assessment can be made regarding the complexity and risk of the operation. An assessment of the total personnel required, and their job scope, is used to determine the likelihood of having an EHS incident. 

Table 1 summarizes all required services and personnel to complete the shifting for each job type. The ball-activated shifting can be completed with less equipment and personnel, with the most significant piece of equipment removed being the coiled tubing unit and picker to support the coiled tubing injector. 

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CONCLUSION 

Ball-activated OCDs for use in SAGD injector wells are an effective tool for improving operational efficiency and project economics. This new OCD utilizes a dissolvable ball dropped from surface to activate a sliding sleeve downhole using hydraulic pressure, which eliminates the need to use coiled tubing to shift the OCDs when converting the injection well to SAGD. Some of the advantages provided by the ball-activated OCD include: 

• Ball-activated OCDs can provide a significant efficiency advantage when compared to coiled tubing-shiftable OCDs and can be shifted using the same volume of fluid pumped to coiled tubing-shiftable OCDs. 
• Ball-activated OCDs provide greater confidence of sliding sleeve shift and do not require multiple attempts to shift. 
• Ball-activated OCDs can be coupled with surface acoustic monitoring to provide complementary confirmation of sliding sleeve shift. 
• A comparison of pre- and post-steam injection pressures can be used to confirm OCD shift success. 
• Ball-activated OCDs can be shifted with less equipment and personnel, lowering the likelihood of an EHS event. 

ACKNOWLEDGMENT

This information was presented at the SPE Annual Technical Conference and Exhibition, Calgary, Alberta, Canada, Oct. 2, 2019 (SPE-195877-MS) © 2019 Society of Petroleum Engineers.