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Risk analysis on the blowout in deepwater drilling when encountering hydrate-bearing reservoir
Ocean Engineering 170 (2018) 1–5
Contents lists available at ScienceDirect
Ocean Engineering journal homepage: www.elsevier.com/locate/oceaneng
Risk analysis on the blowout in deepwater drilling when encountering hydrate-bearing reservoir
T
Yonghai Gaoa,b, Ye Chena, Xinxin Zhaoa,b, Zhiyuan Wanga,b, Hao Lia,b, Baojiang Suna,b,∗ a b
China University of Petroleum (East China), Qingdao, Shandong, 266580, China National Engineering Laboratory for Testing and Detection Technology of Subsea Equipments, 266580, China
A R T I C LE I N FO
A B S T R A C T
Keywords: Deepwater Hydrate Well control Blowout Risk analysis Fault tree
Significant risks are associated with deepwater drilling when encountering hydrate-bearing reservoir. This paper analyses the influencing factors of geologic, environmental and drilling risk as well as their impacts on safety operations in drilling of hydrate-bearing reservoir. A fault tree is established based on a large-scale blowout as the top event. The key risk factors are analysed and the methods used to control these risks are identified. Drilling design, well control design and risk control measures must maintain precise wellbore pressure and temperature in drilling hydrate-bearing reservoir under deepwater conditions, which inhibit hydrate dissociation and reduce the risk of large-scale blowout.
1. Introduction Natural gas hydrate may constitute a significant future energy source due to its huge reserves and clear combustion (Collet, 2000; Kvenvolden, 1993; Yao, 2005). Hydrates are widely distributed 500 m below the deepwater mud line, where the pressure is high and the temperature is low (Boswell, 2011; Makogon, 2007; Pooladi, 2004; Profio, 2009; Chong, 2015; Liu, 2006a). Currently, Japan, China, the United States, India, South Korea and other countries have accelerated the exploration and development of natural gas hydrate (Chen, 2003; Heo, 2009; Ashutosh, 2012; Lee, 2005; Matsushima, 2005). Drilling operations are essential for exploration and development procedures. Since the marine hydrate-bearing reservoir is located in deepwater and the hydrate can easily decompose, a significant risk is associated with deepwater drilling when encountering hydrate-bearing reservoir (Zhou, 2013). Compared to traditional deepwater drilling operations, the various characteristics and difficulties associated with drilling and cementing in deepwater hydrate-bearing reservoir can be summarized as follows (Boswell, 2009; Freij, 2007; Liu, 2010; Toon, 2002): First, the hydratebearing reservoir is shallow, and the reaction time is short when sudden accidents occur. Second, the hydrate-bearing layers can partially decompose during the drilling process due to pressure and temperature disturbances. Thus, deepwater drilling in hydrate-bearing reservoir encompasses significant risks, which are specifically embodied in two phases. The hydrate dissociation caused by pressure and temperature
∗
disturbances can lead to well instability, the products of hydrate dissociation, especially the output gas may infiltrate the wellbore, leading to well kicks or blowouts (Birchwood, 2005; Khabibulling, 2011; Khurshid, 2010; Locat, 2002; Sultan, 2004). Therefore, deepwater hydrate drilling requires more specific equipment than conventional offshore drilling. In addition, the significant risks associated with deepwater drilling require more safety measures than traditional operations. The potential risks, particularly the well control risk, must be analysed and evaluated before drilling operations commence to ensure that the deepwater drilling and completion engineering processes can be effectively completed (Dou, 2012; Liang, 2003; Qing, 2010). Fault trees are used to qualitatively, quantitatively and logically analyse the system engineering risks (Gao, 2008; Liu, 2006b). This paper uses a fault tree analysis method to analyse the drilling including cementing risks in a deepwater hydrate-bearing reservoir and determine the importance of various events. The most dangerous events and their influencing factors are noted and discussed. 2. The major risk factors of deepwater drilling when encountering hydrate-bearing reservoir Risks in deepwater drilling of hydrate-bearing reservoirs are more extensive and significant than risks associated with conventional onshore drilling and deepwater drilling in non-hydrate layers. The major risk is associated with hydrate dissociation in the pores, which can lead to well control risks (Barker and Gomez, 1989). The main risks of the
Corresponding author. School of Petroleum Engineering, China University of Petroleum, Qingdao, China. E-mail address: [email protected] (B. Sun).
https://doi.org/10.1016/j.oceaneng.2018.08.056 Received 18 April 2018; Received in revised form 3 August 2018; Accepted 27 August 2018 0029-8018/ © 2018 Published by Elsevier Ltd.
Ocean Engineering 170 (2018) 1–5
Y. Gao et al.
Disaster caused by blowout Seawater temperature gradient
Sea water
Normal
Seafloor
Sticking Gas escape
Borehole enlargement
Geothermal gradient
Blocking BOP blocking by hydrate reformation
Collapse
Hydrate stable zone
Phase boundary
Hydrate reservoir
Fig. 1. The main risks of the deep water hydrate-bearing reservoir drilling.
3. Risk fault tree model and analysis of blowout in drilling of hydrate-bearing reservoir in deep-water environment
deepwater hydrate-bearing reservoir drilling are shown in Fig. 1. Hydrate only exists in certain pressure and temperature environments. When drilling in deepwater hydrate-bearing layers, the initial reservoir pressure and temperature are disturbed by circulating drilling fluids. Hydrate dissociation in the pores can cause significant issues under the certain conditions, including reservoir instability, landslide and collapse, which may cause drill pipe-sticking. In addition, hydrate dissociation can lead to the subsidence and collapse of the reservoir, as well as cause underwater wellhead BOP instabilities (Durham, 2003; Winter 2002). The produced natural gas and water flow into the wellbore after the hydrate dissociation in the pores, altering the drilling fluid composition and affecting the drilling equipment. Hydrate dissociation can lead to gas invasion, which causes gas to cycle with the drilling fluid. The gas then forms hydrate in the wellbore and BOP under appropriate temperature and pressure. The risks are listed as follows (Botrel, 2001; Dou, 2006): the BOP and the space below it become blocked, disallowing precise pressure detection in that area; the choke pipes become blocked and the cycle operation cannot recover; the BOP closed gate valve becomes blocked and cannot reopen, causing the BOP to fail; and the dissociated gas of hydrate mixes with the drilling fluid, decreasing the drilling fluid density and well pressure, which induces additional hydrate dissociation. The hydrate dissociation cycle and decreased well pressure can increase the potential for blowouts, damage drilling equipment and cause personnel casualties. The well control risks associated with conventional deepwater drilling also exist for deepwater hydrate drilling, including risks linked to geological conditions, low temperature conditions, well control equipment, water depth, kill line size, well surge detection methods, shut-in and well killing methods and the ability to address unexpected events (Fossli, 2006; Isambourg, 2002; Rommetveit, 1997; Shanks, 2003).
