Record-length expandable liner enables gas lift completion, improves production

An innovative application of expandable liner technology re-lined a non-sour-gas-compliant wellbore, clearing the way for a gas-lift recompletion and restoring production to a pressure-depleted oil well. Moreover, at 7,047 ft in length, the non-traditional installation established a world record for a solid-expandable liner run.

The main factor driving the decision to re-line an existing wellbore was the unexpectedly high hydrogen sulfide (H₂S) levels observed later in the productive life of a number of wells completed with non-sour service, 51/2-in. P-110-grade production strings. With the existing downhole architecture unqualified to resist H₂S embrittlement and potential health, safety and environment (HSE) ramifications, traditional gas lift was not an option for offsetting the natural decline rates of the affected wells. Accordingly, the service provider explored alternative methods for installing a 7,000-plus-ft continuous string of expandable liner, to isolate the non-H₂S-tolerant casing and clear the way for a gas-lift completion.¹

A full suite of independent qualification tests was undertaken, to determine the feasibility of such an operation. Ultimately, the service company produced an expandable liner that was certified to meet National Association of Corrosion Engineers (NACE) compliance. The conceptually complex operation was performed successfully, using a workover rig and a specially selected casing jack on an H₂S-corrupted and underperforming oil well in the Eagle Ford shale.

GAS LIFT RESTRICTIONS

While evaluating an asset that sits primarily in the southwestern portion of the Eagle Ford play, ConocoPhillips noticed increasing levels of H₂S, where the combination of partial pressure and low formation temperatures (<175°F)^2,3,4 in the upper hole raised the risks of sulfide stress cracking of non-compliant production tubing.

A common way to overcome the natural decline rate, and restore production in unconventional wells, is to install an artificial lift completion. However, because of the incompatibility between P-110 metallurgy and H₂S gas, the preferred method—gas lift—was not an option on these wells. Otherwise, comingling associated production gas with higher H₂S content through the incompatible 51/2-in. production string could propagate stress cracking and severe HSE ramifications.

Thus, artificial lift options were largely off the table for numerous Eagle Ford wells exhibiting high sour gas levels. Water build-up, and the resultant backpressure, required periodic swabbing runs to restore production. Owing to steady depletion and proportionately declining flowrates, unless an artificial lift system could be installed, the affected wells would need to be re-drilled and re-completed, or else the remaining reserves would be stranded.

A number of options were weighed to convert the non-compliant wells to H₂S-compliant status, thereby allowing artificial lift to maximize reservoir drainage. However, using the wells’ existing architecture to do so posed a number of formidable obstacles, not the least of which was the inability to run a conventional-sized casing to isolate the non-compliant 51/2-in. casing. First and foremost, the solution needed to provide wellbore integrity to prevent H₂S from escaping to surface, and endangering personnel and the environment. Secondly, the value of the remaining reserves had to justify the cost of the selected approach.

Of all the alternatives considered, a solid-expandable liner provided the most intriguing prospect for delivering an H₂S-tolerant wellbore. Expandable liner technology conceivably offered a cost-effective option that would maintain well integrity, while providing an inside diameter (ID) that would accommodate artificial lift options. Yet transforming that theory into a workable reality required defying conventional wisdom.

EVALUATING THE HURDLES

Isolation of the temperature threshold of sulfide stress cracking—around 175°F—would require running a 7,000-ft string of pipe and seals. As this application was well beyond the design limitations of conventional expandable liner technology, the first hurdle to be addressed was determining if it was even physically possible to run and expand a continuous 7,000-ft string of 41/4-in. liner while maintaining wellbore integrity.

Approximately 60,000 lb of force were required to expand the pipe, and around 100,000 lb of force were needed to effectively compress the seals. As the hanging liner weight was greater than the expansion forces, the liner could be expanded under its own weight. Once the liner was landed, the expansion cone could be picked up, and the liner weight would effectively expand and anchor the continuous liner.

