Polymer seal tests reveal elastomer needs for future EOR programs
John Kerwin - Precision Polymer Engineering
Extracting oil is becoming more technically and financial challenging as operators face increasingly complex and deeper wells. The lifespan of a well is dictated by production volume versus economic viability. This has led to technologies for enhanced oil recovery (EOR) to increase volumes extracted from a well, thereby improving its profitability.
EOR can involve the injection of super-critical CO2, steam, or H2S into a well in order to recover a larger proportion of the oil. The solvating properties of high temperature steam and CO2 super critical when injected at high CO2 reduce the viscosity of heavy oil, enabling more oil to be extracted.
These same solvating effects, however, can affect sealing elastomers, thermoplastic liners, and composites that contact the fluids, leading to swelling and a weakening of the polymer’s structure. This can cause loss of sealing due to extrusion of the seal under pressure, increased fluid permeation, and seal volume loss. As a result, polymer seals on pumps and compressors, for example, must be replaced frequently.
With a 1% improvement in world oil production efficiency estimated to be worth an additional 20-30 Bbbl, the ability to extend the operational life of seals and other polymer-based components would provide significant financial benefits.
A UK government-supported project – “Durability of Polymers Under Injection Conditions for Enhanced Oil Recovery (PEOR)” has been established to improve understanding of the effects of EOR environments on polymers used for reinjection and storage purposes in new and existing production infrastructure. PEOR is managed by MERL, assisted by polymer technology specialists Precision Polymer Engineering and Clwyd Compounders, and offshore tooling provider Baker Hughes.
The aim of the project is to identify, qualify, and develop for EOR operations new polymeric materials offering longevity and safe operations in hostile applications. The EOR injection process also can be applied in CO2 storage and carbon capture by pumping super critical CO2 into a well and displacing the oil. It can then be re-injected and sealed underground rather than venting into the atmosphere. Part of the PEOR project calls for the development of guidelines on the use of polymers in carbon capture applications
The PEOR project simulates the operating and re-injection conditions for North Sea and other fields around the globe, and assesses what effect these conditions might have on current and emerging state-of–the-art polymers.
The 34 materials evaluated in the project include elastomers such as ethylene propylene (EP), butyl, hydrogenated nitrile (HNBR), tetrafluoroethylene propylene copolymer (FEPM), fluoroelastomers (FKM and ETP), and perfluoroelastomer (FFKM) as well as thermoplastics including PEEK, PPS, and PVDF. These polymers were selected because of their proven success in current field applications, and their potential to be developed and incorporated into future EOR technologies.
Initial screening of the polymers involved exposure to steam, super critical CO2, and hydrogen sulfide. The materials’ performance was assessed by means of visual inspection, tensile testing for steam, and H2S, rapid gas decompression damage evaluation using the NORSOK M-710 oil and gas standard.
•Steam tests (exposure of dumbbells followed by tensile testing) have shown that materials including FKM, FFKM, ETP, and FEPM perform well when subjected to temperatures of 220 °C (428 °F) and pressures of 150 bar, under a two-week exposure. Other materials including HNBR do not perform well under these conditions.
•Super-critical CO2 was applied by soaking of O-rings while constrained in rapid gas decompression (RGD) fixture. The tests have revealed that very few materials are unaffected by exposure to super-critical CO2. Swelling is followed usually by damage resulting from RGD (tested according to NORSOK M-710 standard with a decompression rate of 20 bar/min). HNBR and FKM (with high fluorine content) have performed well with little damage seen following one decompression, at 110 °C (230 °F) from 350 bar. Other materials such as ETP have exhibited extrusion, while the base resistant FKM O-ring was split into two halves. Blister damage was also common. Thermoplastic PPS showed slight swelling (PEEK does not under these conditions), and both PPS and PEEK exhibited discoloration, although no blistering was observed.
•Hydrogen sulfide testing was conducted in a harsh environment of 65% H2S + 35% CO2. Interestingly, more material grades showed good resistance to H2S (through tensile testing and swell measurements), including FKM, HNBR, FEPM, BUTYL, EP, and FFKM.
None of the materials tested exhibited good resistance to both steam and super-critical CO2. In practice, however, it is unlikely that materials would encounter both environments: more likely they would be subjected to hydrocarbon exposure followed by super-critical CO2 or steam (as in well conversion).
The initial list of 34 polymer materials was reduced to seven material grades (based on FKM, FFKM, ETP, EPDM, FEPM, and PPS). These were then exposed to the full test conditions. Each of the polymers was subjected to exposure to steam at 260 °C (500 °F) and 250 bar, and to 65% H2S and 35% CO2 at 220°C (428 °F) and 20 bar.
Rapid gas decompression also was performed in 100% super-critical CO2 at 150 °C (302 °F) and 410 bar. Just one material, a fluoroelastomer, performed acceptably well in all tests. The next stage of the project with this material will involve molding of a three-element packer component for test under steam conditions to ISO 14310.
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(Below) Blister damage during rapid gas decompression following super critical CO2 immersion.