Fault tree risk analyses are used to determine the top event, bottom event and minimal cut sets, and have been widely applied on engineering evaluation (Mentes, 2011; Wang, 2011; Lavasani, 2015; Cheliyan, 2017). Fault tree models are the easiest and most used technique in dependability assessment (Talebberrouane and Lounis, 2016). Risk analysis fault tree in deepwater drilling when encountering hydrate-bearing reservoir is established based on hydrate-bearing reservoir characteristics and conventional deepwater drilling risk factors. These parameters are used to estimate the probability of occurrence of the top event. 3.1. Establishing the fault tree The largest potential accident associated with deepwater drilling is large-scale blowout. Therefore, large-scale blowout is established as the top event in the fault tree model, allowing well control risks to be analysed. Well kicks occur when the bottom pressure is less than the formation pressure. Insufficient bottom pressure can be caused by gas invasion due to insufficient drilling fluid volume, small drilling fluid density, large suction pressure, overflow, long pump off time, mud leakage and hydrate dissociation. Pressure differences may also be caused by anthropogenic factors, such as improper operation and design. Blowouts can occur if well kick is not recognized in a sufficient amount of time. Large-scale blowouts typically occur when the wellhead pressure exceeds the safety limits of the shut-in and well killing methods. Operation, design and equipment shortcomings can also lead to largescale blowouts. Hydrate dissociation due to the heat of cementing slurry can significantly impact cementing quality, which also may cause largescale blowouts. An assessment model was established to clearly and comprehensively identify the causes of blowouts by using the fault tree method. Based on the analysis of these risk factors, the fault tree is shown in 2
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Fig. 2. Fault tree analysis diagram of blowouts associated with deepwater hydrate-bearing reservoir drilling.
P5 = {X15,X16, X17, X18,X19,X27}
Fig. 2. The names of each event have been listed in the following Table 1 in section 3.2 to help the fault tree being neater.
3.3. Structural degree of importance analysis
3.2. Minimal radius set calculations
The importance of the issues to large-scale blowout can be obtained, as shown in formula (7) from the minimal radius sets. Event 20 and 27 were identified as the most important issues, suggesting that they can most easily induce a large-scale blowout.
The minimal cut and minimal radius sets are used in qualitative and quantitative analyses to provide information that is used to control the occurrence of the top event. The minimal cut and radius sets depend on the fault tree structure. The fault tree in this study includes 143 minimal cut sets, which is too complicated to providing a clear and concise analysis of the top event. However, the fault tree includes 5 minimal radius sets, which can effectively provide accident prevention measures. Therefore, the deepwater hydrate-bearing reservoir drilling risks are analysed using minimal radius sets based on a large-scale blowout as the top fault tree event. The minimal cut sets can be obtained by altering the “And Gates” and “Or Gates” of the fault tree so that all occurred events can be changed into not. Then, the result is translated into the minimal radius sets. The minimal cut sets of the success tree can be obtained using a Boolean algebra simplification method with a structure function given by formula (1).
T ′ = A′ + B′ = C′D′ + N ′O′ = (E′X 1′)(F ′G′) + (X 20′ + P′Q′X 19′)(X 27′ + S′) = (X 1′X 2′X 3′X 4′X 5′X 6′X 7′X 8′X 9′X 10′X 11′X 12′X 13′X 14′) + (X 20′X 27′) + (X 17′X 18′X 20′X 21′X 22′X 23′X 24′X 25′X 26′) + (X 15′X 16′X 17′X 18′X 19′X 21′X 22′X 23′X 24′X 25′X 26′) + (X 15′X 16′X 17′X 18′X 19′X 27′)
(6)
I(20) = I(27) > I(17) = I(18) > I(15) = I(16) > I(21) = I(22) = I(23) = I(24) = I(25) = I(26) > I(1) = I(2) = I(3) = I(4) = I(5) = I(6) = I(7) = I(8) = I(9) = I(10) = I(11) = I(12) = I(13) = I(14) (7) Large-scale blowouts mainly occur when the wellhead pressure exceeds the safety limits, which is caused by design, operation and equipment failures during the shut-in and well killing processes. BOP failure caused by design, manufacture and maintenance flaws and hydrate dissociation can also result in a large-scale blowout. All other factors exhibit nearly identical importance degrees. Therefore, controlling the risk of the top event by eliminating the risk of a single event is difficult, indicating that deepwater hydrate-bearing reservoir drilling possesses greater inherent risk than conventional drilling. Based on statistics and empirical analysis of field cases (Abimbola, 2014; Vinnem, 2014), the probabilities of the 27 basic events in the fault tree can be assumed as shown in Table 1. The well control success rate is given by formula (8) and the blowout risk probability is given by formula (9).
(1)
The minimal radius sets can be obtained from formula (1) using formulas (2)–(6).