The fixed-free expansion mode, which is the most commonly used method of expansion, requires one end of the liner to be “fixed” while the other end of the liner remains “free” to move or reduce in length. In bottom-up expansion, the lower end is fixed and the upper end is free, which enables it to reduce in length as the liner is expanded. Using the fixed-free expansion method in this application would have resulted in a reduction in length of 380 ft. The change in length would have required stripping over 13 joints of pipe and complex scaffolding to safely make connections at different heights as the liner was expanded, thereby increasing the risk and time required to complete the operation. Furthermore, calculations had pipe stretch and liner compression, or “squat,” requiring 84 ft of distance to pull the casing slips, which would be difficult on the double workover rig.

Given the safety risks and additional time requirements associated with the fixed-free method, the alternative fixed-fixed expansion was identified as the only suitable and cost-effective methodology. In fixed-fixed expansion, both ends of the liner are anchored, which leaves the length unchanged, but increases wall thinning and tension load build-up.

Consequently, a finite element analysis (FEA) was performed to determine if the casing weight and tension load build-up would be within the tensile capacity of the connections. Using the dynamic load expansion bench (DLX) apparatus described by Setterberg, et al,⁵ a testing program was initiated with simulated downhole conditions at various points. The test results and actual loads, which compared closely to the FEA model, showed that an expected tension load build-up of 116,000 lb would have no impact on the survivability of the liner and connections, or an effective seal.

In addition, as the existing 51/2-in. casing hanger likewise was non-H₂S compliant, the initial plan to expand the liner with termination at the casing hanger had to be discarded. Following collaboration with the operator, and expandable liner and wellhead providers, it was agreed that a pack-off for the expandable liner would be designed to allow anchoring at the top of the production casing and sealing in the wellhead. This required adding an additional casing spool to the Christmas tree. In addition, a seal had to be specially designed and qualified to accommodate the uncommon size (4.619-in. OD) of the liner. With this, both the non-qualified production string and the casing hanger would be completely isolated and taken out of the equation.

QUALIFICATION PROTOCOL

Parallel to the FEA analyses and load tests, two pipe mills were qualified as being capable of manufacturing expandable liners that are H₂S-compliant and meet applicable NACE standards (MRO 175/15156). To be NACE-compliant, any material cold-worked beyond 5% has to be stress relieved, but the liner in this case would be expanded 16%, with no possibility of stress relieving downhole. As NACE provides exceptions with proper testing and documentation, post-expanded liner samples, which were evaluated under the simulated production environment, passed the 30-day NACE TM 0177 Method B sulfide stress-cracking tests at 90% of yield strain (ultimate stress) and evaluated to meet H2S tolerance of 9 partial pressure at 4.7 ph.

With sour-gas service qualified, pressure testing was conducted on two expanded connection samples to ensure sustained integrity and qualification to the pending addendum (API RP 5EX ballot draft) to API 5C5 Premium connection qualification. The qualification included testing to failure in all four stress quadrants of the Von Mises Envelope (VME), used to ascertain the capacity of a design to withstand given load conditions. When tested in ambient conditions, the connections held successfully at pressures up to 8,000 psi, which was the maximum pressure tested.

Load-test simulations were performed on the expandable liner, and isolated 51/2-in. production casing and hanger, to ensure all potential loads remained within the operational limits of the wellbore architecture. All load simulations resulted in passed conditions, and the engineering and planning proceeded.

Tests showed that during the expansion process, in addition to the inherent weight of the liner, the liner would build up to 116,000 lb of tension, which could not be released safely at surface. With the expandable liner being held in the slips at surface, this build-up had to be accounted for, with respect to both slip crush and the release of the tension between the slips and the casing anchor. Slip crush calculations were performed to determine the length and angle of slips required to prevent the liner from collapsing under the loading. Additionally, a wellhead support system (a type of casing jack) was selected to hold the liner in place below the rotary table. The wellhead support system featured two I-beams mounted on a pair of dual hydraulic cylinder frames and a rotary bowl to hold the casing slips. Upon completion of expansion, the hydraulic cylinders could be lowered to release the tension build-up.

Fig. 1. The schematic shows the MetalSkin expandable liner, which was used to isolate the upper 7,000 ft of production casing, and the packer seat that facilitated setting the packer deeper in the well.

