Lab tests and field deployment of the swellable packer design showed the technology’s potential to help address waterflood challenges in offshore Valhall Field.
Graeme McRobb, Swellfix BV; and Jeroen Nijhof, BP Norge AS
Valhall Field, operated by BP Norge AS in the North Sea, is undergoing a massive redevelopment that will allow the field to keep producing until about 2050. In total, more than $2.3 billion is expected to be invested in upgrading the field. The operator is investigating strategies to protect the field against damage associated with waterflood and to minimize costs in its next phase of production.
The reservoir management plan for the Valhall redevelopment relies on multi-zone water injection and management of offset water in producing wells. It was recognized that cementing the reservoir liner could prevent isolation between the injection points or make the pre-perforated sliding sleeves inoperable, due to cement fallout.
Swellable packers were identified as a potential solution for zonal isolation that would limit the risk of damaging the perforation valves and reduce operational risk when running and cementing the reservoir liner.
Swellable packers combine the advantages of both cement and mechanical packers, without the inherent complications associated with the traditional technologies. The basic principle of swellable elastomer packers is natural and very simple: When water or oil is added to the appropriate rubber-based compound, it will swell as it absorbs the liquid. There are no moving parts to fail, and the integrity of the casing string is maintained.
Like cement, swellable packers adhere to the profile of the formation, and like conventional packers, they create a pressure-holding seal within the wellbore. However, unlike traditional methods of zonal isolation, swellable packers have reserve capabilities in case of a washout in the future or if water breakthrough occurs. In such cases, the packer can swell further and adapt to the new structure until a seal is re-established.
BP decided to carry out full-scale tests on both oil and water swellable packers under the type of high-pressure conditions that would likely be experienced in the field. The objective was to see if the technology would allow the operator to reduce operational risk by adopting openhole zonal isolation for the reservoir completions. If the tests found that swellable packers were potentially suitable, a design for field application in Valhall was to be created.
FIELD REQUIREMENTS
The requirements in Valhall are challenging, with maximum Differential Pressure (DP) of 10,000 psi for propped fracturing across the swellable packer and a long-term DP of 4,000 psi. To meet the operator’s needs, the swellable packers would need to have a high-pressure sealing capacity and be able to cope with the wide temperature variations they would experience between reservoir temperature and seawater injection processes.
BP wanted to establish the pressures at which both the water and oil swellable packers would fail and determine how they would respond to the type of temperature cycling that would be experienced in the redeveloped Valhall wells.
The operator decided to test two multi-element packers supplied by Swellfix: an oil swellable packer for the production wells and a water swellable packer for the injection wells.
SOLID SWELLABLE TEST
BP Norge had previously tested a 9-m solid swellable oil packer from another company. The first test of this packer failed after 4,500 psi DP was applied following the calculated theoretical swelling time. However, after the swellable packer was allowed to “heal,” 6,300 psi DP was reached before final failure. The test was carried out at bottomhole static temperature of 92°C in a 14.5-ppg Oil-Based Mud (OBM).
Despite the failure of the packer, real promise in terms of handling pressure was shown. However, BP did identify challenges with the packer’s design.
Uneven swelling was measured in the packer after removing it from the test setup, and it was determined that eccentricity of the packer in the wellbore could have a major impact on its sealing capacity.
In OBM with high solids content, it cannot be assumed that the packer will self-centralize because of filter caking and the accumulation of solids on the lower part of the packer. The packer’s eccentricity could cause uneven pressure resistance, and in some parts of its lower side it is possible the packer wouldn’t swell due to lack of contact with the OBM swelling agent.
Theoretically, if correctly centralized, the solid swellable packer should swell by 28% of its thickness around its circumference and create and maintain a seal of more than 10,000 psi. However, due to eccentricity and barite sag/separation, the upper side of the tested packer had to swell 57%, which resulted in a differential seal of just over 5,000 psi.
MULTI-ELEMENTS HOLD TIGHT
A key difference in the Swellfix packers is that they are made of several small elements rather than a large single section of elastomer. This design effectively means that there are multiple packers in the complete packer section. The overall rubber length of the multi-element packers was just 4.2 m, compared with 9 m of rubber on the solid packer previously tested.
By trapping quantities of the swelling agent in pools between the packer elements, the multi-element design provides much greater surface contact area than with a solid swellable packer.
The multi-element packer testing was carried out at the supplier’s newly opened testing facility in Aberdeen, Fig. 1.