P1 = {X1,X2, X3, X4, X5, X6, X7, X8, X9, X10, X11, X12, X13, X14}
(2)
P2 = {X20,X27}
(3)
P3 = {X17,X18, X20, X21, X22, X23, X24, X25, X26}
(4)
p′ = 1 − (1 − 0.85 × 0.953 × 0.985 × 0.92 × 0.9 × 0.963) × (1 − 0.982) × (1 − 0.97 × 0.962 × 0.986) × (1 − 0.95 × 0.86 × 0.97 × 0.963 × 0.985) × (1 − 0.95 × 0.86 × 0.97 × 0.962 × 0.98) = 0.999556 (8)
P4 = {X15,X16, X17, X18,X19,X21,X22, X23, X24, X25, X26}
(5)
p = 1 − p′ = 0.000444 3
(9)
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events 12, 17, 24 and 25 are larger than the probabilities of conventional deepwater drilling events. Assuming that the probability of event 12 is 0.06, the probability of event 17 is 0.045, the probabilities of events 24 and 25 are 0.03. Then the well control success rate is given by formula (12), the blowout risk probability is given by formula (13).
Table 1 The corresponding events in the fault tree with their basic probability. Sequence Number
Event Name
Probability
T A B C D E F G H I J K L M N O P Q R S X1
Large scale blowout Blowout Control failure Blowout in drilling Blowout in cementing Inadequate bottom pressure Leakage in cementing Cement pollution caused by gas channeling Insufficient drilling fluid volume Overflow found not in time Excessive suction pressure Inadequate drilling fluid density Leakage in drilling Going down too fast Shut in failure Well killing failure Operation failure Equipment failure Operation failure Equipment failure Drilling the abnormal-high pressure oil-gas reservoir shallow water and shallow gas Grouting not timely Excessive drilling fluid density Design failure Operation failure Design calculation error Inaccurate formation pressure prediction Drilling fluid pipe leakage Hydrate layer dissociated gas into the wellbore Incorrect detection method Personnel negligence Long time for pump off Excessive cement paste density Casing or seal failure Step execution error Incomplete execution Design, manufacture and maintenance failure of BOP Underwater wellhead fault caused by hydrate dissociation in the pores Unreasonable design method (Shut in) Exceed the safety limit of shut in Throttle line over loss due to unreasonable drilling fluid pump velocity Unreasonable throttle control Unreasonable design calculation and method Block up caused by formation of hydrate from decomposing gas Throttle valve malfunction Well killing pump malfunction Exceed the safety limit of well killing
/ / / / / / / / / / / / / / / / / / / / 0.15
X2 X3 X4 X5 X6 X7 X8 X9 X10 X11 X12 X13 X14 X15 X16 X17 X18 X19 X20 X21 X22 X23 X24 X25 X26 X27
p′ = 1 − (1 − 0.85 × 0.953 × 0.985 × 0.92 × 0.9 × 0.962 × 0.94) × (1 − 0.982) × (1 − 0.955 × 0.962 × 0.984 × 0.972) × (1 − 0.95 × 0.86 × 0.955 × 0.972 × 0.963 × 0.983) × (1 − 0.95 × 0.86 × 0.955 × 0.962 × 0.98) = 0.999434 (12)
p = 1 − p′ = 0.000444
This result indicates that hydrates increase the risk probabilities for large-scale blowouts, which is 2.35 times larger than the risk associated with conventional deepwater drilling. Therefore, deepwater hydratebearing reservoir pre-assessments should be improved, and related preventive measures should be taken. Immediate measures must be taken if a large-scale accident occurs. 4. The risk control measures in deepwater hydrate-bearing reservoir drilling process
0.05 0.02 0.05 0.05 0.02 0.08 0.02 0.1 0.04 0.02 0.04 0.02 0.04 0.05 0.14 0.03
According to the analysis of the large-scale blowouts possibility of deepwater drilling when encountering hydrate-bearing reservoir, control methods should be conducted. (1) Event 20 and event 27 are the most important issues, that's mean large-scale blowouts mainly occur when the wellhead pressure exceeds the safety limits, which is caused by design, operation and equipment failures during the shut-in and well killing processes. Risk control designs must be optimal. The optimal design methodology includes engineering design, hydraulic design, timely well kick controls and a suitable tripping speed. The well control equipment must be integrated and effective, especially to minimize the failure effects of the equipment. The design methods and operations cannot exceed the safety limits. Prevention measures specific to hydrates must be taken prior to drilling, including safety training for the relevant workers, in-well control operations and effective job preparation. (2) In addition to the conventional well controls, hydrate dissociation risks should be accounted for when drilling in hydrate-bearing layers. - The wellbore pressure and temperature must be controlled to prevent hydrate dissociation during the drilling process. The wellbore pressure and temperature directly affect the hydrate stability, which is related to the wellbore pressure balance, wellbore wall stability, casing strength, drilling string strength and well control safety. Potential problems and risks must be analysed before drilling, and the optimum parameters must be selected to maintain stable wellbore pressures and temperatures. - Gas will gather in the BOP and other areas, posing a significant hydrate reformation risk in case of the hydrate dissociation in the layers are encountered. Therefore, the wellbore pressure and temperature should be calculated and supervised during the shutin period, and certain hydrate inhibitor should be injected into the BOP. - The hydrate dissociation risk caused by thermal cementing disturbances must be controlled. Cement slurry with low hydration heat must be designed because of high heat of hydration of conventional well cements. In addition, thermal cementing disturbances should be properly analysed in hydrate-bearing layers.
0.04 0.04 0.02 0.02 0.02 0.04 0.02 0.02 0.02 0.02
Compared to conventional deepwater drilling, the probabilities of events 9, 18 and 21 are 0. Thus, the conventional deepwater drilling well control success rate is given by formula (10) and the blowout risk probability is given by formula (11).