The all-inclusive suite of tests confirmed that a continuous, 7,000-ft string of H₂S-compliant tubing and connections could be expanded safely under the expected well-design loads and sustain well integrity, Fig. 1. With all components, including the newly engineered wellhead seal, qualified; and with the execution procedures meeting all operator, contractor and service provider design and QHSE requirements; the final step was applying the method in the field.

PROJECT EXECUTION

Upon selection of a candidate well and rig-up, the existing tubing and packer were pulled, followed by cleanout and logging runs, which included a caliper and magnetic flux casing image tool to ensure casing and cement integrity.

The operator required two pressure barriers. The liner would be placed across the BOP during expansion. To satisfy the barrier requirements, 2% KCL completion fluid was to be used, along with a bridge plug above the horizontal section. Drilling out the bridge plug raised concerns about potential debris being left in the horizontal section of the well that would need to be pushed to the toe of the well. As an alternative, a 150-ft expandable liner was installed at the desired packer-setting depth, and a retrievable production packer was set with an X-nipple. This would provide the barrier requirement and would be used as the final production packer, avoiding the time and risk of drilling out.

With the packer set, 7,047 ft of expandable liner and cone assembly were run to depth, with the casing slips secured in the rotary bowl above the casing jack. The casing jack was extended 12 in. and the inner string run. The inner string was attached to the bottom cone assembly, expansion initiated with 52,000-lb overpull and the anchor set. At 75,000 lb, the weight of the liner, as calculated, exceeded the required expansion force, thereby allowing it to expand under its own weight, by pulling the cone with the inner string.

Expansion continued for 18 hr and was terminated when the cone was visible above the annular preventer, with sufficient space between the cone and the BOP to perform the initial external casing cut. The casing jack of the wellhead support system was lowered 6 in. to relieve built-up tension and free the slips. At that point, the liner was cut below the cone, and the newly engineered pack-off adapter was installed in the wellhead.

Fig. 2. The cased-hole liner system provides high-pressure ratings and multiple running lengths, using proprietary expandable connections.

A post-run logging suite verified the integrity of the expanded liner and established a baseline for future evaluations. The production tubing was run, and the sand that had been dumped on top of the packer upon installation was flushed. The operation was completed with installation of the tubing, the side-pocket-mandrel gas lift and, finally, the Christmas tree. Once the X-plug was removed, the now-remediated and H₂S-compliant well was delivered to the production team.

As predicted, the expandable liner was run trouble-free to 7,047 ft, effectively isolating the existing casing and casing hanger from H₂S, Fig. 2. The temperature in the hole section below 7,000 ft was above the threshold of hydrogen embrittlement, and did not require isolation. The ID of the liner was expanded to 4.140 in., which was sufficient to allow the gas lift mandrels to be installed. The well was then completed with 23/8-in. tubing, a retrievable production packer and a traditional side-pocket-mandrel gas lift.

The well has since been on continuous gas-lift production with up to triple the pre-reclamation rates and, importantly, with zero HSE issues related to wellbore integrity.  

REFERENCES

1. Contreras, J. D. et al, “Solid expandable solution to qualify existing non-sour service production casing,” IADC/SPE paper 178780, presented at the IADC SPE Drilling Conference, Fort Worth, Texas, March 1–3, 2016.
2. DuBois, P. F. et al, “Correlation of high hydrogen sulfide concentration to deep features, in Eagle Ford shale wells, McMullen County, Texas,” SPE paper 171624, presented at the SPE/CSUR Unconventional Resources Conference–Canada, Calgary, Alberta, Sept. 30–Oct. 2, 2014.
3. Zhang, L., et al, “Effects of temperature and partial pressure on H₂S/CO₂ corrosion of pipeline steel in sour conditions”, NACE paper 11079, presented at CORRISION, Houston, Texas, March 13–17, 2011.
4. Kvarekvål, J. and G. Svenningsen, “Effect of high H₂S partial pressures on localized corrosion of carbon steel,” Institute for Energy Technology, NACE paper 5720, presented at CORROSION, Dallas, Texas, March 15–19, 2015.
5. Setterberg, J. R. and M. E. Evans, “Application of a new method for predicting downhole loading of tubulars during expansion,” SPE/IADC paper 140262, presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, The Netherlands, March 1-3, 2011.