Is it necessary to install a downhole safety valve in a subsea ... - NTNU

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Is it necessary to install a downhole safety valve in a subsea oil/gas well? 6.2.6 Result of the HAZOP analysis The HAZOP analysis has revealed several hazards. The hazards and its causes should be evaluated in order to reduce the risk related to this procedure. The main hazards related to the BOP handling procedure are delay in operation, dropped BOP and leakage to sea. If the operation is delayed it will result in lost production and extra cost related to hiring of a workover rig and other equipment. If the BOP is dropped this will always lead to a delay, but more serious scenarios may also occur. The BOP may fall down and hit the xmas tree, manifold or other subsea equipment. A damaged x-mas tree is not only a scenario of economic character but there are also environmental consequences related to this. The downhole safety valve (DHSV) will play an important role if the x-mas tree is damaged. If no DHSV is present the leakage of hydrocarbons from the reservoir can be significant. It would be a disaster. If by any chance a DHSV is present the leakages still will be extensive and the damages may require an abandonment of the well. The most frequent finding in this HAZOP is the need for preparation before the different operations begin. It is important that all steps are carefully planned and the testing of the equipment is done properly. Another important issue is the securing of the subsea equipment. This should be considered already when a new well is in the planning phase. If the BOP should be lost, or any other equipment, and hit the subsea equipment the consequences may be enormous. A list of the most important recommended actions derived from this HAZOP analysis is given below. 1. Evaluate the probability of dropping the BOP and potential consequences 2. Make sure the AX-seal is present and adjusted on the BOP and that the BOP is tested and functioning prior to running 3. Make sure the pipe handling system and the iron roughneck is operated correctly 4. Make sure there are enough riser pipes present and that they are stacked the right way 5. Find a satisfactory running and pulling speed on the riser elevator 6. Have redundant lifting gear present on the workover rig if the riser elevator should fail Diploma thesis, NTNU 2002 52
Is it necessary to install a downhole safety valve in a subsea oil/gas well? 7 Conclusions and recommendations for further work 7.1 Conclusions The overall objective has been to determine whether or not a DHSV should be installed in a subsea oil/gas well from a risk point of view. A conclusion is presented in this section. Based on the quantitative findings in this study the DHSV reduces the risk of blowout with approximately 50%. A removal of the DHSV represents an increased failure probability, and two independent and tested well barriers are not present in all cut sets. None of the cut sets do, however, violate a required SIL3 level when the DHSV is removed from the completion. The blowout frequency caused by the DHSV during workover is 1.7E-4 per well year, and 8.5E-5 per well year for a well without a DHSV. The blowout frequency during production is based on the assumption that all occurrences of the ‘TOP’-event, “leakage to the surroundings”, classify as a blowout. During production the blowout frequency is found to be 4.47E-3 per well year for a well with a DHSV, and 1.85E-2 per well year when the DHSV is removed. In addition to the blowout frequency during production and workover a blowout frequency caused by accidental events should be included. The total blowout frequency is found adding up the different contributions: ftotal = fproduction + fintervention + (faccidential event * MFDTaccidential event) The DHSV blowout frequency contribution during installation is not included in this study. There is no data revealing the changes in blowout frequency when the DHSV is removed for the installation phase. The blowout frequencies found in the calculations are of very high. In total a removal of the DHSV increases the blowout frequency by 1.13E-2 per well year. It is reasonable to believe that the calculations in this report are either based on insufficient data, a bad model or calculated errors. Other factors may also have contributed to the high frequency. An alternative calculation method based on the proportion of the frequencies of the ‘TOP’-events, and the experience data found in ref.[7] is applied. In the new calculations a removal of the DHSV will increase the blowout frequency of 3.0E-5 per well year. The author finds this result more reasonable. 50% of the shut-ins of a well leading to a workover are caused by a DHSV failure. A DHSV failure requires a workover generating a loss of oil production of up to $5,6 million. In addition there will also be expenses concerning the rental of a workover rig. A total cost of 20 million dollars per intervention is therefore not unrealistic. The author cannot recommend removing the Downhole safety valve (DHSV) from a subsea oil/gas production well based on the findings in this thesis. Although there may be some economic advantages in removing the DHSV the risk of blowout should be given the greatest attention. In addition to causing pollution, the occurrence of a blowout may in severe cases lead to a bad reputation among consumers and environmental organisations. Diploma thesis, NTNU 2002 53
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Page 69 and 70: APPENDIX A A1 Subsea production sys
Page 71 and 72: A1.3 Well completion A1.3.1 Tubing
Page 73 and 74: A1.5.2 Guidelineless system Several
Page 75 and 76: Appendix B In this appendix a figur
Page 77 and 78: Appendix C Fault trees constructed
Page 79 and 80: Production Wing valve ITL WV Produc
Page 81 and 82: Component: Production Packer Failur
Page 83 and 84: Reliability data dossier Component:
Page 85 and 86: Component: Production wing valve Fa
Page 87 and 88: Component: Crossover line Failure r
Page 89: Appendix F The guide-words used in
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Is it necessary to install a downhole safety valve in a subsea ... - NTNU

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