p′ = 1 − (1 − 0.85 × 0.953 × 0.985 × 0.92 × 0.963) × (1 − 0.982) × (1 − 0.97 × 0.96 × 0.985) × (1 − 0.95 × 0.86 × 0.97 × 0.962 × 0.984 ) × (1 − 0.95 × 0.86 × 0.97 × 0.96 × 0.98) = 0.999759 (10) p = 1 − p′ = 0.000241
(13)
(11)
The blowout risk in deepwater when encountering hydrate-bearing reservoir is nearly 84% higher than the conventional drilling based on the same conditions. Because the hydrate is sensitive to temperature and pressure, gas invasion caused by hydrate dissociation and hydrate regeneration in pipe and BOP must be addressed, the probabilities of 4
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5. Conclusions
Dou, B., et al., 2012. Mechanical stability of strata above a gas hydrate exploitation well. Marine Geology Frontiers 28, 30–34. Durham, William B., et al., 2003. The strength and rheology of methane clathrate hydrate. Journal of Geophysical Research-Atmospheres 108 (4), 237–241. Fossli, B., Sangesland, S., 2006. Controlled mud-cap drilling for subsea applications: wellcontrol challenges in deep waters. SPE Drill. Complet. 21 (2), 133–140. Freij, Ayoub, R., et al., 2007. A wellbore stability model for hydrate bearing sediments. J. Petrol. Sci. Eng. 57 (1), 209–220. Gao, Y., Sun, B., Cao, S., 2008. Risk assessment on well control in deepwater drilling based on fault tree analysis. Oil Drilling and Production Technology 30, 23–27. Heo, E., Kim, D., Lee, S., 2009. Analysis of gas hydrate development R&D Program of Korea using technology-product diagram. In: AGU Fall Meeting Abstracts, San Francisco, California, America, December 14–18. Isambourg, P., Simondin, A., 2002. Offsetting kill and choke lines friction losses for deepwater well control the field test. In: IADC/SPE Drilling Conference, Dallas, Texas, America, February 26–28. Khabibullin, T., Falcone, G., Teodoriu, C., 2011. Drilling through gas-hydrate sediments: managing wellbore-stability risks. SPE Drill. Complet. 26 (2), 287–294. Khurshid, I., et al., 2010. Heat transfer and well bore stability analysis in hydrate bearing zone in the East Sea, South Korea. In: Offshore Technology Conference, Houston, Texas, America, May3–6. Kvenvolden, K.A., 1993. A primer on gas hydrates. The Future of Energy Gases 1570, 279–291. Lavasani, et al., 2015. Utilisation of fuzzy fault tree analysis for quantified risk analysis of leakage in abandoned oil and natural-gas wells. Ocean Eng. 108, 729–737. Lee, J.H., et al., 2005. A seismic survey to detect natural gas hydrate in the east sea of Korea. Mar. Geophys. Res. 26 (1), 51–59. Liang, Y.J., et al., 2003. Key technique and countermeasures for natural gas hydrate drilling. Explor. Eng. 30, 45–48. Liu, F., 2010. Hazards in marine hydrocarbon exploitation engineering due to gas hydrate. International Petroleum Economics 18 (09), 63–67 +95. Liu, H., et al., 2006a. Status of research on nature gas hydrate drilling and production techniques. Drill. Prod. Technol. 34, 87–90. Liu, G., Jia, G., Yang, X., 2006b. The application of risk tree analysis in the drilling engineering accidents. Fault-Block Oil Gas Field 13 (3), 69–71. Locat, Jacques, Lee, Homa J., 2002. Submarine landslides: advances and challenges. Can. Geotech. J. 39 (39), 193–212. Makogon, Y.F., et al., 2007. Natural gas-hydrates—a potential energy source for the 21st Century. J. Petrol. Sci. Eng. 56 (1), 14–31. Matsushima, J., 2005. Characteristics of sonic waveform attenuation in methane hydratebearing sediments at the Nankai Trough exploratory well and comparison of several methods for estimating attenuation. Proceeding of the SEGJ Conference 112, 114–117. Mentes, A., et al., 2011. An application of fuzzy fault tree analysis for spread mooring systems. Ocean Eng. 38 (2–3), 285–294. Pooladi, Darvish, M., 2004. Gas production from hydrate reservoirs and its modeling. J. Petrol. Technol. 56 (6), 65–71. Profio, P.D., et al., 2009. Comparison of hydrogen hydrates with existing hydrogen storage technologies: energetic and economic evaluations. Int. J. Hydrogen Energy 34 (22), 9173–9180. Qingtao, M.A., 2010. Geologic hazard analysis of natural gas hydrate in drilling. Stud. Mar. Sin. 3, 72–78. Rommetveit, R., Bjorkevoll, K.S., 1997. Temperature and pressure effects on drilling fluid rheology and ECD in very deep wells. In: SPE/IADC Middle East Drilling Technology Conference, Bahrain, November 23–25. Shanks, E., Dykes, A., Quiliei, M., 2003. Deepwater BOP control systems: a look at reliability issues. In: Offshore Technology Conference, Houston, Texas, America, May 5–8. Sultan, N., Cochonat, P., Foucher, J.P., Mienert, J., 2004. Effect of gas hydrates melting on seafloor slope instability. Mar. Geol. 213 (1), 379–401. Talebberrouane, M., Lounis, Z., 2016. Safety assessment of flare system by fault tree analysis. J. Chem. Technol. Metall 51 (2), 229–234. Toon, J., 2002. Ice that burns-methane gas hydrates offer a potential energy reserve, danger to petroleum drilling and global warming concern. Res. Horiz. 19 (3), 11–13. Vinnem, J.E., 2014. Offshore Risk Assessment. Springer, London. Wang, Y.F., et al., 2011. Probability analysis of offshore fire by incorporating human and organizational factor. Ocean Eng. 38 (17–18), 2042–2055. Winter, W.J., et al., 2002. Sediment properties associated with gas hydrate formation. In: The 4th International Conference on Gas Hydrates, Yokohama, Japan, May 19–23. Yao, B.C., Wu, N.Y., 2005. Gas hydrate, a future energy resource. Earth Sci. Front. 12 (1), 225–233. Zhou, F., 2013. Overview of deepwater drilling engineering risk. Offshore Oil 33 (2), 113–118.