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Fig. 1. Testing of the multi-element swellable packers showed both units capable of withstanding greater differential pressures than the previously tested solid expandable packer.
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The oil swellable packer was tested to slightly over 7,000 psi, which was higher than any previous test completed on oil swellable packers by BP Norge.
At a pressure differential of about 1,800 psi between elements 11 and 12, the packer suffered a dramatic failure of several elements, effectively reducing the number of elements holding the pressure from 12 to just four. However, the packer still maintained its overall seal.
The oil swellable packer was also tested for the impact of thermal cycling, to simulate the changing conditions that would be found downhole at Valhall over time. After cooling, the tested packer’s maximum pressure differential capability was reduced by more than 50%, down to around 2,500 psi. After reheating, this maximum DP was maintained, and after a two-week “healing” period the maximum DP had climbed back to 4,000 psi.
The manufacturer’s water swelling elastomers work on the principle of osmosis. The water swellable packer was tested with water supplied by BP Norge at 90°C. The packer held up to a 9,000-psi differential-2,000 psi more than its design specification-without any returns noted at the open end of the test fixture. At 9,000 psi, leaks started to occur from the test fixture’s standard National Pipe Thread (NPT) fittings, so the pressure was decreased to a safe level to allow repair of the fittings. Pressure was then re-applied back up to a maximum of 7,500 psi, and this was held successfully.
The temperature was then decreased to 23°C with a resulting pressure decrease to 3,500 psi. Further cooling to 16°C resulted in a further pressure decrease to 2,000 psi with only minimal returns from the open end of the test rig.
The three tests led to some key conclusions relevant to a swellable packer design for Valhall:
- Centralization is critical for even hardness and maximum sealing capacity.
- Horizontal 9-m uncentralized solid oil swelling packers did not self-center in OBM at 1.36 specific gravity.
- Temperature reduction significantly reduces the DP of swellable packers.
- Multi-element, water swelling packers allow equalization and spread the differential pressure over multiple packers, whereas multi-element, oil swelling packers attempt to support most of the pressure over a small number of elements.
The test also concluded that the failure modus of multi-element packers is consistent and repeatable, meaning packers can be reinforced with additional elements to increase their operating envelope.
FIELD TRIAL AT VALHALL
The real test for swellable elastomer packers in Valhall came with the design optimization and subsequent deployment of the technology in the field’s water injection well 2/8-G14.
The packer chosen for the field trial used a water swellable elastomer compound vulcanized to pipe in nine sections with a solid spiralizer centralizer between elements 5 and 6. The centralizer was put in place to help ensure an even swell when deployed in the horizontal section of the well. Due to pipe handling restraints at Valhall and the short length of the 6⅝-in. base pipe, the swellable packer was mounted onto two base pipes.
The completion design has two half packers separating each major zone and additional packers placed on either side of the main faults and propped fractures.
The downhole design took into account a number of factors to ensure optimum operational performance, including:
- Water saturation
- Porosity
- Hard grounds
- Propped fracture intersections
- Fault locations
- Pressures
- Acoustic caliper data
- Reservoir thickness.
To mitigate any risk of the packers swelling prematurely, the packers were run in OBM. Swelling was then optimized by displacing the open hole in the reservoir with seawater after landing the liner.
After stimulating the well, the operator found that the zonal isolation was functioning across the range of pressures applied.
Following treatment of a zone, the operator did not observe any residual pressure when opening the next zone. Even with large pressure differentials from one zone to the next, no noticeable leakage was found, demonstrating the sealing ability of the packer design.
The cost of swellable packers in Well 2/8-G14 was offset by not having to cement the reservoir liner on the critical path and by reduced running time for both liners and the inner string.
CONCLUSION
Following the onshore tests and deployment of the swellable packer design in Valhall Field, BP has been able to demonstrate the technology’s potential to help address the field’s waterflood challenges, significantly reduce operational risk and help Valhall to continue to produce for the next 40 years. 
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THE AUTHORS
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Graeme McRobb is Engineering Manager for Swellfix and has been with the company since June 2007. He has over 25 years of oilfield experience. He completed a 3-year, full-time Higher National Diploma in mechanical and offshore engineering at the Robert Gordon University in Aberdeen.
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Jeroen Nijhof is a Drilling Engineer in the BP Norway Valhall Injection Platform drilling team. He earned a BSc degree in drilling and production technology from the Noorderhaaks Polytechnic in Den Helder, Netherlands, in 1997, and a master’s degree in petroleum engineering from Heriot-Watt University, in Edinburgh, UK, in 1998.
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