Well A-01A in the Valhall field has been on production since late 1993, but its performance has been unstable with proppant and chalk flowback. Mechanical impairments have been repaired, the subsurface safety valve (SSSV) was locked open, and an insert SSSV was installed in May 2001. Although the control line was repeatedly treated with a pressure-activated sealant, leakage has been a recurring problem.
Recently, a production tubing annulus communication was detected in Well A-01A. The leak point was believed to be at the seal assembly at the bottom of the production tubing string. The operator and service company engineers evaluated the mechanism of the leak and its severity.
In January 2003, 30 bbl of a long-life, high-strength polymer system (HSPS) were placed in the annular space between the 5 1/2-in. production tubing and 9 5/8-in. casing. Applying this polymer system as an annular barrier was a new technique. A temporary gel plug (TGP) consisting of a hydroxy propyl guar polymer and a crosslinker was pumped both ahead and behind the HSPS for placement accuracy and to prevent contamination. Because the well was at low pressure, base oil was used as a displacement fluid. The base oil helped reduce hydrostatic head under placement. The well was kept producing at normal rates during the operation, and pumping was completed within 4 hr with no production loss and no downtime.
Annulus pressure was dramatically reduced from 1,300 psi to less than 250 psi. Some pressure increase was observed following well intervention work, but later pressure stabilized at 600 to 700 psi. When the well was shut in, there was no pressure increase observed in the annulus, while the tubing pressure increased from approximately 800 to 2,000 psi. Currently, the well is producing oil at 2,200 BOPD. Stable annulus pressure and normal production performance indicate that the annular gel plug is effectively blocking the communication. The use of this long-life polymer gel plug as an annular barrier is intended to keep the well producing until a tubing workover is possible and a permanent barrier is established. Payback time for the total cost of this operation is approximately four days.
This paper describes the polymer gel systems, placement technique, operational aspects, and benefits of the method used.
Norwegian safety regulations require that a reservoir have two barriers.1 In the event of a barrier failure, immediate measures must be taken to maintain an adequate safety level. No well activities other than re-establishing the secondary barrier are accepted during failures such as tubing and casing communication. Immediate re-establishment of the permanent barrier may not always be possible in the absence of an available workover rig. The economic losses associated with production shut-in can be significant.
The major cause of communication between tubing and casing in fields with chalk formation has been compaction/subsidence, on both the overburden and the reservoir formations. The leak point in this case was believed to be at the seal bore assembly, caused by damaged packing elements. Under an injection test to determine the extent of the leak, base oil was pumed at 0.9 bbl/min. The pumping pressure eventually decreased from 1,400 to 1,250 psi.
Different treating methods were evaluated, based on the operational complexity, potential negative consequences, safety, economics, and environmental impact. Methods considered included (1) placement of mechanical barriers like straddle or a casing patch inside the production tubing (2) placement of a cement plug, and (3) placement of a polymer gel plug. The mechanical methods were eliminated from the start, because the leak mechanism was believed to be caused by damaged packing elements in the seal assembly. The use of cement as an annular barrier was evaluated further, but then ruled out because of low placement accuracy and the need for tubing mill-out to perform tubing change-out. Ultimately, a relatively new organically crosslinked polymer gel technology was selected and used as an annular barrier to keep the well flowing until a planned tubing change-out could be conducted. This successful operation on Well A-01A demonstrates that communication between production tubing and casing can be blocked effectively. The results offer a promising example of a low-risk, low-cost solution for other wells worldwide.