Combining the hydrate-bearing reservoir characteristics and deepwater drilling factor risks, a fault tree was established based on a largescale blowout as the top event. The following conclusions were ascertained based on the fault tree analysis: (1) Shut in failure and well killing failure because of exceeding the safety of limit is the first risk in hydrate formation drilling, equipment failure caused by hydrate dissociation and design, manufacture and maintenance of BOP is the second reason. (2) Risks in drilling of hydrate-bearing reservoirs are clearly higher than the conventional drilling risks in deepwater environment due to hydrate dissociation. Therefore, pre-assessments and preventative measures must be improved in deepwater drilling when encountering hydrate formation. Acknowledgments The authors gratefully acknowledge the financial support by the National Basic Research Program of China (2015CB251200), Program for Changjiang Scholars and Innovative Research Team in University of China (NO. IRT_14R58), National Natural Science Foundation—Outstanding Youth Foundation (51622405), National Natural Science Foundation (51876222) and National Key Research and Development Program of China (NO. 2017YFC0307304). Appendix T′—structure function of fault tree, used to describe the minimal cut sets of the success tree in this research. P—the minimal radius sets of the fault tree. I—the importance of issues. p—the blowout risk probability. p’— the well control success rate. References Abimbola, M., Khan, F., Khakzad, N., 2014. Dynamic safety risk analysis of offshore drilling. J. Loss Prev. Process. Ind. 30 (3), 74–85. Ashutosh, Kumar Jha, et al., 2012. Will gas hydrate lying on oceanic floors in India solve its energy problem? A futuristic approach. In: SPE Europec/EAGE Annual Conference, Copenhagen, Denmark, June 4–7. Barker, J.W., Gomez, R.K., 1989. Formation of hydrates during deepwater drilling operation. J. Petrol. Technol. 41 (3), 297–301. Birchwood, R., et al., 2005. Wellbore stability model for marine sediments containing gas hydrates. In: American Association of Drilling Engineers National Technical Conference and Exhibition, Houston, Texas, America, April 5–7. Boswell, R., 2009. Is gas hydrate energy within reach? Science 325 (5943), 957–958. Boswell, R., Collett, T.S., 2011. Current perspectives on gas hydrate resources. Energy Environ. Sci. 4 (4), 1206–1215. Botrel, T., 2001. Hydrates prevention and removal in ultra-deepwater drilling systems. In: Offshore Technology Conference, Houston, Texas, America, May 1–3. Cheliyan, A.S., Bhattacharyya, S.K., 2017. Fuzzy fault tree analysis of oil and gas leakage in subsea production systems. J. Ocean Eng. Sci. 3 (1), 38–48. Chen, D.F., et al., 2003. Proceeding of gas hydrate research and development in US. Adv. Earth Sci. 18 (2), 321–325. Chong, Z.R., et al., 2015. Review of natural gas hydrates as an energy resource: prospects and challenges. Appl. Energy 162, 1633–1652. Collett, T.S., 2000. Natural Gas Hydrate: Natural Gas Hydrate as a Potential Energy Resource. Springer, Dordrecht. Dou, Y., Guan, Z., Xu, Y., 2006. A review and prospect for the development of offshore drilling. Offshore Oil 26, 64–67.
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Ocean Engineering journal homepage: www.elsevier.com/locate/oceaneng
Risk analysis on the blowout in deepwater drilling when encountering hydrate-bearing reservoir
T
Yonghai Gaoa,b, Ye Chena, Xinxin Zhaoa,b, Zhiyuan Wanga,b, Hao Lia,b, Baojiang Suna,b,∗ a b
China University of Petroleum (East China), Qingdao, Shandong, 266580, China National Engineering Laboratory for Testing and Detection Technology of Subsea Equipments, 266580, China
A R T I C LE I N FO
A B S T R A C T
Keywords: Deepwater Hydrate Well control Blowout Risk analysis Fault tree
Significant risks are associated with deepwater drilling when encountering hydrate-bearing reservoir. This paper analyses the influencing factors of geologic, environmental and drilling risk as well as their impacts on safety operations in drilling of hydrate-bearing reservoir. A fault tree is established based on a large-scale blowout as the top event. The key risk factors are analysed and the methods used to control these risks are identified. Drilling design, well control design and risk control measures must maintain precise wellbore pressure and temperature in drilling hydrate-bearing reservoir under deepwater conditions, which inhibit hydrate dissociation and reduce the risk of large-scale blowout.
1. Introduction Natural gas hydrate may constitute a significant future energy source due to its huge reserves and clear combustion (Collet, 2000; Kvenvolden, 1993; Yao, 2005). Hydrates are widely distributed 500 m below the deepwater mud line, where the pressure is high and the temperature is low (Boswell, 2011; Makogon, 2007; Pooladi, 2004; Profio, 2009; Chong, 2015; Liu, 2006a). Currently, Japan, China, the United States, India, South Korea and other countries have accelerated the exploration and development of natural gas hydrate (Chen, 2003; Heo, 2009; Ashutosh, 2012; Lee, 2005; Matsushima, 2005). Drilling operations are essential for exploration and development procedures. Since the marine hydrate-bearing reservoir is located in deepwater and the hydrate can easily decompose, a significant risk is associated with deepwater drilling when encountering hydrate-bearing reservoir (Zhou, 2013). Compared to traditional deepwater drilling operations, the various characteristics and difficulties associated with drilling and cementing in deepwater hydrate-bearing reservoir can be summarized as follows (Boswell, 2009; Freij, 2007; Liu, 2010; Toon, 2002): First, the hydratebearing reservoir is shallow, and the reaction time is short when sudden accidents occur. Second, the hydrate-bearing layers can partially decompose during the drilling process due to pressure and temperature disturbances. Thus, deepwater drilling in hydrate-bearing reservoir encompasses significant risks, which are specifically embodied in two phases. The hydrate dissociation caused by pressure and temperature
∗
disturbances can lead to well instability, the products of hydrate dissociation, especially the output gas may infiltrate the wellbore, leading to well kicks or blowouts (Birchwood, 2005; Khabibulling, 2011; Khurshid, 2010; Locat, 2002; Sultan, 2004). Therefore, deepwater hydrate drilling requires more specific equipment than conventional offshore drilling. In addition, the significant risks associated with deepwater drilling require more safety measures than traditional operations. The potential risks, particularly the well control risk, must be analysed and evaluated before drilling operations commence to ensure that the deepwater drilling and completion engineering processes can be effectively completed (Dou, 2012; Liang, 2003; Qing, 2010). Fault trees are used to qualitatively, quantitatively and logically analyse the system engineering risks (Gao, 2008; Liu, 2006b). This paper uses a fault tree analysis method to analyse the drilling including cementing risks in a deepwater hydrate-bearing reservoir and determine the importance of various events. The most dangerous events and their influencing factors are noted and discussed. 2. The major risk factors of deepwater drilling when encountering hydrate-bearing reservoir Risks in deepwater drilling of hydrate-bearing reservoirs are more extensive and significant than risks associated with conventional onshore drilling and deepwater drilling in non-hydrate layers. The major risk is associated with hydrate dissociation in the pores, which can lead to well control risks (Barker and Gomez, 1989). The main risks of the
Corresponding author. School of Petroleum Engineering, China University of Petroleum, Qingdao, China. E-mail address: [email protected] (B. Sun).
https://doi.org/10.1016/j.oceaneng.2018.08.056 Received 18 April 2018; Received in revised form 3 August 2018; Accepted 27 August 2018 0029-8018/ © 2018 Published by Elsevier Ltd.
Ocean Engineering 170 (2018) 1–5
Y. Gao et al.
Disaster caused by blowout Seawater temperature gradient
Sea water
Normal
Seafloor
Sticking Gas escape
Borehole enlargement
Geothermal gradient
Blocking BOP blocking by hydrate reformation
Collapse
Hydrate stable zone
Phase boundary
Hydrate reservoir
Fig. 1. The main risks of the deep water hydrate-bearing reservoir drilling.
3. Risk fault tree model and analysis of blowout in drilling of hydrate-bearing reservoir in deep-water environment
deepwater hydrate-bearing reservoir drilling are shown in Fig. 1. Hydrate only exists in certain pressure and temperature environments. When drilling in deepwater hydrate-bearing layers, the initial reservoir pressure and temperature are disturbed by circulating drilling fluids. Hydrate dissociation in the pores can cause significant issues under the certain conditions, including reservoir instability, landslide and collapse, which may cause drill pipe-sticking. In addition, hydrate dissociation can lead to the subsidence and collapse of the reservoir, as well as cause underwater wellhead BOP instabilities (Durham, 2003; Winter 2002). The produced natural gas and water flow into the wellbore after the hydrate dissociation in the pores, altering the drilling fluid composition and affecting the drilling equipment. Hydrate dissociation can lead to gas invasion, which causes gas to cycle with the drilling fluid. The gas then forms hydrate in the wellbore and BOP under appropriate temperature and pressure. The risks are listed as follows (Botrel, 2001; Dou, 2006): the BOP and the space below it become blocked, disallowing precise pressure detection in that area; the choke pipes become blocked and the cycle operation cannot recover; the BOP closed gate valve becomes blocked and cannot reopen, causing the BOP to fail; and the dissociated gas of hydrate mixes with the drilling fluid, decreasing the drilling fluid density and well pressure, which induces additional hydrate dissociation. The hydrate dissociation cycle and decreased well pressure can increase the potential for blowouts, damage drilling equipment and cause personnel casualties. The well control risks associated with conventional deepwater drilling also exist for deepwater hydrate drilling, including risks linked to geological conditions, low temperature conditions, well control equipment, water depth, kill line size, well surge detection methods, shut-in and well killing methods and the ability to address unexpected events (Fossli, 2006; Isambourg, 2002; Rommetveit, 1997; Shanks, 2003).
Fault tree risk analyses are used to determine the top event, bottom event and minimal cut sets, and have been widely applied on engineering evaluation (Mentes, 2011; Wang, 2011; Lavasani, 2015; Cheliyan, 2017). Fault tree models are the easiest and most used technique in dependability assessment (Talebberrouane and Lounis, 2016). Risk analysis fault tree in deepwater drilling when encountering hydrate-bearing reservoir is established based on hydrate-bearing reservoir characteristics and conventional deepwater drilling risk factors. These parameters are used to estimate the probability of occurrence of the top event. 3.1. Establishing the fault tree The largest potential accident associated with deepwater drilling is large-scale blowout. Therefore, large-scale blowout is established as the top event in the fault tree model, allowing well control risks to be analysed. Well kicks occur when the bottom pressure is less than the formation pressure. Insufficient bottom pressure can be caused by gas invasion due to insufficient drilling fluid volume, small drilling fluid density, large suction pressure, overflow, long pump off time, mud leakage and hydrate dissociation. Pressure differences may also be caused by anthropogenic factors, such as improper operation and design. Blowouts can occur if well kick is not recognized in a sufficient amount of time. Large-scale blowouts typically occur when the wellhead pressure exceeds the safety limits of the shut-in and well killing methods. Operation, design and equipment shortcomings can also lead to largescale blowouts. Hydrate dissociation due to the heat of cementing slurry can significantly impact cementing quality, which also may cause largescale blowouts. An assessment model was established to clearly and comprehensively identify the causes of blowouts by using the fault tree method. Based on the analysis of these risk factors, the fault tree is shown in 2
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Fig. 2. Fault tree analysis diagram of blowouts associated with deepwater hydrate-bearing reservoir drilling.
P5 = {X15,X16, X17, X18,X19,X27}
Fig. 2. The names of each event have been listed in the following Table 1 in section 3.2 to help the fault tree being neater.
3.3. Structural degree of importance analysis
3.2. Minimal radius set calculations
The importance of the issues to large-scale blowout can be obtained, as shown in formula (7) from the minimal radius sets. Event 20 and 27 were identified as the most important issues, suggesting that they can most easily induce a large-scale blowout.
The minimal cut and minimal radius sets are used in qualitative and quantitative analyses to provide information that is used to control the occurrence of the top event. The minimal cut and radius sets depend on the fault tree structure. The fault tree in this study includes 143 minimal cut sets, which is too complicated to providing a clear and concise analysis of the top event. However, the fault tree includes 5 minimal radius sets, which can effectively provide accident prevention measures. Therefore, the deepwater hydrate-bearing reservoir drilling risks are analysed using minimal radius sets based on a large-scale blowout as the top fault tree event. The minimal cut sets can be obtained by altering the “And Gates” and “Or Gates” of the fault tree so that all occurred events can be changed into not. Then, the result is translated into the minimal radius sets. The minimal cut sets of the success tree can be obtained using a Boolean algebra simplification method with a structure function given by formula (1).
T ′ = A′ + B′ = C′D′ + N ′O′ = (E′X 1′)(F ′G′) + (X 20′ + P′Q′X 19′)(X 27′ + S′) = (X 1′X 2′X 3′X 4′X 5′X 6′X 7′X 8′X 9′X 10′X 11′X 12′X 13′X 14′) + (X 20′X 27′) + (X 17′X 18′X 20′X 21′X 22′X 23′X 24′X 25′X 26′) + (X 15′X 16′X 17′X 18′X 19′X 21′X 22′X 23′X 24′X 25′X 26′) + (X 15′X 16′X 17′X 18′X 19′X 27′)
(6)
I(20) = I(27) > I(17) = I(18) > I(15) = I(16) > I(21) = I(22) = I(23) = I(24) = I(25) = I(26) > I(1) = I(2) = I(3) = I(4) = I(5) = I(6) = I(7) = I(8) = I(9) = I(10) = I(11) = I(12) = I(13) = I(14) (7) Large-scale blowouts mainly occur when the wellhead pressure exceeds the safety limits, which is caused by design, operation and equipment failures during the shut-in and well killing processes. BOP failure caused by design, manufacture and maintenance flaws and hydrate dissociation can also result in a large-scale blowout. All other factors exhibit nearly identical importance degrees. Therefore, controlling the risk of the top event by eliminating the risk of a single event is difficult, indicating that deepwater hydrate-bearing reservoir drilling possesses greater inherent risk than conventional drilling. Based on statistics and empirical analysis of field cases (Abimbola, 2014; Vinnem, 2014), the probabilities of the 27 basic events in the fault tree can be assumed as shown in Table 1. The well control success rate is given by formula (8) and the blowout risk probability is given by formula (9).
(1)
The minimal radius sets can be obtained from formula (1) using formulas (2)–(6).
P1 = {X1,X2, X3, X4, X5, X6, X7, X8, X9, X10, X11, X12, X13, X14}
(2)
P2 = {X20,X27}
(3)
P3 = {X17,X18, X20, X21, X22, X23, X24, X25, X26}
(4)
p′ = 1 − (1 − 0.85 × 0.953 × 0.985 × 0.92 × 0.9 × 0.963) × (1 − 0.982) × (1 − 0.97 × 0.962 × 0.986) × (1 − 0.95 × 0.86 × 0.97 × 0.963 × 0.985) × (1 − 0.95 × 0.86 × 0.97 × 0.962 × 0.98) = 0.999556 (8)
P4 = {X15,X16, X17, X18,X19,X21,X22, X23, X24, X25, X26}
(5)
p = 1 − p′ = 0.000444 3
(9)
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events 12, 17, 24 and 25 are larger than the probabilities of conventional deepwater drilling events. Assuming that the probability of event 12 is 0.06, the probability of event 17 is 0.045, the probabilities of events 24 and 25 are 0.03. Then the well control success rate is given by formula (12), the blowout risk probability is given by formula (13).
Table 1 The corresponding events in the fault tree with their basic probability. Sequence Number
Event Name
Probability
T A B C D E F G H I J K L M N O P Q R S X1
Large scale blowout Blowout Control failure Blowout in drilling Blowout in cementing Inadequate bottom pressure Leakage in cementing Cement pollution caused by gas channeling Insufficient drilling fluid volume Overflow found not in time Excessive suction pressure Inadequate drilling fluid density Leakage in drilling Going down too fast Shut in failure Well killing failure Operation failure Equipment failure Operation failure Equipment failure Drilling the abnormal-high pressure oil-gas reservoir shallow water and shallow gas Grouting not timely Excessive drilling fluid density Design failure Operation failure Design calculation error Inaccurate formation pressure prediction Drilling fluid pipe leakage Hydrate layer dissociated gas into the wellbore Incorrect detection method Personnel negligence Long time for pump off Excessive cement paste density Casing or seal failure Step execution error Incomplete execution Design, manufacture and maintenance failure of BOP Underwater wellhead fault caused by hydrate dissociation in the pores Unreasonable design method (Shut in) Exceed the safety limit of shut in Throttle line over loss due to unreasonable drilling fluid pump velocity Unreasonable throttle control Unreasonable design calculation and method Block up caused by formation of hydrate from decomposing gas Throttle valve malfunction Well killing pump malfunction Exceed the safety limit of well killing
/ / / / / / / / / / / / / / / / / / / / 0.15
X2 X3 X4 X5 X6 X7 X8 X9 X10 X11 X12 X13 X14 X15 X16 X17 X18 X19 X20 X21 X22 X23 X24 X25 X26 X27
p′ = 1 − (1 − 0.85 × 0.953 × 0.985 × 0.92 × 0.9 × 0.962 × 0.94) × (1 − 0.982) × (1 − 0.955 × 0.962 × 0.984 × 0.972) × (1 − 0.95 × 0.86 × 0.955 × 0.972 × 0.963 × 0.983) × (1 − 0.95 × 0.86 × 0.955 × 0.962 × 0.98) = 0.999434 (12)
p = 1 − p′ = 0.000444
This result indicates that hydrates increase the risk probabilities for large-scale blowouts, which is 2.35 times larger than the risk associated with conventional deepwater drilling. Therefore, deepwater hydratebearing reservoir pre-assessments should be improved, and related preventive measures should be taken. Immediate measures must be taken if a large-scale accident occurs. 4. The risk control measures in deepwater hydrate-bearing reservoir drilling process
0.05 0.02 0.05 0.05 0.02 0.08 0.02 0.1 0.04 0.02 0.04 0.02 0.04 0.05 0.14 0.03
According to the analysis of the large-scale blowouts possibility of deepwater drilling when encountering hydrate-bearing reservoir, control methods should be conducted. (1) Event 20 and event 27 are the most important issues, that's mean large-scale blowouts mainly occur when the wellhead pressure exceeds the safety limits, which is caused by design, operation and equipment failures during the shut-in and well killing processes. Risk control designs must be optimal. The optimal design methodology includes engineering design, hydraulic design, timely well kick controls and a suitable tripping speed. The well control equipment must be integrated and effective, especially to minimize the failure effects of the equipment. The design methods and operations cannot exceed the safety limits. Prevention measures specific to hydrates must be taken prior to drilling, including safety training for the relevant workers, in-well control operations and effective job preparation. (2) In addition to the conventional well controls, hydrate dissociation risks should be accounted for when drilling in hydrate-bearing layers. - The wellbore pressure and temperature must be controlled to prevent hydrate dissociation during the drilling process. The wellbore pressure and temperature directly affect the hydrate stability, which is related to the wellbore pressure balance, wellbore wall stability, casing strength, drilling string strength and well control safety. Potential problems and risks must be analysed before drilling, and the optimum parameters must be selected to maintain stable wellbore pressures and temperatures. - Gas will gather in the BOP and other areas, posing a significant hydrate reformation risk in case of the hydrate dissociation in the layers are encountered. Therefore, the wellbore pressure and temperature should be calculated and supervised during the shutin period, and certain hydrate inhibitor should be injected into the BOP. - The hydrate dissociation risk caused by thermal cementing disturbances must be controlled. Cement slurry with low hydration heat must be designed because of high heat of hydration of conventional well cements. In addition, thermal cementing disturbances should be properly analysed in hydrate-bearing layers.
0.04 0.04 0.02 0.02 0.02 0.04 0.02 0.02 0.02 0.02
Compared to conventional deepwater drilling, the probabilities of events 9, 18 and 21 are 0. Thus, the conventional deepwater drilling well control success rate is given by formula (10) and the blowout risk probability is given by formula (11).
p′ = 1 − (1 − 0.85 × 0.953 × 0.985 × 0.92 × 0.963) × (1 − 0.982) × (1 − 0.97 × 0.96 × 0.985) × (1 − 0.95 × 0.86 × 0.97 × 0.962 × 0.984 ) × (1 − 0.95 × 0.86 × 0.97 × 0.96 × 0.98) = 0.999759 (10) p = 1 − p′ = 0.000241
(13)
(11)
The blowout risk in deepwater when encountering hydrate-bearing reservoir is nearly 84% higher than the conventional drilling based on the same conditions. Because the hydrate is sensitive to temperature and pressure, gas invasion caused by hydrate dissociation and hydrate regeneration in pipe and BOP must be addressed, the probabilities of 4
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5. Conclusions
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Combining the hydrate-bearing reservoir characteristics and deepwater drilling factor risks, a fault tree was established based on a largescale blowout as the top event. The following conclusions were ascertained based on the fault tree analysis: (1) Shut in failure and well killing failure because of exceeding the safety of limit is the first risk in hydrate formation drilling, equipment failure caused by hydrate dissociation and design, manufacture and maintenance of BOP is the second reason. (2) Risks in drilling of hydrate-bearing reservoirs are clearly higher than the conventional drilling risks in deepwater environment due to hydrate dissociation. Therefore, pre-assessments and preventative measures must be improved in deepwater drilling when encountering hydrate formation. Acknowledgments The authors gratefully acknowledge the financial support by the National Basic Research Program of China (2015CB251200), Program for Changjiang Scholars and Innovative Research Team in University of China (NO. IRT_14R58), National Natural Science Foundation—Outstanding Youth Foundation (51622405), National Natural Science Foundation (51876222) and National Key Research and Development Program of China (NO. 2017YFC0307304). Appendix T′—structure function of fault tree, used to describe the minimal cut sets of the success tree in this research. P—the minimal radius sets of the fault tree. I—the importance of issues. p—the blowout risk probability. p’— the well control success rate. References Abimbola, M., Khan, F., Khakzad, N., 2014. Dynamic safety risk analysis of offshore drilling. J. Loss Prev. Process. Ind. 30 (3), 74–85. Ashutosh, Kumar Jha, et al., 2012. Will gas hydrate lying on oceanic floors in India solve its energy problem? A futuristic approach. In: SPE Europec/EAGE Annual Conference, Copenhagen, Denmark, June 4–7. Barker, J.W., Gomez, R.K., 1989. Formation of hydrates during deepwater drilling operation. J. Petrol. Technol. 41 (3), 297–301. Birchwood, R., et al., 2005. Wellbore stability model for marine sediments containing gas hydrates. In: American Association of Drilling Engineers National Technical Conference and Exhibition, Houston, Texas, America, April 5–7. Boswell, R., 2009. Is gas hydrate energy within reach? Science 325 (5943), 957–958. Boswell, R., Collett, T.S., 2011. Current perspectives on gas hydrate resources. Energy Environ. Sci. 4 (4), 1206–1215. Botrel, T., 2001. Hydrates prevention and removal in ultra-deepwater drilling systems. In: Offshore Technology Conference, Houston, Texas, America, May 1–3. Cheliyan, A.S., Bhattacharyya, S.K., 2017. Fuzzy fault tree analysis of oil and gas leakage in subsea production systems. J. Ocean Eng. Sci. 3 (1), 38–48. Chen, D.F., et al., 2003. Proceeding of gas hydrate research and development in US. Adv. Earth Sci. 18 (2), 321–325. Chong, Z.R., et al., 2015. Review of natural gas hydrates as an energy resource: prospects and challenges. Appl. Energy 162, 1633–1652. Collett, T.S., 2000. Natural Gas Hydrate: Natural Gas Hydrate as a Potential Energy Resource. Springer, Dordrecht. Dou, Y., Guan, Z., Xu, Y., 2006. A review and prospect for the development of offshore drilling. Offshore Oil 26, 64–67.
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